Report of Working Committee 1
TRIENNIUM 2003 - 2006
Chairperson Colin Lyle
United Kingdom
EXPLORATION, PRODUCTION AND TREATMENT OF NATURAL GAS
June 2006
1 PREFACE
This report presents part of the work carried out by the Upstream Committee (WOC1) of the International Gas Union. WOC 1 has the very wide subject area of Exploration, Production and Processing of Gas. During 2003-2006 WOC1 continued to develop some of the themes investigated in past triennia, but also took a new approach to the organization of the work of the committee. The halves of this report have been put together by our two study groups.
SG 1.1 The World’s Most Significant Gas Fields Study Group Leader Djaouid Bencherif, Sonatrach, Algeria Technical Advisor Marie Françoise Chabrelie, Cedigaz
SG 1.2 New Horizons for Exploration, Production and Treatment of Gas Study Group Leader Dominique Copin, Total, France Technical Advisor Mark Howard ,BP
During the period 2003 -2006 the committee has been chaired by Dr Colin Lyle, Managing Director Gas Market Insights Ltd., UK, and former Director of European Policy Centrica plc.
Dr. Vadim Kobilev, Gazprom, Russia started the triennium as Vice Chairman, and Dr. Vladimir Yakushev, VNIIGAZ (Gazprom), Russia took over the role in spring 2005.
Rebecca Hyde, Centrica, UK acted as the Committee Technical Secretary until autumn 2005 when she was replaced by Adam Hinds, Centrica plc, UK.
PRÉFACE
Ce rapport présente une partie de l’analyse réalisée par le Comité de Travail “Amont” (WOC1) de l’Union Internationale du Gaz. Ce Comité couvre le domaine très vaste de l’Exploration, de la Production et du Traitement du Gaz. Au cours du triennat 2003-2006, le Comité a continué à développer certains des thèmes examinés lors du précédent triennat, mettant aussi en œuvre une nouvelle approche dans l’organisation du travail. Les sections de ce rapport ont été réalisées par nos deux groupes :
SG 1.1 Les gisements gaziers les plus significatifs au monde Groupe de travail conduit par Djaouid Bencherif, Sonatrach, Algérie Conseiller technique : Marie-Françoise Chabrelie, Cedigaz
SG 1.2 Nouveaux horizons pour l’Exploration, la Production et le Traitement du gaz Groupe de travail conduit par Dominique Copin, Total, France Conseiller technique : Mark Howard, BP
Au cours de la période 2003-2006, le comité a été présidé par Dr Colin Lyle, Directeur Général de Gas Market Insights Ltd., Royaume-Uni, ex-Directeur des affaires européennes, Centrica plc.
Dr. Vadim Kobilev, Gazprom, Russie a commencé ce triennat en tant que Vice-Président du comité. Au printemps 2005, il a été remplacé par Dr. Vladimir Yakushev, VNIIGAZ (Gazprom), Russie.
Rebecca Hyde, Centrica, Royaume-Uni a été en charge du secrétariat technique du comité jusqu’en automne 2005, avant d’être remplacée par Adam Hinds, Centrica plc, Royaume-Uni.
2 ACKNOWLEDGEMENTS
WOC 1 would like to thank all the contributors to this report; especially the members of the study groups and the various companies that have supported our work through personnel resources, sponsoring our meetings and/or through making data available for our work. All their contributions have been greatly appreciated and this report would not have been possible without them.
REMERCIEMENTS
Le Comité de Travail 1 remercie toutes les personnes ayant contribué à la réalisation de ce rapport, en particulier les membres des groupes de travail et les compagnies pour leur soutien logistique et financier de nos réunions et/ou pour la fourniture de données disponibles pour alimenter nos travaux. Toutes leurs contributions ont été vivement appréciées. Sans elles, la rédaction de ce rapport n’aurait pas été possible.
3 TABLE OF CONTENTS
Preface
Acknowledgements
Table of Contents
Overall Summary and Conclusions - Introduction - Trends and Key Messages - Outlook and Future IGU Work
1 Part 1 – World’s most significant gas fields
Introduction
1.1 – Gas Field Summaries 1.1.1 Aconcagua (United States) 1.1.2 Groningen (The Netherlands) 1.1.3 Hassi R’Mel (Algeria) 1.1.4 Karachaganak Field (Kazakhstan) 1.1.5 Nuggets Field (United Kingdom) 1.1.6 Shtokmanovskoye (Russina Federation) 1.1.7 South Morecambe (United Kingdom) 1.1.8 Urengoy (Russian Federation)
1.2 - Analysis by selected criteria 1.2.1 Market Impact 1.2.2 Technological advances References to 1.2.2 1.2.3 Sustainable development 1.2.4 Future potential
Conclusions to Part 1
2 Part 2 – New horizons for gas exploration and production
Introduction to Part 2
Summary of Part 2
2.1 - New Horizons in Gas Exploration and Associated Technical Challenges 2.1.1 Exploration for Gas in Artic 2.1.2 Exploration for Gas in Fold Belts 2.1.3 Deep Exploration 2.1.4 Technical Challenges
2.2 - Offshore Gas Development Challenges 2.2.1 Gas Export from Floating Production Systems in Deep Water 2.2.2 Flow Assurance for Long Distance Flow-Lines in Cold and Deepwater Environments 2.2.3 Subsea Gas Processing Challenges 2.2.4 High Pressure High Temperature Reservoir Developments 2.2.5 Development Challenges in Offshore Artic and Ice Prone Regions References to 2.2
4
2.3 - Processing of Natural Gas Containing Acid Components 2.3.1 Pre-Extraction Process 2.3.2 Amine and Chemical Solvent Processes 2.3.3 Physical Solvent Processes 2.3.4 Physical/Chemical Solvent Processes 2.3.5 Chemical Absorption Processes 2.3.6 Physical Absorption Processes 2.3.7 Biological Processes 2.3.8 Electrochemical Processes 2.3.9 Introduction of New Technologies to the Industry
2.4 - CO2 Geological Storage: Principles and Application to Field Projects 2.4.1 CO 2 Storage Projects - Currently Operating at the Commercial Scale 2.4.2 CO 2 Storage Projects - Planned Operation at the Commercial Scale 2.4.3 Selected CO 2 Storage Pilot and Demonstration Projects 2.4.4 Summary and Conclusions: Current Status and Needs to Progress Geologic Storage References to 2.4
2.5 - Commercial Development of Gas-to-Liquids Industry 2.5.1 Growth of the GTL Industry 2.5.2 Brief History of GTL 2.5.3 The GTL Process 2.5.4 The markets for GTL Products 2.5.5 Economics of GTL
2.6 - Methane Hydrates and their Prospects for the Gas Industry 2.6.1 Gas Hydrates in Nature 2.6.2 Exploration and Production 2.6.3 Ecologic Problems Attributed to Natural Methane Hydrates. 2.6.4 Gas Hydrate Technologies for Storage and Transportation of Natural Gas and CO 2 Sequestration. 2.6.5 Review of Gas Hydrate Activities in Different Countries
Conclusions to Part 2
Appendix 1: Members of the Committee
5 OVERALL SUMMARY AND CONCLUSIONS
INTRODUCTION
This opening section gives some brief background to the study group work, summarises some themes that emerged as the committee considered the combined results of the study groups and looks forward to further investigations in the next triennium.
The first main part of this report reviews the experiences that have been gained from the discovery and exploitation of the world’s most significant gas fields: what is their current status and what lessons have been learnt and applied? The second part presents information on some new commercial horizons for exploration, production and treatment of gas, in particular some new developments that could have a significant commercial impact in the coming decades of the 21 st century.
The starting point for our Study Group dealing with the World’s Most Significant Gas Fields was to define the criteria on which to evaluate their significance. The four categories chosen were
• Market impact • Technological advances • Sustainable development • Future potential
These are further explained in the report. Examples of the fields selected in these four categories are shown below.
WOC 1: Exploration & Production of Natural Gas Examples of Significant Gas Fields & Categories
Shtockman Bovanenkovo Snoehvit
Troll Urengoy
Groningen
Aconcagua Hassi R ’Mel In-Salah North Field, South Pars,
Malampaya
Market Impact Sustainable Development
Technical Advances Future Potential
Datasheets on these, and some other fields that are considered significant on a global basis are presented in the report as an overview of some of the world’s most significant upstream gas developments. There is then a short analysis of the four criteria. Case studies of some of these developments are being presented at the 23 rd World Gas Conference in Amsterdam, at which the results of a delegate vote on the world’s most significant Gas Fields will also be revealed.
6 The second main part of this report reviews some of the most interesting and current developments in the exploration, production and treatment of gas that we expect will have their first major commercial applications in the 21st century.
The following diagram gives an indication of the wide work scope of study group 1.2:
SOME NEW HORIZONS FOR UPSTREAM GAS
- HP/HT Reservoirs - Low Permeability New Gas Exploration Exploitation in East Offshore Production Permafrost Siberia N.European Gas Areas Zones E&P for LNG Export
Russian LNG export to Japan Deep Water Potential E&P Potential Methane Methane Hydrate Hydrate Production Production
GTL Onshore New S.American Gas Exploration New production for LNG Export Plays from Caspian & Middle East
New horizons cover new geographical and geological areas of gas exploration and production, new technology that is being, or soon to be, commercially applied to discover, exploit or treat upstream gas, and new management approaches across the whole E&P gas business. There is also a special chapter to review the technical and commercial potential for exploitation of methane hydrates.
TRENDS AND KEY MESSAGES
Through combining the experience gained from studying the world’s most significant gas fields with the information and analysis on new commercial upstream opportunities, we have identified some global trends and key issues that materially affect the upstream international gas businesses in the coming decades.
Current trends in production
Giant and Super Giant Gas Fields (fields with reserves above 1 Tcm) provide about 20% of world gas production. The share of smaller fields is growing and we expect in the longer term it will continue to grow. However, because several giant gas fields started to produce only recently (North Field, South Pars, Zapolyarnoye) and also because most of the giant gas fields have yet to be developed, the share of production of the giants in the next decade will very likely grow more quickly than that of smaller fields.
7 Marketed gas production in 2004 (Bcm) Gas giants vs others (estimated) Giant fields Others Total North America 10 706.8 716.8 of which US 10 523 533 Latin America 0 166 166 Europe 61.1 264.3 325.4 Norway 26.4 57.1 83.5 Netherlands 34.7 42.8 77.5 CIS 334 462.9 796.9 Russia 325 308.5 633.5 Other CIS 9 154.4 163.4 Africa 76 73.6 149.6 Algeria 76 4 80 Middle East 74 208.6 282.6 Iran 35 49.9 84.9 Qatar 39 0 39 Asia-Oceania 0 340 340 TOTAL 555.1 2222.2 2777.3 US: Hugoton Norway: Troll Netherlands: Groningen Russia: Medvezhye, Urengoy, Yamburg, Zapolyarnoye Algeria: Hassi R'Mel Data Source: Cedigaz
The natural gas industry is well known to operate over very long timescales, not least because of the capital intensive nature of the infrastructure projects and the complexity of putting together the necessary operational and contractual arrangements throughout the whole gas chain. Although some small upstream projects can now be brought to market within a couple of years of discovery, the world’s gas giants inevitably take much longer when they are located far from the main markets. Examples are Bovanenkovo and Stockmann, both discovered in the 1980s each with reserves estimated to be more than the annual gas consumption of the whole world, but production from these fields is only expected to commence during the next decade. Giant disc overies:
Tc Year of discovery and initial in-place reserves 30 North 25
20
15 South Gronin 10 Zapol Hassi yar Bovanenk 5 Yamb East Shtockm Tr 0 1950 1960 1970 1980 1990 2000 2010 Year of
Data Source: Cedigas
8 Global supply/demand : Upstream industry performance in renewing world gas reserves
The gas produced and consumed in the world has to be roughly in balance. All world gas demand projections, as set out in IGU Programme Committee B’s report, show significant increases in world gas demand averaging [2-4%] over the next [20-25 years]. In WOC1 we anticipate gas production increasing by something in the region of an average of 2-2.5% over the next 20-25 years.
Throughout the last three decades of the 20 th century, the world R/P ratio for natural gas grew steadily as increasing quantities of natural gas were discovered and proven to be technically and economically recoverable. The upstream industry was averaging nearly 4tcm per annum of increased gas reserves, while consumption was averaging 2-2.5 tcm. By the mid 1990s the R/P ratio, of proven gas reserves to world gas consumption, had reached 60 years.
Evolution of World R/P Ratio
Years 70 60 50 40 Proven reserves on 1.1.n 30 ------Production year n 20 10 0
7070 7474 7878 8080 8282 8484 8888 9090 9292 9494 9898 0202 0404 1919 19721972 1919 19761976 1919 1919 1919 1919 19861986 1919 1919 1919 1919 19961996 1919 20002000 2020 2020
Lower gas prices and rapidly increasing gas demand at the end of the 20 th century led to a flattening of growth in the R/P ratio. Looking forward, in a growing global gas market the 60 years R/P ratio will start to decline rapidly unless far more gas than is produced is discovered and proven to be economically recoverable. However, the upstream industry continues to add to the quantity of proven reserves more quickly than it is depleted by consumption, and we expect this trend to continue, helped by the added impetus of higher energy prices.
Exploration : The Challenge is high but should be met
Gas exploration is not as mature as oil, with many more significant discoveries still possible, but likely to be geographically spread and in remote areas.
Because of the growth in world gas demand and the maturity of oil exploration, there is a general expectation that E&P companies will increase their gas activities, but in many cases gas investments currently seem to be less attractive to them than oil.
Many of the challenges are technical and also involve care to ensure environmental sustainability. Developments in Arctic zones, exploration and exploitation of fold belts and deep and tight reservoirs will play a major role for the increase of supply.
9 One of the main technical challenges to meet is the improvement of seismic imaging through improved acquisition, processing and interpretation.
Not only are there challenges in moving to farther locations around the globe, but also exploring in deeper water depths and for deeper reservoirs. If we define a deep reservoir as more than 4,500 metres below the surface then it is the case that only 5% of world gas reserves have been discovered in deep reservoirs. However, because of easier or more economic targets, only 5% of the world’s exploration drilling has taken place at such depths… there may be a lot of deep gas still to be discovered.
Development and operations : the industry will face new challenges.
Arctic challenges include how to deal with construction and year-round drilling and production operations, offshore ice management, impact on facilities and infrastructures (permafrost) and establishing remote operation with minimum intervention.
New gas developments will present us with serious cost challenges associated with increasingly tight reservoirs, complex structures or difficult environments such as deep water (e.g. riser systems, flow assurance, subsea compression for floating facilities in >500m etc…).. Other challenges include the need to minimise the surface footprint of on-shore developments for environmental reasons and establishing confidence in reliable HPHT technology offshore.
Technological developments will improve the prospects for successful exploration as well as improved economics, leading to improved recovery from mature fields as well. Improved seismic, hydraulic fracturing, formation treatment, reservoir modelling, water conformance etc…all continue to make an impact on upstream gas industry performance.
We feel that there may be far-reaching implications of the increasing proportion of sour gas remaining in some established gas producing provinces (e.g. Mid East) – there will be environmental issues of sulphur mountains or effects of major re-injection, but also an opportunity for a step change in technology to reduce costs.
Generally, the industry will need to cope with ecological and environmental issues. A prime illustration of this is CO2 sequestration, which is becoming a feature of acid gas development and may well be expected as the norm in future. Indeed we expect that the natural gas upstream industry will be well placed to provide environmental solutions for sequestration of CO2 from other anthropogenic production.
Resources and markets : making physical, chemical and commercial links.
Developing physical pipeline or LNG links between upstream gas reserves and downstream markets will remain a fundamental feature of the global gas market, but we anticipate the development of other linkages, in particular “chemical” links through the conversion of natural gas to something else that is then distributed to the market. In particular Gas-To-Liquids (GTL) is establishing itself as the chemical link between remote sources and markets – and should be helped if high energy prices continue.
Gas is becoming a regional and soon a global commodity business, creating larger market opportunities for remote or major fields – e.g. LNG to China could stimulate growth of gas markets eventually creating the possibility for the development of major pipelines from Siberia to the Asian market and creating opportunities for incremental gas sales to spot markets.
Methane Hydrates
Methane Hydrates may be of commercial significance for some industrially developed areas in the next decade, particularly if current energy prices are sustained.
10 OUTLOOK & FUTURE IGU WOC1 WORK
This summary reveals several areas of further study that could be developed by WOC1 in the next triennium. These could relate to the exploration challenge of replenishing the world’s proven reserves, the development and operational challenges of increasingly remote and difficult reservoirs, and the technical and environmental issues posed by future sour gas production and the trend to control CO2 emissions.
Some specific new topics that might be considered include:
• Re-evaluating Deep Gas Potential (>4,500m reservoir depth) • Challenges of increasing water depth (current limit is 2000m, what next?) • Long distance transportation options (jointly with another IGU Committee) o Can GTL work away from the sea? (so its not competing with LNG) o Other remote reserve options (Gas-to-Wire, Gas-to-H2, LNG, CNG) • Abandonment and De-commissioning of upstream structures
But it will be the new Committee that makes the decisions on what topics to study. From the members of WOC1 in the 2003-2006 triennium we wish them every success, and hope that the rest of this report provides an interesting and informative basis for their work in the coming triennium.
11 PART 1 - WORLD’S MOST SIGNIFICANT GAS FIELDS
INTRODUCTION
From the outset it was clear to our Study Group, under the leadership of Djaouid Bencherif, that we needed to set criteria to help us make judgements about what makes a gas field significant in a global context. Clearly size would be important, but there would be other factors too.
After conducting an internal questionnaire among WOC1 members and analysing the results, the study group held a brainstorm in Copenhagen and came up with the following table. This was not a definitive list, but formed the basis of further evaluation.
The four categories require some explanation and examples:
12
Market impact
This measure of significance is based on an assessment that,production from the field has led to the development of a large downstream gas market or has enabled gas to become the leading fuel in a particular region. The effect of the field on the local economy or the market structure can also be considered.
Examples of gas fields with significant market impact
Groningen, The Netherlands The main gas source for the development of Continental NW Europe’s residential gas market Hassi R’Mel, Algeria North Africa’s largest source for pipeline and LNG exports Urengoy, West Siberia, The gas source for the first pipeline corridor through Ukraine to Russia Europe
Technological advances & challenges:
This is also primarily a historical category, in which
• difficulties faced to develop the reservoir required the application of new techniques, equipment or processes that have subsequently been applied in other upstream projects or are expected to be further developed for future gas production.
Examples of gas fields with significant technical advances
Loma la Lata, Argentina Onsite analysis combining 3D seismic, directional drilling, dynamic reservoir simulation and stimulation by hydraulic fracturing Malampaya, Philippines The 500-km subsea high integrity steel pipeline is at the forefront of 21 st century deep water technology Troll, Norwegian Sea Constructed in 350 meters water depth, involving overland transport of the world’s longest concrete structure
Sustainable development:
This covers a wide range of issues including
• exploitation of natural gas found in ecologically sensitive or environmentally challenging locations, through to issues arising from the production and treatment of acid gas to satisfy economic and environmental imperatives.
Examples of gas fields where sustainable development is significant
Bovanenkovo, Russia The largest gas field on the Yamal peninsular, involving an arctic development and long-distance delivery via ecologically sensitive areas In Salah, Algeria First large-scale example of CO2 capture and storage in the same reservoir Snohvit, Barents Sea, The world’s most northern LNG project, also involving CO2 Norway sequestration
13 Future potential:
This is a forward-looking measure in which
• large remaining reserves or production levels that could be sustained for several decades to come are indicators of high potential, as are major possibilities for developing new production or enhancing existing production or increasing recoverable reserves by a very substantial amount
Examples of gas fields with significant future potential
North Dome, Qatar The gas field expected to lead world’s gas production during the next decade Schtokman, Barents Sea, The first offshore Russian giant expected to be developed, Russia enhancing Russian gas production South Pars, Iran Potentially the largest phased development in the world to support the domestic market growth and exports
The following pages of this part of the report comprise a series of field datasheet or summaries for a selection of these significant gas fields, followed by a short analysis under the headings of the four criteria. Clearly there are some gas fields that are in several categories and these are likely to be the most significant on a global level. We do not aim to pick a winner, but we do hope that this information and analysis will help share understanding of the lessons that can be learnt from the development and future prospects for a wide range of significant natural gas reservoirs on out planet.
14 1.1 GAS FIELD SUMMARIES
1.1.1 ACONCAGUA (UNITED STATES)
Over the past decades, oil and gas exploration in the Gulf of Mexico (GOM) was first carried out in shallow shelfal areas (<200 m) adjacent to the coast, later progressing to the broad slope (200 - 2,000 m) as key government fiscal incentives were implemented. Starting in the early 1990s, exploration shifted outwards rapidly into ever-deeper waters as technology and new field discoveries fuelled the move towards the abyssal plain (> 2,000 m). Significant ultra-deepwater oil and natural gas discoveries then transformed the GOM Basin from a declining petroleum province to one of world class stature.
Located in the Mississippi Canyon area (eastern Gulf of Mexico), some 140 miles Southeast of New Orleans, Aconcagua is one of three ultra-deepwater natural gas fields produced by the Canyon Express system, the others being Camden Hills (operator, Marathon Oil Co.) and King’s Peak (operator, ATP).
Aconcagua was discovered in March 1999 in block MC305 in 7,073 feet (2,155 meters) of water. The field was drilled with an appraisal well to 14,113 feet with over 250 net feet of gas pay encountered. The appraisal well confirmed reservoirs extending approximately two miles to the Northeast.
Location map of major fields in the Mississippi Canyon and Desoto Canyon Blocks
Aconcagua is 50% owned and operated by Total E&P USA Inc. Partners on the field also include Pioneer Natural Resources (37.5%), and Nippon Oil Exploration USA Ltd, (12.5%).
Geology
The producing reservoirs are a series of high-permeability, unconsolidated sands, underlain in several cases by water-bearing sands. Aconcagua lies in a Miocene 1c production horizon.
Reservoir Characteristics
Maximum water depth: 7,096 ft Measured depth (MD): 13,150 – 14,113 ft True vertical depth (TVD): 13,031 – 13,971 ft Measured reservoir depth: 12,386 – 13,546 ft Perforated interval thick: 35 -161 ft Permeability: 200-2,000 mD Max. wellbore deviation: 57 degrees Initial reservoir pressure: 6,490 - 6,550 psi Reservoir temperature: 175°F
15 Gas Composition and Fluid Data
Dry gas. No H 2S and very limited amounts of CO 2 and inert gases. Primary produced fluid: gas Gas gravity: 0.56 Condensate yield: 1 – 3 bbl/MMcf Calorific value: 1020 Btu/MMscf
Major Development Milestones and Facilities Design
Developed with four wells (2-3 producing intervals per well), the Aconcagua field started producing in September 2002, setting a new world record in deep-water production (7,130 ft). This record was then beaten by Camden Hills (7,209 ft) which began to produce a few weeks later.
As no single field contained sufficient reserves to economically justify development costs - their total gas reserves were estimated at less than 1 trillion cubic feet of gas -, Aconcagua, Camden Hills and King’s Peak, were pooled altogether into a multifield deep-water development named Canyon Express, sharing infrastructure to improve the economics of such marginal development, while involving three different operating companies and different field co-owners. The gas accumulations are located in Mississippi Canyon (Blocks 217, 305, and 348) and Desoto Canyon (Block 133), the most distant well location being 57 miles far from the platform.
Intelligent completion technology was used in eight of the nine production wells in all three fields to optimize the subsea development of this marginal reserve base, along with pipeline, platform and subsea system synergies and to maximize production capability and reservoir management efficiency. This technology enables gas production from multiple zones to be commingled, and the well to be reconfigured to shut-off water production without the requirement for well intervention. Because these reservoirs water-out very quickly, once water production begins, this ability to drain the multiple gas sands was key to the completion design which also eventually came to include stacked frac-pack sand control, pressure-operated fluid-loss and well-control devices.
It also allows operators to obtain real-time or near-real-time reservoir data, and then reconfigure the wellbore production-injection architecture to adapt to the information obtained. Data from the downhole pressure and temperature gauges help maximize field potential. The data, processed on surface, are integrated into reservoir models to obtain a better understanding of field depletion, water encroachment, and reservoir extent.
Produced gas and condensate from all wells are conveyed using the dual parallel 12-inch flowlines Canyon Express Gas Gathering Pipeline System, back to the host processing platform, located in Main Pass Block 261 and known as Canyon Station. Canyon Station is a fixed-leg platform installed in 300 feet of water. Commissioned on September 19, 2002 when the well MC 305 N°1 started producing, it is designed to treat, process and handle up to 500 Million cf/d of natural gas. Williams Field Services operates the Canyon Station platform.
Operated by Total, the Canyon Express Gas Gathering Pipeline System was given permit by the Minerals Management Service (Gulf of Mexico region) in September 2001. It comprises 32 pipeline segments and is jointly owned by the Aconcagua owners (45%), King’s Peak owners (35%) and the Camden Hills owners (20%).
Flowline sleds laid in-line connect the flowline to the individual wellheads via short conventional inverted U-shaped jumpers with a maximum 80-ft length. As a result, flowline routing is dictated to a large part, by the location of the subsea wells. A wet-gas Venturi multiphase flowmeter, at each well production jumper, is used to allocate production prior to the fluid entering the flowline.
A short jumper that allows for pigging connects the western and eastern flowlines at the termination point in the Camden Hills field. The surface control on Canyon Station employs a common master control station (MCS) for sending and receiving data and emergency shutdown (ESD) signals from the subsea control modules.
16 A single muliplexed electro-hydraulic control umbilical (MUX) connects the platform to the three fields in a daisy chain configuration. This umbilical transmits power, communication, chemical, and hydraulic fluid from the platform to the individual fields via an electro-hydraulic distribution unit (EHDU). A separate umbilical supplies methanol. Dual 12” Flowline Canyon Station Ptf Single Methanol Distribution Line 280 ft C D 2 3# C 13 M 2 7# Electro-hydraulic 21 Umbilical C M 6,530 ft #3 17 2 ine L est W C M 2 5# 30 C e M 4 in 5# L 30 st Ea 7,200 ft C M 1 C C 5# M 1 M 30 C 8# 2 M 3 34 8# 5# 7,000 ft 34 30
Source: Total E&P USA
The EHDU distributes a constant 5,000-psi control pressure at the subsea control system for operating downhole equipment. Each EHDU, one for each field, distributes all functions controlled through the umbilicals to the individual subsea control modules. Affixed to each subsea tree is a subsea control module to execute tree, downhole equipment, and flowline valve controls.
The project’s umbilical system is the deepest steel tube umbilical ever installed, containing steel tubes, electrical cables and fiber optics. The $600 million project is one of the most advanced tiebacks yet achieved.
Economical and Technical Challenges
The Canyon Express Project overcame many challenges which are typical of an area which is already mature (with existing production infrastructures nearby) or of a declining producing region. Subsea well completion design and implementation in record-setting water depths in Aconcagua field and the entire Canyon Express Gas Gathering Pipeline System are part of these.
This project indeed represented the largest field-wide deployment of intelligent completion technology with eight of the nine production wells completed as intelligent wells to optimize the reservoir. Because limited gas reserves in this high-cost, deep-water environment precluded future economic intervention, the completion design had to balance the complexity of multiple-zone production with high life-of-well reliability. The Canyon Express Pipeline System has to produce the three fields, under different operating regimes and varying production rates from multiple zone completions –without any field taking on the performance risk of another field. Accurate flow allocation was therefore essential.
During the life of the field, the technology will improve field efficiency by increasing production and minimizing workover needs.
Because of the tight field-development economics and scarcity of available personnel resources within each company, the operators on the project had to agree to a personnel-sharing arrangement. A joint group called “The wells integrated project team (WIPT)” was formed for subsea tree installation and for well-completion design and implementation. The Canyon Express is a unique development as for the collaboration of several operators in an effort to reduce costs in developing three separate deep-water fields.
17 1.1.2 GRONINGEN (THE NETHERLANDS)
The Groningen gas field was discovered in August 1959, when well Slochteren-1 struck gas in the northern province “Groningen” of the Netherlands, situated some 180 km NE of Amsterdam. The gas accumulation was later confirmed in 1960 and 1961 by well Delfzijl-1 drilled about 20 km from discovery wells Slochteren-1, Noordbroek, Schildmeer and Bierum.
The large size of the Groningen field was however not recognised until 1963 when -after reinterpretation of the seismic data- the various accumulations were recognized to be part of one huge gas field that covered an area of some 900 square kilometres. The North-eastern part of the field extends slightly offshore into an area of common interest for the Netherlands and Germany.
The Groningen concession was granted to the Nederlandse Aardolie Maatschappij B.V. (NAM) in 1961, whereby NAM is a 50-50 partnership between Royal Dutch Shell and ExxonMobil. Shell was designated as operator of the field.
Groningen
Source: Oil and Gas in the Netherlands, 2005, TNO, Ministry of Economic Affairs Location map of Groningen field
18 Geology and reservoir properties
Three horizons in the Groningen field were found to be gas bearing: (1) The Ten Boer claystone, which is the upper member of the Rotliegend formation. It comprises out of shales intercalated with thin gas-bearing sand lenses.
(2) The Slochteren sandstone, which is the main productive reservoir and the lower part of the Permian Rotliegend formation.
The depth of the sandstone reservoir is approximately 2,900 m. Its gross thickness increases from 230 ft (70 m) in the Southern part of the field to 790 ft (240 m) in the most Northern part. On average the gas-bearing sand thickness exceeds 100 m. The reservoir is bounded in all directions by faults, except to the North where it is in contact with a number of small aquifers. The Northern part of the field is underlain by bottom water, whereas this is not the case in the structurally higher situated Southern part of the field. Many faults, with throws that range from 100 ft (30 m) to several hundred feet, divide the field into numerous blocks; these faults do however not pose significant barriers to flow. The gas/water contact is at 9,744 ft (2,970 m) tvss in the main field.
The Slochteren reservoir is a homogeneous clean sandstone, with well-sorted grains. The in- situ weighted well porosity range from 16 to 20%, with the highest values situated in the central part of the field. Individual sands may have porosities up to 30%. The permeability varies from 50 to 600 mD, which agrees well with core permeabilities. The ratio between vertical and horizontal permeability is roughly 0.3. The only significant continuous shale break (Ameland claystone) is only encountered in the Northern part of the field.
(3) The Carboniferous formation directly underlie the Slochteren sandstone. These consist of shales, coal beds, and sandstone layers varying from only 3 to 100 ft (1 to 30 m) thick. Some of these sands are juxtaposed against the Slochteren sandstone and directly are partly drained through this formation.
Groningen gas composition
The Groningen gas is relatively dry (condensate and water content are about 1 vol/million vol gas and 4 vol/million vol gas, respectively).
Average reservoir composition “Pseudo” wellhead composition Component Mol % Component Mol % MolWT SP.GR Helium 0.05 Helium 0.04999 Nitrogen 14.35 Nitrogen 14.34611 Carbon dioxide 0.89 Carbon dioxide 0.88982 Methane 81.23 Methane 81.21361 Ethane 2.85 Ethane 2.84943 Propane 0.37 Propane 0.36933 Iso-butane 0.07 Iso-butane 0.05599 N-butane 0.07 N-butane 0.08398 Iso-pentane 0.02 Iso-pentane 0.02000 N-pentane 0.02 N-pentane 0.02000 Neo-pentane 0.02000 Hexane 0.02 Benzene 0.01 C6+A 0.01187 74.52 0.6654 Heptanes & 0.05 C6+B 0.01667 82.22 0.6702 heavier C6+C 0.01561 91.33 0.6784 C6+D 0.01267 101.52 0.6900 C6+E 0.00930 112.87 0.7055 C6+F 0.00624 125.49 0.7255 C6+G 0.00384 139.51 0.7505 C6+H 0.00216 155.10 0.7817 C6+I 0.00110 172.43 0.8199 C6+J 0.00082 204.34 0.8994
Source: Nederlandse Aardolie Maatschappij, 1991
19 To avoid hydrocarbon condensation in the gas transmission system, Groningen gas is generally conditioned at cold separator conditions of –12 Deg.C and 74 bars.
The delivery contract for Groningen gas specified a minimum delivery pressure, a water dew point of -2 Deg.C at 63.8 bar, but no hydrocarbon dew point.
Groningen gas reserves
Original gas in-place in the Slochteren sandstone is 2,840 billion normal cubic meter sales volumes (appr. 100 Tcf). The expected remaining reserves of the Groningen Field as of 1.1.2006 are approximately 1045mrd Nm3 sales volumes, whilst some 20% of these reserves remain to be developed through the finalisation of the current Groningen Long Term investment programme (expected in 2009).
Field development and facilities
The Groningen gas field started producing in 1963. Initial development was limited to the Southern part of the accumulation, where the complete reservoir was not underlain by an aquifer.
On the basis of favourable reservoir properties (high permeability and good reservoir connectivity), it was decided to drain the reservoir by wells grouped together in clusters, thus economizing on surface facilities. Production wells were drilled from one cluster, feeding into a gas- treatment plant that is situated next to the well-location. The first 14 clusters were set up in the structurally high southern part of the field, with each cluster consisting of 8 wells at an initial (total) capacity of appr. 14 million m 3/d. The gathering system consisted of a looped pipeline with three sales manifolds.
Due to rapid market growth and increased off-take from the Southern part of the Field, pressure differences across the field were experienced. At the end of 1969, reservoir simulation studies demonstrated that a restricted off-take from the Southern part of the field would result in considerably lower average wellhead pressures, when compared with development of the entire field (i.e. Central and Northern area). In order to meet capacity requirements, a considerable amount of new wells were drilled in the Central and Northern parts of the field - with the installation of corresponding new cluster treatment facilities. Each cluster had an initial capacity of about 24 million m3/d (through 11 wells), whilst a newly constructed gathering centre was connected with a pipeline to the Southern loop.
The Groningen field is currently produced through some 300 wells at 29 cluster locations (14 standard size clusters and 15 king size clusters). Some 30 observation wells are also drilled over the peripheral part of the field.
The total nominal (name plate) gas processing capacity of the surface facilities is some 555 millions m 3/d (0 Deg. and 1.01325 bar), although many clusters are now capacity constrained due to reduced well deliverabilities. With an average of around 10 –12 wells, each cluster produces through a common manifold into five low temperature separation units, in which the gas is cooled down to -12 Deg. C (at 74 bar) to meet the required specifications. Cooling is achieved by a Joule Thomson (JT) valve and a gas/gas exchanger. This low temperature is obtained principally by expansion of the gas. Condensate and water are eliminated to prevent build-up of liquid slugs in the delivery pipelines.
Extending the field’s operating life
Up to the end of the 1980’s, the initial reservoir pressure of 350 bar had been sufficient to meet the required flow at the minimum manifold pressure that was required to operate the low temperature separation plants effectively (about 25 bar higher than the gas delivery pressure).
However, the reservoir pressure soon started to decline some 3 bar. per year, thereby reducing the required production capacity, which urged NAM to develop a framework plan to meet the demand for Groningen gas in the decades to come.
20 Free-flow production (i.e. without compression) in Groningen is expected to cease at approximately 2010. In order to ensure access to the remaining reserves and continue its role of swing producer to cover peaks in demand, NAM launched the “Groningen Long-Term Field Renovation and Compression project” in 1998. This 2 US$ billion modernisation programme, was kicked off in 1996 with the aim to rejuvenate the production facilities, improve the environmental performance of the plant and install a total of 500 MW gas compression. The first wellhead cluster was equipped with a compressor in 1998 as part of the first-phase covering 11 clusters. The compressors are centrifugal compressors, driven by electrical motors and installed upstream of the treatment units. The development of this “silent compression system” also represents significant progress for the gas industry as it eliminates the need for costly compressor buildings. The rotors of these 23 MW compressors are fully supported by “magnetic bearings”. In addition, new instrumentation fully automates the control system and further speeds gas delivery time. All of the field’s 29 production clusters will ultimately be upgraded, securing gas production for at least another 40 years. The Groningen Long Term rejuvenation programme is due to be completed by 2009.
The programme also aims to apply the principles of sustainable development, a key element of the plant modernisation being a glycol regeneration system that separates water and condensate to eliminate gas emissions.
Gas marketing
The Groningen Field undoubtedly marked the beginning of a new chapter in the Dutch history and the start of an industrial era of natural gas production and consumption in Western Europe. Soon after confirmation of its large potential, it became apparent that the potential of this economic deposit exceeded domestic gas needs and could significantly contribute to supplement gas supplies in neighbouring countries. Export contracts were signed with Belgium, France, Germany, Italy and Switzerland, covering some 50% of identified reserves. In the 1980’s, these contracts were extended through the period 1995 to 2010.
Producing at minimum flow during the summer period and high production capacity during winter-periods, the Groningen field has played a major role in balancing gas demands in both the Netherlands and much of Western Europe. After 40 years of production, the Field is still a major energy supply source in the NW-European region. With 38 billion cm produced in 2004 (out of a total Dutch gas production of 78 billion cm), the field accounts for about 7% of total European gas supply. Groningen gas is delivered to Gasunie through a 195 km long transportation system to seven custody transfer stations.
Source: NAM Groningen’s producing flows versus temperature fluctuations
21 In accordance with the provisions of the Gas Act, the Minister of Economic Affairs has set an upper limit for the production of natural gas from within the Netherlands in the medium-term, including Groningen deposit. This scenario assumes that over the period 2005 - 2009, the Groningen field will supply almost as much gas (184 billion cm Groningen Gas Equivalents) as all other accumulations in the Netherlands (190 bcm). Over the period 2010 - 2014, the maximum supply from the Groningen accumulation on the basis of the upper production limit should even exceed that from non-Groningen accumulations (198 bcm Geq compared to 152 bcm Geq).
Source: Oil and Gas in the Netherlands, 2005, TNO, Ministry of Economic Affairs
While the regeneration programme will put the production capacity of the renovated field at around 340 million cubic metres of gas per day (12 bcf/d), the balancing role for Groningen is expected to continue. With about 1,060 billion cm of gas remaining, “Groningen is still expected to be a key producer for up to another 25 years and a smaller-scale producer for the years thereafter.
22 1.1.3 HASSI R’MEL (ALGERIA)
Sonatrach owns 100% and operates the Hassi R’Mel (desert gate) non-associated gas field which was discovered in 1956 by the French company SEHR, a branch of SN Repal (Société nationale de recherche et d’exploitation en Algérie) and CFP-A (Compagnie Française des Pétroles).
Located 550 km south of Algiers, Hassi R’Mel is the first and by far the largest gas field in Algeria. It extends over 70 km from north to south and 50 km from east to west, on an area of more than 3,500 square kilometers.
Source: Sonatrach
Geology and reservoir properties
The Hassi R’Mel gas condensate reservoir is a large anticline structure presenting an elliptical shape with a SouthWest/North-East orientation. Gas is being produced at three different Triassic sands levels (A-B-C) encountered between 2 110 m and 2 280 meters:
- layer A occurs throughout all the field. It is composed of fine sandstone with strong anhydritic cementing. Height ranges from 34 m to 13 m. Average xx=15%. K= 260 md.
- layer B is much more restricted and wedges out on the southern and eastern flanks. It is constituted of more or less shaly fine sandstone, intercalated in a series of shale. Height ranges from 30 m to 0 m. Average xx=15%. The average k is greater than 500 md in the axis of the channels, which decreases to low permeability (0.1 md on the edges).
- layer C is also restricted. It is composed of fine and medium sandstones with many conglomerates. This is the thickest of the three layers, the thickness Ht regularly ranges from North towards the South with 60 m in the Northern zone up to 0 m in the southern zone. It shows excellent petrophysic characteristics (average k = 641 md, average xx= 16.8%) and has significant net pay zone, as well as better production and storage capacities.
23 Nord Sud
HR127 HR115 HR102b HRi32 HR135 HR27 HR145
TD 2400.0 m TD 2400.0 m TD 2400.0 m TD 2400.0 m TD 2400.0 m TD 2400.0 m TD 2400.0 m
m m 0 5000 10000 15000 20000 25000 30000 35000
LO G 1 TO PS LO G 2 LO G 3 LO G 1 TO PS LO G 2 LO G 3 LO G 1 TO PS LO G 2 LO G 3 LO G 1 TO PS LO G 2 LO G 3 LO G 1 TO PS LO G 2 LO G 3 LO G 1 LO G 3 LO G 2 LO G 3 LO G 1 TO PS LO G 2 LO G 3
DT (u s/ft) DT (u s/ft) DT (u s/ft) DT (u s/ft) DT (u s/ft) RHOB (g/cm3) DT (u s/ft) 140.0 40.0 140.0 40.0 140.0 40.0 0.0 100.0 140.0 40.0 1.9 2.7 140.0 40.0 GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) GR (gAPI) NPHI (m3/m3) LLD (ohm.m) 0.5 -5.0E-03 0.5 -5.0E-03 0.5 -5.0E-02 0.0 0.45 0.5 -5.0E-03 -5.0E-02 0.45 0.5 -5.0E-03 m 0.0 150.0 RHOB (g/cm3) 0.11000.0 0.0 150.0 RHOB (g/cm3) 0.11000.0 0.0 150.0 RHOB (g/cm3) 0.11000.0 0.0 160.0 RHOB (g/cm3) 0.22000.0 0.0 150.0 RHOB (g/cm3) 0.11000.0 0.0 150.0 DT (u s/ft) 0.12000.0 0.0 150.0 RHOB (g/cm3) 0.11000.0 m 1.8 2.8 1.8 2.8 1.8 2.8 0.0 100.0 1.8 2.8 140.0 40.0 1.8 2.8
TOP A -1350 -1350
TOP A
TOP A
-1375 -1375
MUR A MUR A MUR A
TOP B
-1400 TO P A -1400
TOP B TOP C MUR B
MUR B
TOP C
TOP C
TOP A MUR C
-1425 MUR C -1425 TOP A
MUR A
MUR A
MUR C TOP B
-1450 -1450
MUR A
TOP A MUR B
TOP B
TOP C TOP C -1475 -1475
MUR C
MUR B
MUR A -1500 -1500 TOP C
TOP B
MUR B
MUR C -1525 -1525
TOP C
-1550 -1550
MUR C
-1575 MUR C -1575
Cross section North-South, Hassi R’ Mel Source: Sonatrach
The fluvial environment for the three sandstone levels shows a northward transport orientation. The sand bodies are in the form of stretched bars with a length of several tens kilometres and a width of 7 kilometres.
Natural and artificial thermoluminescence (TLN and TLA) are identical for the three layers but with well differentiated quartz nodules in layer C. Besides, a study was conducted on the Saharian Paleozoïc platform to localize the eventual origin of Triassic sandstone. Among the numerous formations studied, only three contain quartz identical to TLN and TLA with the Hassi R’Mel sandstone. These formations are Moscovian, Ordovician (El Gassi, El Atchane and undifferentiated Ordovician sandstones) and Cambrian. Ordovician sandstone is probably the main Hassi R’Mel Sandstone origin area in Upper Triassic.
Reservoir characteristics
Average water saturation (obtained from Archie equation): - reservoir A: 18.5% - reservoir B: 20.48% - reservoir C: 16.5%
Dew point: 311 kg/cm 2
Gas composition at Hassi R’ Mel
- C 1: 78.6% - N 2: 5.3% - C 2: 7.3% - C 7+ : 2.3% - C 3: 2.7%
Hassi R’Mel field gas is wet and contains 200 grams of condensates and four grams of LPG per cubic meter, necessitating a partial recycling for the dry gas to be recovered.
Calorific value
9.4 th/m 3
24 Natural gas and condensate reserves
The Hassi R’Mel is essentially a gas and condensate field. Only the latest wells drilled to the east of the structure encountered oil. • Natural gas: - Initial reserves in place: 3 295 billion m 3 - Proven recoverable reserves: 2 415 billion m 3 - Probable reserves: Estimated at 2 700 to 3000 billion m 3
Hassi R’Mel field contains around 60% of Algeria’s total natural gas reserves.
Milestones in Hassi R’Mel field development
Hassi R’ Mel field was developed in phases to respond to the growth of local and European gas markets.
♦ Hassi R' Mel started operating in 1961 with two gas processing units producing up to 1.3 billion m3/year of wet gas. In 1969, another four units were installed, increasing the capacity to 4 billion m3/year. From 1972 to 1974, six additional units started operating, boosting production to 14 billion m 3/year and enabling the field to supply feedstock to the Skikda liquefaction plant. In 1974, 21 production wells were in operation at Hassi R’Mel.
Stimulated by the significance of the recoverable reserves of gas, condensate and LPG in the field, and the prospects for growing gas demand in Europe, Sonatrach implemented plans to further develop the field’s output. However, over the period 1961 to 1979, the yield of gas liquids had decreased from 210 tons per million m 3 of dry gas (in 1961) to 195 tons (in 1979) and it became necessary to maximize the LPG and condensate recovery by partial cycling of the dry gas.
♦ From 1980 to 1996, while the yield of gas liquids had continued to drop from 192 to 132 tons per million m 3 of dry gas, a major development program was completed in October 1980, the purpose of which was to establish alternate production and reinjection zones to boost pressure in the field. The scheme consisted in re-injecting part of the gas produced into the reservoir at high pressure through two 30 billion m 3/year compressor stations. Two lines of injectors (one line between northern and central producing areas and the other between the southern and central producing areas) were installed. All gas production and injection modules were to operate at capacity until the plant inlet pressure of 100 kg/cm 2 limited gas production. Over the period, wet gas production was boosted from 23 standard billion m 3/year to 98 standard billion m 3/year with additional processing facilities and an LPG recovery complex, raising Hassi R’ Mel’s total LPG production capacity to 3.84 million tons/year, was commissioned.
Over these 15 years, more than 1 374 standard billion m 3 of wet gas, 215 million tons of condensates and 44 millions tons of LPG were produced from 160 wells and 619 standard billion m3 were injected from 54 injectors.
♦ Since 1997, Hassi R’Mel has been producing more than 100 standard billion m3/year of wet gas at its maximum capacity. The cycling rate has decreased dramatically from 38% (in 1997) to 21% (in 1999), causing the yield of liquids per million m 3 of dry gas drop from 127 to 98 tons. Liquids recovery has fallen to a level close to the minimum rate of operation required for the gas processing facilities. In addition, the pressure drop impacted the influx of the aquifer and some wells located on the top of the structure, in the southern part of the field, had to be shut-in due essentially to high salinity.
As the field matures and since a portion of the gas is sold, pressure declines. The constraints of the surface facilities imply a minimum pressure value of 115 kg/cm 2 at well-head. The lower pressure in the reservoir results in lower wellhead pressure and insufficient energy to move the gas until its treatment into the different modules, accordingly necessitating gas compression to be
25 installed. The challenge which was raised to Sonatrach consequently consisted in optimising the field and predicting when gas compression (installation boosting) would be required. Improvement in the simulation model, integrating and combining surface constraints (network facilities) and the reservoir characteristics, was the key to the implementation of boosting. The reservoir simulator used for calculations is the Miscible Vectorised Implicit Program MVIP. MVIP was a 3D, four phases simulator intended for use in modeling miscible flood performance. The four phases were designated as wet gas, dry gas, oil and water, with wet gas being the initial gas in place and dry gas corresponding to the injection gas.
The Hassi R’ Mel model was performed utilising a grid system, constructed with either rectangular or radial coordinates, comprising 41 cells along the X axis and 53 along the Y axis. Individual area cell sized in the model ranged from a typical cell in the middle of the field covering 1118 square metres to a cell covering 40 249 square meters in the aquifer. In the vertical direction, the Z-axis, there were three cells, or layers (Triassic A, B and C).
The result of various simulations on sales profile showed that compression was required by 2003. Sonatrach accordingly had three major gas boosting compressor stations and 11 compression lines installed at the field in late 2003. The second phase in compression installations is to be completed in 2007. It will add another six compression lines to the enhanced recovery system. This will maintain pressure at a level allowing maximum recovery of condensates and LPG and will extend Hassi R' Mel production life to 2020, keeping its maximum capacity of 100 billion m3/year.
Hassi R’ Mel gas markets
Over the years, nine lines have been built to carry dry gas from Hassi R’ Mel, while four others transport condensate and LPG. Some of these pipelines supply the domestic market. However, a major share of the dry gas transportation capacity has been dedicated to exports.
Since the Seventies, Hassi R’ Mel gas has been transported to the Mediterranean coastal ports of Arzew to the north-west and Skikda to the north-east, for exports as liquefied natural gas to the United States and Europe. With two LNG plants, Algeria’s current liquefaction capacity amounts to 27.4 billion m3/year.
Pipeline Length (km) Diameter (inch) Comments Hassi R’ Mel to Arzew 507 to 509 each line 24 – 20 (GZ0), Main gas pipelines from (GZ0, GZ1, GZ2, GZ3 40 (GZ1, GZ2) Hassi R’ Mel to LNG and LZ1) 42 (GZ3) plants. 24 (LZ1) Hassi R’ Mel to Skikda 573 40 (GK1) (GK1, GK2) 42 (GK2) Alrar – Hassi R’ Mel 956, 962 42 and 48 From Alrar gas fields to (GR1, GR2) Hassi R’ Mel
Later in the Eighties, Hassi R’Mel started supplying feedstock for a gas export line to Italy, with the Enrico Mattei pipeline, built across Tunisia and Sicily. This pipeline has an export capacity of 27 billion m3/year.
More recently, in 1996, Algeria started operating its second export pipeline to Continental Europe. The Petro Duran Farell was built across Morocco and the Strait of Gibraltar to supply Spain and now has a transportation capacity of 11 billion m3/year.
Algeria is pursuing its dual strategy of combining LNG and pipeline export infrastructures. Additional pipelines are being built (offshore Medgaz to Spain) and planned (offshore Galsi to Italy) and two LNG plants are also being considered. While Hassi R’ Mel enters a new production phase, additional fields gradually enter the picture to supplement the old gas giant and push Algeria on its way for continued export growth.
26 1.1.4 KARACHAGANAK FIELD (KAZAKHSTAN)
Karachaganak oil and retrograde gas-condensate reservoir is located in the Northwest of Kazakhstan, 150 km east of Uralsk, near the Russian border. It was discovered in 1979 and covers an area of over 280 square kilometers.
Figure 1. Location of the Karachaganak field and associated transportation infrastructures
The Karachaganak field started producing in 1984 under the operatorship of Karachaganakgazprom, a subsidiary of Russia’s Gazprom. In 1992, when Kazakhstan became an independent state, Kazakhstan state gas company, Kazakhgas, took over operatorship. At that time, BG and Agip secured exclusive rights to negotiate for the further development of the field and in 1995 signed a Production Sharing Principles Agreement with Gazprom, KazakhGas and the government of Kazakhstan.
Under a 40-year Production Sharing Agreement (PSA) signed in November 1997 with the Kazakh government, four international partners joined and formed Karachaganak Petroleum Operating B.V. (KPO), a consortium aimed to develop and operate the field. Shareholders in the j-v are:
- BG Group (United Kingdom): 32.5% interest, - AGIP (Italy): 32.5%, - ChevronTexaco (United States): 20% (Texaco acquired its shareholding from British Gas/Agip in August 1997), - Lukoil (Russia): 15% (replaced Gazprom in the j-v in November 1997).
Under the agreement, KPO will operate the Karachaganak facilities through to 2036.
Geology and reservoir properties
The Karachaganak field is located at the northern margin of the Precaspian Basin that contains a number of hydrocarbon discoveries such as Astrakhan, Tengiz and Kashagan. The field overlies a Devonian-Visean aged horst, upon which Upper Visean to Upper Serpukhovian carbonate platform lithologies (Permian evaporated salt layers) have been deposited. This carbonate massif measures 40 km by 15 km. Pay height is 100 to 600 meters at 4,050 to 5,250 m true vertical depth. The
27 Karachaganak reservoir has been found to be highly heterogeneous and limestone deposits are of low porosity and permeability (micro fractured) with local enhancements due to dolomitisation. The dolomitisation has been adversely impacted by a later diagenetic anhydrite precipitation.
The lower stratum contains oil with a compositional gradient from top to bottom, followed by a thick stratum of condensate. The upper stratum, the largest, contains natural gas. Historically, the reservoir has been divided into three principal reservoir layers, known as Objects. The crest of the structure is at 3500 mSS, the gas-oil-contact at 4950 mSS and the oil-water-contact at 5150 mSS.
Object 1 starts from the top of the formation down to the Permian-Carboniferous unconformity at around 4450 mSS. This Object is laterally discontinuous and production wells produce a leaner gas condensate fluid and typically exhibit more rapid rates of pressure decline and well productivities.
Object 2 wells produce a richer gas condensate fluid and typically show good pressure communication within their immediate area.
Object 3, which contains the reservoir oil leg, has been noticed to be laterally continuous and the gas condensate and oil rim is exhibiting pressure communication.
Reservoir properties
Static bottom hole temperature at 5100 m (ss): 85°C Shut-in bottom hole pressure at 5100 (ss): 600 bar (8700 psi) Maximum shut-in wellhead pressure: 400 bar (5800 psi) Flowing wellhead temperature: 10 to 40° C Flowing wellhead pressure: 180 to 250 bar (2610 to 3625 psi) Initial reservoir pressure: 520 to 595 bar Temperature: 70 to 95°C
Gas composition
C1: 80% CO 2: 5.5% to 7.45% as a maximum H2S: 3.5% to 5% as a maximum
Gas - condensate Ratio: 1000 to 3000 m 3/m 3. The reservoir contains a uniquely complex gas condensate fluid system with a continuously changing fluid composition that ranges from a rich gas condensate with a GOR of 2000 sm 3/m 3 at the reservoir structural top to very rich gas condensate with a GOR of 800 sm 3/m 3 at the GOC and an under-saturated black oil at the reservoir base and OWC.
Gas - Oil Ratio (GOR): 300 to 800 m3/m 3 Condensate gravity: 42 to 52° API. The condensate has initial density of 47°API. Condensate density: 0.62 to 0.79 kilograms per cubic metre Oil gravity: 34 to 42 degrees API Liquid hydrocarbons contain: CO 2: 1% H2S: 65%
Well average porosity varies between 7.3% and 15.4% and the permeability between 1.3 to 81.1 m Darcy.
Oil, gas and condensate reserves
Initial in-place gas: 1,350 billion cubic meters Initial oil and condensate in-place: 1,200 million tons (9.4 billion bbl)
Estimated recoverable gas reserves: 1,040 to 1,170 billion cubic meters Estimated recoverable oil & condensate: 480 million tons
28 Field development and production facilities
The Karachaganak field was only partially developed until the break-up of the Soviet Union in 1991. During that period, rather small volumes of gas and partially stabilised liquids were transported to the processing facility in Orenburg, Russian Federation. Production peaked at 4.5 billion cubic meters/year of gas and 4.5 million tons/year of liquid hydrocarbons.
The Production Sharing Agreement signed in 1997 led to and governed the full development of the field, also putting in place long-term transportation and processing agreements for the gas and liquids.
Second phase (1998-2003)
In August 2003, the Karachaganak Processing Centre (KPC) was opened, to process the oil and the natural gas produced from the field. The KPC has a processing capacity of 96 million barrels/year of oil and 14.5 billion cubic metres/year of natural gas. A 240 MW power plant and three high-pressure compressors also started operating during the period.
Currently, hydrocarbons production is delivered from the wells to manifolds, where they are blended. After that, blended hydrocarbons travel to the treatment facility, where oil and gas are separated and then treated. The consortium KPO transports the gas across the Russian border to the Orenburg plant for processing. KazRosGaz, a Russian-Kazakh joint venture, in which Gazprom and KazMunayGas (KMG) - a joint venture established in 2001 between Gazprom and Kazakhstan as a vehicle for cooperation in gas development, transport and marketing - hold equal interest, sells the treated gas. The western Kazakhstan Region consumes gas processed at the Orenburg plant. In 2004, the consortium KPO produced 9 billion cubic meters of gas.
The primary reservoir drive mechanism is a combination of pressure depletion and gravity drainage. Current reservoir development strategy aims to reinject gas into the top of the Object 2 carboniferous reservoir for partial pressure maintenance and production from producing wells completed in the lower half of the Object 2 and Object 3. 40% (6.4 billion cubic meters) of produced gas is accordingly reinjected into the field, requiring one of the highest pressure sour gas reinjection schemes in the world.
Liquid hydrocarbons are transported by pipeline from Karachaganak to Atyrau over 650 km to the Caspian Pipeline Consortium (CPC) for exports.
Since signing of the Karachaganak project PSA in 1997, total investments by all the parties involved have exceeded $4.3 billion, including $3.5 billion in the second phase.
Third phase (2003-2008)
A few years ago, major plans to expand the field production facilities were considered. Kazakhstan initially planned to independently process and sell gas from Karachaganak. Accordingly, in 2003, the country’s government began a feasibility study to build another gas processing facility at the field to treat natural gas and, possibly, sulfur, as part of the third phase of the project. With an approximate cost of $1.2 billion, the scheme also included the construction of a petrochemical plant and an export gas pipeline. The export pipeline was to be connected to the Central Asia-Centre system or to the Western Border-Orenburg gas pipeline, 70 km from the field.
In 2004, Gazprom, Orenburggazprom and the operator of the Karachaganak project, KPO, had signed a long-term 15-20 year contract to deliver 7 to 8.5 billion cubic meters per year of gas to the Orenburg Gas Processing Plant (OGPP).
Early in 2005, Gazprom submitted a new project for the third phase of Karachaganak expansion. It consists in delivering Karachaganak gas to the Orenburg processing pant, from where gas may be connected into the Russian grid, going to Samara. Gas sweetening could also be done in Orenburg.
29 This scheme involves the modernization and the upgrade of the OGPP, requiring the reconstruction of existing facilities, three new units and the addition of two gas pipelines from Karachaganak to Orenburg. The capacity of OGPP will accordingly be raised to 15 billion cubic meters/year.
A joint venture to expand OGPP facilities, partly owned by Gazprom, was set-up. Under the current scheme, Gazprom is expected to contribute the assets of the gas processing plant as its contribution to the joint venture. KazMunayGas is to purchase 50% of the shares of the plant.
Besides, realization of the gas portion of the Karachaganak project is the responsibility of the Kazakh side. Under the current Production Sharing Agreement for the project, 60% of the financing is to be provided by Kazakhstan and foreign investors bear 40% of the project’s costs.
Gas Marketing
Although the gas resource is the largest part of the accumulation, the way the Karachaganak field has been developed shows that a key value driver is to deliver increased volumes of liquids over a significant plateau period to Western markets. To achieve this, increasing volumes of gas, arising from the natural growth in gas-liquids ratio as the reservoir depletes, have to be handled. In the years ahead, this will increasingly be managed by the drilling of horizontal wells into lower sections of the reservoir, by increased gas injection and by expansion of gas sales.
Karachaganak represents a large resource base with significant prospects for exports, demand on the local market expected to show rather moderate growth.
Planned peak production capacity of Karachaganak:
Oil & Condensate: 37,000 tons/day (290,000 bpd) = 12 Million t/annum from 2008 Oil density 0.8 kg/m 3 = 7.84 bbl/ton
Gas: 70 Million m 3/d (2.5 bcf/d) = 25 billion cubic meters/annum
Over the entire contract term at Karachaganak field, production is forecast at 320 million tons of liquid hydrocarbons and 797 billion cubic meters of gas.
Sales market for Karachaganak gas could in Europe with, according to KazMunayGas, exports of 29 to 34 billion cubic meters by 2015. As a result of the signature of a long-term transportation and transit agreement for Central Asian gas through the Kazakh network concluded by Gazprom and KazMunayGas, gas from Karachaganak could also flow to CIS markets.
30 1.1.5 NUGGETS FIELD (UNITED KINGDOM)
Nuggets is a cluster of small hydrocarbon finds located in the Alwyn area, in the UK sector of the North Sea, 160 km east of the Shetlands Islands and 400 kilometres north-east of Aberdeen. It consists of four gas-bearing accumulations stretching over seven blocks (3/19a, 3/19b, 3/20a, 3/18c, 3/24a, 3/24c and 3/25a) of UK Quadrant 3, approximately 40 to 70 km south of Alwyn.
Total Exploration & Production UK plc operates Nuggets N1, N2, N3 and N4 with a 100% working interest, under licenses number P.239, P.118, P.491 and P.090. In 1994, Total and Elf had purchased Shell/Exxon’s (block 3/19a) and Mobil’s (block 3/19b) respective stakes in Nuggets.
The Nuggets field distinct gas discoveries were made in 1973 (Nuggets N1), 1974 (Nuggets N4), 1989 (Nuggets N2) and 1991 (Nuggets N3). These accumulations lie in an Eocene production horizon.
In 1973, Total drilled exploration well 3/19a-1B in 123m of water, to a depth of 2,468 m. The well tested gas at an initial rate of 12.4 MMscfd. A second well (3/20a-1) drilled in 1989, tested up to 23.4 MMscfd gas at 2,180 m. These two wells discovered and delineated the Nuggets N1 (North Nuggets) accumulation.
In 1974, the Nuggets N4 accumulation was discovered by Total-operated wildcat 3/25a-2 which tested 14.9 MMscfd of gas. A subsequent well (3/24a-3), drilled to the east in 1990, also encountered gas and proved the extension of Nuggets N4 (South Nuggets) into the 3/24a block.
In 1989, Shell drilled exploration well 3/19b-2 in 109 m of water, and predominantly found gas with some oil in this 4,100 m well (drilled to deeper Jurassic objectives). This Eocene accumulation discovered became the Nuggets N2 (West Nuggets) accumulation.
In 1991, Total drilled 3/19a-4 to the west of Shell’s find and tested gas at 25.5 MMscfd from the Eocene. This discovery was called Nuggets N3 (Southwest Nuggets).
Gas composition at Nuggets:
- C1: Approximately 98% - H2S: no evidence - CO 2: 0.15%
The Nuggets reservoirs contain relatively dry gas having a calorific value of 37.6MJ/m3, with a low proportion of condensate and water.
Production
The Nuggets system is designed to produce up to 6 MMscm/d (220 MMscf/d) of gas (peak) with around 150 bbls/day of associated condensate and up to 1000 bbls/day of water.
The field has now been on production for 4 years with current production of around 5.3 MMscm/d (190 MMscf/d) with around 140 bbl/day of condensate.
Field development and production facilities
The completion of the debottlenecking of the gas processing plant and the subsequent increase in treatment capacity at the Alwyn North platform in 1999, enabled the development of the Nuggets gas-bearing accumulations.
In July 2000, the UK authorities gave consent for the development plan for the Nuggets N1 gas accumulation. Less than a year later, in March 2001, development plans for Nuggets N2 and N3 natural gas fields, received approval. The remaining structure, Nuggets N4 was given development approval in April 2003. As Nuggets fields received development approval after 15 March 1993, they are therefore exempt from Petroleum Revenue Tax (PRT).
31 The Nuggets field development is the biggest satellite development in the Alwyn Area since the Dunbar field was brought on stream in late 1994. The gas accumulations were developed sequentially via isolated subsea wells, tied back to the Alwyn North “B” processing facilities. The development scheme was based on a phased approach and was made viable through the use of new technology. The complete project, required an investment of around $250 million (including N4).
Development process: A successful phased approach
The initial phase, which came into production in November 2001, consisted of N1 with two wells, and N2 and N3 with one well each. The potential also exists for a future well in N1.
Phase 1
N1: The Nuggets N1 accumulation is being produced via two wells, 3/19a-NGA and 3/20a- NGB, some 4 km apart. These wells link to a common (N1) manifold through individual 6” flowlines and from there via a 39.5km 12” trunk line with a methanol/MEG piggy back line from the manifold to the Alwyn North platform. Besides these facilities, the field development also included the installation of control and chemical injection facilities and umbilical on the Dunbar platform and the installation of reception facilities (slugcatcher and methanol storage facilities) on Alwyn North topsides. Wet gas metering had also to be installed at each wellhead with correlation adjustment for watercut prediction, as well as sand detection devices.
N2/N3: The Nuggets N2 and N3 accumulations, which were developed with a single well each, 3/19a-NGC and 3/19b-NGD respectively, are linked via 6” flexible flowlines to a manifold located near N3 located some 14.5 km to the south of the N1 manifold. Their development involved the extension of the 12” trunkline, pipeline and the methanol/MEG piggyback pipeline as well as the umbilical to the N3 manifold via the N1 manifold. These wells were completed in late 2001 and were brought on stream in January 2002.
Phase 2
N4: The Nuggets N4 accumulation started producing in October 2003, just six months after British authorities had approved the project. It was developed as a further single isolated subsea well, tied back via a 13-kilometre 8” subsea pipeline to the existing N3 manifold. From Alwyn North, Nuggets’ gas is exported via the Frigg pipeline system to the Scottish St Fergus Gas Terminal near Peterhead for processing and distribution.
The Nuggets fields are operated and controlled from Alwyn North via a fibre optic cable to the Dunbar platform, located 20 km to the north of the N1 manifold, from which the control and chemical injection umbilical runs.
Production from Nuggets N4 increased output from the Nuggets field from 175 to 220 million cubic feet/day of gas.
Innovative technology
With a total length of 67 km between the five step-out wells and the host platform, the Northern Underwater Gas Gathering Export and Treatment System (NUGGETS) is the longest tie- back producing in the UK North Sea at present. As shown with figure 1, the field layout for the pipeline system comprises:
- 39.5-km long, 12-inch diameter rigid production pipeline from the N1 manifold to the North Alwyn (NAB) platform, with a 3-inch rigid hydrate inhibitor pipeline piggyback (combined MEG/methanol). - 3.3-km long, 6-inch flexible production pipeline from the NGB well to the N1 manifold, with a 2.5- inch flexible hydrate inhibitor pipeline. - 14.5-km long, 12-inch rigid production pipeline from the N3 manifold to the N1 manifold, with a 4- inch rigid hydrate inhibitor pipeline piggyback.
32 - 4.4-km long, 6-inch rigid production pipeline from the NGC well to the N3 manifold, with a 2-inch rigid hydrate inhibitor pipeline piggyback. - 13-km long, 8-inch rigid production pipeline, with a 4-inch hydrate inhibitor line piggybacked alongside an electro-hydraulic control umbilical. These pipelines tie-back the N4 producing well to the N3 subsea manifold.
Lay out of Nuggets gas gathering and transportation system
Combining flexible and rigid pipelines, the Nuggets field development allowed both types to be utilised side by side, thus gaining the individual advantages (technical and economical) that each offers.
Because they fulfil reliability, easy-operation and cost-effective requirements, rigid pipelines formed the majority of the system, in particular for long distance transfer from the manifold to the Alwyn platform.
However, flexible flowlines played an important role, being well suited for short-distance tie- backs from the NGB and NGC wells to the manifolds, respectively being 3.3 km and 4.4 km long. Besides, the use of flexible pipe, against rigid pipeline, brought more flexibility to the installation and drilling schedule as well as low cost anti-upheaval buckling measures.
The gathering and transportation system contained a number of challenges for the designers, equally applying to both types of lines, which were also critical to the project time-schedule. These included:
33 - The design pressure for the 6-inch production pipelines is relatively high at 235 bar. The flexibles accordingly had to be more technically advanced than previous similar designs and optimised to prevent upheaval buckling, hence alleviating the requirement for backfill or rock dumping.
- Nuggets gas is “wet” and the risk of hydrates forming in the 6-inch production pipelines is high. Management of hydrate inhibitor into the well and the ability to remove a plug if formed are accordingly required.
- Upheaval buckling of the pipelines during service has to be mitigated against which is a large commercial concern during the project phase and a large operational risk during production.
The impact of gas production and transportation activities on the environment also represented an issue in the project design. The Nuggets area is heavily fished, and protection from fishing is required.
Gas marketing
As part of Alwyn Area gas pool, Nuggets’ natural gas is sold to a diversity of gas users, mainly on long term contracts.
The cluster of Nuggets field has enabled to prolong the life of hydrocarbon reserves in the Alwyn Area. Potential for maximising further the use of existing facilities now lies in the Forvie North gas/ conden-sate field discovered in June 2002, which is also being developed as a subsea tie-back to Dunbar.
34 1.1.6 SHTOKMANOVSKOYE (RUSSIAN FEDERATION)
The Shtokmanovskoye gas condensate field was discovered in 1988. It lies on the shelf of the Barents Sea, 290 km west of Novaya Zemplya Island and 650 km northeast of the town of Murmansk, at water depths of 305 to 330 m. Extending over 45 km in length and 35 km in width, the field is located in very harsh physical, as well as fragile environmental, conditions, with temperature ranging from - 25 °C in winter to + 25 °C in summer. Rough sea-bed conditions are compounded by drifting ice and waves height can reach 17.5 m.
Rosshelf initially controlled the licence for the Shtokman field. In 1995, a consortium comprising Total (France), Conoco (USA), Hydro (Norway) and Fortum (Finland) was formed to develop the accumulation with 50% of the equity. The other 50% plus one share was held by Rosshelf.
In 2000, the Russian government approved a Production Sharing Agreement (PSA) for the field, designed to establish a long-term legal framework for foreign investment in the natural resources sector. In 2002, the 1995 framework agreement expired and the licence for Shtokman was transferred to Sevmorneftegaz, a Gazprom and Rosneft joint venture. At the end of 2004, Gazprom acquired Rosneft’s 50% stake in Sevmorneftegaz as well as Rosneft’s 26% stake in the Rosshelf company, accordingly securing total control over the offshore fields in the Barents Sea.
Reservoir properties
At the present time commercial gas reserves have been found in the Jurassic deposits and gas accumulations have been revealed in five horizons.
- Initial formation pressure: 200-240 atm - Temperature: + 40 °C
Natural gas reserves
According to the Russian classification of reserves approved by the State Committee on Resources (SCR) in 1996, initial gas and condensate in place reserves (C1 and C2) are estimated at 3.2 trillion cubic meters and 30 million tons respectively. The share of recoverable condensate reserves amounts to around 80%.
Planned development of the field
More than ten development plans have been studied for the Shtokman field which will be Russia’s first gas-condensate offshore deposit to be produced in Arctic environment. This deposit will be developed step by step, optimizing operating conditions, using improved offshore field development technology, with the aim to take the opportunity for potential gas sales “niche”.
Until now Russia’s gas industry had no significant experience in field construction under such conditions. A number of climatic and technological challenges were encountered when designing the Shtokman field development, including:
- water-depth, - distance from the shore. Distance between the field and the shore is over 500 km and is considered as an additional obstacle to the field development. - pipeline transportation security, - possibility of using large diameter holes.
From economical and technological standpoints, the base-case field development assumes that it would be necessary to drill a total number of 56 to 156 production and observation wells, grouped in six clusters, to produce the field.
35 Total number of wells 156 Production wells 144 Stand-by wells 9 Test wells 3
Table 1. Number of wells necessary for the Shtokman field development (base case)
As it is illustrated below, in this scenario, three platforms are expected to be used to develop the field. Although there is no single opinion with regard to the type of platform (SPAR or TLP), specialists tend to favour the TLP platform.
Offshore ice-resistance platform
Loading system Long-distance gas pipelines
Manifold
Underwater producing complex Condensate storage
Fig 1. A general layout of the offshore production facilities of the Shtokman field
The use of underwater producing complexes is one of the innovative solutions, which impact on the existing base option of the field development. This solution will allow the platforms not to be brought into operation at the first stage with the subsequent possibility of quicker launch of the project with no reduction in planned production.
Pipeline transportation security over a distance more than 500 kilometers may be provided by a 200 atm working pressure, 30.2 mm average wall thickness long-distance gas pipeline. Throughput capacity of a single line is 22.4 billion cubic meters per annum, which was of aid in determining the base option of field development. Special attention in the project realization will be paid to an automated control system for production and transportation complex and also to an operating parameter control system.
In case of using large diameter holes additional work will be done to make the wells stable under arctic conditions and to protect against external action.
Two options for condensate transportation are under consideration. Produced condensate would be either exported to the onshore terminal by condensate pipeline or pumped into a tanker directly on the field.
36 Phased development and production potential
The field development is planned to be realized in three stages that will determine the dynamics of gas production over a 54-year period. Total gas and condensate production over the period is expected to reach 2.6 Tcm and 21.4 million tons respectively.
According to the base-case scenario, plateau gas production of 67.5 billion cubic meters annually may be maintained for 25 years. Annual condensate production is expected to reach 0.35 million tons.
First development phase
An initial daily output for one well is expected to be 2.6 MMm 3. 22.5 bcm per annum of natural gas are expected to be produced at the first stage. This volume corresponds to the maximum throughput capacity of a 42-inches gas pipeline that will connect the field to the shore.
Second and third phases
The second and third stages, that will allow gas production to reach 67.5 bcm per annum, are to be achieved in parallel with the construction of two additional gas pipelines, each with a throughput capacity of 22.5 bcm per annum. About a half of the producers will be required to drill only at the third stage, i.e. at the end of a maximum output when it becomes necessary to provide production to maintain the plateau level and for the period of declining output.
80
70 67,5
60
50 45
40 Bcm
30 22,5 20
10
0 the 5th year of project the 9th year of project the 13th year of project Years
Figure 2 - Shtokman gas production ramp-up
Based on the results of the first stage and analysis of demand from the field, a maximum annual gas production capacity of 90 bcm may be anticipated.
Should all the organizational issues be solved shortly, first gas could be produced around 2009- 2010 with planned annual production capacity to be reached by 2020-2021.
Gas marketing
Commercialisation of Shtokman gas was initially conceived in terms of pipeline transportation to markets in north western Russia and Europe. However, in 2004, LNG exports emerged as the option on which the initial development of the Shtokman field would concentrate on. The market analysis shows that in the future, natural gas demand is anticipated to grow significantly in North America and Europe and that Shtokman gas may well be competitive.
37
The first field development stage is accordingly expected to involve the construction of liquefaction facilities for Russian LNG to enter the North American market, but also Europe in addition to the existing gas pipeline supplies. For this, a base-load LNG plant is proposed to be built on the shore, near the town of Pechenega, with a capacity about 6 Million tons of LNG per annum.
The second stage of the field development will be designed to carry gas via a long-distance gas pipeline across Karelia to the Unified Gas Supply System in the region of the town of Volkhov. The pipeline construction will contribute to the gasification of the Murmansk region, Republic of Karelia and to diversify gas supplies in the Leningrad region. Integration of this gas line into the Unified Gas Supplied System will also allow gas from the Shtokman field to be transported to Europe.
As to the third stage of the field development, the market to which gas would be intended for would be considered at a later date, fitting the situation in Russian and Atlantic gas markets by then. In the future, the Shtokman field development will consequently open up more possibilities for the active presence of Russian gas in the world gas market, which is of particular importance as gas production from the main Western Siberian fields is declining.
Over the past few years, international companies have shown much interest in the Stokman field development. The list of companies that Gazprom has currently selected for final negotiations include ChevronTexaco, ConocoPhillips, Norsk Hydro, Statoil and Total.
However, the main issue to be discussed between Russian and foreign companies is the sale of natural gas. The Russian side insists on a single export channel for the Shtokman field gas while the potential partners propose to buy gas on the Russian shore so as to sell it on the markets on their own. Therefore, an arrangement must be made on the sale of gas and an organizational structure must be formed prior to the effective implementation of the field development project by the potential partners.
The development of the Shtokman gas-condensate field becomes very important for Russia’s gas industry. It must be considered as both an element of Russia’s energy security and as an instrument to consolidate the position of Russian gas in the world gas market.
38 1.1.7 SOUTH MORECAMBE (UNITED KINGDOM)
The South Morecambe non-associated gas field was discovered in September 1974, forty kilometres offshore west of Blackpool in North West England. This field, which is 100% owned and operated by Hydrocarbon Resources Limited (a wholly owned subsidiary of Centrica), covers an area of 32 square miles in the East Irish Sea Blocks 110/2a, 3a and 8a. The transfer of the Morecambe area assets in 1997 from BG E&P enabled the formation of Centrica as a FTSE 100 company.
The South Morecambe field contains 80% of the total amount of the Morecambe gas field reserves. The rest of the gas at Morecambe is in the North Morecambe field, discovered in 1976 and where production started in October 1994.
The Morecambe South gas is trapped in Triassic Sherwood Sandstones beneath impermeable mudstone and salt. The gas originated in deeper Carboniferous coals and shales.
The top of the gas reservoir is 670 to 1143 meters below sea level and the sea around Morecambe platforms is approximately 30 meters deep. The shallow depth of the reservoir complicated the development of the field and a slanted drilling rig had to be used to allow the development wells to reach the parts of the reservoir furthest from the production platform.
Cross section of the Morecambe Bay gas field Courtesy of the National Gas Archive (ref N° EM/ZP/ XXX/T/C/5)
39 Gas composition
- C1: 85% - N 2: 7.7% - C2: 4.5% - CO 2: 6% - C3: 1.0% - H 2S: <4.5 pm - C4+ : 1.2%
Although the two Morecambe fields are close together, the gas from the North Morecambe field is different to that from South Morecambe due to its higher content of carbon dioxide and nitrogen.
Calorific value
2853500 (1007 btu/scf)
Natural gas and condensate reserves
• Natural gas: - original: 5 322 bcf - remaining: 1 177 bcf (at 1 st of March 2005)
• Condensate: - original: 15.3 mmstb - remaining: 4.5 mmstb (at 1 st of March 2005)
In 1978, British Gas Corporation took the decision to develop the South Morecambe field. First gas from the field came ashore in 1985.
Offshore at South Morecambe, the field comprises a central production complex with five wellhead drilling platforms (four of which are normally unmanned and operated remotely), a processing/compression platform and an accommodation platform, all of which are bridge-linked. Gas from the remote drilling platforms is transported via four, 24-inch infield pipelines on the seabed to the central production platform. From there, gas is taken to shore to Centrica’s operated Barrow-in- Furness (Cumbria) gas terminal and storage facility, via the 38 kilometre, 36 inch sealine Morecambe South gas pipeline. Onshore, gas is processed ready for use by customers.
Initially free-flowing, offshore compression was installed on the field in 1992, with two 26 MW gas turbine driven compressor trains. Onshore processing capacity was also expanded to increase capacity from 34 million m 3/day (1200 MMscf/day) to 51 million m 3/day (1800 MMscf/day).
On the first year of peak production in 1999, the field produced up to 9.8 billion cubic meters of gas. During the Nineties, South Morecambe delivered up to 15% of the UK’s gas supplies at times of peak demand (winter months), equivalent to nearly 3 million homes.
In 2001, while the South Morecambe field had been delivering gas to the UK grid for over 15 years already, the engineering infrastructure on the field was given an increased life expectancy. To maximise post-plateau production rates, Hydrocarbon Resources Limited commissioned a major expansion of the compression facility for installation onshore at their Barrow Terminal. The South Morecambe Onshore Compression Project comprised two-30 MW gas turbine driven compressor trains, bringing total installed power to circa 110 MW (150,000 HP).
As output from South Morecambe Field must react readily to fluctuations in national gas demand, production from the facility varying considerably between summer and winter months, a GASMAN TM computer model had to be built for the entire gas field system to determine the actual operating conditions for the onshore and offshore compressors for a full range of operating scenarios.
Over the last 10 years, the South Morecambe field has produced in consistently reliable manner with >99% reliability. In 2004, natural gas output was 8.1 billion cubic meters, while condensate production averaged 1 645 bbls/day. Although approaching 80% of proved and probable reserve recovery, potential still exists within the South Morecambe field to enhance production.
40 1.1.8 URENGOY (RUSSIAN FEDERATION)
Discovered in June 1966, the Arctic Urengoy oil-and-gas-condensate field stands as one of Russia’s largest fields. It is located in northern West Siberia, in the centre of the Nadym-Pur-Taz oil- and-gas bearing region of the Yamal-Nenets Autonomous Area (YNAO), between 65 and 68 parallels of north latitude. The Urengoy field extends over 230 km from south to north, while its width varies between 30 to 60 km, encompassing a total area in excess of 6,000 square km. The largest part of the field lies beyond the Arctic Circle.
Figure 1. Location of the Urengoy field in Nadym-Pur-Taz region
Urengoygazdobycha was founded in December 1977 to develop the Urengoy field. In 1978, this company was renamed “Urengoygazprom”.
Geology and reservoir properties
Most of the production is from Cretaceous (Cenomanian) sandstones that were originally deposited as bars and banks by fluvial systems. The gas is trapped in a broad, elongated anticline uplift that reflects drape of sediments across a Permo-Triassic horst, together with some possible rejuvenation of the horst-bounding faults. The horsts are part of the West Siberian rift system, which was most active during Permo-Triassic time, when vast quantities of volcanic basalt were extruded on the East Siberian plateau.
Two oil-and-gas columns are currently well studied and developed. They include:
- a Cenomanian gas horizon (400-1500 m). The reservoir has an initial formation pressure of 122 atm and a temperature of + 31 °C. Methane is a main component of the formation gas. - a Neocomian oil-and-gas condensate horizon (1,700-3,300 m). Formation pressure and temperature of this horizon are 300 atm and + 97 °C respectively. Along with gas there are considerable amounts of oil and condensate.
A third horizon, Achimovian, is being studied and prepared for development. This horizon is characterized by abnormally high pressure and temperature.
41 Gas composition
C1: 98 to 99%
Urengoy’s hydrocarbon reserves
In 1970, the State Committee on Resources (SCR) of the Former Soviet Union initially approved the reserves of the Urengoy field in amount of 3.87 Tcm. As the field developed, progressively approaching a maximum production of 305 bcm/year in 1987, this volume was revised. In 1989, new data for Urengoy’s hydrocarbon proven reserves were accordingly approved as shown in the table hereunder, estimated with Russian methodology.
Fluid, formation Reserves Estimated remaining reserves (In 1989) (as of beginning of 2004) Cenomanian gas, Tcm 7.672 About 3.1
Neocomian gas, Tcm 1.885 About 1.3
Gas condensate, million tons 251
Oil, million tons 422
Source: SCR USSR data, 1989
At the time being, the volume of hydrocarbon proven reserves is to be revised. Increasing attention is focusing on the estimate of proven reserves of oil and condensate in the Achimovian deposits. However, the State Committee on Resources of the Russian Federation (SCR RF) has not yet approved reserves located in these deposits. According to Sibnats’s estimate, condensate and oil reserves amount to 645 and 385 million tons respectively.
Field development and facilities
Innovative engineering solutions developed in the Seventies to produce the Urengoy field established a first in the Soviet and world gas industries. The extensive experience gained during this development was later widely used in subsequent developments in Yamburg (1986), Zapolyarnoye (2001) and other western Siberian gas fields.
These new engineering solutions included:
- a cluster of wells installed in the central part of the reservoir. The harsh climate made Urengoy’s development extremely difficult, the field being operated with winter temperatures down to - 57 °C. Due to these complex natural conditions (permafrost, marshy territories) and the large gas- content area, it was decided to concentrate wells. This resulted in reducing the distance between 2-5 wells in a cluster to 70 m, consequently reducing the length of gas-gathering pipelines and access roads by five times.
- the differential pay-beds penetration , which made it possible to drain pay thickness of the pool.
- large-diameter tubing (168-mm), allowing to reach high working flowrates (over 1 MM m 3/d). The first exploratory wells had demonstrated the high productivity potential of the reservoir.
- high capacity gas conditioning units ( ≥7.5 bcm/year). High gas outputs for separated areas of the field necessitated the construction of high-capacity gas conditioning units (15-25 bcm/year). The equipment of these units was of pre-fabricated modular type with blocks being assembled and piped directly on the field. Besides, multifunctional gas dehydrators with a capacity of 10 million m3/d were included in gas-conditioning units that allowed a 3-fold decrease in steel intensity.
42 These innovations enabled to achieve high-cost efficiency in the field development and made the produced gas one of the cheapest.
The Urengoy field was commissioned in April 1978. For the first 7 years of operation, gas production came exclusively from Cenomanian horizons. In 1985, however, Neocomian horizons were opened up along with the Urengoy Condensate Preparation Plant, the first processing facility built in northern Russia, allowing condensate production to commence. The plant produced diesel fuel, propane-butane and gasoline. Urengoy’s first oil was produced in June 1987.
In 2001, a new condensate de-ethanizer started operation, boosting the plant’s output capacity to 12 million tons/year with more production potentialities for the next field development phase.
The Urengoy field is divided into fifteen sub-fields, each with its own gas treatment unit and network of feeder lines. Altogether, early 2004, the field included 19 complex gas treatment units, 30 booster compressor stations to maintain the field’s production level, 4 gas cooling stations, 1300 km of inter-field gathering main pipelines, more than 2500 drilled gas and oil development wells and about 300 observation wells. 700 km of hard surface roads has been built.
The considerable number of people recruited to develop and operate this large-scale project led to the creation of Novy Urengoi city. Besides a new regional center for the hydrocarbon reserves development, a base was launched for further development of the entire Nadym-Pur-Taz region with subsequent development of Western Siberia’s new gas-bearing provinces. Today, Novy Urengoy has over 100,000 inhabitants, including 17,000 Urengoygazprom’s employees.
Gas marketing
Urengoy’s large-diameter gathering line network delivers processed gas from the processing plants to two initial compressor stations where the gas enters Gazprom’s Unified Gas Supply System.
Source: Gazprom
Over the first ten years of the field’s operation, gas production rose from 11.5 bcm to 305 bcm, supplying the domestic market and boosting the share of gas in the USSR fuel and energy balance, and starting large-scale gas exports to Western and Eastern Europe. Over this period, gas exports doubled from 39.9 bcm to 79.2 bcm in relation to the contracts signed with European importing companies. Such speedy development was largely a function of the political will of the former USSR leadership, which had mobilised the country’s productive, financial, staff and research resources to meet an important objective of the gas industry’s development.
43 Over the Nineties, while the Urengoy field along with other fields in the region continued to fuel the Russian economy with cheap gas, but at fixed prices, also meeting export obligations to foreign partners, the Yamburg field gradually became Gazprom’s major gas source of supply. In 2003, Urengoy produced 142 bcm of natural gas, accounting for 26% of Gazprom’s production, along with 3.3 million tons of condensate and 0.46 million tons of oil.
Since the beginning of this decade, commercial output from Urengoy has started to decline. Pressure drop in the reservoir is leading to the progressive water influx of productive horizons.
Urengoygazprom’ plans to further develop and extend life of the Urengoy field accordingly involve:
- from 2008, development of the Achimovian horizon to slowdown the field gas production decline rate by 2010-2015 and stabilize it at approximately 90-100 bcm. Urengoy’s output may drop later on to 20-30 bcm before complete depletion about 25 years from now. While further development of already producing horizons will require the reconstruction of the gas gathering system and modernization of field gas and condensate processing technology, the Achimovian deposits offer a very complicated geological structure that will require new development technologies.
The Achimovian horizon is characterized by abnormally high reservoir pressures (400-600 atm.) and temperatures (around 110 °), depth of the reservoir (3500-4000 m), low reservoir properties of the pay beds and the presence of carbon dioxide. These parameters will have a significant effect on the increase in capital expenditures and the technologies used in the field development.
Nevertheless, in 2003 Gazprom and Wintershall Company (Germany) launched Achimgaz company, an equally-owned j-v, to develop hydrocarbon deposits in this horizon. Commercial production is scheduled to start in 2008 and it should serve as a base point for commercial exploitation of the Achimovian hydrocarbon deposits in the Western Siberian Nadym-Pur-Taz region.
- the extraction of the liquid hydrocarbon reserves (condensate and oil) to be found primarily in the Achimovian deposits of the field, an objective which is in line with Gazprom’s strategy to diversify marketable output.
44 1.2 - ANALYSIS BY SELECTED CRITERIA
1.2.1 MARKET IMPACT
Assessing Market impact
To ensure that we were making a clear difference between market impact and future potential our definition of market impact implies that the gas field has already been at least partly developed. Evidence of significant market impact could be any combination of the following:
• Production of natural gas from the field has led to the development of a large downstream natural gas market
• The field has enabled gas to become the leading fuel in a particular region
• The gas field causes, or has caused, a very material effect on the local economy or the market structure.
Gas fields with significant market impact are likely to be in other WOC1 categories, as they tend to provide the economic opportunity and activity that is the necessary basis for further investment and new technology. This section provides only some examples, with only two of several of the major gas fields in Russia, for example, mentioned despite several others having importance in historical world gas production. Furthermore, the massive potential of South Pars in the Persian Gulf makes it more appropriate for it to be discussed in the Future Potential section, despite the importance of South Pars for the development of the Iranian market and the tremendous investments in the region for development of the Middle East gas export business.
The source for downstream development
Some of the world’s largest gas fields were discovered in the 1960s but the oil crises of 1973 and 1979 brought about a new impetus in the search and the subsequent development of domestic energy resources across the world. Whilst E&P companies preferred to find oil, there were in fact many important discoveries of natural gas during this decade. Several of these fields either formed the basis of the national or regional gas market, or had a major effect on the downstream market structures. The modern gas industry is reliant on the construction of infrastructure to deliver gas to market. Several fields in this section provided massive resources that were looking for a market in which they could be sold.
Enabling Natural gas to become the leading fuel
Natural gas is the fuel of choice in most regions of the world, but major penetration of the gas market requires major sources of gas that can be delivered economically at a price that is competitive with other alternatives. Increasingly we can expect gas fields in more remote and less hospitable areas to form the sources of supply for emerging market, but to date the fields with market impact leading to natural gas becoming the fuel of choice have been either in countries where the development of expensive natural gas distribution infrastructure would not have been economic (e.g. because of the terrain or the sparcity of population), or where a very large discovery has been made relatively close to centres of gas demand.
Material effect on the economy or market structure
There are three trends that we see here.
• the economic benefits for the producing country,
• the benefits in the downstream economy
• the commercial influence that the contractual or other arrangements for the field can have.
45 There are several examples of significant gas fields that have been primarily for export. Other gas fields that do not classify as a gas giant can still be very significant for the local economy and we have also included some of these.
Finally it is interesting to note that the first or largest gas field in an area can have significant commercial impact on the other contractual arrangements or developing market structures. Three European examples of this are Troll, South Morecambe and Groningen.
Groningen
Groningen is not only the swing producer for the whole of the Low CV (mainly household) gas market in NW Europe, but is the commercial arrangements are also the basis of the structure of the Dutch gas market.
During its early life to midlife the production from the field was reigned back in order to maintain the field as a strategic reserve and to provide the backup for the Dutch “small field policy” that encouraged exploration and development of smaller fields with short-lived production.
In 2005 this went though a dramatic change with the ownership unbundling of Gasunie to Shell and Exxon but with the Government taking full ownership of the transmission assets. How the developments in the Dutch gas market moves forward, in particular the access to Groningen gas, may well provide a signal for the progress of gas market liberalisation throughout Europe and the rest of the world.
Troll
Troll , for which the family of gas sales contracts, with indexation to oil products and price/market reviews on a triennial basis refers back, was a marker for all Europe’s long term gas purchases by pipeline, and arguably set the wholesale price of gas during the 1980s and 1990s in NW Europe.
Until the break-up of the Norwegian GFU gas allocation system in 2001 Troll played the role of the major swing producer and base supply source for unallocated contracted Norwegian gas volumes that provided a certain flexibility to the sellers to develop smaller fields with marginal standalone commerciality and market their gas under a unique supply type contract.
South-Morecambe
South Morecambe has made more impact on the UK gas market than any other UK field. The field originally provided from its start up in 1985 peak shaving services during periods of high gas demand, later, from 1991, it provided base load gas in addition to performing a swing producer role. Between 1990 and 1999 South represented approximately 10% of the entire UK annual gas supply. In 1999 its peak supply of 9.8 bcm represented the highest energy equivalent hydrocarbon production from any UK Field. The transfer of the Morecambe area assets in 1997 from BG E&P enabled the formation of Centrica as a FTSE 100 company. Then, with the development of gas-to-gas competition and the establishment of a traded gas market in the UK, the pricing of the Morecambe gas contacts disconnected from oil and became based on the traded UK gas market price.
Urengoy
The Urengoy field development embodied the political will of the former USSR to create a powerful gas production industry in Western Siberia that had the dimension to deliver a steady long term domestic gas supply and to build a large-scale business of gas exports to Western and Eastern Europe.
Its development gave rise to the creation of a regional gas industry infrastructure that today hosts over 100,000 people including 17,000 specialist workers and served as the base for other field developments in the Nadym-Pur-Taz region.
46 Shah-Deniz
The Shah Deniz field development has the potential to make Azerbaijan a major gas player in the international gas market since it will position the country to become a major gas exporter. A contract on sales to Turkey has already been signed.
Hassi R’Mel
Hassi R’Mel, the giant gas field, is located at the core of the Algerian gas pipeline infrastructure system.
As early as 1964, capitalizing on the huge reserve base of this field, the country had embarked on the construction of the first LNG plant in the world, laying the grounds for countries without any pipeline connection to be supplied with natural gas.
Besides those liquefaction units, the state-owned company Sonatrach as operator of the field undertook major transportation works, namely the laying of two gas pipelines connecting Algeria to Europe. Those are the Enrico Mattei pipeline linking Hassi-R'mel to the south of Italy via Tunisia, and the Pedro Duran Farell pipeline between Hassi-R'Mel and Spain, via Morocco.
Scarab Saffron
The Scarab Saffron gas fields in the West Delta Deep Marine concession near Alexandria, Egypt, represents the first deepwater development to be undertaken in the eastern Mediterranean. It is the first sub-sea completion in the region, and has one of the longest tie-backs in the world. Engineering lessons learned during the field development encouraged the fast-track development of several other deepwater projects in the Mediterranean Sea north of the Nile Delta.
North Dome
The Qatar North Field is by far the largest single gas field in the world. It was discovered in 1971. Qatar Petroleum developed the first project (North Field Alpha) to utilize gas for local consumption in 1991, with capacity of 800 mmscfd. Two new Liquefied Natural Gas projects were developed after that, namely the Qatargas Project and the RasGas Project.
Both projects are currently operational and produce more than 13 million metric tons per annum. Several agreements were signed with UAE, Kuwait, Bahrain, Italy and Spain to supply these countries with gas produced from the North Field whether in the form of LNG or pipeline gas, in addition to Gas to Liquids projects with several international oil companies. Due to these projects Qatar is emerging as a major exporter of liquefied natural gas.
Vorwata, Wiriagar
The super giant Vorwata and Wiriagar fields as the main assets of BP’s Tangguh project in the Papua province of Indonesia. The Projects holds tremendous promise for Indonesia's future in worldwide LNG markets. Indonesia is facing a declining share of global LNG markets, despite its past status as the world's leading LNG and dry gas exporter, in the face of growing exports from Oman, Qatar, Russia, and Australia on world markets. BP’s Tangguh project has the dimension to change this trend.
Based on over 14 Tcf of natural gas reserves found onshore and offshore the project will involve two trains with a combined capacity of 7 million tons per annum, expandable to 14 million tons per annum. BP's current plans call for the project to be completed by 2007.
Gorgon
The Gorgon gas project, off the West Australia coast, addresses the Greater Gorgon area which is one of the largest undeveloped natural gas accumulations in the region including the massive Jansz gas discovery -- Australia's biggest single known reservoir.
47
The terminal, now under construction, will be the first capable of delivering LNG to the US west coast, a market which the federal Government believes will be worth $50 billion to Australian gas producers over 20 years.
Loma La Lata
In Argentina’s Central Western region, the abundance of reserves in Loma de la Lata justified the continuation of major gas pipeline developments and the subsequent expansion of the National domestic market. In 1981 and 1988 two new transmission lines were constructed to increase the connectivity between the basin and specifically the Loma de la Lata field and Buenos Aires.
As with several of the larger fields in this category, the market impact of Loma de la Lata can be seen both in the national market and through exports. During the nineties, the most significant marketing initiatives were the Gas Andes and Gas Pacífico gas pipelines to Chile and the Uruguayana gas pipeline to the South of Brazil, which were specifically related to Loma de La Lata and the development of new discoveries in the Basin. At the same time, in relation to the domestic market, Loma de la Lata started to play an optimising role.
Production from Loma de la Late also enabled several petrochemical projects including Profertil for the production of urea -which is a key material for the domestic agricultural industry -, Plaza Huincul Methanol project and Mega project for the extraction of ethane, propane and butane for local and export markets.
Orenburg
The field was the backbone of the Orenburg project which was the largest project under the Comecon’s concerted plan for the 1976-80 period and was undertaken by all East European Comecon countries. It consisted of an natural gas complex at Orenburg and the 2677 km Sojuz natural gas pipeline, completed in 1978, which links the complex to the western border of the Soviet Union.
The Molve field
The field is situated offshore Croatia, Europe. Some 24bcm remain of Molve’s original 34 bcm. Whilst on a global scale the field is very small, it has been producing over 40% of Croatia’s indigenous natural gas supplies, thus making a significant impact on national self sufficiency.
Krishna Godavari
A significant portion of the gas from the several significant recent finds in the Krishna Godavari basin would be sold to power and fertilizer consumers in India. RIL had bid and won the international bidding for supply of natural gas to the state owned utility, National Thermal Power Corporation (NTPC) for supply of about 12 MMSCMD for 17- year period. This is meant for the 2600- megawatt power plants (1300x2) being put up by NTPC. This gas would also meet unmet demand of fertiliser and power producers in Andhra Pradesh, Maharashtra and Gujarat states. Gas supply for fertiliser production would result in the lowering of subsidy burden of the Government, thereby reducing the fiscal deficit in the economy. Development plans indicate that the infrastructure will be available by 2007.
48 1.2.2 TECHNICAL ADVANCES
Introduction
There is a consensus among industry experts that world gas production will continue to rise during the coming decade to exceed 4 TCM/year by 2030. The technical advances necessary to achieve this have their roots in current upstream gas activities.
Considerable efforts have already been made in the international gas industry to develop technologies in order to add new reserves in hostile environments such as deepwater prospects, thight gas, higher P and T. This chapter is based on contributions about some fields which were received from Algeria, France, United Kindom, Russia, India.
For purposes of accuracy and comprehensive assessment we define the technological advances & challenges as difficulties faced to develop the reservoir required the application of new techniques, equipment or processes that have subsequently been applied in other upstream projects or are expected to be further developed for future gas production.
These kind of technologies could be splitted as follow : 1- Access to the reservoir: a. Hostile weather environments b. Difficulties to access the reservoir ( on shore et off shore) c. Difficulties while drilling before to reach the reservoir. 2- The development of the field as described below : a. Big heterogeneity of the reservoir b. (Seismic , AVO, ) c. Difficulties while exploiting the wells
Deepwater reservoirs
We cannot talk about the offshore deepwater technology as a separate defined technology but as a combination of multitude of different technologies (especially drilling, completion, multiphase pipelines technologies and sub sea facilities) used to overcome obstacles that prevent deepwater fields to be exploited.
Offshore drilling has evolved from fixed plat forms which extended from the shoreline to floating platforms in water depths greater than 1.8 Km theses new frontiers are challenged by water depth, waves, icebergs, tides, storms. The trend in offshore exploration clearly shows that the industry will and can move to deeper water environments to drill and explore for oil and gas this necessitate better and more efficient drilling platforms and completions and learning from current projects.
In the 70’s and 80 ‘s, many companies around the world have implemented some techniques in order to develop deepwater prospects such as Alwyn Area United Kingdom ( 1973), South Morecambe in United Kingdom ( 1973) Troll in Norway ( 1979) South Pars ( 1988. All these field are still in production.
Troll A platform. (Photo: Dag Myrestrand/Bitmap) www.statoil.com
49 The proved mastery to explore deepwater prospects encouraged others country to explore in off shore. Several fields were discovered in the latest 90’s and planned to produce these next years. Krishna / Godavari in India ( Mid 2008),) Snovit in Norway ( 2006), Ormen lange ( 2007)., Gorgon ( 2010).
One of the most challenging projects by its difficulties to realize (water depth) is Malampaya deepwater gas field project.
Extracting natural gas deposits in water depths of 820-850 meters and transporting this to its market over 300 kilometers away posed one of the greatest challenges in deep water developments in the world and required the use of the latest in gas technology and skills. The Malampaya field is located 50 kilometers northwest of the Philippines. Discovered in 1992, it is estimated that over 3 trillion cubic feet (Tcf) of gas and 120 million barrels of condensate will be recovered from this resource. The depth of the reservoir is 2,200 meters below the seabed (a total of 3,000 meters from the sea-level). The principal technical challenge is to ensure continuous delivery of sales specification gas throughout the production chain whilst containing costs and maintaining stringent Health, Safety and Environment standards.
Development Concept
Subsea Facilities
The subsea facilities (water depth: 820 – 850 m) are responsible for controlling the flow from the wells and gathering the gas and liquids. Five christmas trees are installed atop each well which is connected to a subsea manifold. From the manifold, the well fluids are transported to a platform in shallow water (ca. 40 m) via two 30 km flowlines.
Production platform
The production platform located 30 kilometers away from the subsea system separates the gas, water and condensate. The condensate is temporarily stored at the cells of the platform base called the concrete gravity structure (CGS). The wet gas is dried and transported through the 504- kilometer pipeline.
Concrete gravity structure (CGS)
The CGS was built in Subic Bay and towed to its offshore location in June 2000. The top portion of the platform, the topsides, was built in Singapore and was towed to Palawan where it executed a world record in engineering with the float-over installation method.
50 Pipeline
The 504-kilometer subsea high integrity steel pipeline has a diameter of 24 inches and is coated with concrete. It was laid within a period of five months using a dynamically-positioned pipelay vessel with very minimal disturbance to the seabed. An average lay rate of 5-7kilometers of pipes were laid during the period. The field flowline and pipeline route selection, design and installation are at the forefront of deep water pipeline technology and is externally verified by Lloyd's register, a U.K.- based independent risk management organisation providing risk assessment and risk mitigation solutions and management systems certification around the world. The route of the pipeline was carefully selected to avoid environmentally sensitive areas and mass gravity flows.
On shore gas plant
An on-shore gas plant was constructed at a site adjacent to Pilipinas Shell Petroleum Corporation's refinery in Batangas City where impurities (e.g. H2S) are removed and the gas undergoes final treatment for delivery to customers. The gas plant was constructed over a period of two years. It first received gas from the platform to the pipeline on September 24, 2001 .
HP/HT Challenges and Deep Reservoirs
High pressure, high temperature (HPHT) reservoir conditions present difficult challenges to well engineers both to drill and to choose the type of adequate completion. The major problems encountered while exploiting theses types of reservoirs are :
The high cost of these wells: which demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4” through bore diameter dictated by high pressure wellhead housings and blowout preventers (1) . Special attention to drilling equipment: BOPs, wellheads, valves should be done. These equipment should be tested using special HPHT testing procedures (2) . Furthermore, high pressures require thick wall casing, especially if sour service materials (eg. Nickel based CRA : Corrosion Resistant Alloy) are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices. Completion for HPHT wells : generally HPHT wells form problems of hydrates during the production, therefore completions used successfully in many HPHT cases are Nickel based alloys. Taking in account the use of Packers for HPHT conditions (3) . Another challenge is to maintain the well production to a long period, history has shown that early failures (failure of production in the first few months) are more likely with new equipment designs and service conditions, this is caused by : corrosion inhibitors or inadequate completion. Another challenge present here is If there is a failure of a well, the choice of a worke-over equipment should take in consideration the HPHT conditions.
The Molve field is an HPHT gas field, although it is not classified as a giant field (34 BCM) but still has significant impact on the national economy of Croatia (41 % of the total gas produced in Croatia (4) .
Another example of a relatively HPHT gas field is Urengoi Russian Field: a giant gas field (> 9 TCM ) situated in Western Siberia , the field consists of three gas condensate reservoirs. The Achimovian horizon (the deepest reservoir) is characterized by relatively abnormally high pressure (400-600 psi) and temperature(110°C), the other two higher reservoirs are normal pressure (122-300 atm)and temperature (+31 / +97 °c) reservoirs,added to HPHT conditions the other main challenges encountered in the Achimovian deposits development are the low reservoir properties of the pay beds and the presence of carbon dioxide. Nevertheless this reservoir level is expected to be developed from 2008 to lower the other two reservoir levels gas production decline rate (5) .
51 Intelligent Completions
Intelligent well technology can be compared to 3D seismic in that it reduces the negative effects of reservoir uncertainty on expected future production and cash flow. It can provide an operator continuous permanent down-hole monitoring coupled with the ability to reconfigure the well completion upon demand through remotely operated flow control without additional investment (8) . A widely accepted definition is that an intelligent well is one in which control of production or injection takes place down-hole at the reservoir, with no physical intervention (9) , that has all three of the following capabilities (6) :
• Flow segregation , Individual zones in a well are isolated from each other, and flow out or into them can be remotely controlled by means of downhole flow control device (FCD) . • Well parameter monitoring. Wellbore characteristics (P,T and Q) can be remotely monitored in real time. • Well performance optimisation. The wellbore characteristics are evaluated, and the knowledge gained is actually used to determine if any of the FCDs should be adjusted to maximize the overall well performance. The evaluation is performed manually at present, but in the future it could be by means of a closed loop operation.
The Intelligent Well Completion consists of :
••• Flow Control Devices ‘Sliding sleeves, ball-valves..’ ••• Feedthrough Isolation Packer to realize individual zone control and ensure segregation of separate gas reservoirs. ••• Control, Communication and power cables to link the down-hole to surface. ••• Down-hole Sensor for real time measurement of production data. (9) ••• Surface Data acquisition and control .
It is also widely accepted that an intelligent well can provide added value in a number of area (6) :
• Increased recovery (drain more reserves per well) ; fewer wells drilled. • Reduced well life-cycle costs. • Accelerated production profiles. • Reduced well intervention frequency and costs with is also resulting in improved operational safety. • Well’s ability to respond immediately to expected or unexpected changes in the production or injection performance in all operating environments (7) . • better understanding of reservoir performance, and improved reservoir.
A very important feature of intelligent well completions is their utility to develop marginal reserves by commingling. Marginal reserves are too small or too difficult to recover economically by themselves (not economic), the intelligent completion gives the opportunity to develop the marginal reserves in conjunction with other marginal reserves, or with larger reserves by commingling (simultaneous production of hydrocarbon from multiple reservoirs through a single production conduit).
This is the case for two marginal gas deepwater fields : Aconcagua and Camden Hills fields situated in Mississippi Canyon Blocks 305 and 348 , the two fields posed extreme challenges with ultra-deep water depths to 7,209ft, limited gas reserves, multiple zone production and high permeability unconsolidated sands underlain in several cases by water bearing sands. The two fields are operated by Total and Marathon respectively.
Four intelligent completions were installed in the Aconcagua Field and two in the Camden Hills Field. Draining the multiple gas sands and shutting off water production without interventionwas key to the completion design which included stacked frac-pack sand control, pressure operated fluid loss control devices and intelligent well completion equipment including retrievable production packer, mandrel containing sensors (P,T) and two ICVs (Interval Control Valves) (10) used to selectively isolate and flow the individual completion intervals within each well. Faced with reservoir depletion,
52 suspected sand production, and water influx, the intelligent completions have proven themselves usefull in the management of these assets (10) .
Multiphase pipelines
During the past thirty years multiphase flow technology has become increasingly important for the economic transportation of well streams from reservoir to process. In particular, production offshore, where the trend is to develop numerous small fields by transporting untreated fluids via existing infrastructures, imposes high demands on the multiphase science and technology required to ensure economic and safe operation (12) .
A number of design and operational difficulties are associated with multiphase flow. • The prediction of pressure drop-flow rate behaviour is difficult. • The prediction of the sizes, or even existence, of liquid slugs is even more difficult. • Plugging due to hydrates may occur, and adequate methods for evaluating transient effects are non-existent (11) . • Their design has been hampered by uncertainties in two-phase pressure drop relations, in flow regime determination, and in liquid slug length prediction. • This uncertainty makes difficult the choice of pipe size and the design of downstream separation facilities.
Multiphase pipelines offer the potential for substantial cost savings in the offshore transport of hydrocarbons. Two characteristics of the offshore environment make multiphase pipelines potentially attractive.
• First, pipe laying is expensive. If both liquid and vapor must be transported offshore, their simultaneous transport in a single pipe will save the cost of laying separate liquid and vapor lines. • Second, offshore processing facilities are exceedingly expensive. Both the facilities themselves and the platform to support the facilities are very high cost items. If offshore vapor-liquid separation can be avoided, considerable facility and platform cost savings may be realized. The avoidance of vapor-liquid separation offshore implies multiphase pipelines to shore.
The gorgon Offshore “ Australia” Infrastructure gives a good example of significant gas field using multiphase pipelines : To achieve a competitive “cost of supply” (CoS) the Gorgon gas field will be an all sub sea development with a 70 km pipeline tied back to an LNG plant sited onshore , the development of the field is planned for 2010,
Figure 1: South Pars Gathering System Figure 2: Gorgon Gathering System
But the best example for the multiphase transport of gas is South Pars Giant Gas field “Iran” the volumes in place are 280 TCF , South Pars is the largest project in the world to date using multi- phase transport over such a distance: the transport scheme involves two 32-inch pipelines stretching over 105 kilometers from the field to the onshore facilities(longuest in the world to date) (13) . In the next future Snohvit field “Norwegian Field” situated in Barents Sea is planned to produce from 20 wells and the well stream will be transported to land through a 145-kilometre pipeline “ a new record”.
53 CO2 Sequestration
The rising concentrations of CO2 in the atmosphere have led since the 1970s (14) to considering the possible large-scale storage of it underground. CO2 sequestration is the capture, separation and long-term storage of CO2 for environmental purposes. Another term is used for CO2 injection is Geological sequestration when the purpose is to use this technique for enhanced oil recovery, the factors distinguishing sequestration from being simply an EOR process is that :
- the CO2 will ultimately be left inplace when hydrocarbon recovery processes have ended. - The motivation is at least partly environmental to avoid CO2 release to atmosphere as well as it is for pressure maintenance and displacement.
There is different options for capturing and storing CO2 in geologic formations : oil reservoirs , gas reservoirs, aquifers, and coal-beds (15)(16)(17) . One of the most challenging and critical components of sequestration applications is the ability to efficiently model and monitor injected gas. Environmental considerations necessitate the prediction and verification of CO2 movement over time to ensure additional environmental problems are not created like contamination of potable aquifers, a leading project in this technology is the Saline Aquifer Carbon Dioxide Storage (SACD) Program in Sleipner Filed launched by Statoil and IEA Greenhouse Gas R&D. it consists of the separation and Injection of Co2 into a saline aquifer 1000 m below the seabed.
Sleipner west field discovered in 1974 is one of the largest gas producers in the Norwegian sector of the North Sea with a daily gas export capacity of 20.7 MM m 3 and a daily production of 60 000 bbl of stabilized condensate. The produced gas contains 4 to 9.5 % of CO2 which would have to be reduced to 2.5 % to fed directly into sales gas pipelines to Europe, the suggested solution was to capture this CO2 offshore and injecting it into a saline aquifer beneath the Sleipner separation plant. About 1 million Tonnes of CO2 is injected into the Utsira Formation situated far above the gas reservoir each year. Advanced seismic technology is being used to monitor the behaviour of injected CO2 this monitoring is showing that there is no observable carbon dioxide leakage through the overburden, which strongly suggests that the caprocks are sealing.
Results of seismic monitoring. (Illustration: Erik Injection of cabon dioxide into the Utsira Hårberg.) www.statoil.com Formation from the Sleipner A platform. (Illustration: David Fierstein.) www.statoil.com
Another project (Insalah Gas Project – Algeria) differs significantly from Sleipner project in geological character and storage process and offers an ideal opportunity to gain additional information on the performance and safety of CO2 geologic storage. The Insalah CO2 project is the world’s forst CO2 storage in an actively produced gas reservoir.
Insalah Gas (ISG) is a joint venture project between Sonatrach , BP and Statoil. The project comprises a development of eight gas fields located in central Sahara of Algeria. The initial devlopment focuses on the exploitation of the gas reserves within the 3 northern fields of Krechba , Teguentour and Reg , the fields delivers gas stream of 9 bcm/yr. These fields contain CO2 concentration ranging from 1 to 9% which is above the export gas specification of 0.3% and therefore
54 requires CO2 removal facilities. In addition to the CO2 removal facilities ISG has made a further discretionary investment to enable compression and re-injection of the produced CO 2 (up to 1.2 million tonnes per year) (19) for geological storage. The CO2 stream is re-injected back into the aquifer zone of one of the shallow gas producing reservoirs. The choice of the formation that receives the CO2 was based on several considerations which are:
- The reservoir cap seal integrity be demonstrated . - The sufficient storage capacity to meet the predicted CO2 volumes estimated at 12 bcm - Good reservoir properties. - Reservoir pressure below 6000 psi to negate the need of using untested specialist compression equipment. - A single centralised facility and storage site option was chosen to avoid the high cost and increased complexity associated with distributed storage.
All these constraints led to the identification of the shallow Krechba Carboniferous reservoir as the most suitable solution. The storage scheme has the CO2 re-injection directed into the aquifer region in the shallow Carboniferous resrvoir, down-dip of the main hydrocarbon accumulation. The injected CO2 driven by gravitational forces is retained within aquifer zone and does not enter the main field area until after it has been depleted and abandoned, this projected to be after 25 to 30 years of production (19).
The carboniferous reservoir at Krechba offered the benefit of a high quality sub-surface data set, with good well coverage and associated log, core and test data, and importantly a high quality 3D seismic survey.
4D Seismic
Time-lapse, or 4D, seismic, consists of a series of 3D-seismic surveys repeated over time to monitor how reservoir properties (such as fluids, temperature, and pressure) change throughout the productive life. Consequently, fluid movements can be anticipated before they affect production. Similarly, placement of extraction and injector wells can be fine tuned, bypassed oil and gas can be recovered, and production rates can be accelerated. The Troll Field is an excellent example of successful using of 4D seismic to monitor gas oil contact movements.
The Troll Field is situated in the Norwegian North sea, the field is divided into two main provinces, Troll East and Troll West. Troll West is itself divided into the Oil Province and the Gas Province where the oil column is 22-26 m and 10-13 m thick respectively. It is the Troll West Gas Province that is the subject of 4D seismic. In order to recover oil from the thin layer, over 100 horizontal wells have been drilled. One of the objectives of 4D reservoir monitoring at the Troll West Gas Province is to quantify the gas-oil contact movement in order to identify un-drained zones for infill drilling and improve the understanding of the fluid movements across the field. The analysis shows coning along the tracks of a number of multilateral wells and identifies undrained volumes for infill drilling. The movement of the gas-oil contact is found to vary by up to 12 m in the vicinity of some wells. Zones of low movements represent potential undrained volumes for infill drilling (18) .
55 REFERENCES
(1) Designer Casing for Deepwater HPHT Wells 97565 (2) “updated Design Methods for HPHT Equipment” K.Young; C.Alexander ; R.Biel ; E.Shank SPE 97595. (3) “HPHT Completion Chalenges” Ron Zeringue SPE 97589. (4) A8 document WOC1. (5) A3 P18 (6) “Application of Reliability Analysis Techniques to Intelligent Wells” B.K.Drakeley, N.L.Douglas ; K.E.Haugen ; E.Willman SPE 89639 Offshore Technology Conference 2001. (7) “ Reservoir Aspects of Smart Wells” C.A.Glandt , SPE 81107. (8) “Quantifying Value Creation from Intelligent Completion Technology Implementation” A.K.Sharma ; L.GChorn ; J.Han ; S.Rajagopaan. SPE 78277 13 th European Petroleum Conference Aberdeen 2002. (9) “Intelligent Well Complation : Status and Opportunities for Developping Marginal Reserves” M.Konopczynski ; A.Ajayi ; L.A.Russel ; SPE 85676 -2003. (10) “ Case Study : Aconcagua and Camden Hills Fields Utilize Intelligent Completions to Optimise Production and Reservoir Performance” V.B.J.Nielsen ; J.Illman ; T.L.Guillory SPE 96338 – 2005. (11) “Developments in the Simulation and Design of Multiphase Pipeline Systems” H.L.Norris III ; P.Fuchs SPE 14283 – 1985 . (12) “Multiphase Science and Technology for Oil/Gas Production and Transport” R.V.A Oliemans SPE 27958 – 1994. (13) www.simulationrsi.net (14) “Geologic Sequestration: Modelling and Monitoring Injected CO2” J.Birkins ; J.Fanchi SPE 66749 – 2001. (15) “Storage of Carbon Dioxide in Geologic Formations” F.M.Orr Jr SPE 88842 – 2004 . (16) “Engineering Aspects of Geological Sequestration of Carbon Dioxide” J.Ennis-King ; L.Paterson SPE 77809 – 2002 . (17) “The Economics of CO2 Capture and Geological Storage” D.N.Nguyen ; W.G.Allinson SPE 77810 – 2002. (18) “Gas-Oil contact monitoring at Troll using high resolution 4D analysis and neural networks” A.Bertrand ; S.McQuaid ; R.Boboleck ; S.Leiknes ; H.Egil ro . EAGE 67 th Conference & Exibition – Madrid, Spain, 13-16 June 2005. (19) “Monitoring Geological Storage the Insalah Gas CO 2 Storage Project” Fred Riddiford , Iain Wright , Clive Bishop , Tony Espie , & A. Tourqui . (BP ; Sonatrach)
56 1.2.3 SUSTAINABLE DEVELOPMENT
The IGU Strategic Guidelines for the 2003-2006 triennium are, in the Study Group’s view, formulated with sustainable development at their heart. The IGU promotes:
1. Technology, Industry and Customer focus
2. Gas as the fuel of choice, preceding a sustainable energy system
3. The industry’s role as a responsible corporate citizen
SG1.1’s definition of significance in terms of sustainable development covers all these issues. A recurring theme is that, more often than not, the economic and environmental drivers are well aligned through technological advances.
The analysis in this section is presented in two very broad categories for the situations or factors that lead us to consider a gas field as significant from the perspective of global sustainable development. These are
a) the field’s location , in ecologically sensitive or environmentally challenging regions both onshore and offshore
and
b) the field operations arising from it’s development, the production of hydrocarbons and the treatment of reservoir fluids to satisfy economic and environmental imperatives.
The exploitation of natural gas to satisfy mankind’s current needs for environmentally benign energy is fundamental to global sustainable development. All current and future gas fields can play their part in this process, as world demand for energy is increasing fast. At the same time, people require a cleaner, healthier and safer environment. Natural gas meets these objectives in the transition to a less carbon-based economy. Resources are abundant and natural gas impacts the environment least of the fossil fuels. But there are very real challenges to ensure that exploration and production activities meet the higher safety, environmental and ecological standards that are rightly expected as humanity progresses. The practical reality is that, increasingly, reservoir development will take place in more hostile or fragile environments or with less favourable reservoir fluids than in the past How some of the world’s most significant gas fields have risen to this challenge is set out in the following few pages.
Sustainable Development and Field Location
Examples of fields in this category range from major onshore developments in highly populated areas like The Netherlands’ Groningen field originally established in the 1960s, through more recent developments like the sustainability award winning Malampaya project, sustaining a big increase the role of natural gas in the Philippine economy, to as yet undeveloped fields like the giant Bovanenkovo field in the arctic region of Russia’s Yamal peninsular.
Regulations and guidelines about environmental impact have developed at different speeds across the world, and what was considered a high standard 30 or 40 years ago may now no-longer meet up with the expected norms. Legislation changes, and so does society’s expectations as to how oil and gas companies should operate. Upstream gas operators are keenly aware of this, particularly where further investment and enhancement of recovery of gas reserves is planned from major fields. The regeneration programme put in place by the operators of the giant Groningen field exemplifies a conscientious operators desire to reduce the development’s impact on the environment.
Onshore, there is always environmental pressure for the extent of an industrial development (its ‘foot print’) to be minimized, particularly if it is in an area of outstanding natural beauty or if there is a nearby human population or fragile species in the vicinity. Keeping site sizes to a minimum is also
57 good economics (provided there are appropriate allowances for future phases of a project). For exploration drilling activity too, minimizing the number of wells makes both economic and environmental sense. Two ways that new technologies are helping to reduce environmental impact in this area are:
- new methods for interpreting seismic data increase the ability to locate prospective gas accumulations, accordingly reducing the likelihood of drilling unproductive or unsuccessful wells.
- advances in horizontal drilling allow the development of gas fields from fewer drilling sites, with fewer wells. Onshore, this technology allows the selection of sites to minimize impact on land and wildlife, offshore it can reduce the number of platforms needed.
Often it is not the production site itself that is the issue, but the route needed to send the gas from the well-head to a processing plant, or from a terminal to the main transmission system that will take the sales gas to the market. Significant examples of this can be found both for onshore and offshore developments:
- Development of the UK’s Morecambe Fields, which involved a pipeline crossing a protected Site of Special Scientific Interest (SSSI) at Walney Island. Through an ingenious and caring approach the area between the South and North Morecambe terminals is now maintained as a nature reserve and is the habitat for a number of protected species of toad.
- The impact of gas production and transportation activities for many North Sea fields (e.g. the Nuggets area) also present an issue in the project design, not only to minimize the impact on fish, particularly at spawning times, but also to ensure protection to prevent damage from fishing activities
- One of the main challenges for Russia’s Bovanenkovo will be the requirement to lay a long- distance delivery pipeline starting in the permafrost zone via ecologically sensitive areas.
- Offshore, the problems are equally substantial, with projects like the Ormen Lange 745 mile long deepwater subsea pipeline with temperatures as low as 2 degrees Celsius and an extremely uneven seabed, also passing through important fishing grounds and coral areas, or the evacuation of gas from Russia’s Shtokmanovskoye field, the first of Russia’s gas-condensate offshore deposits to be developed in the Arctic region.
In many ways nature is very robust. Increasingly the new upstream gas developments are offshore and in colder and deeper waters; the challenge is more to do with establishing a design and operation that can withstand the hostile environment than the minimal effect that the installation will have on nature.
For sensitive onshore sites new tunnelling techniques may well allow areas of particular sensitivity or ecological fragility to be avoided, but here the economic cost is still a difficult consideration.
An alternative delivery route for offshore projects (or those near the coast) is via LNG tanker.
- Norway’s Snøhvit (Snow White) field is in a vulnerable fishing area in the Barents Sea, and zero harm is expected from the onshore community. When the development is operational it will be the world’s most northerly LNG project
- An LNG plant on Barrow Island in Australia is planned for development within the next few years. This is to allow gas export from the Gorgon complex. Barrow Island is an A class flora and fauna reserve and the site presents serious challenges for the developers.
The future sustainability challenges that result from doubling or even quadrupling worldwide LNG tanker activity would be interesting to address in the coming years, but that would be a topic for another report. Let us turn now to the Upstream Operational issues that seem of most significance for the gas fields that we have studies and given wider, global considerations.
58 Sustainable Development and Field Operations
Exploration and production operations in the gas and oil industry have been subject to ever increasingly stringent safety and environmental requirements. There is a host of operational practices that are now well established to ensure sustainability in terms of safety and environmental considerations. Many of these practices, for example in drilling operations, are common across the oil and gas business.
Once gas production is underway, a major part of operational activities is the automatic monitoring of plant, primarily to ensure safety, but also to oprimise efficiency. Monitoring and analysis technologies as well as detection equipment (in extremis to shut-off gas flows if necessary) is continuously being developed and improved to help assess risks and impact of activities and to better monitor the integrity of the equipment used.
Onshore gas field operators aim to be good neighbours to local residents. The local economy benefits gas industry investment, but during the life of the field constant care is needed to reduce any atmospheric emissions and to maintain and improve the standard of the protection for local farmlands and natural habitats in the vicinity. For example the Groningen regeneration project included a host of new technologies and processes, a key element of which is a glycol regeneration system that separates water and condensate to eliminate gas emissions. The drain system is also segregated to reduce water wastage: rainwater is no longer pumped with production water, but purified and disposed of locally.
In recent years, with the emphasis on ‘greenhouse gas’ (GHG) reduction, controlling the emission of CO2 has become a significant new feature of the upstream industry developments. This trend is set to continue as the proportion of ‘sour’ gas that is exploited is also likely to increase.
Natural gas, when replacing coal or oil for power generation, can result in dramatic reductions in undesirable atmospheric emissions. The Norwegian Troll field, is discussed in other sections as it has had a major imopact on the European market, not least through enabling natural gas to displace more polluting fuels. But on the troll platform itself the equipment is powered by electricity that is brought from the ainland where the main source is hydro power.
CO2 sequestration
Some technical advances in this area were outlined in section 1.2.2. CO2 sequestration (the capture and storage of CO2) has the potential to solve about a third of the planet’s GHG problem. Industry is working on cost reduction and confidence in geological storage can be gained by a number of diverse demonstrations of geological storage. Governments are now beginning to work on fiscal and regulatory frameworks to support the widespread deployment of CO2 sequestration.
Among the prime examples of gas field CO2 sequestration projects are:
- The Sleipner West natural gas field in the Norwegian sector of the North Sea, which is characterized by a high (9%) concentration of CO 2, well above the limit imposed by European export specifications. Excess CO 2 is separated from the recovered gas on the offshore production platform before exporting the sales gas. the captured CO 2. is injected into a confined aquifer-800 meters below the seabed and 2,500 meters above the Sleipner West hydrocarbon reservoir. About a million tons of CO 2 per year has been injected since 1996. (This project was examined in detail in WOC1’s 2003 report)
- In Salah, Algeria, which was the first large-scale example of CO2 capture and storage in the same reservoir. The In Salah Gas project is demonstrating geological storage assurance and is providing a valuable dataset to contribute to the development of CCS fiscal and regulatory frameworks.
- The Gorgon gas development is planned to have one of the largest geological CO2 sequestration projects in the world.
59 - The Snohvit project, in the Barents Sea, Norway will also involve CO2 sequestration.
Increasingly CO2 sequestration is becoming the norm, particularly for acid gas reservoirs. But the industry. particularly upstream, has also the issue of methane emissions to tackle, as methane itself is a GHG. Furthermore, the practice of gas flaring has come under increased scrutiny in recent years.
Flaring & venting
Avoiding unnecessary loss of gas is important not just from environmental reasons but also as a matter of simple economics. System designs and maintenance procedures in all parts of the business have aimed to reduce the need for venting of natural gas, but in certain cases, emergency safety considerations mean that the best solution may be to vent natural gas to the atmosphere. A more specific issue for exploration and production activities is gas flaring.
Gas flaring occurs for safety reasons routinely in certain drilling or pre-commissioning hydrocarbon production operations. In many of the gas fields in our examples there is little or no flaring
- South Morecambe flaring has been dramatically reduced since startup.
- The environmentally sensitive area around Loma La Lata requires constant monitoring and preventative measures; Gas flaring is prohibited.
Gas flaring is used to dispose of waste and non-commercial gases in a safe and reliable manner through combustion in an open flame. On the down side the method generates a greenhouse gas emissions, and is may, at least technically, be wasting gas resources.
Significant flaring of natural gas in the upstream industry occurs primarily where infrastructure for the gas market has not been developed and the gas that is flared is primarily associated gas that is released when crude oil is brought to the surface.
Last year (2005) the World Bank launched a voluntary global standard to provide more incentives particularly in Africa and the Middle East, where most flaring and venting occurs
The World Bank program focuses on ways to commercialise associated gas, including developing domestic markets and access to international markets, creating legal and fiscal regulations for associated gas, and capacity building for the pursuit of carbon credits under the Kyoto clean development mechanism for flaring and venting reduction projects. The aim is to significantly cut venting and flaring in partnership countries over the next 5–10 years.
According to World Bank estimates, eight countries—Algeria, Angola, Indonesia, Iran, Mexico, Nigeria, Russia, and Venezuela— account for 60% of flaring and venting worldwide. Of these, Nigeria (16%), Russia (11%), and Iran (10%) alone are responsible for more than a third of global flaring and venting.
These gas flaring nations are exploring ways to deal with the problem, and Nigeria has said that it plans to eliminate gas flaring altogether by 2008.
Concluding remarks on Sustainable Development Upstream
It is necessary that the industry continues to improve its performance by applying adequate management systems, state-of-the-art technology and improving HSE performance. The exploration and production industry has learnt to deal effectively with environmental impact and to take remedial action if damage occurs. As the exploration and production of natural gas now enters its next phase of expansion the challenge will be to continuously aim to minimize the environmental impact so that our earth’s heritage is preserved at the same time as we husband its natural resources.
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We conclude this section with the words of International Chamber of Commerce Secretary- General Maria Livanos-Cattaui, when the Malampaya gas field was awarded a UN sustainability award for its program for natural gas development using a Sustainable Development Management Framework .
“It is vital that business is recognized for the constructive role it has to play in the pursuit of sustainable development. Business is not a philanthropic sector. It is interested in building strong markets. The strongest markets are those which are the most sustainable.”
We can see from the examples in this report that the natural gas industry is ready for the upstream challenges that face the exploration and production business Indeed it is through meeting these challenges that the industry is strengthened and economic development is sustained in the interests of us all.
61 1.2.4 FUTURE POTENTIAL
Gas fields that exhibit significant future potential can be arranged in two groups according to their situation for future development. One group comprises established or mature fields that are characterized by stable or even declining production. Another group of fields are new development projects, where gas production has not even yet started or is expected to grow. Future production may be comparable from field in both categories, but they may well involve very different approaches to future development.
The future life of mature fields is dependent on new reserves, which can be tied into existing field/production facilities. These reserves could be found in deeper formations/reservoirs, for example, the Urengoy field. Individually, deeper reservoirs to extend the life of existing fields are not expected to have major potential, but taken together the aggregate incremental qualities may be very significant indeed. Another feature can be smaller satellite fields in the area (like fields in the North Sea around Sleipner) are tied into the main field, which acts like a hub and provides processing and transportation infrastructure. Deeper horizons, however, are usually characterized by less productive formations and more complex composition of the formation fluids. HP/HT reservoir conditions also require new production technology development. All these factors create additional production costs at the main hub installation. Mature field facilities require new equipment and facilities for transportation and processing of additional feed-gas from deeper reservoir or satellite fields. All these factors can result in a gradual increase of unit production costs and at a certain level of gas prices future production may become uneconomic. But technological development, see section 1.2.2, tax incentives and environmental issues, see section 1.2.3 could enable the life of mature fields to be extended considerably.
One possibility to extend the life of mature fields is CO 2-sequestration in these fields. CO 2 injection into the reservoir could solve two problems simultaneously – increase of recovery and disposal of greenhouse gases. In-Salah and Gorgon fields are examples of such future potentials of mature fields. Future production from new fields is more and more tied to greenhouse gas injection into subsurface (Gorgon, In-Salah) or acid gas processing (Karachaganak, Snohvit). This is a reflection of a global trend in exploration and production of natural gas – the increasing share of acid gases in proved reserves. Probably, the technologies developed for CO 2 separation and injection will soon be required for economically effective production according to environmental regulation.
And, of course, exploration of new reserves around and deeper main fields (such as Morecambe area and Krishna-Godavari area) should give new solutions for the extension of field life and additional reserves. According to the general trend in the structure of world gas reserves (remote, offshore reserves, acid gases, HP/HT conditions, tighter reservoirs), development of improved technologies for gas production and processing of new fields will be required more and more.
In the coming decade the increase in world gas production will include significant contributions from several fields that have not yet reached their full potential or that are in the early phases of production (e.g South Pars, North Dome, Karachaganak). There will also be major contributions from several significant fields that are not yet in production at all (e.g. OrmenLange, Snohvit, Shtokman, Bovanenkovo). Altogether, these fields could provide 600 to 700 Bcm per year by 2020.
A short review of future potential from some significant gas fields in different part of the world follows:
North America
Production is spread in all oil and gas bearing provinces, which are considerably exhausted already. We have not identified any individual field that is significant in its own potential on a global scale, but in aggregate the gas production in the region remains strong and there are interesting, albeit increasingly difficult prospects. The main interest for exploration and production of new reserves is now concentrated in the Gulf of Mexico, Prudhoe Bay and Mackenzie Delta areas. Some industrial expectations are in unconventional gas production (coalbed methane, tight sands and, especially, methane hydrates).
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South America
Production is concentrated around large fields (Dolphin and Hibiscus fields in Trinidad and Tobago, Campos basin offshore Brazil, Camisea in Peru). Future projects will be tied to existing facilities of developing fields. There any many exploration possibilities inland and overall the region has significant potential to expand gas production.
The Bolivia-Brazil gas pipeline sparked a flurry of exploration and development in Bolivia, which has yielded such vast gas reserves that the country is mulling additional export schemes to monetize gas discoveries that the export pipeline can't accommodate in the foreseeable future.
The largest fields in Bolivia are the gas/condensate fields Itau, San Alberto and San Antonio which supply most of the natural gas sold to Brazil. It is broadly understood that Bolivian gas must take advantage of the windows of opportunity in the Brazilian markets lest it be substituted by Argentine and/or domestic gas.
West Europe
North and Norwegian Seas gas reserves are the main source for gas production in West Europe in the near future. But the main UK fields are and the older Norwegian developments are now considerably exhausted and the future life of facilities will need to be supported by the development of smaller fields nearby. Nevertheless, altogether, such giants like Troll, Snohvit and Ormen Lange as well as other North Sea fields can provide up to 200 BCM/year production during the next decade. But the general trend is that gas production in West Europe is decreasing.
In the Groningen field with its varied roles as strategic reserve (mainly during the 1980s) and export booster in the 1990s, the production capacity of the field declined due to depletion. This decline was halted from around 2005 when field-wide installation of depletion compression was installed. Production is significantly picking up since and the Dutch Government has agreed that production can increase by 2.5 Bcm/year during the coming 5 years.
The Troll production plateau will be prolonged, perhaps even increased, when the Troll West gas province will be developed. The timing of it is currently under debate since this will have an impact on the ultimate recovery of oil that is under production from this field segment. Future production of 30 Bcm/year is expected until 2027.
The Ormen Lange field is the first deepwater development project on Norway’s continental shelf. Starting up in 2007 it will produce gas for 30-40 years. With production gradually building-up to 70 million cubic metres gas per day, Ormen Lange has the potential to increase Norway’s gas export by 25%, making the country the world’s second largest gas exporter. The Ormen Lange project will require one of the most extensive subsea gas export pipelines in Norway (Langeled system) that opens up alternative evacuation routes to the UK as well as to the continent.
The Snohvit project in the Barents Sea is Europe’s first LNG export facility and the World’s northernmost LNG project with a start-up of deliveries to the USA and elsewhere scheduled for early 2007.
East Europe and CIS.
Russia is the largest gas producer in this region. Having still super giants like Zapolyarnoe, Bovanenkovo, Kovykta and Astrakhanskoe fields, Russia has all opportunities to increase gas production for a long time and produce gas in different parts of its territory supplying it to East and West Europe as well as to China, Korea and Japan.
The development of the super-giant Shtokman in the southern Barents Sea represents an enormous challenge not least because of the complete lack of export infrastructure in the region. The assistance of foreign companies is expected to be required for its development including evacuation
63 either through pipeline or via LNG. The timing with an expected start-up in 2011 will fit with anticipated growth in the target gas markets of Europe and North America.
The Shah Deniz field in Azerbaijan is one of the world’s largest natural gas field discoveries of the last 20 years, and for BP as the operator of the field it is the largest discovery since the Prudhoe Bay discovery in the early 1970s. The project including the gas export pipeline to Turkey provides more than 5000 jobs during construction in the country and neighbouring Georgia.
Kazakhstan has the potential to be a world-class oil and gas exporter in the medium term and the country’s economic future is linked to oil and gas development such as the Tengiz, Karachaganak and Kashagan projects. The Karachaganak field development (in its first phase from 1995 to 1997) absorbed $160 million of investment. The second phase, from 1998 to 2003, needed $3.5 billion and increased the annual liquid hydrocarbon production to 7 million tons. By 2008 (third phase), the condensate production will be increased to 12 million tons annually before full capacity is reached in the fourth and final phase from 2009-2038. Kazakhstan's government plans to raise $2 billion for development of the field between 2003 and 2008 which will involve construction of another gas processing plant as well as petrochemical facilities. Several gas evacuation options, e.g. to China, Turkey, are under consideration to mitigate the Orenburg bottleneck.
Middle East
The world’s largest natural gas fields (North Field (Qatar) and South Pars (Iran)) are situated in the region. These are in fact geologically one super giant gas structure holding many times the annual quantity of natural gas consumed in the whole world. Future production is expected to attain whatever rates are needed to fill the downstream facilities that are being built to satisfy market requirements.
Qatar’s supergiant offshore non-associated gas field North Field holds 25 tcm and extends into Iranian waters as South Pars. Seven different LNG production units developed by RasGas- and QatarGas-joint ventures are underway in Qatar. The North Field will also provide feedstock for the Oryx GTL (under completion) and planned Pearl GTL plants, as well as for a world-scale methanol plant planned to come on-stream by 2008, all located at Ras Laffan. Three projects, including the Dolphin gas line and Al-Khaleej gas lines, are also going ahead to export North Field gas to neighbouring countries. Overall, North Field gas output can be expected to reach 137 to 153 Bcm by 2015.
The South Pars Field , located about 100 km off the Iranian coast is due to be developed in some 30 phases, each phase planned to produce 10 Bcm/year. Production from the first phase started up in 2002. All the gas produced from the first 10 phases will be for local consumption or injection into oil fields, while from phase 11 onward at least part of the gas is expected to provide feedstock for export projects (LNG and GTL).
Saudi output relies heavily on its Ghawar oil field which accounts for one-third of the country’s proven natural gas reserves (associated gas). Its non-associated gas reserves have not yet adequately been explored. Recently, with a move in policy to open the hydrocarbon sector to foreign investment, several licences in gas prone provinces with challenging prospectivity in the Khuff and deeper formations have been granted. The necessary infrastructure to accommodate the non- associated gas volumes was installed in 2002 at Hawiyah in the vicinity of the Ghawar field and an additional gas processing plant was completed at Harad at the southern tip of the Ghawar field.
South-East Asia
Major fields like Natuna, Trat and Pailin are the centers of growing natural gas production in the region, but much associated gas is produced from oil fields offshore Brunei, Vietnam, Indonesia, which makes a large share of total gas production.
64 India has a bright long term natural gas supply outlook. Certified reserves of over 28 BCM on a deepwater block in the Krishna/Godavari basin is a conservative figure with respect to significant potential for future discoveries in the basin and the Bay of Bengal. More than 9 big discoveries have been made in less than 3 years and a further multi-million deepwater exploration program was kicked off recently.
The very first exploratory venture by RIL in this block has resulted in world’s largest gas discovery for the year 2002. In addition, there is a high probability of success based on the data available is expected for the unexplored deeper targets. These targets are expected to yield new discoveries and consequently the resources from the field are expected to grow with time. It is anticipated that through sustained exploratory drilling in the next few years, the reserves are likely to increase and may range from 23 - 30 tcf. From the initial 40 MMSCMD production level , the gas availability in India is likely to increase by 50 to 55%.
In the Papua province of Indonesia BP’s Tangguh LNG facility which incorporates the super giant 14 tcf Vorwata and Wiriagar fields is on the way to completion in 2007. The plant will supply shipments to China, the USA and South Korea. Now, since an LNG project has been anchored, other finds in that area and further prospects warrant further development activities. The targets of ongoing exploration are mainly stratigraphic traps at Jurassic level.
While natural gas trade in Asia historically has centered on LNG, pipelines may provide an alternative in the future. As a share of overall primary energy, East Asian countries consume far less gas than Europe or North America, in part due to the lack of an integrated international gas grid, but there has been discussion in recent years of building pipelines linking the region. Another idea would include a link to supply southern China and Chinese Taipei with gas from Southeast Asia.
International pipelines currently under construction include one from the offshore Thailand Malaysia Joint Development Area (JDA), and another to bring gas from Indonesia’s Natuna gas field to Singapore. The proposed Asian Gas Grid (AGG) project, with an estimated cost of around $8 billion, would link the Natuna gas field to Shanghai, China ,and tie-in existing gas networks in Malaysia, Indonesia, and Thailand, and possibly Vietnam. With its projected rapid increase in gas demand, China could be expected to absorb the bulk of gas exported through the new system.
Australia
The main reserves of natural gas are discovered at the Northwest Shelf offshore Australia. Central Gorgon and Perseus fields are the centers for exploration and production in future. Gas production can satisfy domestic needs and some volume could be exported.
The Gorgon gas field and others further offshore comprising the ‘Greater Gorgon’ gas accumulations fall into this category of ‘stranded gas’ reserves, that have previously been uneconomical for development. The field, located approximately 130 km off the West Australian coast was discovered in the mid 90’s. Subsequent gas discoveries in the general vicinity of Gorgon have heightened the importance of Gorgon as a LNG export project. Up to 14 tcf of hydrocarbon reserves have been certified as proven in the Greater Gorgon area, which is the basis for a two-train LNG Project. Additional potential could exceed another 20 tcf. The Gorgon project is listed by the International Energy Agency as a carbon sequestration demonstration project. There are firm plans to realize the second world-wide example CO 2 storage project next to the Sleipner project.
Africa
Main reserves are concentrated in Algeria, Libya and Nigeria. Largest fields are located in Algeria (Hassi R’Mel and In-Salah). Future main production is expected from these fields and in their vicinity.
The further potential of Hassi R’Mel extends beyond its function as core of the Algerian gas pipeline infrastructure system. In June 2005, the first Request for Proposals (RfP) was published by
65 the New Energy Algeria (NEAL) Agency for a 150 MW Integrated Solar Combined Cycle plant with parabolic trough technology to be privately financed and operated.
It is designed as a 130 MW hybrid solar-gas plant with a 25 MW solar field, which requires a surface of around 180-000 m² of parabolic mirrors. NEAL is the project developer, set up by SONATRACH, SONELGAZ and SIM with the aim to carry out projects to make use of renewable energy. Sonatrach has engaged themselves to buy the produced electricity.
A Memorandum of Understanding signed in 2003 by nearly 20 parties including the Nigerian government called for a study of the Floating LNG design option for the sprawling Nnwa field in combination with Shell's Doro discovery in an adjacent lease. These recent discoveries are located at a water depth of more than 1000 m and approximately 180 km offshore the Nigerian coast. Currently several joint development scenarios are under scrutiny by the operators Shell and Statoil.
66 CONCLUSIONS TO PART 1
From the examination of the collected information and of the data in the literature, a general overview of the upstream gas activities in many significant fields has been made and lets us to draw the following conclusions. As mentioned previously four criteria were chosen in order to establish this diagnostic.
A) Market Impact:
Groningen, Hassi R’Mel and Urengoy have undoubtedly changed the market. These fields are an example of significant gas sources that led to the development of: • LNG and pipeline for gas exportation (Hassi R’Mel ) • Continental NW Europe’s gas market ( Groningen) • First pipeline corridor through Ukraine to Europe (Urengoy )
Fields like Troll and So uth Morecambe have played a significant role in the commercial and operational dynamics of the residential gas market.
Within LNG, pipeline gas and Gas to Liquids projects involving several international oil and gas companies, North Dome Field is emerging as a major exporter of liquefied natural gas.
New LNG projects based in fields like Vorwata, Wiriagar and Gorgon are expected to have a significant market impact.
Production from Krishna Godavari and Loma La Lata will play a significant role in their respective national domestic markets.
B) Technical advances
1) Developing deepwater reservoirs is one of the most challenging issues, especially when marginally profitable. In the 70’s and 80 ‘s, many companies around the world have implemented some techniques in order to develop deepwater prospects.
As technology enhances, companies continue to move into ever-deeper waters and the risks associated to costs and safety increase hence the challenges facing operators to exploit gas reservoirs go higher.
Fields such as Alwin Area and South Morecambe in the United Kingdom, Troll in Norway, South Pars in Iran, Malapaya in Philippines and more recently Aconcagua in the USA, have developed and used a multitude of sophisticated technologies that allow economic development of these deep water fields.
2) Intelligent wells completions and multiphase pipelines are examples of technologies becoming very important for the economic exploitation of marginal complex reservoirs and for the transportation of well streams from reservoir to process in offshore fields. Deepwater reservoirs Aconcagua and Camden Hills fields are leading applications of intelligent wells completions technology.
3) To show the role of multiphase pipelines, the Gorgon offshore field gives a good example, but the best example for the multiphase transport is South Pars Giant field “Iran”
4) Other developed technologies for deepwaters and onshore fields is the 4D seismic as discussed above the best case of successful 4D seismic are Troll and Sleipner fields where this technology was used to monitor gas oil contact movements and CO2 sequestration respectively.
As a result, difficulties of exploiting deep and unconventional reservoirs and challenges they present push the limits of the upstream gas industry higher and stimulate innovation by the operators to develop new technologies and tools.
67 The proved mastery to explore deepwater prospects encouraged others countries to explore off shore fields. Several fields were discovered in the latest 90’s and planned to produce coming next few years. Over 50% of all major discoveries in 2004 were made in water depths greater than 200 m, thirteen finds were made in water depths greater than 1000 m.
C) Sustainable development
Coal and oil have played and still play a gigantic role in the generation of energy needed to the world’s industry and economy demands. Natural gas, when replacing coal or oil for power generation, can result in huge reductions in undesirable atmospheric emissions. The exploitation of natural gas to satisfy mankind’s current needs for environmentally benign energy is fundamental to global sustainable development yet a multitude of challenges face the gas industry, in this report two categories of factors that lead us to consider a gas field as significant from the perspective of global sustainable development :the field’s location, and the field operations arising from it’s development.
Field Location : Location vary from major onshore developments in highly populated areas like The Netherlands’ Groningen and the sustainability award winning Malampaya project, to as yet undeveloped fields like the giant Bovanenkovo field in the arctic region of Russia’s Yamal peninsular. Often it is not the production site itself that is the issue, but the route needed to send the gas from the well-head to a processing plant to the market. The most used system is multiphase pipelines, significant examples of this are UK’s Morecambe and Nuggets offshore fields, Ormen lange Norwegian deepwater field, and the Russians fields Bovanenkovo and Shtokmanovskoy . An alternative delivery route for offshore projects (or those near the coast) is via LNG tanker. Snovit will be the world’s most northerly LNG project, another challenging project is the Gorgon complex on Barrow Island ( an A class flora and fauna reserve).
Field Operations : Operators aim to be good neighbours to local residents and friendly to environment, three field operations are discussed:
Regeneration Project : Groningen regeneration project included a glycol regeneration system that separates water and condensates to eliminate gas emissions.
Platform Equipment : on the Troll platform, the equipment is powered by electricity that is brought from the Ainland where the main source is hydro power.
CO2 Sequestration : Increasingly CO2 sequestration is becoming the norm, particularly for acid gas reservoirs. Among the prime examples of gas field CO2 sequestration projects are : The Sleipner West natural gas field in the Norwegian sector of the North Sea; In Salah, Algeria, which was the first large-scale example of CO2 capture and storage in the same reservoir and the Gorgon gas development which is planned to have one of the largest geological CO2 sequestration projects in the world. The Snohvit project, in the Barents Sea, Norway will also involve CO2 sequestration.
Flaring & Venting : Avoiding unnecessary loss of gas through flaring and venting is important not just from environmental reasons but also as a matter of simple economics, In many of the gas fields in our examples there is little or no flaring, South Morecambe flaring has been dramatically reduced since start-up, for the Loma La Lata field Gas flaring is prohibited.
As conclusion it’s necessary that the industry continues to improve its performance by applying adequate management systems, state-of-the-art technology and improving HSE performance.
D) Future Potential
Gas fields that exhibit significant future potential can be arranged by their maturity (mature fields that have satellite fields or new reserves that can be tied into existing fields production or new development projects) and locations, A short review of future potential of big gas fields in different parts of the world, is showed :
North America : The main interest for exploration and production new reserves is now concentrated in the Gulf of Mexico, Prudhoe Bay and Mackenzie Delta areas.
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South America : the Loma la Lata reservoir complex still holds significant potential for new discoveries that would allow the reserves and production levels to stay fairly constant. Other production is concentrated around large fields ( Dolphin and Hibiscus fields in Trinidad and Tobago, Campos basin offshore Brazil and Bolivia’s large gas fields: Itau, San Alberto and San Antonio )
West Europe : North and Norwegian Seas gas reserves are the main source for gas production in West Europe in the near future. Nevertheless such giants like Troll, Snoevhit and Ormen Lange can provide up to 200 BCM/year production during the next decade. But the general trend is that gas production in West Europe will decrease.
East Europe and CIS : Russia is the largest gas producer in this region. Having giants like Zapolyarnoe, Bovanenkovo, Kovykta and Astrakhanskoe fields . Shtokman in the southern Barent Sea represents an enormous challenge not least because of the complete lack of export infrastructure in the region. Two other giants are the Shah Deniz field in Azerbaijan, and karachaganak in Kazakhstan
Middle East : The world’s largest natural gas fields are situated in the region: North Field (Qatar) and South Pars (Iran) offer the biggest potential increase in gas production from any field in the world over the next decade.
South-East Asia : In this region two kinds of gas reserves exist:
a. Non associated major gas fields like Natuna, Trat and Pailin b. Associated gas produced from oil fields offshore Brunei, Vietnam, Indonesia, which makes a large share of total gas production.
In India Krishna Godavari basin and Bay of Bengal have significant future potential another giant in the region is Vorwata and Wiriagar fields in Indonesia (14 tcf) on the way to completion in 2007.
Australia : The main reserves of natural gas are discovered at the Northwest Shelf offshore Australia. Central Gorgon and Perseus fields are the centers for exploration and production in future.
Africa : Largest fields are located in Algeria ( Hassi R’Mel and In-Salah ) and in Nigeria ( Nnwa and Doro fields).
69 PART 2: NEW HORIZONS FOR GAS EXPLORATION AND PRODUCTION
INTRODUCTION
In the years to come, it is anticipated that the consumption of gas will continue increasing at a rate of approximately 2%per annum.
Apart from renewables, gas will be the faster growing source of energy. Among the reasons for this leading position for gas are: the amount of available reserves, the environmental performance, and the lower capital intensity of gas fired power generation.
However, for sustainable growth of gas consumption, there must be a shared trust throughout the whole value chain that gas can be supplied at reasonable prices and in the volumes needed. To answer this global question, it is necessary to discuss a few pertinent questions as follows;
1. What are the current trends in exploration for gas, what can be expected for the amount of gas to be discovered over the coming years and what will be the main characteristics of these discoveries, ie where will they be located around the globe, what new technological advances will be most needed to make exploration more successful, what kind of environment will the architects of new developments have to face in order to make the step between exploration and economic production?
2. How to face the new technological challenges which will have to be overcome to develop this gas exploration potential is the next question. During its History, the upstream industry has proven its ability to meet harsher and harsher environments. There has been an impressive evolution of development technologies brought into operation. This will certainly need to accelerate in order to place the upstream industry in a position where it can fulfil the demands from other industry segments.
3. Treatment of gas containing acid components has been an important and abiding issue for gas production. It will be difficult for the industry to meet both cost and environmental requirements associated with the increase of gas demand if it does not develop further its ability to treat and dispose of acid gas components. This challenge is not specific to the upstream industry and probably needs a strong cooperation with other sectors in order to make the best of the synergies of interest. A status on the recent and future developments on this matter is presented in this report.
4. Among the specificities of gas compared to oil is the feasibility and cost of transporting gas to market. This makes gas monetisation a fundamental question for the upstream industry and also for other segments since the difficulties in monetisation have an impact on the “efficient” or really available world-wide gas reserves. Gas pipeline networks are dramatically developing year after year. LNG projects are being developed in many places, either green field or brown field. Previous LNG consumer’s needs for gas are now again on a fast growing track, not least the USA, and new consumers are emerging. New types of links between resources and markets are on track based on chemical conversion from gas to hydrocarbon liquids which will impact gas monetisation, particularly of remote gas. In principle, the development of this new type of link might have an influence on gas availability by accounting for significant reserves of natural gas. Or will this potentially negative impact be more than compensated by an increase of the interest of the industry for gas exploration which might result in more gas supply to the market. GTL technology is described below as well as the markets for liquids produced from this technology.
70 5. Year after year, greenhouse gas emission is becoming an ever greater and shared concern for Society. This is one of the factors which will sustain the future growth of gas consumption because of the higher carbon efficiency of gas compared to fuel oil or coal for generation of heat and power. But it is still more than likely that CO 2 sequestration will be a must in order to reconcile economic growth and environment constraints. CO 2 sequestration in aquifers or depleted reservoirs is much more than a concept: it already finds commercial applications in a number of places all over the world. A status report is presented on these projects showing the full span of maturity from concept to commercial application.
6. And what for the next decades? Eventual peak in gas production is observed or will soon be in such great gas consuming areas like North America, Western Europe. For those areas the question arises of whether it is better on the long term to import more and more natural gas from conventional resources or to develop their own unconventional gas resources, thus contributing to their energetic independence? Much is dependent on gas prices, development and transport technologies. It is timely to start working on the fantastic potential of methane hydrates. There are now good reasons to state that some commercial projects might start before 2015. If the story is successful, one can anticipate that methane hydrates will be a very important factor in the overall energy equation of our planet. A discussion on methane hydrates is presented here below as well as a status on the main projects which are underway on this subject.
SUMMARY
Exploration: recent trends and its future for gas
The potential of gas exploration is probably such that it can cope with the anticipated growth in demand for some decades to come. With the exception of most of North America and Northern Europe, gas exploration is not as mature as oil exploration. By itself, this should give optimism on the potential of gas exploration. As a result of this, exploration activities should be more and more balanced between oil and gas.
More specifically, three types of environment are described which should be among the main contributors to the renewal of gas reserves: the arctic zone, the fold belts and the deep sedimentary basins.
The Arctic zone, particularly offshore, has been relatively little explored and can provide the same order of reserves to those already discovered.
Exploration in fold belts has mainly been shallow up to now. This has resulted in great successes for the industry. The easiest objectives, which are close to the markets or transportation infrastructure or whose size justified dedicated infrastructure investments, have been identified and largely developed. Now, the trend is to move to deeper horizons which are largely unexplored and look for objectives which are much harder to identify and more expensive and risky to drill. However, the potential is large and should justify technological advances and investment risk, while the understanding of the complex geology of fold belts is improving.
In addition, it is quite possible that between one third and one half of the yet to be found gas reserves are in the deep horizons of numerous sedimentary basins spread over the world which have generally been poorly explored up to now.
Exploration potential is anticipated to be relatively dispersed globally (or at least much less concentrated than for oil). Although Arctic is definitely a geographical concept, fold belts and deep to very deep sedimentary basins are much less specific from this point of view.
Exploration in zones close to established markets is very mature (North America, Western Europe). Distances between reserves and markets will therefore tend to get larger and larger. Monetisation of gas will depend on the ability of the industry to establish cost effective links between gas resources and markets. Gas pipeline and Liquefied Natural Gas will continue developing, but other types of links will also probably emerge.
71 One of the main technological advances needed concerns seismic imaging in foothills, subsalt/sub-basalt and for deep exploration. A better definition of the geological models is also a must in order to reduce risk. Deep exploration will discover reserves with higher pressures and temperatures: strong cooperation with the drilling teams is necessary in order to optimize the drilling and testing operations.
Gas development challenges
Some major new development areas, particularly the deepwater Gulf of Mexico, are requiring the operators to simultaneously deploy multiple technologies at new extremes of conditions on single developments. But this does not only apply to deep water provinces. Arctic developments, which experience the most challenging climatic conditions, and deep reservoirs where very high fluid temperatures and pressures are found are also making gas developments more complex.
For deep offshore developments, subsea gas processing, flow assurance, riser design and installation, gas export via subsea pipelines and HPHT are among the challenges which have to be met by the upstream segment in order to safely provide gas to the other segments while optimizing costs.
In the Arctic zone, the climatic conditions create many specific obstacles such as the difficulties of year round drilling and production operations and environmental sensitivity: substantial technology development is required in order to enable large scale, economic exploitation of the resources in regions with heavy, seasonal ice.
The upstream industry is working hard to enable year-round drilling operations in the heavy ice conditions experienced in regions such as Sakhalin.
Not only does deep exploration mean High Temperature, High Pressure, but it also means tight reservoirs with the specific difficulties to overcome like reducing environmental footprint through application of extended reach drilling, better reservoir modelling to improve targeting, and improved fracturing technology to increase production and recovery.
No matter how significant these challenges are, it is reasonable to state that the industry will demonstrate its ability to overcome them as it always has in the past.
Treatment of gas containing acid components
Generally speaking, and quite rationally, the easiest gas fields to produce have been produced first. In order to meet the growth of gas demand, exploration will need to be successful and new fields will no doubt be discovered and developed. However, some already discovered gas fields have been put aside until now because of development difficulties which put them at the end of the queue. Future gas markets will also need gas from these already discovered fields. Among the main reasons which hampers gas development is the presence of acid components in the gas.
The industry has considerably enlarged its portfolio of tools to solve this question. By abiding by the environmental constraints and contributing to cheap and abundant gas production, the development of new technologies for acid gas treatment will play its role to the overall gas supply.
Among the most promising emerging technologies are a variety of techniques using microbes for desulphurization, new oxidation techniques and photolytic processes.
For high H2S content and when liquid H2S can be reinjected, cryogenic processes are very promising for upstream H2S bulk removal : the output gas is treated downstream through a conventional amine process.
And among the most promising improvement of already applied ones are improvements of membrane separation in conjunction with amine techniques. Main goal here was optimization of energy consumption and separation efficiency.
72 The commercial development of the gas-to-liquids industry
The conversion of natural gas to liquid is now becoming a large scale commercial reality. Many new developments have been launched over recent years. The specifications of the products from this process are very competitive compared to other petroleum products. This is particularly the case for GTL diesel and naphtha.
GTL diesel can be blended with heating oil or gas oil in refineries which have difficulties in meeting diesel specifications. This could be the most important outlet for GTL diesel. GTL diesel should attract premiums compared to refinery diesel because of its high cetane index and attractiveness in terms of emission reduction.
GTL Naphtha products benefit from a higher paraffin content than typical naphtha, which enhances ethylene yield in steam cracking, and the complete absence of sulphur and aromatics can benefit refinery processing.
GTL economics can compare favourably to LNG under certain circumstances, while one can list some other advantages of GTL: more value-added locally, faster project development and ramp- up because of the size and liquidity of the GTL diesel and naphtha markets. In high energy price scenarios, GTL economics should be particularly attractive for remote gas.
Significant investments are being progressed now particularly in the Middle-East. The development of this new activity should have a tangible impact on gas projects as it offers a new way to monetise gas. It will make gas oriented exploration more attractive and will speed up some gas developments.
CO 2 geological storage
Geological storage of CO 2 has emerged as a leading option to slow the trend towards global warming resulting from anthropogenic CO 2 emissions to the atmosphere.
The main reasons for this situation are:
Carbon dioxide can be efficiently injected into depleted oil and gas reservoirs, or into un- mineable coal beds and saline aquifers situated below ~800m where CO 2 is in its supercritical state. Collectively, the storage capacity of these geological venues is estimated to be equivalent to hundreds of years of anthropogenic emissions at present rates. The oil and gas industry, with its decades long experience in gas processing, transportation and injection, is well-equipped to develop and deploy the necessary technologies for large scale CO 2 storage.
Three projects are now operated at a commercial scale: Sleipner in Norway since 1996, Weyburn EOR, Saskatchewan, Canada since 2000, and In Salah in Algeria since 2004.
Three projects are planned at a commercial scale: K12 in Netherlands, Snohvit in Norway and Gorgon in Australia.
However, although the technology is becoming proven, there is still a lot to do to achieve acceptability to all stakeholders on permanence and HSE issues.
Methane Hydrates
Volumes of gas in its hydrate form are probably in the 2 500 to 7 000 10 12 m 3 range but might be as high as 21 000 10 12 m 3. More than 100 Methane hydrates spots have already been identified mainly in the Arctic zone and in deep offshore. As deep offshore activity is increasing either for industrial or scientific purposes, this trend should remain positive.
73 There is still a large span for the costs of producing gas from hydrates (from competitive costs around 20-25 $/1000 m3, to more than 200 $/1000 m3). Unfortunately our knowledge on economy of gas production from different hydrate accumulations is still poor in the absence of data from full-scale gas production projects.
Nevertheless, many projects are being carried out all over the world which could lead to the start of economic production from hydrates by 2015.
US, Canada, Japan, Korea, Germany and India are participating to the Mallik project which evaluates the potential of gas hydrates accumulations in the Mackenzie Delta (North of Canada). The U.S. Department of Energy (USDOE) in partnership with the U.S Geological Survey (USGS), industry, academia, and other government agencies are targeting a start of commercial production in 2015.
In Japan, METI has started a 16 year program which regards methane hydrate as a future energy resource. In 2004, a multi-well drilling was carried out in the Nankai Trough area offshore Japan and results are under investigation now.
In Canada, a large review of the methane hydrates resources is on going. Russia, whose reserves in conventional gas are very large, is studying methane hydrates as a factor complicating exploration and production activities, for conventional oil and gas, in permafrost and offshore areas.
Korea, like US, has defined 2015 as the starting date for methane hydrate production. For this purpose, significant programs of exploration have been launched in 2005. India has declared that gas hydrates are of utmost importance to meet their growing domestic energy needs.
Germany has launched research programs on methane hydrates.
74 2.1 NEW HORIZONS IN GAS EXPLORATION AND ASSOCIATED TECHNICAL CHALLENGES
ABSTRACT
The exploration for gas is currently at a degree of maturity significantly lower than for oil, with the exception of certain regions such as North America. It can thus be stated that a not insignificant portion of the world's conventional gas resources is yet to be discovered.
To illustrate this future gas exploration, three themes have been taken which are considered to be of the greatest importance: - a "geographic theme": the Arctic - two "geological themes" (with their associated technical challenges): fold belts, worldwide deep exploration, within a very large number of sedimentary basins, on every continent.
The Arctic domain, notably under-explored in the offshore, delivered essentially gas and could, in a favourable scenario, provide discoveries of the same order as that already discovered. The historical tendancy in hydrocarbon exploration is to investigate deeper and deeper objectives. This opens up relatively large potential for gas exploration of fold belts provinces and prolific deep to very deep basins all over the world. Recent hydrocarbon exploration results combined with new technical and technological progress suggest a high potential for future discoveries and thus a significant part of yet to find gas reserves will come from these areas/themes.
RESUME
L'exploration du gaz a atteint aujourd'hui un degré de maturité significativement plus bas que celle du pétrole, à l'exception de certaines régions comme l'Amérique du Nord. On peut donc affirmer qu'une partie non négligeable des ressources de gaz conventionnelles est encore à découvrir.
Pour illustrer cette exploration future du gaz, nous avons retenu trois thèmes qui nous paraissent de première importance : un thème "géographique" : l'Arctique - deux thèmes "géologiques" (et leurs challenges techniques) : les chaînes plissées et l'exploration profonde qui concerne un nombre très élevé de bassins sédimentaires répartis sur les continents.
L'Arctique dont le domaine marin est très nettement sous-exploré a donné lieu essentiellement à des découvertes de gaz et pourrait, dans un scénario favorable, apporter de nouvelles découvertes de l'ordre de grandeur de celles déjà faites. Par ailleurs, la tendance historique de l'exploration des hydrocarbures est de reconnaître des objectifs de plus en plus profonds. Cela ouvre des perspectives importantes pour l'exploration du gaz dans les chaînes plissées et dans les bassins prolifiques profonds. Les résultats récents de l'exploration des hydrocarbures et les progrès techniques et technologiques associés suggèrent un potentiel élevé de futures découvertes et qu'une partie significative des ressources de gaz à découvrir viendront de ces domaines/thèmes.
75 INTRODUCTION – GENERAL SUMMARY OF GAS EXPLORATION
The results of studies allowing the evaluation of worldwide resources of oil and gas differ considerably depending upon the method used and whether they include non-conventional hydrocarbons or not. In general one can simplify the results and consider that there exists a range of evaluations. On the one hand they are very conservative evaluations, notably that of C.J. Campbell. These consider that the growth of reserves in already discovered fields will be negligible, and with a yet to find Oil potential of less than 27 billion tons; on the other hand a much more optimistic evaluation such as that of the United States Geological Survey (USGS). This, even when limited to conventional oil and gas, estimates the reserves growth potential in existing fields plus the hydrocarbons yet to find to be roughly equivalent to the initial reserves already discovered (and therefore greater than the remaining proved reserves).
The range of gas volumes calculated by the USGS are noted here, knowing that they form the high end of the range of possible evaluations. The diagram (Fig. 1) is a summary (using the hypothesis mentioned below) of the world gas resources. The total of 420 Tcm 1 (approximately 15000 Tcf 1) can be split into four categories :
Produced to date 50 Tcm (1800 Tcf) Proved remaining reserves 135 Tcm (4800 Tcf) Growth in reserves of discovered fields 100 Tcm (3600 Tcf) Yet to find 135 Tcm (4800 Tcf)
The map shown as Fig. 2 represents the split by continent of the conventional gas resources discovered to date. One can note that the bulk of these are located in the Middle East and FSU.
As a general comment it is clear that the exploration for gas is currently at a degree of maturity significantly lower than for oil, with the exception of certain regions such as North America. It can thus be stated that a significant portion of the world's conventional gas reserves yet to be produced will come from fields that have not yet been discovered, and that these future discoveries are likely to be distributed across all continents.
1 Tcm : 10 12 standard cubic meters – Tcf : 10 12 standard cubic feet - Gt : 10 9 tons of oil equivalent
76 To illustrate this future gas exploration, three themes have been taken which are considered to be of the greatest importance (even if not exclusive to the exploration of gas). - A "Geographic theme" : - The Arctic - Two "Geological themes" (with their associated technical challenges) : Fold belts, worldwide deep exploration, within a very large number of sedimentary basins, on every continent.
2.1.1 EXPLORATION FOR GAS IN THE ARCTIC
Numerous sedimentary basins, both ancient and recent, surround the entire Arctic domain as follows: Principal basins associated with North America are the Chuchki Sea, the North Slope of Alaska, the Beaufort Sea, MacKenzie Delta, Sverdrup Basin (and the Arctic islands). There are the peri-Greenland Basins, and in the Russian zone the Northern Far East Sea, the Laptev Sea, Kara Sea, the north of the West Siberia Basin, the Pechora Basin and the Barents Sea, extending into Norway.
Exploration activity has been relatively irregular in these basins. In the USA and Canada drilling started in the 1950s, with a peak in the 1970s and a rapid decline since 1985. In Norway, a first phase of exploration began in the 1980s, followed by almost 20 years of no activity. Today, however, the recently launched Snovhit project is the first offshore development project in the Arctic Circle. In contrast the Russians have had a continuous and consistent exploration and development programme in their Arctic areas over the past 30 years. Fig. 3 shows the remaining (oil + gas) reserves of hydrocarbons discovered to date in the Arctic basins. These reserves total 8.0 Gt if one includes only the offshore portion of the Russian basins. Integrating the onshore Arctic basins of Russia adds a further 20.5 Gt (essentially gas).
The exploration of the northern part of West Siberia began in the 1960s and led to the rapid discovery of major reserves. Notably these include the super giant gas condensate fields such as Zapolyarnoye (discovered in 1965) with 3.7 Tcm of reserves, Urengoiskoye and Yamburgskoye (in 1966) with initial reserves of 10.5 Tcm and 6.5 Tcm respectively. This exploration was extended northwards onto the Yamal and Gydan peninsulars with major success, and into the Kara Sea, where only two prospects were drilled, encountering significant discoveries.
A little further westward, in the Pechora Basin, even though the first exploration wells were drilled prior to 1900, exploration north of the Arctic Circle began in the 1960s with offshore exploration beginning in the 1970s achieving a high (around 50 %) success rate. To the north, in the Barents Sea, exploration in the Russian zone began in the early 1960s leading to several gas and gas condensate discoveries including the giant Shtokmanovskoye Field (around 2.8 Tcm) in 1988. However, this area remains largely under-explored. In the Norwegian sector of the Barents Sea exploration in the 1980s
77 led immediately to the discovery of the Snovhit gas field (around 0.17 Tcm). This discovery was considered at the time to be non-commercial and led to a halt in exploration. It has been necessary to wait almost 20 years to re-start this project, thanks to new economic conditions, but also the technological advances since the discovery. This project is Europe's first large LNG development and will come on stream in 2006. This has re-launched exploration in the Norwegian Barents Sea, and this move indirectly made the Russian Sector more attractive.
In Canada exploration activity in the Arctic began in the 1950s, on the Arctic Nanuvut Islands, with a first well in 1961. Almost 150 exploration wells have been drilled in this basin, with a peak of 37 wells in 1973. Twenty discoveries with a total reserves of 0.4 Tcm and 100 Mt (oil) have been made. Three significant discoveries, Hecla (0.1 Tcm), Drake Point (0.1 Tcm) and Whitefish (0.07 Tcm) contain one half of these reserves. No wells have been drilled since 1987. Since 1969 just over 250 exploration wells have been drilled on the MacKenzie Delta and Beaufort Sea, with also a drilling peak in 1973. This exploration activity declined to almost zero from 1985, but very recently there has been an upturn in exploration in this area. Around fifty discoveries have been made, with around 0.35 Tcm and less than 14 Mt (oil) reserves. A relatively well supported exploration activity in Canada between the end of the 1960s, to the early 1980s has led to some interesting results, notably gas discoveries. However these results are relatively modest given the scale of the Arctic basins and the number of wells drilled.
In Alaska the petroleum industry in 1958 took over exploration from the US Navy which had undertaken the first exploration in the North Slope between 1944-1953. The discovery of the Prudhoe Bay super giant field in 1968 led to a high level of exploration activity (up to 30 wells/year) with a series of major discoveries. After 1985 the activity declined to about 10 exploration wells/year for the whole of Alaska. Alaska contains 1.1 Tcm of gas remaining reserves in developed and known undeveloped fields.
In conclusion, the Arctic basins present a very high potential for hydrocarbons, particularly gas. The offshore is very under-explored (no wells have been drilled in the offshore basin situated to the north of East Siberia, or in the northern part of the Barents Sea, and almost no wells have been drilled in the Kara Sea). Onshore, even though more mature, also presents significant potential. The reserves already discovered are around 28 Gt, including those in the onshore portion of West Siberia, with almost 90 % of these volumes being gas (65Tcm). The remaining exploration potential could be, in a favourable scenario, the same order as that already discovered.
2.1.2 EXPLORATION FOR GAS IN FOLD BELTS
Fold belts have a worldwide distribution, and include both young, active systems such as the Rockies and Andes of the North and South Americas, the European Alpes and the Asian Caucasus, Zagros and Himalayas, and the older inactive systems such as the North America Appalachians and the Eurasian Urals.
78 Hydrocarbon exploration in fold belts has a very long history, practically coinciding with the development of petroleum and gas industries. The first significant exploration successes were located in the foothills of the Caucasus and Zagros (Iraq and Iran). This area is one where the surface geology data allowed, at that time, the easy location of exploration wells. The map in Fig. 4 represents the hydrocarbon reserves (both gas and liquids) discovered in fold belts. The total is greater than 60 Gt. The importance of the Middle East (over half of the reserves) can be noted, with the super giant fields developed in the Zagros belt of Iran and Iraq. The first discovery made in Iraq was Kirkuk in 1927, and the biggest in Iran (Marun, over 4 Gt) was made in 1964, both in the Zagros belt. Gas constitutes about one third of the volume of the Zagros discoveries, which conforms to the fact that exploration has been more oriented towards the search for oil rather than gas, and that deep exploration has been limited. The exploration in this region was almost stopped in the 1970s, and has only restarted in Iran since the end of the 1990s.
Behind the Middle East, the most important area is Latin America with 10 Gt where exploration has been more recent and with major discoveries in several countries (Venezuela (El Furial), Columbia (Cusiana/Cupiagua), Bolivia (San Alberto/Itau) and Argentina).
Outside recent significant activity in North and South America, and several punctuated exploration phases (eg in Papua New Guinea and Italy), this thematic has been relatively neglected in the 1990s, with a switch of focus to exploration of the deep offshore. It must be underlined that this onshore theme is relatively difficult and risky. Seismic acquisition in the mountainous regions is technically difficult and costly. In addition the geology is complex, necessitating major time consuming efforts to process and interpret the seismic. Also drilling is difficult and costly, leading to the fact that, outside North America, three quarters of exploration wells in fold belts are no deeper than 3000 m. Only 6 % go deeper than 4500 m.
In conclusion, even though exploration in fold belts has contributed to past success, it has been focussed on the shallowest objectives that are the easiest to identify. The map on Fig. 4 shows all those areas of fold belts with a residual exploration potential. Deep exploration in fold belts has been little undertaken, leaving the hope of future major discoveries, particularly of gas in this geological theme. We should not forget the progress that has been made in the geological understanding of these areas of complex geometry, and in the seismic imaging that is beginning to lead to new discoveries.
2.1.3 DEEP EXPLORATION
A large number of basins are characterised by very thick sediments (eg the central Caspian Sea where a sedimentary succession of up to 25 km (80000 feet) is present). These are greatly thicker than the depths attained by hydrocarbon exploration wells. There is an historic tendancy in hydrocarbon exploration to investigate deeper and deeper objectives. This tendancy has been re- inforced by results that contradict negative a priori conclusions of certain petroleum explorers. These are mainly with regard to the preservation of reservoir quality (porosity and permeability) with depth, the nature of fluids at depth, trapping conditions and the size of potential accumulations. These results are joined with technological advances that have already been made or which can be envisaged in the short or medium term, driving the petroleum industry to intensify its deep exploration effort.
Deep exploration (> 4000 m of sediments) began, outside the USA and FSU, in the 1960s (at around 100 wells/year) climbing to 500 per year during the 1980s and 90s before decreasing towards 300 per year in the 1990s and 2000. A hundred or so wells deeper than 5000 m have been drilled each year since 1975. Around 40000 deep wells have been drilled worldwide, with almost 25000 of them being in the USA and 5000 in the FSU.
In the USA, after the first deep well (> 15000 ft) in 1920, a real interest in deep exploration developed in the 1940s. The 1960s brought the first major production from deep reservoirs, and deep exploration has not ceased to grow to today. Although deep wells are distributed over all the basins of the USA, there is a concentration in five principal petroleum regions. These are the Rocky Mountains, the Mid-Continent, the Permian Basin, the Onshore Gulf Coast, the Federal Offshore and recently the Gulf of Mexico. It is also necessary to note that 50 % of the deep wells in the USA are production wells. The region of the Gulf Coast contains the largest number of production wells (25 %), followed
79 by the US Federal Offshore region. A very important point regarding the recent deep exploration in the US is the large growth in offshore activity, including the Deep GOM with final depths currently exceeding 9 km (30000 feet).
The numerous basins of the FSU are among the deepest in the world, with sedimentary thickness exceeding 20 km (65000 feet) in the North and South Caspian and South Barents Basins. The basins are both on and offshore, and are situated in very variable geological contexts, which explains the high level of deep exploration in the FSU which has had numerous successes. One can note particularly the South Caspian where deep exploration activity commenced in the middle of the 1950s. By 1975 more than 500 exploration and development wells deeper than 4500 m had been drilled, and around ten significant oil and gas discoveries had been made. Likewise the Dniepr-Donets, North Caspian and Amu-Darya Basins have seen a large number of wells drilled, with significant discoveries. Despite the large number of deep wells drilled in the FSU a number of Russian basins have deep sedimentary section that is poorly or non-explored, as is the case for a large percentage of the worlds sedimentary basins.
Fig. 5 shows the distribution of the worlds reserves (outside North America) by reservoir depth. Around 5 % of the worlds' reserves have been found deeper than 4000 m of burial. This correlates with the percentage of deep exploration wells and allows hope that there will be an elevated contribution to the growth of future hydrocarbon resources with future deep drilling.
The current petroleum industry activity in this theme is spread all over the globe (Fig. 6) but with a major peak in North America, particularly in the Gulf of Mexico, and a lower level in several very hydrocarbon rich and relatively mature basins such as the North Sea, the Niger Delta, offshore Brazil and the western, onshore, basins of China.
In conclusion, all the recent petroleum exploration results suggests a significant potential for future hydrocarbon discoveries, particularly of gas, in the deep portions of sedimentary basins. It is possible to think that between a third and a half of the potential yet to find reserves could come from these objectives.
2.1.4 TECHNICAL CHALLENGES
One of the main, geoscience, technical challenges for the future exploration in the foothills domain (but equally for deep exploration, or subsalt/sub-basalt) is the improvement of seismic imaging through improved acquisition, processing and interpretation. The following example illustrates these challenges.
80 Seismic data acquired in the foothills environment generally suffer from the following imaging problems :
- poor signal to noise ratio in the mountainous areas due to the scattering of surface noise ; - complex wave propagation through the steeply dipping shallow layers and overthrust structures.
This is particularly true while recording 2D seismic lines. The recording of 3D seismic data aims to improve the imaging by using a better wavefield reconstruction and a proper sampling of noise. However, due to the surface conditions in the foothills environment, classical 3D seismic acquisition is characterised by operational difficulties and high survey costs. Consequently, the newer "spare 3D" method is being promoted.
The spare 3D technique consists of reducing the shot and receiver density to the lowest acceptable level, and all lines are "slalomed" to avoid surface obstacles and the steepest slopes. Comparisons between previous 2D lines and random lines extracted from the 3D-PSTM cube show a clear improvement of the seismic image at the target level. This confirms the potential of the spare 3D method for exploration in the foothills (Fig. 7). The resulting image is, however, also very dependant on the processing sequence.
With the present day exponential increase in computing power, even though the fundamentals (accurate velocity model, properly processed input data, correctly applied migration algorithm) remain the same, the rapid evolution of the processing methodology has increased the integration between the processing and interpretation phases (Fig. 8).
The 3D survey in the foothills shown here confirms the potential of the spare 3D method for deep exploration : - compared to "conventional" 3D surveys acquired in the same area, the acquisition turnaround per km² has been dramatically reduced, and we estimate that the acquisition cost per km² has been reduced by a factor of 4 ; - the 3D data show a clear improvement of the target seismic image compared to the previous 2D data ; - the resulting image is very dependent on both the processing sequence and the quality of integrated work between processing and interpretation geoscientists.
For the Geoscientists deep exploration presents a number of specific risks, related to extreme physical conditions. It is necessary therefore to evaluate these risks and reduce the associated uncertainty in a region where data is generally of poor quality. The geometry of traps is poorly defined because, in addition to the fact that they are generally complex, deep objectives are difficult to image. The reservoirs have often been affected by a long and complex diagenetic history. They have poor to very poor (or even no) reservoir properties with exceptions that are difficult but necessary to predict. It is a major concern to identify those processes that lead to a conservation (or creation) of effective porosity and permeability.
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The petroleum systems often have a long and complex history, and the generation, expulsion and migration of hydrocarbons and its preservation in these conditions is poorly known. It is necessary also to define and understand the conditions of preservation of fluid quality, and the effectiveness of seals under conditions of high temperature and pressure.
To conclude, the Geoscientists must also work in close collaboration with the drilling teams to pre-define the conditions of temperature and pressure which constitute the key points in the proper design and safe operation of these difficult wells (Fig. 9).
CONCLUSION
The exploration for gas is currently at a degree of maturity significantly lower than for oil, with the exception of certain regions such as North America. It can thus be stated that a significant portion of the world's conventional gas resources is yet to be discovered. This future gas exploration has been illustrated in the Arctic domains and in fold belt provinces and deep sedimentary basins. The Arctic domain, notably under-explored in the offshore, delivered essentially gas and could, in a favourable scenario, provide discoveries of the same order as that already discovered. The historical tendency in hydrocarbon exploration is to investigate deeper and deeper objectives. This opens up relatively large potential for gas exploration of fold belts provinces and prolific deep to very deep basins all over the world. Recent hydrocarbon exploration results combined with new technical and technological progress suggest a high potential for future discoveries and thus a significant part of yet to find gas reserves will come from these areas.
82 2.2 OFFSHORE GAS DEVELOPMENT CHALLENGES
ABSTRACT
As shallow water oil and gas resources in mature provinces such as Gulf of Mexico Shelf or the North Sea decline, the offshore industry is now developing resources in ever deeper waters and also moving into ice prone areas such as around Sakhalin Island and the Russian Arctic. At the same time, the industry is encountering more complex, difficult to image, more dispersed and higher temperature and pressure reservoirs. These more demanding environments are stretching technologies to or beyond their current limitations in a number of areas, with some deepwater developments deploying multiple technologies at new extremes simultaneously. With a focus on deepwater and ice prone areas, this paper provides an overview of the industry status and future challenges in the key areas of concern for offshore gas developments. Starting with export of processed gas by subsea pipeline, the challenges of flow assurance in unprocessed gas and gas/condensate (i.e. controlling multiphase flow and gas hydrates) in these cold, high pressure environments are considered. Progress in subsea gas processing is reviewed and the challenges of high pressure high temperature (HPHT) reservoirs discussed, exemplified by the Gulf of Mexico Thunderhorse development which represents the current industry limit for deepwater HP/HT (~1000bar/120 oC). The paper concludes with a discussion of developments in ice prone waters, particularly the challenge of extending drilling and installation operating windows to all-year-round.
RESUME
Alors que les productions d’huile et de gaz dans les provinces matures comme le plateau continental du golfe du Mexique ou la Mer du nord déclinent, l’industrie offshore développe des ressources d’huile et de gaz par des profondeurs d’eau de plus en plus grandes et dans des régions susceptibles d’être prises dans les glaces comme l’île de Sakahline et l’océan Arctique en Russie. Parallèlement, l’industrie fait face à des réservoirs plus complexes, plus difficiles à imager, plus dispersés et avec des températures et pressions plus élevées. Ces environnements plus exigeants imposent d’appliquer les technologies actuelles aux limites de leurs domaines, voire au-delà : pour certains développements en eau profonde, plusieurs technologies doivent élargir simultanément leurs domaines d’application vers de nouveaux extrêmes. En s’intéressant plus particulièrement aux développements en mer profonde et dans des régions susceptibles d’être prises dans les glaces, ce rapport montre le statut de l’industrie et les défis futurs dans le domaine clé des développements de gaz offshore. L’export de gaz traité par pipeline sous-marin est abordé, ainsi que les défis de flow assurance pour les gaz non traités et les gaz à condensats (contrôle de flots multiphasiques et de formation d’hydrates de gaz) dans ces environnements froids à haute pression. Les évolutions en matière de traitement de gaz sous-marin sont aussi décrites, ainsi que les défis liés aux développements des réservoirs haute pression haute température (HPHT), illustrés par l’exemple de Thunder Horse qui atteint les limites du savoir-faire de l’industrie pour l’offshore profond HPHT (~1000bars/120°C). Le défi des développements en ea ux zones susceptibles d’être prises dans les glaces est traité, avec notamment un point sur l’élargissement à l’ensemble de l’année des fenêtres de forage et d’opération des installations.
83 INTRODUCTION
In its continued search for new production, the Oil and Gas Industry needs to develop hydrocarbon resources from increasingly challenging reservoirs in ever more demanding environments. For offshore developments, this means deeper water regions of continental shelf in places such as Gulf of Mexico and West Africa, as well as moving into ice infested waters such as around Sakhalin Island and eventually the Arctic. Flow assurance becomes a key issue in these cold environments, whether this is shallow water Arctic or the cold waters at 2000+m in Gulf of Mexico and West Africa. Many of these resources are becoming more complex and aerially dispersed, and may include high pressure/high temperature reservoir fluids. This report will describe some of the engineering challenges of these off-shore gas field developments, focusing on deep or ice prone waters.
The figure illustrates the evolution of offshore oil and gas developments and concepts deployed as water depth increases, using the Gulf of Mexico as an example. As depth increases beyond 500m, fixed structures are replaced by various floating concepts such as tension leg platforms (TLPs) up to 1000m and Semi-submersibles and Spars (sometimes called Deep Draft Caisson Vessels) beyond. Outside of the Gulf of Mexico, where pipeline infrastructure to shore is less available, ship-shaped FPSOs (Floating Production, Storage and Offloading systems) are more common, for example in deepwater off West Africa. The next generation of developments in these regions will encounter water depths well in excess of 2000m, and in some cases involve tie-backs from subsea wells to floating production hubs of 100 to 200km.
Many of the challenges faced by deepwater offshore gas developments are shared by offshore oil developments; a comprehensive description of these common challenges will not be attempted here. In particular, the extensive engineering and scientific know-how developing around the behaviour, design and installation of floating production systems with their risers and umbilicals and associated moorings is equally important to deepwater oil and gas. This includes riser design and monitoring, and modeling of dynamic effects such as vortex induced vibration, with prediction of fatigue lifetime a key focus area. These are extensively covered in offshore oil and gas Industry reports and conferences. This report will focus only on development challenges that are of particular importance for either non-associated or associated gas.
Offshore oil production systems can either export product via export pipelines or by direct transfer to oil carriers, usually via single point buoy moorings and flexible transfer lines. In contrast, offshore gas developments need an export riser, pipeline manifold and export pipeline – although
84 alternatives such as offshore LNG or CNG are now considered feasible, these have yet to be deployed. Export pipelines are becoming increasingly challenging for deepwater developments, as illustrated by elements of the Mardi Gras export system recently completed in the Gulf of Mexico.
In some areas the offshore Industry is encountering increasingly complex reservoirs or seeking to develop smaller pools of resource that can only be economically developed via longer distance tie- backs of subsea wells to floating production hubs, such as Spars, Semi-submersibles or FPSOs. Flow assurance in cold, deepwater environments is a key technical challenge, especially for these increasingly long distance tiebacks. This includes multiphase flow in gas condensate systems and control of gas hydrate formation.
The nature of the fluids encountered presents challenges associated with start-up of subsea wells, and long term corrosion. Subsea processing and compression is also an area of growing interest that is briefly described below.
In addition, an increasing proportion of off-shore developments are of reservoirs containing high pressure and high temperature fluids, so called HPHT. Appropriate technology is relatively available and proven for on-shore or shallow water environments utilizing dry production trees. However, in deeper waters requiring floating production systems this represents the current technical frontier, for example the Thunderhorse development in Gulf of Mexico (~1000 bar, 120 oC operation). Further development is required to extend temperature and pressure limits still further and understand long term equipment behaviour, especially as current exploration and development of very deep gas reservoirs with well-head pressures above 1500bar is extended into off-shore environments.
Industry activity in ice prone and Arctic waters is increasing rapidly, as exemplified by the developments happening around Sakhalin Island and being planned in the Barents Sea. The limited open water season in these ice infested areas greatly increases drilling and installation costs, and lengthens development timescales. Even with entirely subsea production strategies, extending the drilling and installation operating window, eventually to all year round, is a major Industry prize that will require new concepts to be developed for heavy ice conditions. Ice scour of the seabed in the vicinity of shore crossings for export pipelines will also need to be managed. The specific gas development challenges in deep and ice prone waters referred to in this introductory section are elaborated below.
2.2.1 GAS EXPORT FROM FLOATING PRODUCTION SYSTEMS IN DEEP WATER
The design of a deepwater pipeline export system for oil or gas must take into account the following factors:
• the constraints of diameter and weight of riser system that can be installed off the floating production system – which in turn influences the choice of concept (e.g. TLP, Semi- submersible, Spar buoy or ship-shape FPSO)
• the availability of pipe or flexible pipe in the size required.
• the availability and capability of installation vessels.
For example, taking these considerations into account, the recently installed and commissioned Mardi Gras Pipeline system in the Gulf of Mexico had to extend and develop technology to meet the requirements of six major deepwater fields. A number of these technical challenges were at or beyond the limit of industry experience:-
• Steel catenary risers of up to 0.5m diameter and 200 bar rating supported via a large flex-joint to accommodate vessel motions.
• Assurance of the design life of the riser to extreme hurricanes, and fatigue arising from both vessel motions and vortex induced vibration from persistent loop currents.
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• Large diameter export pipeline systems laid in water depths of up to 2400m, including sections across steeply sloping and uneven sea beds. • Pipeline wall thicknesses in excess of 30mm set by hydrostatic pressure collapse criteria.
• Design of valve seals to both internal and external pressure.
• Provision of large in-line tee assemblies for planned and future tie-ins.
• Use of large dynamically positioned vessels for pipelay in both S and J-lay modes.
Similar challenges are now being faced by deepwater gas pipeline export schemes in West Africa to supply domestic demand and on-shore LNG facilities. This may be extended to 3000m over the next decade in both Gulf of Mexico and West Africa, stretching subsea pipeline materials and installation technology still further. Alternatively, gas export via offshore LNG, compressed natural gas, or chemical conversions may eventually become competitive – especially for smaller deepwater gas fields more remote from existing pipeline infrastructure.
2.2.2 FLOW ASSURANCE FOR LONG DISTANCE FLOW-LINES IN COLD AND DEEPWATER ENVIRONMENTS
Assuring continuous flow of production fluids is an issue common to all parts of the oil and gas industry; but this is particularly acute in the cold, high pressure conditions encountered in deepwater developments. For deepwater flow-lines and risers or long distance tie-backs, issues associated with assuring continuity of flow for gas and gas condensate systems fall into two principal categories. The first concerns liquid management in systems where water and condensates are formed resulting in multiphase flow conditions. The second involves thermal issues, where the need for accurate temperature predictions during the design phase impacts hydrate formation and mechanical design. These are described in more detail below.
Multiphase flow
In systems where liquid condensate is either produced directly into the flow-line along with gas, and possibly water, e.g. the Nam Con Son system in Vietnam, or forms as the temperature drops, liquid management becomes a key issue. Liquid inventory in the pipeline will fix both slug-catcher sizes and production ramp-up rates, and it is essential that this is recognized in commercial (transport) agreements, which may be signed well ahead of even a preliminary design.
86 21500
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18500 0 10 20 30 40 50 60 70 80 Time [days]
TOTAL LIQUID CONTENT [m3] TOTAL WATER CONTENT [m3]
The figure illustrates the slow approach to liquid inventory equilibrium in a recently restarted, 60 km, 32” gas condensate line. The true equilibrium between water and hydrocarbon will clearly take many months to establish. As new gas is brought into the system the production of this liquid and its transport to the on-shore facilities (in this case) will present significant challenges, and needs careful modeling to plan operations and design facility modifications.
Tie-back of subsea developments into production hubs raises a further multi-phase flow issue associated with fiscal metering – where more accurate subsea multiphase flow meters are still required by the industry.
Temperature prediction
While the need for accurate temperature predictions in order to support wax and hydrate studies is well understood, there are particular issues with deepwater systems. In long risers, with sophisticated insulation (e.g. pressurised gas in an annulus, or many segments of foam with sea- water penetration), convection cells may be formed that significantly reduce the effectiveness of the insulation, resulting in colder than expected arrival temperatures.
It should also be stressed that in these systems it is essential that simulations are developed with the most precise thermal descriptions of pipeline and riser coatings available. Experience shows that even an anti-corrosion coating of a few mm thickness can significantly alter heat transfer between riser fluids and the surrounding sea, and needs to be taken into account in order to provide a sound design basis for receiving equipment.
Hydrate control
The key flow assurance issue facing gas developments in deepwater environments, which will also be important for Arctic and onshore developments in cold regions, is the control of gas hydrate formation.
Hydrocarbon Gas and liquid water can combine to form crystalline solids which resemble wet snow or ice. These solids are called Gas Hydrates, or more correctly Natural Gas Hydrates (NGH). They are formed by certain low molecular weight hydrocarbons such as methane combining with water under conditions of temperature and pressure commonly found in flow-lines carrying hydrocarbon fluids during normal oil and gas production. These compounds contain gas molecules trapped in a metastable "host" crystal lattice made up of water molecules forming a three-dimensional structure. Gases that form hydrates are light, non-polar, and generally have low solubility in water. They are usually C 1 to C 4 inclusive. Other gases found in oil field fluids such as CO 2 and H 2S will also form hydrates under favourable conditions. Conditions favouring hydrate formation are high pressures (typically >30 bar) and low temperatures (typically <20°C).
87 As well as being a natural occurrence in many parts of the world, often below the sea bed in the proximity of natural gas accumulations, hydrates can form in wet gas, condensate or black oil lines. Gas hydrate formation can cause problems during hydrocarbon production by blocking pipelines, valves or other process equipment. It can occur relatively quickly, be difficult to remove and potentially cause serious damage and/or fatalities if not removed with care. The problem is becoming more important as natural gas and gas condensate resources are discovered where operating conditions (deep, cold water and on-shore colder climates) surpass the conditions needed for hydrate formation. Often hydrates will form from gas streams (which are produced saturated with water) in downstream transportation networks once the stream has cooled from reservoir conditions. This can cause large pressure drops throughout the system and reduce or stop the flow of natural gas.
Hydrate plug removed from a flow-line The problems associated with gas hydrates in gas production and transportation were first reported by Hammerschmidt in 1934 where he states ‘the presence of water vapour in natural gas has always been a source of trouble to the natural gas industry. The movement of gas through the pipe tends to collect and compress the snow at low spots until the line may become entirely plugged’. As a result of these issues, technology has developed to predict and prevent hydrate formation in gas lines and wells. The technical solutions to prevent hydrate formation include methanol or monoethylene glycol solvents as thermodynamic inhibitors, triethylene glycol contactors to dehydrate gas, and pipeline insulation/heating to keep the system warm and hence outside the hydrate formation region (ie to the right of the red line shown in the graph below).
Hydrate dissociation curve for a GOM fluid with pure water
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Pressure /Pressure psia 2000 1000 0 30 40 50 60 70 80 90 Temperature / deg F
88 In recent years, new low dose Hydrate Inhibitors have been receiving considerable industry attention. Replacement of the traditional thermodynamic inhibitors methanol and glycol is highly desirable from both commercial and Health & Safety considerations. The operating costs for these solvent based inhibitor treatments are high, and the off-shore facilities for these treatments can be complex and logistically intensive. From a safety perspective, it is becoming increasingly unacceptable to store large inventories of solvent on off-shore platforms. The Industry has been working since the mid 90’s to develop robust and cost effective low dose inhibitor technology which can be commercially deployed in oil and gas production operations. This is exemplified in the Ravenspurn Southern North Sea Gas field where Kinetic Hydrate Inhibitors (KHI) have been deployed since 1996 and in the North Sea ETAP field where substantial capital costs were realized through the removal of ‘conventional’ methanol solutions and replacement with KHI technology in the design and subsequent operation.
The latest development in Low Dosage Hydrate Inhibitor (LDHI) technology centres around the use of Anti Agglomerates (AA). Also known as dispersants, AA’s target the hydrate crystal size and morphology. Unlike KHI’s, AA’s do not try to delay the onset of hydrate growth. The goal is to produce a transportable oil/water/hydrate slurry. This is accomplished by forcing the hydrate crystals to form slushy to fine powdery particles, which do not adhere to surfaces. Recent successes have been reported in Deepwater Gulf of Mexico (GoM) fields especially as a replacement for methanol in cold oil well start-ups. LDHIs are an emerging new technology in offshore oil and gas production. In certain situations, applications of KHI and AA technology are more economical than methanol or other glycols. This is because LDHI dosage levels are an order of magnitude less than the dosage levels of thermodynamic inhibitors. These low KHI and AA dosage levels translate into lower pumping, storage and transportation capital and operating expenditures. LDHIs can also provide an alternative technical solution, e.g. where sufficient volumes of methanol cannot be injected (pumping or umbilical limitations). This technology also overcomes some of the growing concerns about the environmental impact of large volumes of methanol on downstream processing facilities.
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250 GOM & Vietnam Angola
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Pressure (Bar) 100 UKCS New targets
UKCS Operational 50 Experience
0 0 5 10 15 20 25 Hydrate Formation Temperature (Degrees C)
In the past few years, the ‘challenges’ surrounding hydrate management have stretched with increasing water depth and subsea developments meaning much colder environments. The previous graph illustrates the technical challenge the industry faces in deepwater areas such as the Gulf of Mexico and West Africa. Many of these new provinces are outside the technical limit of KHI, and in some instances current AA technology, which allows scope for improvements in the chemistry by the chemical vendors, amongst others. The industry is also looking toward other solutions such as improved insulation, pipeline heating, and ‘step out’ technologies such as ‘Cold Flow’. One or more of these technologies needs to come to fruition if we are to avoid widespread use of thermodynamic inhibitors as the preferred hydrate management strategy.
89 2.2.3 SUBSEA GAS PROCESSING CHALLENGES In addition to the engineering and technical challenges associated with deepwater installation depths and longer distance tie-backs, subsea gas developments also face processing issues specifically linked to gas/condensate fluids properties. Start-up of subsea gas/condensate production wells can result in low temperature conditions for flow-lines and instrumentation systems close to the wellhead that challenge design, material selection and fabrication. In extreme cases the initial start- up conditions can produce temperatures as low as -50 oC which create brittle conditions in pipework and out of range parameters for standard temperature instrumentation sensors at the wellhead. This drives material specifications to address not only issues during the start-up of subsea production, but also the associated difficult machining and weldability issues with high specification materials. In addition, flow-line metallurgy, weldability, and corrosion management issues associated with the fluid properties such as hydrogen sulphide and carbon dioxide in the process gas, and oxygen in any required injected chemicals for flow assurance purposes must also be addressed.
Subsea separation and compression has been the subject of significant effort by the oil & gas industry over the last 10 years or more. Whilst subsea liquid pumping systems (as opposed to electrically submersible pumps, which tend to be platform deployed) have now started to gain acceptance for reliability and are seeing early commercial trials, there has been a slow take-up of separation and gas compression systems (1).
The current state of technology qualification testing would suggest both subsea pumping and the integration of modular separation systems are ready for commercial application. For pumping in particular, there are examples of deployed system for oil developments.
Subsea liquid pumping and separation modue However, the case for gas compression boosting is not as well accepted, predominately from a reliability viewpoint in relation to rotating equipment and associated power delivery, and further development and qualification testing will be required. Gas compression requires considerably more power delivered to the subsea equipment than oil pumping and this lead to a requirement for very high power deliver components such as subsea connectors and variable speed drives. Overall, there seems to be a future requirement for subsea gas compression systems for application to longer distance tie-backs for gas developments. In particular, this will enable full field development of remote, off-shore gas fields using an entirely subsea architecture. This may be important for the development of gas fields in ice infested and Arctic waters. 2.2.4 HIGH PRESSURE HIGH TEMPERATURE RESERVOIR DEVELOPMENTS Whilst not exclusively an issue with gas developments, high pressure reservoir fluid conditions to 1,000 plus bar are increasingly associated with subsea gas developments, and are being encountered in a number of regions of the world including Gulf of Mexico, North Sea, Offshore Egypt, the Caspian and Trinidad. Oil and gas fields that have both high pressure and high temperature are typically referred to as HPHT fields by the industry. This combination of conditions is dictated by several factors such as age of oil and gas or geologic and tectonic history of the reservoir; another factor being that pressure and temperature of fluids normally increase with well depth.
The definition of HPHT has changed over the years as the industry has matured and exploration has moved to deeper horizons. Although there is not a universal acceptance of an HPHT definition, it generally refers to fields that have a flowing oil or gas temperature in excess of 100 oC and a well shut-in pressure of 700 bar at the wellhead. Thus, the definition is mostly related to the surface
90 equipment required to contain the flow of oil or gas; the temperature and pressure conditions at the reservoir would be much higher than those stated here.
HPHT fields equally occur onshore and offshore. Over the last two decades, the E&P industry has developed sophisticated technology for exploration drilling in much deeper horizons. As the industry moves deeper in search of oil and gas, one should expect an increasing percentage of new prospects to be HPHT.
The main issue for exploration drilling of HPHT gas fields is that of availability of equipment for well control. The critical equipment for well control is a blowout preventor. While drilling a well, a blowout preventor (BOP) is placed on top of the well to ensure that, in case of an emergency, flow of gas from the well to the environment can be safely shut-off. The BOP is designed for maximum potential well pressure and temperature conditions. Exploration drilling is therefore not feasible without an appropriate BOP. The pressure limit for subsea BOPs is currently 1000bar and 120 oC; new technology will be needed to move beyond these limits. Operators are currently evaluating off- shore prospects that will require well head shut-in pressures of ~1700 bar and flowing oil and gas temperatures greater than 200 oC.
Once discovered, the main issues for production of HPHT fields are also related to availability of equipment for such conditions. The list of such equipment is rather long and includes items such as:
• Tubular pipe to case the hole or is used as a conduit for flow of gas • Down-hole jewelry such as the safety valve • Wellhead where all casings are hung • Production tree that sits on top of a wellhead and controls the production flow • Choke that is used to reduce the pressure
The Thunderhorse Semisubmersible development in deepwater Gulf of Mexico will access HPHT conditions(~1000bar and ~120 oC)
In general, exploration and production equipment is available for onshore HPHT fields and has a long history of application. Within the offshore industry, exploration and production of gas from shallow water fields is reasonably straight forward because activities can be performed from platforms
91 that are fixed to the ocean floor, and ‘dry trees’ can be deployed. On the other hand, exploration and production beyond around 600m water depth has to be performed using floating vessels and more specialized equipment such as subsea BOP. As such, current limits of technology as related to pressure and temperature are lower for deepwater offshore fields compared to shallow water offshore fields.
A major consideration for exploration and production of HPHT gas fields is their cost compared to that of non-HPHT fields. This cost can manifest itself in several aspects of the field life:
• Initial appraisal and design of an HPHT field can be longer and more costly than a similar non-HPHT field. • If technology gaps do exist for exploration or production activities, one would have to wait until the technology gaps are closed and appropriate equipment becomes available. In some severe HPHT cases, this wait time can be 4-5 years. Both the technology lead time and cost of technology can substantially add to the cost of a field. • Even if there are no ‘technology’ issues in developing an HPHT field, such fields are generally more expensive compared to non-HPHT fields because of thicker conduit pipes and specialized equipment for production and maintenance of the field. • An HPHT field may require additional safety equipment to ensure that accidental leakage of gas can be promptly controlled and that the wells can be shut-in. In addition, specialized safety equipment may be required to reduce the pressure and maintain the lower pressures in flow-lines during production.
In deepwater HPHT developments, it is often not feasible or economic to design flow-lines that can sustain these flowing pressures of oil or gas. A solution is to choke the pressure down close to the subsea wellhead. However, should there be a plug in the flow-line downstream of the choke, the line pressure would increase leading to flow-line failure. In this case, the risk of flow-line failure can be mitigated by a High Integrity Pressure Protection (HIPPS) system. HIPPS is a high integrity system of sensors and valves that senses the pressure increase in the flow-line and rapidly shuts-in the HIPPS valves before a failure can occur. There are currently six HIPPS systems operational worldwide and a seventh will be installed in the near future.
Subsea developments incorporating HIPPS have been installed in the UK continental (2,3) shelf since the late 1990’s, but have not yet been installed in all oil & gas provinces. In all project cases a specific project safety case is required to satisfy regulatory requirements and show that the design is safe to install and operate.
Industry operators are now evaluating so called ‘deep gas’ prospects at geological depths of 6000m to 10000m, for example in the shallow water and on-shore regions of the Gulf of Mexico. Uncertainty around reservoir porosity and permeability at these depths is generally the greatest risk, and issues associated with extreme HPHT (e.g. 2000 bar, 250oC) the greatest technical development challenge. As well as issues similar to those discussed in the previous section, new down-hole testing tools are needed for extreme HPHT conditions to enable logging whilst drilling (LWD) and pressure and permeability measurement.
2.2.5 DEVELOPMENT CHALLENGES IN OFFSHORE ARTIC AND ICE PRONE REGIONS
In its continued search for new production, the world wide oil and gas Industry is now increasing its activity in cold waters such as offshore Sakhalin Island and the Russian Arctic seas where ice management becomes the major development challenge. In contrast to the development of on-shore Arctic resources, such as those under the Alaskan North Slope, the Oil and Gas Industry has relatively limited capability in heavy offshore ice, and new drilling and production concepts will be required. Supported by the high oil prices of the mid 1970s and early 1980s, early exploration in Canadian Arctic waters and the Beaufort Sea employed artificial islands in shallow waters (<10m) and caisson systems out to around 25m to allow year-round drilling. In deeper waters (up to 200m), existing ice strengthened drill ships or ice resistant floating drilling units can now extend the annual drilling window by one or two months beyond the open water season with ice breaking and management support. Ice resistant oil production units based on Gravity Based Structures (GBS) are
92 also now in operation in water depths up to 80m (e.g. Hibernia). Nevertheless, as the development needs of areas such as offshore Sakhalin, or the Barents and Kara seas are now showing, substantial technology development is required in order to enable large scale, economic exploitation of the resources in regions with heavy, seasonal ice.
The conditions experienced offshore Sakhalin Island illustrates the challenges faced. For much of the year, level ice can be more than 1m thick and ‘rafted’ ice more than 3m thick, with ice ridges forming keels as deep as 30m. This ice moves at typical speeds of 0.25-0.5 m/s, and maximum speeds up to 2m/s, sometimes with unpredictable changes of direction. The seabed in shallow water is deeply scoured by ice keels, presenting a hazard to any subsea pipelines or facilities. One of the first requirements for oil and gas development is the collection of good information on the ice conditions that will be encountered by drilling and production facilities; regulators generally require a minimum of five seasons’ data to form the basis for design.
The ‘Kulluk’ ice resistant offshore drilling rig operating in the Beaufort Sea
Arctic developments are currently characterized by very long exploration, appraisal and development timescales due to the limited seasonal window for drilling and installation. One of the biggest opportunities is therefore to enable year-round drilling operations in the heavy ice conditions experienced in regions such as Sakhalin. Several approaches are being explored by the Industry. In depths up to around 100-150m water, bottom founded structures will probably provide the best solutions. Ice resistant mobile offshore drilling units (MODUs) are needed for exploration and appraisal, and to support subsea development strategies. Ice strengthened jack-ups have been deployed in light ice conditions in Canadian waters to extend the drilling season, and have the advantage of a conventional air gap between the topsides and water line. Addition of ice breaking cones to the legs at the water line may extend ice resistance, as deployed on some jacket structures, but may introduce vibration issues. Ice deflecting walls may also be installed around the unit, and some form of ice protection is required for the risers, for example a caisson that drops down from the moonpool to below the level of any ice keels. Attaching the legs to a bottom ‘mat’ structure that can be ‘de-ballasted’ and lifted to allow movement of the rig may also be advantageous. Nevertheless, concepts based on jack-ups may have limited adaptability to heavy ice conditions, and GBS based concepts may provide more robust solutions.
Most concepts for moveable GBS MODUs have two parts, with a bottom founded element either being ‘de-ballasted’ and lifted by a buoyant top part or simply left behind when the unit moves
93 (perhaps as the base of a production GBS). In general, these concepts have a central ‘monopod’ column of either constant or declining diameter rising from the bottom founded structure. The drilling rig must sit on top of this column, which provides ice protection for the drilling risers inside. A key disadvantage of this concept is the fixed height of the monopod column, which fixes the height of the drilling rig above the seabed rather than the water line and may create stability and supply issues. At least one conical monolithic GBS concept that ‘de-ballasts’ and floats-off has also been proposed; the narrow diameter section at the water line being strengthened to resist ice. An additional consideration for bottom founded structures is the need for seismic isolators to protect the topsides in earthquake prone regions such as offshore Sakhalin.
Above about 150m water depth, floating MODUs are likely to offer more economic solutions than bottom founded structures. Drill ships based on the latest generation of double acting ice breaking tankers are a possibility. These would require turret mooring systems, with ice protection around the turret, mooring lines and risers, with azipod thruster systems supporting the mooring lines and helping to manage changes in ice flow direction. Heavier load turret systems will be required for these concepts. Alternatively, ice strengthened semi-submersibles, perhaps with ice cones at the water line and ice protection for the moonpool could be considered, as could large floating buoys with highly tensioned mooring systems. In all cases, station keeping will be a key challenge which is more stringent for drilling operations than for production, and test the capability of mooring systems to withstand ice loads that may be well in excess of 10,000 tonnes. An ability to disconnect safely with minimal discharge to the environment and no risk to subsea equipment will be essential, and an ability to reconnect without waiting for ice free conditions highly desirable.
In the very long term, subsea or ‘submarine’ drilling concepts may be developed, at least in deeper waters away from regions of ice scour on the seabed. These are still likely to need ice resistant surface support vessels with umbilicals requiring ice protection. However, this seems significantly further away than the prospect of subsea architectures for production facilities.
Many of the concepts and considerations above for drilling also apply for oil and oil/associated gas production facilities in ice environments, whether they are based on GBS concepts up to 100- 150m water depth or floating concepts for deeper waters. Extended reach drilling (ERD) out to more than 10km lateral distance from such facilities offers a means of reducing the need for multiple surface installations or for deploying MODUs, but can extend the time needed for development drilling compared to multiple drilling rigs with wells tied back to the production facility. GBS concepts offer good protection to the drilling and production risers when using an ERD template within the bottom founded structure. On the other hand, ERD rigs increase the size and weight of the topsides and therefore the size of the facility and ice loads that need to be managed. For example, large GBS production facilities around Sakhalin may have to withstand ice loads in excess of 30,000 tonnes.
Ultimately, subsea development of oil and gas reserves tied back to shore in ice prone regions offers a solution that avoids the need for surface production facilities altogether, either bottom founded or floating. The flow assurance issues associated with subsea gas and gas/condensate developments are less demanding than for oil/water/gas systems, and subsea gas developments are therefore more likely in the near term. The development of the Snohvit and Ormen Lange gas fields in Norwegian waters using subsea wells tied back to shore illustrates this approach, although not in ice prone regions. Full-field, subsea development of off-shore gas reserves will require further development of subsea gas compression equipment, and intervention and maintenance under ice will also need to be resolved. Where ice extends all the way to shore, export pipelines will need to be buried in shallow water regions to prevent damage from ice scour, which can cause soil deformation at depths considerably greater than that of the actual trench created.
Almost all Arctic and ice prone environments are considered sensitive, and emissions from drilling and production must be minimised. Integrity of the facilities created will be a key consideration. Emergency response, and evacuation and escape for offshore operations personnel are further areas requiring new approaches in Arctic and ice prone areas.
94 REFERENCES
1. Bjerkreim, B. (2004). Subsea gas compression - A future option. OTC Paper number 016561.
2. Hundseid, J., Flaten, G., Fossum, T. K. (2004). Subsea System Design for the HPHT Kristin Field Development. Thermal and Pressure Loads. OTC Paper number 016688.
3. Theobald, M. C. (1996). Subsea High Integrity Pressure Protection Systems for High Pressure Oil and Gas Developments. OTC Paper number 008180.
95 2.3 PROCESSING OF NATURAL GAS CONTAINING ACID COMPONENTS
ABSTRACT
This paper makes an overall comparison of commercially available and emerging natural gas processing technologies for removal of acid components.
The major natural gas processing categories included in this report are: hydrogen sulphide removal, carbon dioxide removal, sulphur recovery/tail gas cleanup, and scavenging.
For many years, only a limited number of technologies were commercially available to the natural gas industry for treatment of natural gas streams. Although many of these processes are still applicable, numerous new technologies have emerged either as improvements of these processes or as new processes.
The paper includes: • a brief description of the process including the process type, chemicals used and typical process applications; • operating conditions including typical or recommended operating conditions; • achievable purification levels; • process limitations or hindrances; • and other information available for the processes.
A short discussion about the drivers for developing new gas processing technologies concludes the paper.
RESUME
Ce document compare les technologies de séparation des composants acides contenus dans le gaz naturel actuellement disponibles ou en cours de développement.
Les principaux types de traitement présentés dans ce rapport sont les suivants : séparation de l’hydrogène sulfureux, de dioxyde de carbone, récupération du soufre / traitement des gaz résiduaires, traitements de désacidification non régénérables.
Depuis de nombreuses années, un nombre limité de technologies étaient disponibles à l’échelle industrielle pour le traitement du gaz naturel. Même si nombre d’entre elles restent d’actualité, de nouvelles technologies apparaissent avec l’amélioration de procédés déjà éprouvés et le développement de nouveaux procédés.
Ce document contient : Une brève description des procédés (type de procédé, réactifs utilisés et applications), Les conditions opératoires types ou recommandées La performance en terme de niveau de purification Les limitations et inconvénients Et d’autres informations disponibles
Une courte discussion sur les facteurs de développement des nouvelles technologies de traitement de gaz conclut le document.
96 INTRODUCTION
The major natural gas processing categories included in this report are: hydrogen sulphide removal, carbon dioxide removal, sulphur recovery/tail gas cleanup, and scavenging. For many years, only a limited number of technologies were commercially available to the natural gas industry for treatment of natural gas streams. Although many of these processes are still applicable, numerous new technologies have emerged either as improvements of these processes or as new processes.
This report makes an overall comparison of commercially available and emerging natural gas processing technologies. The report includes the following information when available: (1) brief description of the process including the process type, chemicals used and typical process applications; (2) operating conditions including typical or recommended operating conditions; (3) achievable purification levels; (4) process limitations or hindrances; (5) and other information available for the process.
The report excludes processes mainly used for tail gas cleaning downstream of Claus plants and only outlines the most common amine and solvent absorption processes. The processes used to remove H 2S and CO 2 from a gas stream fall into four main categories:
reversible chemical or physical absorption in a liquid direct conversion through absorption and oxidation in a liquid adsorption on a solid physical separation through a semi-permeable membrane
A circulating solvent that contacts the gas being treated through counter-current flow in an absorber typifies the large number of absorption processes available. The absorbed acid gases are then stripped from the solvent by the application of heat (chemical solvents) or the reduction of pressure (physical solvents) in a regenerator tower.
Adsorption processes are typified by multiple fixed beds of adsorbent material. One or more beds are always in adsorption service, while the remaining bed or beds are being regenerated through heat and then cooled.
Direct conversion processes consist of either fixed catalyst beds or circulating liquid phase catalysts for oxidizing H 2S to elemental sulphur.
Membranes consist of semi-permeable barriers which selectively permit permeation of acid gas components from the natural gas.
Sulphur can be recovered through the modified Claus process and newer variations on the Claus process. Catalytic oxidation processes are also available in which the Claus reaction is used but the SO 2 required for the reaction is generated by a catalytic step instead of through combustion. Liquid oxidation processes involve oxidizing H 2S to elemental sulphur.
2.3.1 PRE-EXTRACTION PROCESS
Amine processes find their economical limits in case of very high H2S content. A solution is being developed by Total and Institut Français du Pétrole jointly which can be applied where separated acid gas can be reinjected in the geological reservoirs.
It is based on a cryogenic distillation whose outputs are: • High pressure liquid H2S (50 to 60 bars) which has to be reinjected in the geological reservoirs because of the dissuasive cost of its final treatments, and • Partially sweetened gas which will be processed in a conventional amine unit for example so as to meet the sales gas specifications.
97 A 18 month pilot plant has been running since early 2005 to treat the very sour gas produced in Lacq (South West of France). The first preliminary results are very encouraging since they are in line with the expectations. Industrial applications can be envisaged as early as summer 2006.
2.3.2 AMINE AND CHEMICAL SOLVENT PROCESSES
Amine and chemical solvent processes are widely used for removal of CO 2 and H 2S from natural gas streams. This report will only give a rough overview, as they are common and their range of applicability is well known.
Amine processes
In this part of the following chapter the sour gas is sweetened by using an amine absorption technique. The graph shows a general scheme of an Amine plant. Ethanolamines react directly and rapidly with hydrogen sulfide in aqueous solution to form amine sulfide and hydrosulfide. These reactions occur at theoretical molar ratio of one mole of hydrogen sulfide per one mole of amine (1:1), regardless of whether a primary, secondary or tertiary amine is involved.
Monoethanolamine (MEA)
MEA is the strongest base of the different amines and so reacts most rapidly with the acid gas. Possessing the lowest molecular weight of the common amines, it theoretically has the largest carrying capacity for acid gases on a unit weight or volume basis. It has been and continues to be widely used to sweeten natural gas. Historically MEA has been the preferred solvent for gas streams that contains low levels of H 2S and CO 2 and that have essentially no carbonyl sulfide (COS) or carbonyl disulfide (CS 2). If COS is present in the feed gas, MEA should not be used due to the irreversible reaction between MEA and COS, resulting in degradation of the solvent. MEA has a higher vapor pressure than the other amines. This can result in significant solution losses through vaporization. The problem usually can be overcome by a simple water wash of the sweet gas stream. MEA scrubbing can successfully reduce both H 2S and CO 2 concentrations to pipeline specifications( generally less than 4 ppm). The H 2S content can be reduced as low as 8 ppm. In practice, however, acid gas loadings and solution concentrations are limited because of corrosion problems. MEA which minimizes the thermal degradation of the solution is relative stable.
Diethanolamine (DEA)
DEA has traditionally been used to sweeten refinery and manufactured gas (because of the presence of COS and CS 2), and it is also widely used in natural gas service. The reaction of DEA with COS and CS 2 is slower than those of MEA, and results in different products. Consequently, there are minimum DEA losses caused by reactions with these sulfur components. DEA is non-selective and will remove both H 2S and CO 2. Difficulties are sometimes encountered with low-pressure DEA systems being able to reduce H 2S levels to pipeline specifications. An advantage of DEA compared to MEA is its minimal corrosivity.
98 SNPA – Diethanolamine (DEA)
The SNPA-DEA process is a modification of the of the DEA process and was developed by SNPA (Societe Nationale des Petroles d`Aquitaine) for natural gas sweetening during the late 1950`s. In cases where this process is applicable, the main differences lay in equipment sizing, DEA circulation rate and utility consumption. This is the result of higher solution loadings employment. Wendt and Dailey have discussed the process and its application. It has been used with considerable success for treating high-pressure gas and gas streams with high-acid concentration, down to the level of approximately 1.6 ppm H 2S.
Triethanolamine (TEA)
Although aqueous TEA was the first commercially applied amine sweetening process, it has been largely displaced. Very little TEA is used commercially for sour gas sweetening. Diglycolamine (DGA)
DGA, diglycolamine is the trade name for 2-2 amineethoxy-ethanol and is a primary amine. The solution employed is usually 65-70 % DGA, which allows an acid gas loading of 2.5 kmol acid gas/m 3 solvent which is much higher than for any other alkanolamine. DGA has the potential advantages of high reactivity, low equilibrium partial pressure, etc. that are characteristic of the primary ethanolamines. A disadvantage is the relatively high steam consumption. However, it has not been so widely accepted as DEA for high pressure acid gas treating.
ADIP – Diisopropanolamine (DIPA)
ADIP is the trade name of gas treating processes developed by Shell using DIPA and MDEA. 4 molar DIPA and MDEA can be used in the ADIP process and reduce the energy consumption up to 40 % and investment costs. DIPA is a secondary amine like DEA and it is mostly applied for removal of H 2S from several types of refinery gas because of its robust resistance to degradation. It can also be used for selective absorption.
ADIP – Methyldiethanolamine (MDEA)
MDEA is a tertiary amine. The main difference compared to primary and secondary amines is that CO 2 does not react to form carbamate. Only a slow reaction to bicarbonate takes place. For this reason tertiary amines have the highest selectivity for H 2S. If the gas is contacted with MDEA at pressure of about 80 bar, pipeline gas specifications can be met. MDEA can also be applied for treating gases at low pressure (1-3 bar) if a high CO 2/H 2S ratio is present.
Methyldiethanolamine (MDEA)
MDEA is a relative newcomer in the group of ethanolamines used for natural gas sweetening. This process is used to upgrade the H 2S content of Claus feed gases, to recover H 2S from sulfur plant tail gases, and to treat natural gas to achieve H 2S specifications.
The advantages offered by MDEA systems are the reduced energy requirements because of its lower heat of reaction, the absence of a reclaimer in most cases and a lower required circulation rate because of higher allowable amine concentrations, selective removal of H 2S over CO 2 and a high thermal stability. It does not react with COS and CS 2, which avoids loss of solution. MDEA has a lower corrosion rate than MEA or DEA and is most resistant of the three amines to oxidation.
Ucarsol – HS
Ucarsol solvents are a series of amine solvents developed by Union Carbide. Ucarsol HS-101 is a 50% aqueous solution of methyldiethanolamine (MDEA) with special additives and has been developed for selective absorption of H 2S removal from refinery off gas, natural gas and Claus tail gas. Ucarsol HS-102 is used for deep H 2S removal from low pressure natural gas streams where it is often difficult to achieve a 4 ppm H 2S specification.
99 Amine Guard – ST
The Amine Guard ST system uses a sulfur tolerant (ST) corrosion inhibitor added to MEA or DEA. The Amine Guard ST is applied for H 2S and CO 2 removal. It uses a combination of two oxidizing passivators. The amine concentration can be increased to 30% MEA and 55% DEA. In case of MEA there is no need for continuous reclaiming.
Flexorb
Flexorb is a trade name for a gas sweetening process developed by Exxon. Two different solvents for H 2S removal have been developed: • Flexorb-SE for selective H 2S absorption, • Flexorb-PS for bulk CO 2 and H 2S removal Flexorb-SE is a chemical solvent, while Flexorb-PS is a combination of a physical and a chemical solvent. Specifically Flexorb–SE achieves 1-2 ppm H 2S in the tail gas at low H 2S pressures of only 1.2 psia . Flexorb-PS is a “moderately hindered” secondary amine in an organic solvent plus water for bulk CO 2 and H 2S removal, but which can also remove COS and RSH (mercaptans). It is chemically stable with essentially no CO 2 degradation.
In selective H 2S absorption the selectivity of H 2S over CO 2 is caused by the higher absorption rate of H 2S. Therefore CO 2 must be suppressed as much as possible. For selective H 2S absorption conventionally secondary and tertiary amines like DIPA and MDEA are used. Tertiary amines are mostly used, because they do not react with CO 2 to form carbamate. Certain hindered amines react very slowly with CO 2 and therefore are used for selective absorption of H 2S.
2.3.3 PHYSICAL SOLVENT PROCESSES
The processes use an organic solvent which absorbs the acid components as a function of their partial pressure. In general, the higher the partial pressure and the lower the absorption temperature the better the absorption. A numbers of processes are available, but only the main ones are described here.
Purisol
The Purisol process, developed by Lurgi, uses NMP, which means N-methyl-2 pyrrolidone as solvent, and is applied for natural gas treating. This process has high absorptivity for H 2S and indications of selectivity between H 2S and CO 2.
Rectisol
The Rectisol process was jointly developed by Linde and Lurgi. The Rectisol process uses a refrigerated solution of methanol as solvent.
Ifpexol
The Ifpexol patented technology for natural gas treatment is based on methanol as solvent for dehydration, NGL extraction (Ifpexol-1) and acid gas removal (Ifpex-2) steps in the scope of the complete gas processing. An Ifpexol-1 dehydration system added to an Ifpexol-2 system is a good application to avoid more costly and complicated amine plus glycol processes for dehydration and desulphurization. But for this thesis just Ifpexol-2 is of note.
The vapor phase from Ifpex-1 process enters the bottom of the contactor. The sour gas flows counter-current upwards through a cold methanolated solvent. As the gas flows through the packing, most of the acid gas in the gas stream is absorbed by the solubility of the solvent for CO 2 and H 2S. Some hydrocarbons are also co-absorbed. The sweet gas stream leaves the top of the column with low CO 2 and H 2S content at cold temperature and high pressure. The heat exchange with the raw sour gas occurs successively in the gas/gas exchanger. The cold rich methanol solvent leaving the bottom of the contactor is taken to the flash tank wherein most of the co-absorbed hydrocarbons are flashed off at low pressure. The remaining part of flashed liquid from the tank is drawn-off under level
100 control and heated by heat exchange with lean solvent from the stripper. The mixed phase passes to the Ifpex-2 stripper wherein complete regeneration of the methanol solvent takes place to assure the delivery of dry sweet export gas at required H 2S concentrations. The reboiler provides the required duty to generate stripping vapor for the complete stripping of acid gas from the solvent. The stripping vapor, acid gas and any remaining hydrocarbons are cooled in the water cooler. Condensed methanol collected in the reflux condenser is pumped back to the stripper. Purified lean solvent leaving the bottom of the stripper is first cooled down and then enters the top of the contactor to supply the gas production on specifications. The Ifpex-2 flow sheet is shown in figure below:
2.3.4 PHYSICAL/CHEMICAL SOLVENT PROCESSES
These processes use a mixture of a physical and chemical solvent and are called hybrid systems because acid gases are physically and chemically absorbed. Physical/chemical processes are used to remove H 2S, CO 2 and organic sulfur components like COS, CO 2 and mercaptans from gases like natural gas, synthetic and refinery gas at high partial pressure.
Sulfinol
The Sulfinol process was developed by Shell Oil Company and there are two different types available: • The Sulfinol-D process uses a mixture of sulfolane (tetrahydrothiophene dioxide) which is a physical solvent, DIPA (diisopropanolamine) and water, • and the Sulfinol-M process is a combination of MDEA (methyldiethanolamine) with sulfolane and water.
The Sulfinol process is widely applied to meet commercial sales gas specification. It has treated gas containing up to 55% H 2S to easily meet pipeline specifications of 4 ppm. The flow scheme is similar to the typical amine system. Simultaneous physical and chemical absorption occur under feed gas conditions of elevated pressure and moderate temperature. Regeneration is accomplished by application of heat to release the acidic constituents at near atmospheric pressure and increased temperature. Regenerated solvent is heat exchanged with rich solvent to decrease energy losses, cooled and returned to the absorber. A few advantages are higher acid gas loading, lower energy requirements for regeneration, organic sulfur removal, selective removal of H 2S, lower corrosion rates and lower foaming tendency.
Direct Conversion Processes
Direct conversion processes (or liquid redox processes) are based on the air oxidation of H 2S to sulfur with the assistance of a compound that is easily oxidized by atmospheric oxygen and reduced by H 2S. Absorption of hydrogen sulfide into solvent involves a chemical reaction. H 2S is removed from the gas stream by a circulating solution using a vanadium-based catalyst (for Stretford and Unisulf processes) or an iron-based catalyst (for ARI LOW-CAT and Sulferox processes).
101 The figure below shows a simple flow sheet of a liquid redox system. Sour gas enters the bottom of the absorber where it contacts a catalyst solution. The catalyst solution removes the H 2S from the gas stream and converts it into elemental sulfur. The sweet gas leaves the top of the absorber. The solution containing the catalyst and the sulfur particles flows to a tank (oxidizer) that settles the sulfur and regenerate catalyst solution by sparging it with air. Sulfur may be removed in a settling tank (vessel), as common in the iron based processes, or alternately may be removed as a foam layer, as common with the vanadium-based processes.
Stretford
The Stretford process is one of the oldest and most common liquid redox processes. It is characterized by a vanadium catalyst, relative large tanks and circulation rates and a relatively high conversion of H 2S to byproducts. The flow diagram for Stretford is shown in 0 except the sulfur is often removed as a foam from the top of the oxidizer.
Unisulf
The Unisulf process utilizes a vanadium-based solution for absorbing H 2S from gas streams and oxidizing it to elemental sulfur. The process is an improvement of the Stretford system. The vanadium agents used suppress the development of thiosulfate and sulfate. In all other procedures the Unisulf is similar to the Stretford process.
ARI LO–CAT
ARI LO-CAT is an iron-based technology that has been offered commercially since the late 1970`s, and it is the most common one. In the early 1990`s a modified process was developed, which is called ARI LO-CAT II. The improvements are smaller equipment size, lower liquid circulation rates and reduced byproducts.
In the ARI LO-CAT II process sour gas contacts the ferric chelate in the contacting tower. H 2S is converted to sulfur, while the ferric chelate is reduced to ferrous form. This reduced catalyst is regenerated by aeration and returned afterwards to the contactor. The sulfur is separated from the liquid by filtration for further upgrading or removal. The remaining solvent is recirculated to the oxidizer.
Sulferox
The Sulferox process uses a chelated iron solution at up to 3 weight percent iron concentration. This high concentration allows a lower solution flow rate, reduces equipment sizes, pumping costs and makes Sulferox a good candidate for direct treatment of high pressure natural gas. Sulferox typically reduces the H 2S content to less than 0.5 ppm.
BIO – SR
The BIO-SR process employs a nonchelated-iron solution. A schematic flow diagram is shown in figure 3.9. Natural gas containing H 2S is contacted with ferric sulfide solution [Fe 2(SO 2)3] in an absorber such as a packed column, bubble column or jet scrubber. The H 2S is absorbed into the solution and oxidized to elemental sulfur. At the same time the ferric sulfate is reduced to ferrous sulfate (FeSO 4). The elemental sulfur formed is conglomerated to a large particle size in the slurry tank. Sulfur is separated from solution through filter and settler. The ferrous sulfate solution is then
102 introduced into the bio-reactor where Thiobacillus ferrooxidans bacteria are employed for the regeneration of the solution. The bacteria oxidize ferrous sulfate into ferric sulfate with the aid of air. The oxidizer solution is recycled to the absorber to repeat the cycle. In this closed loop system, there is no degradation of the solution, no waste is generated and essentially neither catalyst nor any chemicals need to be added.
A few advantages are: the high H 2S removal efficiency whereby the concentration of H2S in the treated gas is reduced to pipeline specifications, low operation costs because there is no degradation in the solution and no special catalysts or chemicals are needed.
Hot Potassium Carbonate Processes
Besides the well known amine processes the main class of regenerative chemical absorption processes is based on carbonate solvents containing alkali salts. The graph shows a general layout of such a process. Both absorption and solvent regeneration are carried out at elevated temperatures to keep reaction products in solution, hence the designation "hot". This process was developed by the United States Bureau of Mines for bulk removal of CO 2 from synthesis gas at high CO 2 partial pressures. The process non-selectively removes H 2S and CO 2, and also removes some COS and CS 2 through hydrolysis. It cannot be used in treating gas streams with only H 2S because CO 2 is necessary to regenerate the potassium bi-sulfide. The process uses a 20 to 35 wt% aqueous solution of potassium carbonate (K 2CO 3) with a process flow similar to amine systems, although typically no process cooling is required.
Most of the regeneration is accomplished through flashing and because regeneration of potassium carbonate requires less steam per unit volume of acid gas than amine, operating costs are lower than for an amine system. As the absorption process operates at elevated temperatures, lean/rich heat exchangers and process gas coolers are reduced or eliminated, thereby reducing capital costs. The low hydrocarbon solubility limits gas losses. As an electrolyte, the carbonate solution is corrosive, however inhibitors help control corrosion. Vaporization losses are lower than for amines, however, solution losses occur as contamination with salts of acids, such as potassium formate and potassium Sulphate necessitates precipitation from a cooled slip stream of solution.
The activated hot pot systems have found application in CO 2 removal in EOR projects and are used to treat gas having CO 2 or CO 2 plus H 2S partial pressures from a minimum of 25 psia to 80 or 125 psia (depending on the amount of H 2S present). Minimum gas treating pressure is about 300 psig.
Examples are: • Benfield Processes • Catacarb Processes • Giammarco Vetrocoke Processe • Stretford Processes • Vacuum Carbonate Processes
103 2.3.5 CHEMICAL ABSORBPTION PROCESSES
Activated Carbon
The applications of activated carbon for natural gas processing are limited. Activated carbon is capable of removing, partially light, hydrocarbons and can adsorb certain impurities such as mercaptans and mercury from gas streams, but activated carbon has a negligible capacity for water.
2.3.6 PHYSICAL ABSORPTION PROCESSES
Molecular Sieves
Molecular sieves are alkali metal aluminosilicates (very similar to natural clays) which can physically adsorb water and other constituents from natural gas, cracked gas, propylene, butadiene, acetylene, other saturated gas and liquid hydrocarbon streams, and air plant feed streams.
Molecular sieves have the selective capacity for different size molecules and, depending of the type, molecular sieves are capable of adsorbing various molecules including water, NH 3, H 2S, CO 2, C 2H4, C 2H6, C 3H6, C 3H8 to C 22 H46 , n-C4H9OH, n-C4H10 , iso-paraffines, and /or olefins.
Compared with other solid desiccants, molecular sieves possess the highest water capacity at low water partial pressures and will produce the lowest water dew points. In addition, molecular sieves can be used to simultaneously sweeten and dry gas liquids. The typical continuous molecular sieve configuration consists of two or more fixed bed adsorbers and regeneration facilities. With two adsorption beds, one bed is treating the feed gas while the other is being regenerated. A typical bed is designed to remain online for 8 to 24 hours. During adsorption, the bed has essentially three zones: (a) the top zone or saturation zone where the sieve material is in equilibrium with the saturated feed gas, (b) the middle zone or mass transfer zone where the water content of the gas is reduced from saturation to less than 1 ppmw, and (c) the bottom zone which consists of unused sieve material.
The mass transfer zone moves down through the bed when the bed ages and eventually will be at the bottom of the bed at the end of the bed life. Bed life ranges from 2 to 10 years for desulphurization and CO 2 removal, and from 2 to 6 years for dehydration. By heating with regeneration gas, usually slip streams of dry process gas, a bed will be regenerated. After the regeneration gas has been cooled and any free water has been removed, it is recycled to the process under regeneration gas pressure, which will be achieved through frequently depressurizing and repressurizing of the bed during the regeneration process.
Pressure swing adsorption, which involves depressurization with regeneration slightly above atmospheric pressure, will be applied by some molecular sieve plants. The operating temperature for the adsorption lies between 60 and 120°F, and betwe en 200 and 1,200 psig for the pressure. For the regeneration, the operating temperature ranges from 450 to 550°F. Further, a product dew point of - 130 °F can be achieved, as long as the water front never reaches the end of the bed, in normal service. Additional, molecular sieves can dehydrate to 0.1 ppmw, and they can also reduce the sulphur content to 4 ppmv.
104 Molecular sieves are usually the most expensive method for dehydrating or sweetening gases and liquids, but CO 2 removal with molecular sieves will be most attractive when the product gas is required to have a very low CO 2 content and the feed gas contains less than 1.5% CO 2. For the following situations listed below, Molecular sieves will probably be the process of choice:
Dehydrating fluids at a temperature above 125°F, Dehydrating liquids with heavy hydrocarbons and/or aromatics, Co-adsorbing water and sulphur compounds, Selectively adsorbing H 2S from gas with a high CO 2 content, Treating acid gases when the adsorbed water pH is less than 5.0, and When product dewpoints less than -100°F are requir ed.
UCB (University of California at Berkeley)
In the UCB Process, the hydrogen sulfide is absorbed by a physical solvent and the resulting solution of H,S is mixed with a stoichiometrically equivalent amount of sulphur dioxide dissolved in the same solvent. The reaction between the two sulphur compounds forms water, which is miscible with the solvent, and elemental sulphur, which crystallizes from solution when its solubility will exceed.
Sulphur is recovered by cooling the solution, settling the additional crystals that form and centrifuging the slurry pumped from the bottom of the crystallizer surge tank. Part of the sulphur formed in the reaction is burned to make the SO 2 needed in the process, and the heat of combustion is recovered in a waste heat boiler. The water content of the solvent is maintained at 3 to 4 wt% by stripping the excess water from the side stream of solvent that is subsequently used to absorb the SO 2.
The solvent used in the UCB process is 2-(2-methoxy ethoxy) ethanol, the monomethyl ether of diethylene glycol. The solvent contains a proprietary catalyst, an aromatic aniline, which enhances the kinetics in the crystallization unit. The process is still in the conceptual stage. There have been no demonstration units or pilot plant runs performed to date.
2.3.7 BIOLOGICAL PROCESSES
Biological Process (ARCTECH)
ARCTECH has isolated a microbial culture (containing more than one particular species), which is capable of removing H 2S from gas streams. The intended application is a direct treatment of natural gas streams. The SS-II (sewer sludge isolate 2) microbe consortium exhibits a high degree of removal and simultaneous oxidation of H 2S to other sulphur compounds.
The research to date has been insufficient to determine the overall workability of the process on an industrial scale, but it shows several promising features which are listed below:
in a CSTR (continuous stirred-tank reactor), it reduces the H 2S concentration in a simulated natural gas stream from 5500 ppm to less than 4 ppm (provided that sufficient solution contacts the gas stream) it effects an overall decrease in CO 2 concentration. it operates anaerobically (no oxygen needs to be added to the gas stream to get rid of the H2S). it has, potentially, lower chemical costs than redox processes. the size of vessel required per ton of sulphur is, potentially smaller than that for redox processes.
However, there are concerns that the SS-II microbe consortium may
cause CH 4 shrinkage. react slower with H 2S in comparison with existing processes. produce sulphur compounds that are difficult to separate or convert to elemental sulphur as molten or cake product.
105 All the work done by ARCTECH so far was at a laboratory scale. After preliminary experiments to screen the cultures were performed, mixtures of varying concentrations of N 2, CH 4, H 2S, CO 2, COS and CS 2 were contacted with SSII.
In many cases, SS-II was able to oxidize the H 2S to below detectable concentration limits, even in some of the CSTR experiments. In all cases, it was demonstrated that SS-II can oxidize the H 2S to <4 ppm provided that a sufficiently high ratio of liquid volume to gas flow rate is imposed. Oxidation rates were slightly greater at higher pressures. Overall, the specific oxidation rates reported were high enough to indicate that ARCTECH’s concept could be economically competitive with existing processes.
Preliminary calculations based on these oxidation rates show that (assuming typical attainable bacterial number densities and conversion rates do not significantly change with scale up) this process has the potential to be cheaper than existing processes. For example, one of Kellogg's estimates for broth volume is 600 gallons to process 1 LTD of sulphur, which is significantly less than the required bioreactor volume for an equivalent BIO-SR process. However, a complete understanding of the factors involved (pathways, mass transfer resistances, solubility’s, specific growth rates, yield coefficients, etc.) has not been attained with the research to date. Not enough is known about the process to design a unit with confidence. Thus, a thorough economic analysis is not yet possible.
The research has proven that: Gas phase H 2S concentration can be reduced to acceptable levels; The number of bacteria necessary to accomplish this conversion indicates a broth volume considerably smaller than existing processes (such as Tail gas cleaning processes).
Because of the promising features of this process and the experimental data to date, it is feasible that ARCTECH continue research efforts to answer some of the questions and concerns which must be answered before the industrial potential of the process can be evaluated. Specific research objectives need to be delineated to obtain the necessary answers to do a preliminary design of the process.
By focusing on the design, one could determine the factors necessary to complete the economic evaluation of this process. Then, the researchers could design and run experiments to produce the data which are required to support the design, and thereby completing the preliminary analysis of this process.
However, the ARCHTECH process for biological H 2S removal has potential as a workable process that may have an economic advantage over many existing processes. Further, the research to date has not provided all of the data necessary to verify the technical soundness or fully evaluate the economic potential.
NKK BIO SR Process
The NKK Bio-Reactor H 2S treatment system evolved from the discovery that bacteria could be used to treat acidic mine water. The Bio-SR process is a non-chelated iron-based redox process. It operates at a lower pH than ARI LO-CAT or Sulferox, and it does not require a chelating agent to keep the iron in solution.
Based on experience in treating sour gases from chemical plants, refineries and sludge digesters, the Bio-SR process offers a good potential for upgrading natural gas to pipeline quality
specification (less than 4 ppm H 2S) in a single step. The basis of the process consists of a non- chelated solution of ferric sulphate contacting Sour gas in an absorber. The solution absorbs the hydrogen sulfide and oxidizes it to elemental sulphur while, at the same time, the ferric sulphate is reduced to ferrous sulphate. The elemental sulphur is removed from the solution by mechanical separation.
The solution then goes to a Bio-Reactor where, upon contact with air, the bacteria oxidize the ferrous sulphate back to ferric sulphate. The oxidized solution is recycled to the absorber.
106 The Bio-SR process has some commercial scale installations, treating off-gas from a chemical plant and digester gas from a municipal plant. The process has also undergone pilot plant demonstrations at a refinery installation (for direct-treat Bio-SR and for Amine/Bio-SR) and at a sludge plant installation (for digester off-gas). So it shows some potential for the future.
2.3.8 ELECTROCHEMICAL PROCESSES
Electrochemical Process (ABB Combustion Engineering System)
The electrochemical membrane separation (EMS) process is capable of removing H 2S from fuel or natural gas as part of the overall upgrading to pipeline quality natural gas.
The separation process is based on the reduction of H 2S to elemental sulphur and hydrogen across the surface of a porous electrode in an electrochemical cell. The EMS process is capable of removing H 2S and recovering sulphur in a single step rather than the conventional two-step absorption-conversion route. The EMS operates at near gasifier temperature and can therefore operate more thermally efficiently than aqueous or organic liquid processes.
The feed gas, at a temperature above the sulphur boiling point, passes through an electrochemically-driven membrane separator consisting of a porous cathode and anode separated by a molten salt electrolytic solution in a ceramic matrix. At the cathode, the H 2S in the gas is converted to a sulfide ion and hydrogen. The hydrogen exits with the gas stream while the sulfide ion is transported through the molten salt electrolyte from the cathode to the anode. At the anode, the sulfide ion is oxidized to sulphur and carried away in a sweep gas.
Investigations are focused on the evaluation of electrode materials, electrolyte composition and fabrication, and performance of a complete bench scale cell with respect to removal efficiency and power requirements. Metal sulphides and ceramic oxides were found to be promising electrode materials. Electrolyte composition and fabrication technique are of major importance to cell selectivity. Single Stage removals in excess of 90% were achieved. Most experiments operated at current densities of 20-50 mA/cm 2 at approximately 1 volt and would extrapolate to commercial design densities of 50-100 mA/cm 2 using more sophisticated cell and electrolyte membrane fabrication.
However, with respect to natural gas, it was shown that H 2S can be selectively removed down to levels of 5 ppm or less. The effect of gas phase mass transfer on increasing selectivity was also demonstrated in tests employing recycle. Both scrubbing (1.5% H 2S) and polishing (100 ppm H 2S) applications have been demonstrated, and sulphur recovery from the discharge side of the cell has verified the overall mechanism.
A future development requirement of this process implies that more commercial-type electrolyte matrices need to be investigated to determine their resistance to hydrogen diffusion, and longer term testing is necessary to further verify stability of electrodes and electrolytes. The next supplementary logical step of development would be scale-up to larger size cells and further assessment of materials and performance.
Development of fabrication techniques for larger electrodes and electrolytes would be conducted using MCFC knowledge as a guide. The scale-up process is envisioned to proceed through sizes of 1 ft 2 and 16 ft 2. A factor of 10 for reduction from inlet to the outlet of the cells is practical and would necessitate the use of cells in series to achieve high removal efficiencies.
Photolytic Processes (Textron Defence Systems)
This process is to date an exploratory project executed by Textron Defence Systems a subsidiary of Textron Inc. and it support the premise of photolytic purification of natural gas.
The capability of the process to achieve natural gas purification had been confirmed in this project, and it has been shown that the H 2S content can be reduced to at least a few tens of ppm, and there are no reasons why even deeper purification would not be possible. The efficiency of radiant energy utilization achieved in the laboratory experiments amounts to, at best, 0.05-0.07 for 95% (i.e.,
107 from 100 ppm to 5 ppm) natural gas purification. This value is substantiated by analytical modelling predictions after accounting for differences between the optimum (model) and actual (experiment) conditions, and the comparison verifies the model and allows its use for the scale-up estimates.
In summary, the test data combined with the analytical model indicates that the PPNG process would be cost effective in lowering the H 2S concentration in sour natural gas by about two orders of magnitude. The data and analysis also showed that the process would be most effective for treatment of natural gas with H 2S levels below 400 ppm as bulk processing systems are more economical for treating the more highly contaminated gas resources. Further, the experimental results and supporting analytical model data indicate that the PPNG process is feasible as a scavenging technique, providing reasonably low energy consumption for reducing concentration of H 2S contaminant from several hundred ppm by one or two orders of magnitude.
However, the affirmed technical feasibility of the PPNG technology together with a positive economics prognosis for H 2S removal at low, < 200 ppm , concentration level, warrants further experimental, modelling, and market research.
Membrane Hybrid Processes
A membrane separates gases by selective permeation of the gas constituents in contact with the membrane. The gases dissolve in the membrane material and move across the membrane barrier under an imposed partial pressure gradient, and this pressure gradient is established by feeding high pressure gas to one side of the membrane while maintaining the permeate side at much lower pressure.
Through the polymeric membrane material, gases are separated on the basis of their solubility and diffusivity. Polymers commonly used in gas separation membranes include cellulosic derivatives, polysulfone, polyamides and polyimides. Membrane elements are either formed as spiral wound flat sheets or hollow fibre.
In a spiral-wound membrane system, flat sheet membranes are packaged into spiral-wound modules, increasing the packing efficiency. The feed gas enters the pressure tube at high pressure and flows into the element via the high pressure channel spacer. The more permeable acid gases pass rapidly through the membrane into the permeate channel spacer where they are concentrated at low pressure.
In comparison, in a hollow fibre system feed gas enters on one end of the shell side and product gas exits on the other end of the shell. Acid gas components which permeate to the inside of the hollow fibres pass through an internal tube sheet and are discharged through the closure flange on the pressure vessel. With either type of membrane element, several elements can be connected in series or parallel to meet specific requirements.
Membrane permeation is pressure driven. The pressure differential between the feed and permeate streams has the greatest impact on membrane performance, impacting both, the membrane area required and the volume and composition of the residue and permeate streams. In fact for
108 single-stage membrane systems, residue stream purity increases with increasing pressure differential and membrane area requirements decrease.
The absolute pressure of the permeate stream also plays an important role. In addition, feed flow rate impacts the residue product purity, but has relatively little effect on the total permeate flow rate. Residue purity decreases with increasing feed flow rates, but recovery increases.
Finally, residue purity increases with increasing membrane area, but permeate purity increases with decreasing membrane area. In both cases, recovery decreases as the purity requirements is increased. Membranes can operate up to 2000 psi. Most membranes used for CO 2 removal have an inherent ability to dehydrate a gas stream, but these membranes were not designed to intentionally dehydrate a gas stream and because of this certain problems can arise when using the Membranes for dehydration.
In general, as long as the water is kept in the vapour phase no problem should arise in the membrane, but if free water formation occurs in the membrane further separation could cease, or in other membranes, the membrane material itself could be dissolved by the free water. This happens because the latter membrane material is formed or caste with water when manufactured. A solution for this problem are membranes which are casted with alcohol, they should not exhibit problems with free water formation.
In a single-stage membrane system, purification levels are highly dependent on the differential pressure between the feed and permeate streams, the absolute pressure of the permeate stream, the feed flow rate and the membrane area. Through the use of a recycle loop, product recovery can be improved.
In a two stage membrane arrangement the first stage membrane is designed to produce the desired natural gas product. Permeate from the first stage is compressed and then fed to the second stage membrane. Residue from the second stage is recycled to the inlet of the first stage membrane. Acid gases are concentrated in the second stage membrane and exit in his permeate.
When a membrane system is employed upstream of a Claus Sulphur recovery plant, care must be taken, because in addition to H 2S and SO 2, the acid gas permeate stream to the Claus plant also will contain some amounts of Hydrocarbons. These Hydrocarbons will increase the Claus plant oxygen demand which in turn will have a diluents effect on the Claus feed in decreasing the Claus plant process efficiency. This probability, to reduce the Claus sulphur quality by darkening the sulphur colour, exists for unburned hydrocarbons.
Membranes are quite useful for recovering CO 2 from natural gas in CO 2 enhanced oil recovery (EOR) applications because of their effectiveness at high CO 2 concentrations. In fact, membranes were found superior for low-pressure, high CO 2 (70%)-enhanced oil recovery treatment. In addition, membranes show promise in other natural gas treating applications for the removal of H 2S and CO 2. Two recent cost comparison studies of amine and membrane treating of natural gas concluded that membrane processing is economically advantageous over DEA over a wide range of feed gas compositions and flow rates. The studies also concluded that membranes are particularly competitive for lower flow rates (because of their modularity) or for high CO 2 concentrations. However, membranes were found to be less competitive for applications involving low feed and product pressures (e.g. below 350 psig).
109 In hybrid applications, membranes are used to remove the bulk or major portion of the acid gases from the feed gas. Final processing to pipeline quality product is accomplished by conventional absorption or adsorption technologies. A recent cost comparison study of amine, membrane, and hybrid membrane-amine systems for CO 2 removal concluded that a membrane-amine hybrid system can be economical for CO 2 removal from natural gas at lower CO 2 feed concentrations than are normally found in EOR applications.
2.3.9 INTRODUCTION OF NEW TECHNOLOGIES TO THE INDUSTRY
The operators of gas treating plants continue to consider the incorporation of improvements to existing technology and the installation of new technology as a means to reduce the costs of production. In addition, for the treating of streams containing H 2S, ongoing changes in environmental legislation have also meant that the industry has had to consider the use of new technology in order to improve the environmental aspects of gas treating, even if this results in increases in costs.
As a result, the development and acceptance of new H 2S removal and sulphur recovery technology by the industry is primarily driven by the combination of these two factors. For CO 2 removal, the continuing need to reduce the costs of production and the ability to adapt to changing flow rates and concentrations are the main reasons behind technological advances.
The balance between increased costs and minimizing environmental impact has slowly shifted toward a stronger weighting by legislative bodies on the environmental implications. This has resulted from the increasing level of public concern for environmental issues being communicated to legislators.
The low prices, seen for natural gas since deregulation, have also made the reduction in treating costs essential for continued financial viability of the gas treating industry. As a result, operators weigh both the overall costs and environmental impacts of all improvements in order to find the right balance.
110 2.4 CO 2 GEOLOGICAL STORAGE: PRINCIPLES AND APPLICATION TO FIELD PROJECTS
ABSTRACT
Geological sequestration, or the capture and underground storage of CO 2, has emerged as an important option to minimize CO 2 emissions to the atmosphere. With ratification of the Kyoto Protocol and development of national and regional carbon taxes and cap and trade systems, CO 2 storage has received intense interest in recent years. Carbon dioxide can be injected into depleted oil and gas reservoirs, unmineable coal beds and saline aquifers situated below ~800 m where CO 2 is in its supercritical state. Collectively, the storage capacity of these geological venues is estimated to accommodate hundreds of years of anthropogenic emissions at present rates. Storage monitoring programs developed around an existing commercial scale CO 2 injection saline aquifer in the Norwegian North Sea (since 1996) and a Canadian EOR project (since 2001) show encouraging results relevant to the technical viability and safety of CO 2 storage. An additional commercial scale project began in Algeria in 2004 and more are expected to come on line in the next few years in Norway, Europe and northwest Australia. Widespread, massive application of CO 2 storage will require further development of technologies to improve efficiency, particularly of CO 2 capture and transportation, as well as to earn stakeholder approval. Remaining technical issues, including the integrity of natural and engineered systems, process optimization, monitoring and verification and risk assessment are outlined in the present survey with reference to recent R&D efforts and pilot- demonstration projects aimed at their resolution. Over the next decade, creative approaches to regional and local source-sink matching and value chain development may realize profitable or at least relatively inexpensive CO 2 storage while beginning to achieve tangible environmental benefits.
RESUME
La séquestration géologique, ou le stockage dans des cavités souterraines, du CO2 s’avère la meilleure solution actuelle pour ralentir le réchauffement climatique dû aux émissions de CO2 dans l’atmosphère générées par les activités humaines. Avec la ratification du protocole de Kyoto et la mise en place de taxes carbone au niveau régional et national, ainsi que d’outils pour le négoce de permis d’émissions, l’intérêt pour cette solution s’est considérablement accru au cours des dernières années. Le dioxyde de carbone peut être efficacement injecté dans des réservoirs dont le pétrole et le gaz ont été exploités, dans des veines de charbon non exploitables et dans des aquifères salins situés à plus de 800 mètres de profondeur où le CO2 se trouve dans un état supercritique. A l’échelle mondiale, la capacité totale de stockage par ces types de piège correspondrait à des centaines d’années d’émissions anthropogéniques au niveau actuel. Deux opérations d’injection de CO2 à l’échelle industrielle, l’une dans des aquifères salins en mer du nord norvégienne (en cours depuis 1996), l’autre dans le cadre d’un projet canadien de récupération améliorée d’huile (commencée en 2000), donnent des résultats encourageants du point de vue de la viabilité technique et de la sécurité du stockage de CO2. Un autre projet industriel a démarré en Algérie en 2004 et d’autres sont programmés pour les prochaines années en Norvège, en Europe et dans le nord-ouest de l’Australie. La généralisation du stockage massif de CO2 exigera des avancées technologiques pour réduire les coûts, en particulier de capture et de transport du CO2, et pour emporter l’adhésion des parties concernées. Mais les défis les plus difficiles à relever ne concernent pas tant les techniques que les régimes fiscaux et réglementaires qui garantissent la viabilité économique du projet.
Les questions techniques restant à résoudre, en particulier l’intégrité des systèmes naturels et industriels, l’optimisation des procédés, le monitoring, le suivi et l’appréciation des risques sont décrites dans cette présentation qui fait le point sur les efforts récents de recherche et développement et sur les projets pilotes en cours. Des approches innovantes devraient permettre, au cours de la prochaine décade, de lier au plan régional et local la production et le stockage de CO2 de manière à valoriser la chaîne. Cela permettra de développer des solutions profitables ou du moins relativement économiques dont les bénéfices environnementaux commenceront à être tangibles.
111 INTRODUCTION
Climate Change and Mitigation Options
Major steps towards addressing climate change include the Rio de Janeiro “Earth Summit” in 1992, establishment of the United Nations Framework Convention on Climate Change (UNFCCC) in 1994 and the drafting of the Kyoto Protocol in 1997 with subsequent ratification in 2005. Since the late 1990s, there has been a rapid increase in climate change science research and funding of carbon mitigation technologies. In 1991, Norway was the first nation to introduce a carbon tax. The EU has recently instituted a trading system involving emissions caps and credits. The United States, the largest emitter of CO 2, has not ratified the Kyoto Protocol but is in favor of a voluntary reduction in “emission intensity” (expressed as tonnes CO 2 emitted / MM$ GDP) with a target of 18% from 2002 to 2012 ( www.whitehouse.gov/news/releases/2002/02/climatechange.html ). In the 21 st century, focus has shifted towards the rapidly growing CO 2 emissions from economies such as China, India, Brazil, Mexico, and South Africa, which were the five countries that were invited to and participated in the Glenneagles Summit of the G8 nations. These and other developing countries are exempt from the Kyoto Protocol but are eligible for application of clean development mechanisms (CDM) which are envisioned as innovative energy or carbon offset schemes that firms in industrialized nations may apply in exchange for carbon credits.
Among the approaches for stabilizing atmospheric CO2 levels are: energy and fuel efficiency (e.g., high mileage automobiles, integrated residential and industrial technologies), fuel switching (e.g., coal to natural gas in power generation), renewable energy (wind, solar, biomass and hydro), nuclear energy and hydrogen. Other approaches to avoid CO 2 release into the atmosphere include offsets in terrestrial systems (e.g., soil management, reforestation) and capture and disposal of CO 2 into the oceans or geologic formations. The difficulty of addressing an issue of this magnitude is well documented by many researchers and groups (Edmonds, 2003; Pacala and Socolow, 2004; World Business Council on Sustainable Development, 2004). In order to stabilize atmospheric CO 2 concentration to today’s level in 50 years (avoiding 7Gt / year by 2054), a portfolio of technologies and methodologies is helpful to reduce emissions over three major sectors (electricity, heat generation and transportation). All advanced technologies in such a portfolio approach have substantial development needs in cost, safety, environmental impact and / or aesthetics.
Geologic Sequestration of CO 2
Geologic sequestration, or CO 2 storage, entails injecting CO 2 in its dense phase (supercritical fluid) into deep (>800 m) geological formations such as depleted oil and gas fields, unmineable coal beds and saline aquifers (Fig. 1). Whereas this approach is one of a number of options available for avoiding CO 2 emissions, it has distinct advantages. The estimated capacity for geologic CO 2 storage is less than that of the environmentally sensitive oceans but immense all the same (Table 1). Containment of CO 2 within geologic formations is widely expected to be secure given the depth of injection and the multiple, available immobilization mechanisms (solubility, capillary trapping and mineralization). In general, most depleted oil and gas fields are well enough understood to predict the behavior of CO 2 in the subsurface. There is concern, however, that oil fields in particular are populated with abandoned wells that may become conduits for CO 2 migration out of the target formation. The environmental impact of geologic CO 2 storage is considered minimal given that CO2 arriving at the near-surface can be naturally attenuated (Oldenburg and Unger, 2005) and that HSE effects are relatively benign under moderate concentrations (Benson, 2005a). Economic offsets that may defray much or all of the CO 2 capture, transportation and storage costs are a possibility for geologic CO 2 storage venues other than saline aquifers.
Table 1. Estimated global geological CO 2 storage capacity (after Gale, 2004)
Global Capacity: Gt CO 2 % Emissions to 2050 Storage Option - Depleted Oil & Gas Fields 920 45 - Deep Saline Aquifers 400-10000 20-500 - Unmineable Coal Seams 20 <2
112
Fig. 1 Principal venues for geological storage of CO 2 (CO2 Capture Project)
Information Sources
An increasing number of public and private organizations actively assess the science and technology of CO 2 geological storage. These include governments of Canada, Norway, UK, Netherlands, EU, Japan, Australia and the US; government-industry-academic consortia such as the Australian Cooperative Centre for CO 2 (CO2CRC), Canadian IEA Weyburn Project, US DOE Regional Partnerships, the CO 2 Capture Project (CCP) and others. The UK-based International Energy Agency Greenhouse Gas (IEA GHG) program is an industry research consortium that has developed an extensive database on CO 2 capture and storage research, development and field projects. CO2NET is a “thematic” network serving to integrate results from various EU-based CO 2 capture and storage projects. Review articles on geologic CO 2 sequestration (hereafter referred to as CO 2 storage) include Gale (2004) and Benson (2005b).
CO 2 Storage Technology
A convenient organizational scheme for CO 2 storage technology focus areas is a follows (Benson, 2005b; Imbus, 2005):
“Integrity” – Includes elements of the natural (reservoir, caprocks, overburden, faults, etc.) and engineered (wells) system that may impact effective CO 2 containment. Natural (CO 2 and natural gas reservoirs) and industry (natural gas storage, acid gas injection, enhanced oil and gas recovery) analogs examples are particularly instructive (Oldenburg, 2005).
“Optimization” – Leverage well-understood industry practices to improve CO 2 flood performance and economics including offsets through enhanced oil or gas recovery (Maas, 2005).
“Monitoring” – Various methods are applied to observe the flood process and detect leakage. Monitoring also has a role in “verification” of CO 2 amount stored and projection of long-term containment (Hoversten, 2005).
113 Risk Assessment – Refers to methods to predict security of CO 2 storage given site specific data and contingency planning for intervention and remediation in the event of an untoward event (e.g., leakage) (Benson, 2005c).
The technical and economic success of a CO 2 capture and storage projects is impacted by capture technology employed, the purity of CO 2 received from the capture process, mode and distance of CO 2 transportation from the CO 2 capture facility to the CO 2 storage field and national, regional and local economic and policy incentives. These issues are addressed in several articles appearing in the recently released CO 2 Capture Project (CCP) technical volume (Thomas and Benson, 2005).
2.4.1 CO 2 STORAGE PROJECTS – CURRENTLY OPERATING AT THE COMMERCIAL SCALE
Although there are numerous R&D programs addressing various aspects of CO 2 storage, the number of proposed, planned and operating field projects is relatively limited (see IEA GHG database at http://co2captureandstorage.info/co2db.php4 ). Of these, only a few are or will be associated with a commercial operation. The commercial projects are outlined below in detail proportional to information available whereas pilot and demonstration projects 2 will be reviewed in terms of major project objectives. CO 2 injection projects for enhanced oil or gas recovery which do not have a specifically designated CO 2 storage component are not considered.
Sleipner Saline Aquifer, Norwegian North Sea
Sleipner, operated by Statoil in the Norwegian sector of the North Sea, was the first “purpose- built” CO 2 storage facility. Since 1996, approximately 1.0 MM tonne CO 2 / year has been separated offshore from the CO 2-rich natural gas produced from the Seipner Vest Field and injected into the 800-1000m deep, Utsira Sand saline aquifer. Disposal of CO 2 in this manner was considered economically-viable given the carbon tax liability and the lack of area reservoirs for enhanced oil recovery. The Mio-Pliocene Utsira Sand is a regional deposit of rift sediments occupying up to 400km in the north south direction and 50-100 km in the east-west direction with an area of 261000 km 2 with highly variable thickness (Chadwick et al. 2004). It is comprised of highly porous (up to 42%) and permeable (2.0 D) sand units separated by thin (~1m) shales at approximately 30m intervals. Near the top of the formation is a ~6.5 meter sand succeeded by a “sand wedge” and then thick regional seals. Predicted capillary entry pressure for the cap rock succession is 2.5 to 5 MPa which is considered capable of supporting a CO 2 column of several hundred meters.
The Sleipner project is distinguished by its comprehensive and highly successful time lapse 3D seismic monitoring program (Chadwick, et al., 2004; Arts et al., 2004a). The density contrast between supercritical CO 2 injected and the high density saline aquifer makes CO 2 buoyant and easily detectable via seismic. Thin inter-formational shales act as temporary traps or “baffles” to slow upward movement of CO 2 thus allowing lateral migration and more opportunity for CO 2 to dissolve in water (Johnson et al., 2004). These shale intervals were not evident on the pre-injection 1994 survey and thus were “illuminated” by CO 2 injection. Differences between the initial (1994) versus repeat (1999 and 2001) seismic images are clear. Features include a “pushdown” of the base Utsira reflector due to velocity changes caused by CO 2 presence, an apparent “chimney” indicating a vertical conduit for CO 2 migration and evidence for lateral growth of the plume with time. Although quantitative modeling of the seismic data is problematic due to poorly constrained reservoir and fluid properties, signals proportional to the known amount injected are considered “mappable”.
The most recent repeat seismic survey (2002) was interpreted by Arts et al. (2004b). The narrow time interval since that last survey in 2001 (8 months), and thus smaller CO 2 injection quantity, afforded the opportunity to observe subtle changes with time. It is hypothesized that the plume steadily flowed upwards until 2001 and then spread laterally, especially in the middle and upper parts of the reservoir. The observed amplitude anomalies above the reservoir could indicate leakage
2 CO 2 storage pilot and demonstration projects are defined here as “limited injection for the purpose of evaluating specific technologies such as monitoring tools” and “larger scale injection aimed at validating the geologic and engineering system”, respectively.
114 although none were significantly above background noise. It is proposed that seismic resolution is one meter or less within the CO 2-charged Utsira Formation which is sufficient to detect migration to shallower stratigraphic units.
Reservoir simulation is used to predict the long-term migration route and extent of the plume after 20 years of injection totaling 20 MM tonnes (Zweigel et al., 2004). A preliminary simulation that omitted shale partings suggested that the plume would migrate between sands and extend approximately 12 km to the west or northwest which would avoid possible encroachment at the margin of the seal. For the more complex case, which includes the shale partings, migration would be limited to the Utsira sand with accumulation expected in structural traps 2.9-5.2 km from the injection point. The CO 2 injected would only occupy 0.12-0.15% of available Utsira pore space given that there is only one injection well and that structural trapping will prevail.
Torp and Brown (2004) provide information on costs associated with CO 2 storage at Sleipner. These costs, which are incremental to processing produced gas to meet export specifications, include pre-injection characterization (seismic, logging, coring and simulation) totaling ~$2MM, compressors $79MM and the injection well $15MM. Ongoing operations (~$7MM/year) equate to ~$7 tonne stored / year. Initial evaluation and capital costs plus operating costs over 20 years would amount to $236MM. This is substantially below the $1.1B CO 2 tax liability (assuming the initial $55/tonne rate) that would be paid without CO 2 storage.
The success of the Sleipner project has lent considerable credibility to CO 2 storage as an approach to carbon mitigation. This is despite the fact that the Utsira Sand is not an ideal setting for CO 2 storage given the risk of CO 2 phase transition near the (relatively shallow) top of the unit, apparent rapid upward migration of CO 2 through highly porous and permeable rocks (in part offset by intra-formational shale baffles) and possibly limited solubility of CO 2 in highly saline water.
Weyburn EOR, Saskatchewan, Canada
The IEA Weyburn Project was formed in late 2000 around a new CO 2 EOR operation at EnCana’s Weyburn Field on the northern flank of the Williston Basin, southeast Saskatchewan. The 180 km 2 oil field was discovered in 1954 and has since been producing sour, medium gravity oil from the Mississippian Midale beds. The Midale beds include the low permeability “Marly” zone chalky dolomite and the underlying fractured, permeable limestone “Vuggy” zone. The field was waterflooded beginning in 1964 and drilling of horizontal wells began in 1991. The first phase of CO 2 EOR began in 2000 with injection 5000 tonne/day (95mmscfd) of 95% pure CO 2.
The significance of the project for CO 2 storage is considerable as anthropogenic CO 2 was piped 320 km from the Dakota Gasification Plant in Beulah ND, economic performance was a “given” and the most diverse, comprehensive technical program to date was applied. Given that some 22 research organizations from Canada, the US and Europe participated in the technical assessment, numerous presentations and technical papers are available. A more concise compilation of project results, which ended in 2004, were issued in a single volume (Wilson and Monea, eds., 2004).
The overall objective of the CO 2 storage research effort was “…to predict and verify the ability of an oil reservoir to securely store and economically contain CO 2.” Technical studies were aimed at documenting CO 2 behavior in the subsurface including trapping mechanisms such that these findings could be applied to site selection and monitoring of future CO 2 storage sites. Assessing economic realities such as prediction of the economic limits of CO 2 storage in both CO 2 EOR and saline aquifer venues was a secondary objective. The ultimate deliverable of the project was “…a credible assessment of the permanent containment of injected CO 2 as determined by formal risk analysis techniques, including long-term predictive reservoir simulations.”
Whittaker et al. (2004) outline the geological characterization effort for the Weyburn Project. Structural, stratigraphic and hydrogeological studies indicate that the local geologic system is well- suited for CO 2 storage. Seals immediately above the Midale beds are generally good and continuous and multiple aquitards are present in the shallower sedimentary sequence. Midale hydrodynamic conditions are optimal as lateral water movement is slow and there is no evidence for significant vertical flow. Should CO 2 escape above the Midale beds, the more active hydrodynamic regime
115 would allow for rapid CO 2 dissolution in water. Downdip flow, evident in portions of the study, could serve to form a hydrodynamic seal to CO 2 migration. The intracratonic Williston Basin is tectonically tranquil, limiting seismic initiators of fluid transfer between sedimentary units. There is no substantial evidence for vertical movement of fluids along faults or fractured units. Gaps noted in the study include more detailed analysis to confirm seal competence and instrumentation to detect vertical movement of fluid.
Prediction, monitoring and verification of CO 2 movements in the Weyburn unit is summarized by White et al. (2004). In general, seismic and geochemical applications demonstrated the status of physical and chemical responses to CO 2 injection. Using reservoir fluid properties, log-based synthetic seismic and reservoir simulation - production history matching (with seismic constraints), it was concluded that P-wave time lapse seismic monitoring is sensitive to presence of CO 2 at the 5- 10% saturation level with pressure effects playing a secondary role. Volume analysis of seismic data suggests a mean 20% CO 2 saturation in the reservoir. The CO 2 saturation between the Vuggy and Marly intervals is not resolved using seismic although there is an indication of vertical changes in saturation. The seismic data suggests that no more than 2-3% if injected CO 2 has migrated above the reservoir although there is no supporting data, including soil gas anomalies to support this contention. Seismic-based calibration of reservoir simulations is thought to be particularly effective in predicting future CO 2 migration. The geochemical data show a very clear succession of fluid perturbations related to CO 2 injection including CO 2 dissolution (6-10 months) and dissolution of reservoir carbonates (20 months). Silicate dissolution reactions, which are required for permanent storage of CO 2 via precipitation of carbonates, were not observed. Stable isotopic data for carbonate species was found to be particularly useful in documenting CO 2 distribution owing to the marked carbon isotopic contrast between native and injected gas. Among the issues requiring further work include assessing the influence of fluid mixing and CO 2 state on seismic properties, confirming seismic indications of CO 2 migration along higher permeability zones such as fractures, establishing geochemical and isotopic mass balance and reaction status to assess storage mechanisms and rates.
The study on CO 2 storage capacity and distribution predictions and application of economic limits is summarized by Law et al. (2004). Analysis of oil samples indicated that the CO 2-oil system is miscible or near-miscible. A PVT model developed from oil analyses is capable of predicting the equilibrium phase behavior of oil-CO 2 used in reservoir simulation, which in turn, has been used to predict CO 2 storage capacity in the Weyburn reservoir. A preliminary assessment of the amount of CO 2 stored in soluble (22.65MMT), ionic (0.25MMT) and mineral (22.25MMT) forms for a total of 45.15MMT is estimated over the long-term (5000 years). The economic limits of CO 2 storage over a range of carbon prices was developed and tested. Further work aimed at improving the models include more detailed analysis of production fluids, accounting for dynamic CO 2 flow and coupling of reservoir and geochemical models. Extension of CO 2 capacity calculations to aquifers surrounding the Weyburn unit are considered a means to make geologic CO 2 storage more attractive to operators lacking access to oil and gas fields. In addition to the PVT and storage / economic work, techniques aimed at improving fluid conformance in the reservoir were developed and modeled. Simulation of a gel-based treatment predicted substantial improvement of volumetric sweep. Further development and deployment of such agents and long term monitoring of performance is recommended.
Long-term risk assessment of the storage site is reviewed by Chalaturnyk et al. (2004). An initial performance assessment was used to map long term fate of CO 2 and identify containment risks from the Weyburn CO 2 EOR process over a 5000 year time interval. Deterministic and stochastic simulations were applied to CO 2 in the geosphere and wells (respectively). After 5000 years, it is predicted that cumulatively, 26.8% of CO 2 in place will migrate out of the EOR area (18.2% below, 8.6% laterally and 0.02% above). Only 0.001% CO 2 in place is predicted to migrate through wells (n=1000) over this time period. The separate probabilistic assessment over 75 EOR patterns gave similar results for reservoir-well system with 0.2% of CO 2 released to the biosphere and 16% to the neighboring geosphere for a net containment within the geosphere of 98.7 to 99.5%. Wellbore cement degradation (via sulfate attack, mechanical fatigue and leaching) models are expected to result in permeabilities of 10 -4 D for most well types installed over the field’s history. The integrity of the bounding geological seals is considered exceptional with high geomechanical strength and low permeability (10 -7 to10 -8 D). Additional work is suggested on diverse areas relating to validity of upscaling models, detailed characterization of well systems, caprock topography, integrity of overlying
116 aquitards, performance of specific containment elements (e.g., seals, faults, salt dissolution), fluid conductance of faults and alternative CO 2 migration scenarios. The four year Weyburn CO 2 storage study owed its success to establishing clear objectives, innovative management of the projects and the efforts of dedicated researchers. The comprehensiveness and partial redundancy of the study was reflected in its $CDN16.4MM budget. The data gathered and analyzed, however, will enable future CO 2 storage project operators to narrow the range and thus reduce the expense of necessary assessment, monitoring and risk assessment studies. Principal objectives of the Phase 2 Weyburn project aim to conduct technical work surrounding the CO 2 storage and EOR components that will enable production of a complete Design and Operating Manual aimed at site assessment, project design and field implementation of commercial CO 2 geological storage projects.
In Salah, Saline Aquifer, Central Algeria
The In Salah gas project, operated by BP, entails injecting ~1.0 MMTA CO 2 separated from high CO 2 gas reservoirs (5-10%) and injecting it into saline aquifers associated with the producing reservoirs. Injection via horizontal well into the clastic reservoir began in August 2004. Wright et al. (2005) summarizes technical aspects of the project and the expanding effort to develop R&D programs around the project.
The injection target is 20 m thick and averages 20 mD permeability. Geosteering during drilling was used to locate the higher permeability zones and the formation was tested for injectivity. The reservoir is ideal for CO 2 containment as there are no significant faults and the reservoir is overlain by a thick (900 m) mudstone sequence. There is an obvious issue, however, with the possibility that the CO 2 will migrate into the producing horizon. Although this eventuality is not considered a near term problem based on reservoir simulations, it may at some point result in an increase in gas processing costs. There is also the possibility that this may provide a possible mechanism for enhanced gas recovery.
Whereas the In Salah gas production operation is a commercial undertaking, there remains the possibility that the CO 2 storage part of the project may establish a “clean development mechanism” (CDM) suitable for obtaining carbon credits. The formation of a $30MM joint industry project (JIP) around the project has three primary objectives:
1. Provide assurance that secure geological storage of CO 2 can be cost-effectively verified and that long-term assurance can be provided by short-term monitoring. 2. Demonstrate to stakeholders that industrial scale geological storage of CO 2 is a viable GHG mitigation option. 3. Set precedents for the regulation and verification of the geological storage of CO 2 allowing eligibility got GHG credits.
Technical plans for the JIP include system characterization (3D seismic, well logs, reservoir and caprock core analysis, fluids analysis), performance and risk prediction (system and semi-regional model building, risk analysis) and monitoring for migration out of target (4D seismic, gravity, electrical; tracers, deep and shallow observation wells), in shallow intervals and to the surface (soil gas, spectroscopy, meteorology, microbiology), through the seal (geomechanical monitoring and geochemistry) and along the well bore.
2.4.2 CO 2 STORAGE PROJECTS – PLANNED OPERATION AT THE COMMERCIAL SCALE
Public information on planned commercial scale CO 2 storage projects are generally limited owing to confidentiality issues. The summaries below therefore are largely derived from websites, conference proceedings, etc.
K12-B, Depleted Gas Field, Dutch North Sea
The K12-B field located offshore of the Netherlands is a nearly depleted gas accumulation in the Upper Slochteren Member of the Rotliegend sandstone containing about 13% CO 2. Since
117 beginning production in 1985, CO 2 separated from natural gas to meet export specifications was vented to the atmosphere. Gaz de France, through a financial arrangement with the EU and Novem (Netherlands Environmental Agency) and technical assistance from TNO (Geological Survey of the Netherlands) has launched a three phase program to inject CO 2 into K12-B depleted gas reservoirs. As summarized by van der Meer et al. (2004) and Kreft and van der Meer (2005) the three phases comprise:
1. Feasibility study – of CO 2 injection using geological information and optimizing existing infrastructure (completed). 2. Demonstration of CO 2 injection - using a small-scale operational test facility and injection at a rate of 20 K tonne / year (completed). 3. Scale up to full scale injection – with an expected rate of 310-475K tonne/year.
The K12-B project was the world’s first to inject CO 2 back into the reservoir from which it originated.
The phase 2 work involved two tests. The first (May-December 2004) involved testing of the injection facility, proving that injection is feasible and safe and examining the CO 2 phase behavior and reservoir response. The results were used to optimize the measurement program of test (started February 2005) which had as its objectives to assess the reservoir response in a reservoir block that is currently under production, potential for enhanced gas recovery and degree of corrosion along the CO 2 injection well tubing. Test 1 was considered successful and several useful parameters including injection rate (average 29,200 Nm3 / day; cumulative 9000 K tonne) and pressure and temperature data profiles. Preliminary results from Test 1 correlate generally correlate well with the reservoir simulation predictions in that CO 2 remained in the gas phase and the pressure of the CO 2 increased by about 9 bar. These parameters, however, may not necessarily be extrapolated to supercritical CO 2 behavior. A regular pressure increase at reservoir depth was found not be consistent with observed surface temperatures, possible a result of CO 2 impurities (2-6% methane). Injectivity is considered good considering the low permeability of the reservoir rock. Results of test 2 will become available in late 2005.
It appears that the phase 3 program is not fully defined at present. Given that K12-B gas will be fully depleted in 2006, significant infrastructure may have to be developed for the reservoir to receive CO 2 from neighboring fields or land-based anthropogenic sources. It would be of interest to determine if the life of the field could be extended via CO 2 enhanced gas recovery.
Snohvit, Saline Aquifer, Barents Sea
Information on Statoil’s Snohvit project is largely restricted to the IEA GHG project database and Statoil’s website ( www.statoil.com/snohvit ). The Snohvit project entails producing CO 2-rich (~5- 8%) gas from a 2600m deep reservoir, piping the gas stream to land (160 km), separating CO 2 from natural gas (the latter of which is exported as LNG), piping purified CO 2 to the field and injecting it into the Tubasen sandstone which is beneath the producing reservoir but separated from it by impervious strata. Once the project is fully operational in 2006, 0.7MM tonne / year will be injected.
Gorgon
The Greater Gorgon Area, offshore Northwest Australia, includes several gas fields with variable CO 2 content. Chevron is the project operator ( www.gorgon.com.au ) with partners Shell and Exonmobil. The current Greater Gorgon Development scenario includes sub sea gathering and piping of gas from the Gorgon Gas Field (9.6 Tcf with ~14% CO 2) to Barrow Island (~70 km) for gas processing to remove CO 2 for LNG export (2x5 MM tonne/ year trains + 300TJ/d compressed domestic gas). Gas production from the further outboard Jansz Field (trace CO 2) will be phased into using this infrastructure. The Greater Gorgon greenhouse gas management plans to reduce greenhouse emissions from the project from 6.7 to 4.0 MM tonne / year CO 2 equivalent through process efficiencies and injection into the subsurface. The project is expected to become operational in 2010.
Most of the CO 2 separated from the Gorgon Gas will be injected into the Dupuy Formation, a low permeability silt and sandstone >2000 m beneath Barrow Island. The current plan is injection into
118 multiple, deviated wells from two or more injection sites. The number, location and timing of observation wells is under consideration. East-central Barrow Island is the preferred injection site as it coincides with developing infrastructure for the gas processing plant and there appear to be few significant faults present. Given Barrow Island’s status as a “Class A Nature Reserve”, stringent regulatory safeguards can be expected in field development, operations and monitoring activities.
2.4.3 SELECTED CO 2 STORAGE PILOT AND DEMONSTRATION PROJECTS
Depleted Gas & Oil Fields
Casablanca – The Casablanca Field, operated by Repsol, is a declining oil field offshore northeastern Spain. The carbonate reservoir is at 2500 m depth. Up to 0.5MM tonne CO 2 / year from a refinery 43 km from the field may be stored in the reservoir. It is uncertain whether or not use of CO 2 as a tertiary oil recovery agent is not planned. www.co2castor.com
Lindbach – The Linbach Field is a depleted gas field in north central Austria operated by Rohoel. The sandstone reservoir is 850 m deep. Enhanced gas recovery by CO 2 is considered by the operator. www.co2castor.com
Saline Aquifers
Frio Brine – The Frio pilot, operated by the Texas Bureau of Economic Geology (BEG), involved injecting 1600 tonne CO 2 into a 1600 m deep clastic aquifer. The project was notable for its extensive geophysical and geochemical monitoring program which successfully documented CO 2 passage from the injection well to the observation well 30 m away (Hovorka et al., 2005). A “Frio 2” pilot is planned for 2006. This will include follow-up work on the original Frio pilot (e.g., water chemistry) and injection into a deeper sandstone with a monitoring porgarm focused on ground water, vadose zone, soil and atmosphere. ( http://www.beg.utexas.edu/news-events/friologarkiv01.htm )
Ketzin – The Ketzin site, located west of Berlin, was a shallow (250-400m) natural gas storage site in the 1960s. CO 2 injection of up to 30000 tonnes (possibly from a renewable fuel source) is planned for a period of three years at a depth of 700m. The program includes extensive evaluation of the reservoir and cap rock system, 3D and borehole seismic surveys and downhole instrumentation. ( http://www.gfz-potsdam.de/pb5/pb51/projects/project-CO2SINK/content_en.html ).
Australia – The CO2CRC, a public-private collaboration dedicated to geologic CO 2 storage, is presently evaluating pilot project opportunities in central Queensland, the Perth Basin or the onshore Otway Basin. This pilot selected will be integrated to include CO 2 capture, transportation and storage with application of monitoring technologies ( www.co2crc.com.au ).
Coal
Recopol – Recopol, or “Reduction CO 2 Emissions by way of CO 2 storage in coal seams in the Silesian Coal Basin of Poland” is coordinated by TNO. Injection of up to 1000 tonne CO 2 began in late 2004. Testing injectivity and enhanced coal bed methane production are key objectives of the study. A monitoring plan, including cross well seismic and production gas analysis is in place. (http://recopol.nitg.tno.nl/index.shtml )
Alberta – A multiphase program to test coal suitability for CO 2 storage has been coordinated by the Alberta Research Council (ARC): I – Initial assessment and feasibility of injecting CO 2, N 2 and flue gases into the Mannville Coal (completed 1997), II – Design and implementation of a CO 2 micropilot (completed 1999), III – Design and implementation of a flue gas (CO 2+N 2) micropilot (completed 2002) and IV – Design and Implementation of a full scale pilot (2003-2005). The last phase will include studies aimed at matching coal physico-chemical property changes and enhanced recovery economics. Parallel piloting and eventually commercial activities are also applied in the Qinshui basin of China. In addition, the CSEMP pilot program, operated by Suncor, entails injecting CO 2 into the Ardley coal for 18 months with technical assessment of mixed gas effects, reservoir monitoring and verification ( www.arc.ab.ca/energy/Coalbed_pilot.asp ).
119 Other Projects
In addition to the pilot and storage demonstration projects outlined above a number of such projects are expected to be undertaken by 2009 through the US DOE Regional Partnerships Program. Litynski (2004) outlines the phased approach to the program: I (2003-2005) – Characterization, II (2005-2009), Field Validation Tests and III (2009-2013) – Significance to FutureGen (US DOE incentive to develop a carbon-free IGCC power plant with geologic sequestration. Early insights into potential storage projects include (note: individual papers available from Proceedings of the Fourth Annual Conference on Carbon Capture and Sequestration. Alexandria, VA, May 2-5, 2005. CD Available from Monitor Scientific [ www.carbonsq.com ]):
Plains (Steadman, 2004) – acid gas injection into deep carbonates and lignite CO 2 ECBM
Midwest (Ball, 2004) – CO 2 injection into saline aquifers and feasibility of organic-rich shales
WestCarb (Myer, 2004) – CO 2 Injection into saline aquifer and depleted oil (Rio Vista) and gas (Ventura) field
Southwest (McPherson, 2004) – CO 2 injection for ECBM (San Juan Basin) and EOR (Permian Basin); Saline aquifer (Paradox Basin)
Big Sky (Capalbo, 2004) – CO 2 injection into deep carbonate aquifer (develop alkalinity), ECBM and Basalt
Midwest-Illinois Basin (Finlay, 2004) – Up to six field tests in saline aquifers, depleted oil fields for EOR and ECBM
Southeast (Hill, 2004) – CO2 injection for EOR and ECBM
The projects outlined above are by no means exhaustive. A number of additional pilot / demonstration projects are at the concept stage in Europe, Japan, China and Australia.
2.4.4 SUMMARY AND CONCLUSIONS: CURRENT STATUS AND NEEDS TO PROGRESS GEOLOGIC STORAGE
Geological storage is considered one of the promising approaches to large scale CO 2 sequestration given its “technology ready” status from decades of relevant industry experience, potential for long term security and potential for economic offsets to capture and transportation costs. Despite these advantages, however, there remain critical issues to be addressed to satisfy stakeholders on permanence and HSE issues. A number of these issues have been outlined by Gale (2004), Benson (2005b) and Imbus and Christopher (2005). Common themes can be expressed as follows:
Geologic and Engineered Systems – Site assessment based on 3D structural-stratigraphic framework and fluid migration history is essential in the selection of suitable sequestration “systems”. This is particularly true of saline aquifer systems as relevant geological data is typically limited. In any storage venue, an understanding of subsurface processes that act to increasingly immobilize (e.g., dissolution, permeability trapping) CO 2 over the long term versus those features (e.g., inadequate seals, faults) that threaten storage security in the short term need to be modeled. To the extent that flood performance can be predicted over the long term via history matching of reservoir simulations, will establish “success criteria” to justify eventual field abandonment and transfer of liability. The issue of well stability in the presence of carbonated water has become a central issue in geological CO 2 storage, particularly in fields and basins where 100s to 1000s exist in varying condition (Scherer et al., 2005). Innovations in well design and materials are important but less expensive approaches to rehabilitating old wells or contingencies for well remediation need to be developed.
Process Optimization – As part of a given value chain under various incentive regimes, CO 2 storage may be a major (e.g., deep or difficult venues) or minor (e.g., gas processing) expense or even a revenue generating operation. In any scenario there is an ever present demand for cost
120 effectiveness. Flood performance is controlled by reservoir and fluid properties but may be optimized through innovative well configurations that maximize injectivity whilst moderating buoyant flow of CO 2 (e.g., Kumar et al., 2005). Economic offsets in the form of hydrocarbon recovery entail assessment of economic limits for production versus storage in the case of EOR operations and understanding of complex CO 2 interactions with coal (adsorption and swelling). The ability of a storage operation to accept significant levels of CO 2 impurities such as N 2, H 2S or hydrocarbons will improve capture economics. Transportation between capture and storage sites is a major issue where long pipelines and / or offshore facilities are needed.
Monitoring and Verification – A variety of monitoring tools applied from multiple vantage points are available or in development to assess flood performance and leakage out of target or seepage to the surface. Where feasible, the preferred option for monitoring CO 2 movement is time lapse 3D seismic. This approach can cover a wide area but may be infeasible in some areas and can be prohibitively expensive. Observation wells equipped with sampling capability or sensors yield accurate information on fluid status and thus an opportunity to calibrate reservoir simulation but these are also expensive and introduce an additional conduit of CO 2 migration. Generic concepts for “basic” and “enhanced” (Benson et al., 2004) and risk-based monitoring (Chalaturnyk and Gunter, 2004) schemes have been proposed. With cost discounting, monitoring budgets may appear as a trivial portion of commercial CO 2 storage project (e.g., < $0.20 / tonne stored; Benson et al., 2004), although upfront and early operational costs can be a barrier to project deployment. Because few precedents exist and every potential site is unique, it is difficult to assess the scope and longevity of monitoring projects. Aside from the storage security issue, monitoring becomes particularly critical as a verification tool to justify project abandonment and awarding of carbon credits. A “monitoring network” platform, organized by the IEA GHG, has begun addressing these issues. Given the relative inexperience of monitoring CO 2 storage projects (little precedence is available from the decades long EOR experience as monitoring for CO 2 was not a regulatory requirement), there may be pressure from stakeholders to establish elaborate monitoring systems. An alternative to the financial and logistical burdens of this approach could be deployment of a “reactive” monitoring strategy where untoward results in the initial program (e.g., 3D seismic) would trigger supplements to the forward monitoring program (e.g., addition of a seismic survey or observation well).
Risk Assessment – Risk assessment is a high profile element of CO 2 storage project assessment and key to gaining stakeholder approval. Principal risk considerations are those to people, resources (potable aquifers, economic deposits), ecosystems and the atmosphere. Although considerable work has been done by the Weyburn, CCP and GEODISC (CO2CRC predecessor) projects, risk assessment protocols and their implications are difficult to communicate to critical target audiences. Forward progress can be made by standardization of site specific features, events and processes (FEPs), benchmarking of independently developed protocols and bracketing risk relative to familiar hazards, including the risk to global climate for not effectively addressing CO 2 mitigation.
The technical assurance aspects of geological CO 2 storage appear less formidable than either technology challenges of cost-effective CO 2 capture and transportation or implementation of enabling financial and tax incentives. The cost and risk associated with geological CO 2 capture and storage must be weighed against those of other mitigation approaches (e.g., aggressive efficiency measures, renewables and nuclear energy).
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Whittaker, S., Rostron, B., Khan, D., Hajnal, Z., Qing., H., Penner, L., Maathius, H. and Goussev, S. (2004) Theme 1: Geological Characterization. In (M. Wilson and M. Monea, eds.) IEA GHG Weyburn th CO 2 Monitoring & Storage Project Summary Report 2000-2004. Proceedings of the 7 International Conference on Greenhouse Gas Control Technologies. Vancouver, Sept. 5-9, 2004., p. 15-69.
Wilson, M. and Monea, M., eds. (2004) IEA GHG Weyburn CO 2 Monitoring & Storage Project Summary Report 2000-2004. Proceedings of the 7 th International Conference on Greenhouse Gas Control Technologies. Vancouver, Sept. 5-9, 2004. (http://www.ptrc.ca/access/DesktopDefault.aspx?tabindex=8&tabid=81 )
World Business Council on Sustainable Development (2004), Facts and Trends to 2050: Energy and Climate Change. See web site: http://wbcsd.org/DocRoot/gt3V48ILBCnHPpl68ljp/Basic-Facts- Trends-2050.pdf
Wright., I.W., Keddam, M. and Ingsoy, P. (2005) In Salah Gas: Carbon dioxide storage assurance project, Report on year 1. Proceedings of the Fourth Annual Conference on Carbon Capture and Sequestration. Alexandria, VA, May 2-5, 2005. CD Available from Monitor Scientific. www.carbonsq.com
Zweigel, P., Arts, R., Lothe, A.E. and Lindeberg, E.B.G. (2004) Reservoir geology of the Utsira Formation at the first industrial-scale underground CO 2 storage site (Sleipner area, North Sea). In (S.J. Baines and R.H. Worden, eds.) Geological Storage of Carbon Dioxide. Geological Society Spec. Publ. 233, p 165-180.
124 2.5 THE COMMERCIAL DEVELOPMENT OF THE GAS-TO-LIQUIDS INDUSTRY
ABSTRACT
The conversion of natural gas into a liquid fuel has been an elusive objective for a long time. A number of avenues have been proposed, but one is emerging as the first commercially viable process: conversion into high quality products through low-temperature Fischer-Tropsch (LTFT) conversion.
This process is being commercialized in large, world-scale facilities. The first will start up in 2006 in Qatar, followed by another in 2008 in Nigeria. By 2015, there may well be around 800,000 barrels per day of high quality liquid products being made from natural gas.
The history of LTFT involves decades of development in South Africa, where high- temperature Fischer-Tropsch conversion helped serve the country’s entire fuel and chemicals demands for some time. LTFT emerged as a way to focus the process on fewer, higher valued products. The process developed from fixed bed reactors to slurry bed technology, to allow more economic scale-up. Finally, integration of all of the processes and simplification of the flow scheme led to today’s GTL process.
The economics of GTL as we know it today are robust down to low energy prices. This process now can compete successfully with liquefied natural gas (LNG) in some areas, depending on distance from market. The product qualities and their markets make an attractive value proposition for gas field developers. In addition, many countries see value in trying to attract GTL fuels, to capitalize on the environmental benefits of using these fuels.
In summary, the GTL industry is commercially viable today and significant investments will be made in this industry. The push from gas resource holders and the market pull for environmental gains are creating a strong value proposition for GTL. As the perspective for energy costs gets more and more bullish, GTL becomes even more attractive.
RESUME
La conversion du gaz naturel en combustibles liquides (GTL pour Gas to Liquids) a longtemps constitué un objectif difficile à atteindre. Une des nombreuses voies poursuivies est en train d’émerger en tant que procédé commercialement viable : la conversion Fischer-Tropsch basse température (FTBT) en produits de haute qualité.
Ce procédé est en cours d’implémentation sur des projets de taille mondiale. La production du premier projet démarrera en 2006 au Qatar et sera suivie d’un démarrage en 2008 au Nigeria. D’ici 2015, 130 000 m3/j (800 000 barils par jour) de produits liquides de haute qualité pourraient être produits à partir de gaz naturel.
L’histoire du procédé FTBT est marquée par des décennies de développement en Afrique du Sud dont la totalité de la demande en fuel et en produits de base pour l’industrie chimique a pu être fournie grâce à la conversion Fishcher-Tropsch haute température pendant un certain temps. FTBT a permis une focalisation sur des produits à plus grande valeur. Les réacteurs à lit fixe ont été abandonnés au profit des réacteurs de type « slurry » afin de permettre des économies d’échelle. L’intégration de l’ensemble des procédés élémentaires et la simplification des flux a conduit au prodédé GTL actuel.
Les résultats économiques du GTL sont aujourd’hui robustes à des niveaux bas des prix de l’énergie. Ce procédé peut concurrencer maintenant le gaz naturel liquéfié (GNL) dans certaines régions, en fonction de la distance au marché. Les qualités des produits et leurs marchés font du GTL une alternative attractive pour les détenteurs de ressources gazières. En outre, de nombreux pays voient un intérêt à favoriser les carburants issus du GTL pour tirer parti de leurs qualités en terme d’environnement.
125
En résumé, l’industrie du GTL est aujourd’hui commercialement viable et des investissements significatifs seront réalisés sur la base de ce procédé. Le développement du GTL sera poussé par la volonté des détenteurs de ressources gazières et tiré par le développement de marchés sensibles aux performances environnementales des produits. Le GTL sera d’autant plus attractif que la perspective de coûts élevés de l’énergie se confirmera.
126 INTRODUCTION
The conversion of natural gas into a liquid has been an elusive objective for a long time. Some parts of the produced gas – propane, butane, and the natural condensate, can be shipped as LPG or natural gasoline. If it is available in sufficient quantity, the ethane can be split out and converted into petrochemicals (ethylene and its derivatives). The big question has always been what to do with the methane. Natural Gas Value Chain
Natural Gas Products Gas-to-Liquids Products
LNG Ethylene Fuel C3 C2 100% 87% BTU Efficiency Lubricants Natural Gas C1 Fischer-Tropsch Naphtha C1, C2, C3, C4, C5+ Jet 100% 60% BTU Efficiency Diesel Olefins/Lubricants C5+ C4 Methanol Polymers Aromatics 100% 75% Gasoline BTU Efficiency Turbine Fuel
The chart shows the overall picture for natural gas monetization options. The methane, or C1, portion can be transported by pipeline or by liquefaction and shipping, or it can be chemically converted to a liquid as methanol or by using the Fischer-Tropsch reaction.
The LNG option refers to liquefying the natural gas so that it can be economically shipped over relatively long distances. At the other end, it is re-gasified. True, the LNG ships are relatively expensive and transportation is more costly than for conventional liquid products. However, LNG has found a place in moving gas from distant fields to gas markets.
Two of the routes, Fischer-Tropsch and methanol, rely on conversion of natural gas to syngas, a mixture of hydrogen and carbon monoxide. The syngas can then be made into other products. The chart below expands on this, showing the major pathways from syngas to products:
Options for Syngas
Existing Processes Processes Being Researched n IDW Lubricants Chevro hell Sasol, Shell, Exxon, FT Mobil, S Syntroleum, etc. Waxes/ Hydrocracking Transportation Syngas Liquids Chevron, Shell, Fuels CH 4 Various etc. Vendors CO/H 2 Gasoline Mobil MTG Various Process Commodity Methanol Various Chemicals & Processes Lubricants
MTO Various Mobil Process
C2/C 3 Olefins Turbine Fuel To date, the routes to fuels via methanol have not gained widespread commercial application. For example, methanol derivatives such as Dimethyl Ether (DME) have been proposed as substitutes for various fuels, but for the most part DME remains a solvent and refrigerant in spite of some promising project announcements.
127 So long as methanol remains primarily a petrochemical, its market size will limit its use as a gas conversion approach. Energy markets such as diesel, jet, or natural gas are inherently much larger scale than petrochemical markets and are thus more suitable to the gas available in a prolific gas province. A good example is Trinidad & Tobago, where methanol and ammonia production have made the country the world’s largest producer of these commodities, yet most of the volume of gas monetized is via LNG.
But a substantial part (about 20%) of world energy use is devoted to transportation, which creates most of the growth in energy use and remains persistently a market for liquid fuels. LNG can serve gas markets, driven mostly by industrial and power users. On the other hand, GTL serves a different purpose, allowing natural gas to take advantage of the growing transportation markets, using Fischer-Tropsch technology.
Until recently, GTL has been considered not ready for wide-scale commercial application. However, on the strength of the growing transportation markets, the desire to monetize the large reserves of gas in the world, and steady advances in the technology, GTL has emerged as the first commercially viable process to convert large amounts of natural gas into liquid fuels. This process incorporates a reforming step to produce synthesis gas (hydrogen and carbon monoxide), a low- temperature Fischer-Tropsch step to convert the synthesis gas into long hydrocarbon chains, and a hydrocracking-isomerizing step to convert these chains into valuable commercial products. The first large commercial plant using this technology will be starting up next year. This paper deals with the conditions that are leading to the development of the GTL industry.
2.5.1 GROWTH OF THE GTL INDUSTRY
The process of GTL is being commercialized in large, world-scale facilities. These require large gas reserves, on the order of several TCF of gas. Let’s look at the math.
World-scale plants are starting around 35,000 barrels per day of liquid product, growing quickly to 70,000 and 80,000 barrels per day. The ORYX GTL project in Qatar is a case in point, with a greenfield first phase of 34,000 barrels per day and an expansion plant of 66,000 barrels per day. The Pearl project in Qatar is another, planned at two phases of 70,000 barrels per day. Each barrel of product takes around 283 cubic meters (10,000 SCF) of natural gas to produce, so the ORYX GTL project uses roughly 9.6 million cubic meters (340 million SCF) per day. Operating this plant for 30 years will require over 99 billion cubic meters (3.5 TCF) of gas.
In addition GTL plants, like other large onshore investments, benefit from taking advantage of brownfield expansion opportunities. Thus, a typical GTL site will tend over time to have multiple trains – a situation very reminiscent of the LNG industry. Thus, the best GTL sites will be coastal areas with 560 billion cubic meters (20 TCF) of gas or more. As the economics of the industry evolve this may change, as discussed in the ECONOMICS section below.
The ORYX GTL project, the first major commercial GTL plant, will start up in 2006. It will be followed in 2008 by another plant of equal size in Nigeria. By 2020, there may well be around 800,000 barrels per day of high quality liquid products being made from natural gas via the GTL process.
2.5.2 BRIEF HISTORY OF GTL
The heart of the GTL process is the Fischer-Tropsch process, discovered in 1923 by German coal researchers. It was used by the Axis powers to help them get by with less crude oil. Production peaked in 1944 with 16,000 barrels per day in Germany and 1,500 barrels per day in Japan.
In 1955, Sasol started a Fischer-Tropsch plant in South Africa to convert coal to liquids, leading in the 1980’s to the country’s independence from petroleum by gasifying coal. Early plants focused on the high-temperature (350° C) Fischer-Tr opsch process using an iron catalyst. While the majority of the installed capacity in South Africa was based on the high-temperature process, the low- temperature (250° C) process was also being develop ed since 1955. In 1990, Sasol built the first slurry bed low-temperature reactor, followed by a 2,500 barrel per day plant in 1993. The same year,
128 Shell Oil built a 12,000 barrel per day low-temperature Fischer-Tropsch plant in Bintulu, Malaysia, based on fixed bed tubular reactors.
The low-temperature Fischer-Tropsch (LTFT) technology is at the center of the GTL process being implemented today. The high-temperature version (HTFT) can provide a wide array of chemicals and hydrocarbons, but LTFT has the virtue of focusing on fewer, higher valued products. One of the decisions that led to commercialization of GTL technology was to focus on natural gas feed and LTFT, making the plants as streamlined and efficient as possible. In addition, as can be seen in the section on MARKETING, the LTFT products have enormous market potential.
2.5.3 THE GTL PROCESS
The GTL process consists of three principal steps:
CH 1. The first step is reforming the natural 4 gas into synthesis gas, which consists of Natural Gas carbon dioxide and hydrogen. The H2 Reforming simplest gear available to perform this natural step is the autothermal reformer. In this technology, a specialized burner allows syngas the methane to be partially combusted with oxygen and passed through a catalyst to form the synthesis gas, or oxyge syngas. O2 CO
2. The second step is conversion of the Fischer- synthesis gas into a waxy H2 Tropsch syncrude consisting of Conversion long hydrocarbon chains. This step applies the low- temperature Fischer- syngas waxy syncrude Tropsch reaction over a cobalt catalyst.
CO
3. The third step converts the waxy syncrude into valuable products. Some possible products are: Product a. Diesel – the Upgrading largest volume of production GTL expected from Diesel GTL plants. This waxy syncrude diesel has a cetane number GTL over 80, no naphtha aromatics, and no sulfur. With these qualities, it reduces tailpipe emissions compared to any other diesel.
129 b. Petrochemical Naphtha – the second largest product from GTL. The GTL Naphtha has no sulfur or aromatics, but due to its highly paraffinic nature it suffers both from a low octane and from not much octane gain in a naphtha reformer. On the other hand, it has an unusually high ethylene yield when fed to a cracker and tends to coke less in the cracker, thereby extending catalyst life. Ethylene crackers feeding paraffinic naphthas will find GTL Naphtha a superior alternative.
c. Lubricant Base Oils – using a catalytic wax conversion process such as Chevron’s Isodewaxing™ process, a portion of the waxy syncrude can be converted into ultra- high-quality lubricant base oils.
d. Waxes – taken directly out of the waxy syncrude, these can be commercially very valuable, although the markets are small.
2.5.4 THE MARKETS FOR GTL PRODUCTS
The markets served by GTL are generally quite large
As large as GTL projects are in capital investment terms, their production pales in comparison with most world markets they serve. As illustrated in the diagram, the production of GTL diesel from London bus fleet 1,750 bpd UK 380,000 bpd ORYX GTL Global 25,000 bpd automotive diesel Italy market 450,000 bpd EGTL 13,000,000 bpd 25,000 bpd
Germany 540,000 bpd Total GTL projects under development Europe 572,000 bpd 3,200,000 bpd France 610,000 bpd
one of the first plants is a small amount compared with the world market for diesel, or compared with the demand from a country in western Europe. In addition, even adding together all of the more probable project announcements so far only would produce a few percent of world diesel demand. It is apparent that GTL diesel may play an important role in improving diesel stocks and increasing supply, but will not supplant refinery diesel any time soon.
3.50%
3.00%
2.50%
2.00%
1.50%
1.00%
0.50%
0.00% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
GTL as % of World Diesel
130 The graph above shows the current plant announcements for GTL plants as a percent of the expected world diesel market. Even if all of these projects happen by 2015, they will supply less than 5 percent of the world diesel demand. As it is, the timing of these projects is for the most part uncertain.
Another way to picture how GTL diesel will fit into the market is to compare the annual projected growth in diesel demand to the projected annual growth of GTL diesel. In no year, even with the startup of major GTL projects, will the projected GTL diesel growth exceed the diesel market growth. When these projects actually start up, the impact at that time will be even less than shown.
70.00%
60.00%
50.00%
40.00%
30.00%
20.00%
10.00%
0.00% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
GTL Increase as % of Diesel Increase
The chart below illustrates the logic of focusing GTL production on diesel and naphtha. The markets for base oils and waxes have very attractive margins, but could easily be overwhelmed by GTL production. Ultimately, GTL projects will focus largely on diesel and naphtha. The opportunity in the diesel market is quite great, considering occurring and expected growth.
Achievable yield (%)
100
90
80 automotive diesel 13,500,000 bpd 70
60 jet fuel 50 5,000,000 bpd base oils waxes 40 petrochemical 780,000 bpd 42,000 bpd 30 naphtha 5,400,000 bpd 20
10 Value (USD per barrel) 0 0 20 40 60 80 (With oil price at USD 20 per bbl)
131 The market for GTL diesel
GTL diesel does not currently meet on-road diesel specifications in all markets. This will present a challenge for early producers. Given the large world market for diesel, the growth of that market, and the premium quality of GTL diesel, it is easy to imagine selling GTL diesel production at parity with road diesel in future years. The challenge for GTL diesel producers will be to recover a value for the extra quality of GTL diesel. This can come in three principal ways:
• Blending GTL diesel to make road diesel
GTL diesel can be blended with other hydrocarbon streams to make conventional road diesel. Some refinery intermediates have difficulty in meeting road diesel specifications, and may in some cases be used as cutter stock for fuel oil blending. If they can be upgraded from fuel oil value to road diesel value by blending with GTL diesel, this gives GTL diesel a premium value over conventional diesel that has a bearing on its quality. Diesel-range products such as heating oil (in the U.S.) or gasoil (in Europe) have lower values than road diesel and may be upgraded by blending with GTL diesel.
Because of the presence of a variety of intermediates which are typically blended into products in a blend pool, refineries are the ideal site for this type of GTL diesel use. In some cases, GTL diesel has been purchased by a trader, brought to a rented site and blended with other material to make a reformulated diesel, and sold for the reformulated price. However, this will likely be more the exception than the rule. In fact, the size of the markets would indicate that refinery blending into conventional products will likely be the largest-volume use for GTL diesel.
• Blending GTL diesel to make premium diesel
GTL diesel has the most premium qualities of any commercial diesel stock available. This makes it the ideal basis for a premium diesel product. Its cetane creates a performance enhancement that consumers are willing to pay for, plus its other qualities have environmental attributes that consumers prefer but generally will not pay for. In combination, it makes for an attractive offering in the market. Shell Oil has created premium diesel offerings in Thailand and Germany that illustrate the point.
The distinguishing characteristic of premium product offerings is that they offer attractive margins. A premium diesel based largely on GTL diesel can enhance the GTL diesel margin quite a bit more than blending to a conventional product.
• Using GTL diesel as an emission reduction strategy
In urban environments, vehicle fleets such as buses or trucks are frequently pressured or incentivized by the government to reduce vehicle emissions. Typically, diesel fleet owners will consider alternatives such as compressed natural gas or LPG. While these options reduce emissions of key pollutants, they require replacing vehicle engines, specialized fueling stations, and training of employees to be able to handle the new fuel safely. In addition, operating flexibility is impaired by having to refuel at dedicated stations.
In contrast, GTL diesel would allow such an operator to reduce emissions significantly without engine modifications. If a vehicle found it necessary to refuel outside of the indicated stations, it could do so without adverse effect. Naturally, this would reduce the overall emission reductions, but operations would not be impaired and emission reductions would still be verifiable by the amount of GTL diesel used by the fleet. The cost savings from this scheme would allow some additional value to be recovered for the quality of the GTL diesel and still be competitive with other alternatives.
• GTL diesel emission performance
The advantages of GTL diesel for emissions performance are widely mentioned. As an illustration, the chart below shows the tailpipe emission reductions for various pollutants. Note that
132 GTL diesel impacts emissions even when using low-sulfur fuel and advanced vehicles. In addition, the impacts affect both light-duty and heavy-duty vehicles, although to different degrees.
Light-Duty Vehicles Heavy-Duty Vehicles
90 EURO 1 90 80 EURO 2 80 70 EURO 3 70 60 EURO 4 60 EURO 4 w PF 50 50 40 40 30 30
PercentReduction 20 20 10 10 0 0 THC NOx PM CO CO2 THC NOx PM CO CO2
“Emission factors for the combustion of fuels in road vehicles”, IFEU Heidelberg, December 2004 – GTL Diesel compared with a low-sulphur reference fuel.
Another important property of GTL diesel with respect to emissions is that the benefits are non-linear. The chart at left is from passenger vehicle trials done by Sasol Chevron and Daimler Chrysler in 2004. Significant emission benefits are possible without using pure GTL diesel. This has led some such as the California Energy Commission to examine blends of GTL diesel, to optimize the cost-benefit for emission reduction.
GTL diesel greenhouse gas emissions
Finally, with respect to the environmental status of GTL diesel there has been much discussion around the impact of GTL diesel on greenhouse gas emissions. Life cycle analyses were independently commissioned by Shell, ConocoPhillips, and Sasol Chevron to evaluate the well-to- wheels impacts of GTL diesel compared to refinery diesel. All three studies, done according to the recommendations of the ISO14041 standard for studies of this type, came up with substantially the same conclusions:
1. Greenhouse Gas emissions from a GTL system are comparable to a refinery system. 2. The GTL system contributes to improved air quality by generating fewer local emissions than a refinery system. 3. The GTL system currently has a higher energy requirement to meet the same functions as a refinery system. However, GTL’s use of remote gas reserves extends the projected life span of crude oil reserves. 4. The GTL system generates less waste than conventional refining technologies.
133 The refinery is an efficient means to split crude oil into components and make on-spec products with minimal molecular rearrangement. However, it inevitably has to deal with the residuum, either by converting it to petroleum coke or by blending it into residual fuel oil. The GTL plant does not have a 100 percent yield of useful products, with some 35 percent or so of the feed natural gas being emitted as waste carbon dioxide. Because of this, there is a trade-off between the carbon not converted to useful product by the GTL plant and the carbon emissions due to the fact that the refinery needs to make a lot more in order to produce an incremental unit of diesel.
120000 100% 93% 100000 Electricity Generation 80000 Petrochemicals Space Heating 60000 Air Transport 40000 HD Road Transport
tonnes eq. CO2/d eq. tonnes 20000 LD Road Transport 0 Refinery GTL Ref: 180,000 bbl/d Refinery
Source: “Use of a Life Cycle Approach to Compare the Environmental Implications of Sasol’s Slurry Phase Distillate Technology with Alternative Processes producing Transportation Fuels”, Price Waterhouse Coopers, 13 November 2002.
The graphic above shows some advantage for GTL diesel over refinery diesel. While this was true in a base case studied, the overarching conclusion of the study was that in view of the uncertainties in the analysis it was most correct to characterize the greenhouse gas emissions as comparable.
The market for GTL Naphtha
Ethylene is made primarily in crackers, where ethane or naphtha are reacted over a catalyst to produce ethylene. Some byproducts such as propylene and butylene are inevitable, especially when feeding naphtha, but the ethylene is the preferred product and has a very large market in the making of plastics.
In the world of petrochemical naphthas, paraffin content is the most desirable, for its high selectivity towards ethylene production. A typical naphtha may have about 65 to 75 percent paraffins and the most premium product available today, Saudi A-180, has about 92 percent paraffins. GTL diesel is about 98 percent paraffins. In addition to this very desirable quality, the absence of sulfur and aromatics makes GTL diesel better in reducing the production of coke within the cracker. Since coke build-up is typically the limitation on catalyst run life, GTL diesel will likely increase cracker operating time by reducing catalyst turnarounds.
The market for GTL Lubricant Base Oils
The process to convert waxes in lubricant oil streams into high-quality lubricant materials was commercialized in the early 1990’s. First applied commercially by Chevron at the refinery in Richmond, California, this process has the capacity to produce very high quality lubricants if fed a waxy feed stream. Operation with a Fischer-Tropsch waxy syncrude is a very special case of this.
134 In combination with a GTL plant, the catalytic wax isomerization process produces lubricant base oils of the highest quality. These base oils are similar in quality to the synthetic base oils consisting of polyalphaolefins (PAO’s). However, their production cost is quite different form that of PAO’s. The chart below illustrates this point.
200
Manufacturing Cost, $/bbl
PAO
100
Gp III
Gp II + GTL Gp I Gp II
0
Low High Performance Source: PetroTrends Inc, NPRA LW-01-137
2.5.5 ECONOMICS OF GTL
GTL economics as a function of energy price
The economics of GTL are quite robust. Sometimes, GTL economics are mistakenly compared to refinery economics because the plants have some similar gear and make refined products. However, GTL economics are more reminiscent of upstream economics than of refining.
70 Dated Brent On-Road Diesel GTL Feedstock 60
50
40 Refinery Spread 30 US$ / / BBL US$
20 GTL Spread 10
0 Jul-94 Jul-95 Jul-96 Jul-97 Jul-98 Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04
The key is to look at the difference between the feed cost and the product value. For remote gas, the value of the gas is related to its production cost. For illustration purposes, the graph below shows a remote gas with value indexed to crude price, a common practice for gas purchase contracts. What distinguishes GTL from refining is that the margin for GTL is this gas cost compared with refined product prices. Refinery economics must rely on the difference between crude oil and refined product prices, a much narrower margin.
135 It is apparent from the above chart that GTL economics generally benefit from higher crude oil prices. One expected outcome from this is that as crude prices firm up over time more opportunities will arise for GTL application. A related line of thinking looks at the possibilities of crude production reaching a plateau in coming years and of refining capacities becoming more strained. These related trends give rise to speculation that the drivers for GTL will increase, as the market reflects the growing need for this incremental supply of liquid transportation fuel.
Regardless of what drives the increased demand, today’s notions of the requirements needed for a commercial GTL site may become outdated. In time, more robust GTL economics will allow the technology to target smaller gas fields and more remote locations.
GTL economics compared to LNG
Another perspective on GTL economics is to compare it with LNG, the most common competitor to GTL from the point of view of gas producers looking to monetize their reserves. In a 2004 article written for the Society of Petroleum Engineers by Osama Abdul Rahman and Mohamed Al-Maslamani or Qatar Petroleum, the authors conclude that GTL and LNG have similar economic incentives for Qatar.
These conclusions cannot be generalized too much, because the final answer can be affected by both crude oil price and distance to markets. However, some conclusions apply very broadly: • The total investment in the LNG value chain is greater than the total GTL investment • The rate of return for the GTL investment is higher than the overall return for the LNG value chain
One issue is that in some markets, most notably Asia-Pacific, LNG pricing does not track energy prices. This means that especially in times of high crude prices, the LNG producers do not gain much or any of the potential margin increase. Another important issue is that the per-mile shipping cost of LNG is considerably higher than the shipping cost for GTL products. More distant areas such as Australia favor GTL, compared to close-to-market gas provinces such as Trinidad & Tobago.
Other differentiators that have attracted gas resource owners to GTL are: 1. product differentiation from LNG, to spread market risk 2. value-added export product, not a raw material 3. faster project development, since the long-term market does not have to be developed in advance 4. faster production ramp-up, mitigating the “wedge gas” challenge common in LNG projects 5. potential to use byproduct energy and water from GTL for power and industrial water for an industrial site
CONCLUSIONS
In summary, the GTL industry is commercially viable today. Significant investments will be made in this industry, starting with the first major project starting up in 2006.
This industry is being driven by a “resource push” from resource owners as well as a “market pull” from markets anxious to improve supply of high-quality diesel and environmental drives to improve air quality in urban locations. Transportation fuel needs are still best met with liquid fuels, so there is a lot of demand for high-quality liquid fuel production. GTL is well positioned to help meet these growing needs.
Finally, as the general perspective regarding future energy prices becomes more and more bullish, the prospects for GTL improve. As crude oil production becomes more challenged, alternative sources of liquid fuel will become ever more needed. The future for GTL looks very bright.
136 2.6 METHANE HYDRATES AND THEIR PROSPECTS FOR THE GAS INDUSTRY
ABSTRACT
Industrial interest in natural gas hydrate resources and in the use of gas hydrate technologies for natural gas storage and transportation is growing due to general trends in conventional gas- resource development: increasing production and transportation costs (see Key Messages in this report). The larger gas-consuming areas, such as North America, Western Europe and the Far East, have relatively few local conventional resources, and are importing more and more gas. But it is now proven that there are huge offshore gas resources in the form of natural hydrates (up to 21,000 TCM), and a considerable proportion of them are located in these very areas. Growing market prices and new technologies are creating a more favourable environment for the development of this resource. Some countries in the aforementioned areas have therefore already launched exploration and production projects on natural gas hydrates, while other countries are preparing to do so. Another important aspect of natural gas hydrates for the development of the gas industry is their offshore spread above conventional deep-water gas and condensate fields. Their presence in bottom sediments can in some situations cause dynamic geohazards which endanger production facilities. Changes in sea level could also cause catastrophic gas releases from submarine hydrates, leading to safety and ecological problems. Gas-hydrate technologies for natural gas storage and transportation at low or atmospheric pressure have become possible since the recent discovery of a new property of gas hydrates: the self-preservation phenomenon. This makes it possible to transport gas onshore, and more particularly offshore, in concentrated solid form using conventional refrigeration. Hydrate technologies could also be useful for carbon dioxide disposal during offshore natural gas production. Commercial production of natural gas from natural hydrates could begin as early as 2015, and the commercial transport of natural gas in hydrate form could start by 2010.
RESUME
L’intérêt grandissant de l’industrie pour les ressources d’hydrate de méthane et pour les applications au stockage et au transport de gaz naturel vient des tendances observées sur les ressources de gaz conventionnel : augmentation des coûts de production et de transport (voir la section key messages de ce rapport). Les plus importantes zones de consommation comme l’Amérique du Nord, l’Europe de l’Ouest, l’extrême Orient disposent de ressources relativement limitées et importent de plus en plus de gaz. Cependant, il est maintenant prouvé que les ressources en hydrates de méthane, particulièrement offshore sont très importantes (jusqu’à 21 000 Tm3) dont une part importante est située dans ces régions. L’augmentation des prix du gaz et le développement de nouvelles technologies constituent des facteurs favorables au développement de ces ressources. C’est pourquoi certains pays de ces zones de consommation ont lancé des projets d’exploration et production d’hydrates de méthane. D’autres pays sont sur le point de suivre. Un autre aspect important de la question concerne la présence d’hydrate de méthane au dessus des champs de gaz en offshore profond. Leurs présences dans les sédiments peut provoquer des geohazards susceptibles de provoquer la destruction des installations de production. De même le changement du niveau de la mer pourrait provoquer des échappements catastrophiques de gaz d’hydrates sous marins avec des conséquences en termes de sécurité et d’environnement. Le stockage et le transport de gaz naturel à basse pression ou à pression atmosphérique devient possible après la récente découverte d’une propriété des hydrates de gaz : la self preservation. Le transport de gaz sous forme solide concentrée grâce à des réfrigérateurs onshore et offshore. Les technologies liées aux hydrates pourraient être utiles pour traiter le dioxyde de carbone en cas de production de gaz naturel offshore. On anticipe un début de production de gaz naturel à partir d’hydrates dès 2015 et le transport de gaz sous forme d’hydrates dès 2010.
137 INTRODUCTION
(This contribution contains openly published data from VNIIGAZ, Moscow Gas Hydrate Group, US Geological Survey, Japan Oil, Gas and Metals National Corporation, Geological Survey of Canada, US Department of Energy, Ocean Drilling Project (ODP), GEOMAR (Germany), Norwegian University of Science and Technology, KOGAS (South Korea) and some other organizations).
According to the preliminary study, made by IGU WOC1 in previous triennium, the resource base of the world gas industry continues to grow, but natural gas exploration and production costs are also gradually growing. Average production cost of natural gas is expected double compared to the current level by the year 2030. Also another trend is the discovery of new conventional resources in more and more remote areas. This increases the cost of gas transportation to main consumer regions: North America, Europe and South-East Asia. The most important are resources of natural gas hydrates. As an example, possible scenario of natural gas production in USA is shown on Figure 1 suggesting that by the year 2020 there is need for own natural gas hydrate resources development.
Figure 1. Natural gas demand and sources of gas in USA until 2040.
But first of all a short explanation about natural gas hydrates. These are solid crystalline compounds of gas and water, looking like snow (porous hydrate) or ice (monolithic). The molecule of gas is encapsulated in a cage created by water molecules. They could be formed when water and gas are in contact in certain range of pressure and temperature.
A B
Figure 2. Methane hydrate: methane molecule inside water lattice in hydrate structure (A), burning hydrate (B).
138 Main properties of gas hydrates, important for natural gas industry: 1. One volume of methane gas hydrate contains up to 164 volumes of methane at pressures 30 – 100 bars and corresponding temperatures (+1 - +12oC). 2. Gas hydrate self-preservation phenomenon allows to store gas in hydrates at atmospheric pressure and ambient (-5 - -10 оС) temperature. 3. Hydrates accumulate great quantities of natural gas in shallow depth in the Earth, cementing sediments. 4. CH 4 hydrate density is lower, but CO 2 hydrate density is higher than marine water density. 5. Submarine hydrates create environment for oxygen-less life.
A few words about the one of the most important properties of gas hydrates – the self- preservation phenomenon, which has been discovered recently. It is characteristic only for monolithic species of gas hydrates and hydrate-containing sediments. If pressure above hydrate piece is reduced below equilibrium point, but surrounding temperature is subzero, initial surface decomposition of hydrate quickly results to isolating ice film formation and hydrate decomposition stops (Figure 3). Gas content of hydrate is reduced slightly, but sometimes very negligible. Formed self-preserved methane hydrates could be stored at atmospheric pressure and temperature -5 - -20 oC for a few weeks without considerable loss of gas content. In nature self-preserved hydrates form sediments saturated by relic hydrates in hard-frozen permafrost above the top level of current hydrate stability zone. Thus, the self- preservation phenomenon expanded thermodynamic conditions of gas hydrate existence in nature and created theoretical base for development of principally new natural gas industry technologies of storage and transportation of natural gas.
A B C
Figure 3. Formation of self-preserved methane hydrate particle (temperature -5 - -15oC)
A – Hydrate particle at the moment of gas pressure reduction down to atmospheric, B – Partial surface decomposition of a hydrate particle, C – Isolating ice film formation on hydrate particle surface (film thickness 0,1 – 0,2 mm), hydrate metastability moment.
2.6.1 GAS HYDRATES IN NATURE
Enormous quantities of methane are in natural gas hydrates. Total volume of gas in hydrates now is estimated from 2 500 (Milkov, 2004) to 21 000 trillion cubic meter (Kvenvolden, 1998). This is minimum 5 times more than all discovered and expected resources of conventional gas. Resources of gas in hydrates are within thermodynamic Hydrate Stability Zone and relic hydrates are in the Hydrate Metastability Zone (HMSZ) within hard-frozen permafrost. (Figure 4).
139
Figure 4. Hydrate Stability Zone (HSZ) and Hydrate Metastability Zone (HMSZ) in permafrost regions.
HMSZ is the depth interval of self-preserved (metastable) hydrates existence. 1- thermodynamic curve of methane hydrate equilibrium, 2- the curve of pressure/temperature distribution in geologic section.
In the ocean, HSZ begins immediately below bottom from water depth 300 (arctic) 600 (other) seas and more and can reach 500 m in thickness.
Forms of gas hydrate accumulation in sediments.
Hydrates usually accumulate in dispersed sediments, like sand, sandstone where they fill pore space cementing the sediments. In muds, especially below sea floor, they form inclusions represented by layers or nodules (Figure 5). A B
Figure 5. Hydrate accumulation exposed on the sea floor (A), hydrate layers in marine sediments (B).
Figure 6. Hydrate-containing drill core (mud and hydrates)
140 Natural gas hydrate spreading and resources.
There are about 100 proved and inferred locations of gas hydrate deposits, discovered on the Earth by now (Figure 7). This number is growing each year, because hydrates are found in many deep-water areas, where scientific and industrial activity takes place.
Figure 7. Locations of known gas hydrate occurrences in the world.
Many of ocean hydrate deposits are represented by extended fields containing hundreds billion cubic meter of methane gas or even trillions cubic meters. But recovery of this gas is technologically complex task. Total volume of gas is estimated by different researchers in the range 1- 21 quadrillion cubic meters of methane.
Natural Gas Hydrates (21000 trln. m 3)
Aquifer Gas (10000 trln.m 3) Conventional Natural Gas Coalbed Resources Methane Including 3 (100 trln.m ) Resources of Tight Reservoirs (600 trln.m 3) Figure 8. Natural gas resources in the Earth crust down to depth 4,5 km (combined data from VNIGRI (Russia, 1988) and USGS (USA, 1998)).
141 2.6.2 EXPLORATION AND PRODUCTION
Technologies of exploration and production of natural gas hydrate resources have specific features make them different from those for conventional gas. By now, drill core study is the only direct method of gas hydrate identification in sediment section. Also, sometimes in marine conditions, hydrate-containing sediments are visible on seismic profiles, but final answer about hydrate presence can give only drill core recovered by special technique, often including pressurizing and thermal stability of drill cores.
The most advanced study in exploration and production of natural gas from hydrates has been made by international consortium of Canadian, Japanese, USA, Germany and Indian companies at the North of Canada in Mackenzie Delta. Using exploration data, received and calibrated on the exploration wells with hydrate cores 3 more hydrate reservoirs have been revealed in the vicinity of explored one (Figure 9 and Table 1).
Figure 9. Gas hydrate fields in the Mackenzie Delta (North of Canada).
Figure 10. Hydrate-containing drill cores from Mallik gas hydrate field (Mackenzie Delta).
142
Table 1. Natural gas volume in four discovered gas hydrate fields in Mackenzie Delta.
Production of gas from hydrates is now developing in the USA, Canada and Japan. There are different technologies of gas production from hydrates, but all of them are based on three methods and their combination: depressurization of reservoir, heat injection and chemical injection (Figure 11).
Heat (water, Gas+water+inhibitor steam, microwaves) Gas+water Wet gas Inhibitor
Hydrate reservoir Hydrate reservoir
Heat injection Depressurization Chemical injection
Figure 11. Three methods of gas recovery from natural hydrates
143 The cost of natural gas production from hydrates is strongly dependent on the geological structure and hydrate content of the reservoir. The production cost from gas hydrate fields in the Mackenzie Delta (North of Canada) is estimated to be 25-30 USD/1000 m 3. This compares with the production cost of a hypothetical deep water hydrate-containing sediment using “usual” technologies of more than 200 USD/1000 m 3. Application of principally new production technologies can reduce this value to 40-50 USD/1000 m 3 (Yakushev, 1998). Gas flowrates at the wellhead will be dependent on the method of gas production . The most effective is expected combination of heat injection and depressurization.
Safety of natural gas production from hydrates
Technology of natural gas production from onland and offshore hydrates is different from this in conventional gas fields. Hot water, brines use for reservoir stimulation causes additional safety and ecology problems, which could be successfully solved, but production process will require careful monitoring and safety control.
On land in permafrost areas there are problems of conventional gas production caused by hydrates presence in permafrost section and below it. Warm gas rising up along production well heats surrounding sediments. This causes hydrate decomposition and combustible gas leak around wellhead. These problem limits the possibilities of wellhead operation and sometimes results in fire (Figure 12).
A
B
Figure 12. Methane bubbling from defrozen permafrost gas and gas hydrate accumulations around gas production well (A) and gas fire from shallow permafrost well (B).
Another ecology and safety problem of gas production from offshore hydrates is instability of sea floor if production system is installed on submarine slope. Production of gas from submarine hydrates can be the “trigger” mechanism for submarine landslide along the contact between hydrate- containing and hydrateless sediment layers. This landslide can destroy the whole production system (Figure 13).
144
Figure 13. Methane release from submarine hydrates can result to ship sinking and plane explosion.
If submarine gas production will take place from FPSO-type vessels using tubing for warm water injection to the sea floor and sub bottom hydrates decomposition – there is another problem: how to reduce formation of mud pollution around the injection place?
2.6.3 ECOLOGIC PROBLEMS ATTRIBUTED TO NATURAL METHANE HYDRATES.
Being one of the greatest resources of methane on the Earth, natural methane hydrates represent a considerable source of greenhouse gases. They become unstable when pressure or temperature conditions in sediments have been changed. This can happen through sea level lowering (pressure reduction) ( Figure 14 A) or sea level elevation (flooding of permafrost areas) (Figure 14 B) .
A
145 B
Figure 14. Methane release from submarine hydrates when sea level reduction (A) and from permafrost areas when sea level elevation (B).
Methane, released from hydrates to the atmosphere can increase global warming and climate change. The nature of any link between climate change and sea level change is however beyond the scope of this paper.
Another ecological problem is formation of specific biota on the sea floor, where hydrates are exposed to sea water. There is life without photosynthesis and living things take energy from methane from hydrates. This biota is unique and have been discovered very recently. This biota is represented by mollusks, bacteria and worms (Figure 15). Production of natural gas from seafloor hydrates can destroy this life, so subbottom hydrates development is preferable.
A B
Figure 15. Colony of “ice worms” in sea bottom hydrates (A), “Ice worm” under microscope (B).
146 2.6.4 GAS HYDRATE TECHNOLOGIES FOR STORAGE AND TRANSPORTATION OF NATURAL GAS AND CO2 SEQUESTRATION.
There are some regions in the world, where there is no opportunity for underground gas storage construction or LNG storage construction. Usually these are remote gas consumers having small demand for natural gas. How to transport and store gas there if no pipelines? Gas hydrates open new opportunities for gas storage and transportation. Now, after gas hydrate self-preservation phenomenon discovery allowing hydrates to be stored at atmospheric pressure, there could be created natural gas storage of low cost and high capacity. One of such Russian projects is shown at Figure 16.
Parameters Hydrate Dimensions – 250 х200 х25 m 3 blocks Working volume – 140 mln. m о production Storage temperature: - 5 - -10 С Working pressure: 1-5 bar. Construction cost – 43 mln. USD.
Freezing facility Gas to Gas pipeline consumer Gas storage
Gas hydrate blocks
Figure 16. Project of natural gas storage in the form of metastable hydrate blocks for gas capacity 140 mln.m 3.
Other technology – marine transportation of natural gas. There are different suggestions on hydrate carriers construction in Norway, Japan, USA, Russia, but the most important is comparison of expenses for transportation of natural gas by different methods (Figure 17).
Figure 17. CAPEX for different methods of natural gas transportation (data of Norwegian University of Science and Technology, 2002)
147 According to the Figure 17, pipeline is the most effective way of marine gas transportation for this volume in the distance range 0-1200 km, gas hydrate transportation is more effective in the range 1200-12000 km. But if volume of transporting gas is growing, LNG and GTL technologies could be more effective due to reduction of specific cost of transportation.
And one more gas hydrate technology developing now is CO 2 sequestration on the sea floor as CO 2 hydrate. Carbon dioxide hydrate has greater density than sea water, so it can be deposited on the sea floor and be dissolved by this water with time without serious impact on environment. There are 2 ways of CO 2 sequestration: injection of gaseous CO 2 to the depth of hydrate formation and injection of liquid CO 2 to the depth of liquid CO 2 stability. In the second case there will be formed a hydrate film isolating liquid CO 2 from sea water.
But the most interesting could be combination of offshore methane production and CO 2 sequestration using marine hydrate transport. The concept should include heat exchange of one hydrate formation and other hydrate decomposition in the carrier. So raw methane being recovered at offshore facility should be converted to methane hydrate in the carrier, where transported from shore CO 2 hydrate should be decomposed simultaneously. Then CO 2 gas should be injected to the water depth providing CO 2 hydrate formation and its deposition on the sea floor or to subbottom reservoir. Heat exchange within carrier should provide energy saving for hydrate formation/decomposition. On the shore, there should be opposite process: methane hydrate decomposition and feeding to treatment unit and injection of gaseous CO 2 and its hydrate formation within carrier. This shuttle system is very flexible for different water depth and locations of marine gas and gas hydrate fields. Figures 18 and 19.
- methane
- carbon dioxide To consumer
natural gas treatment unit combustion gas production compressor station platform hydrate carrier CO 2
CO 2 separation unit
CO 2 underground storage
Figure 18. Concept of open gas production and CO 2 sequestration technology.
148 hydrate carrier
СО 2 separation unit CH 4 hydrate СО 2 storage
CO 2 hydrate shore natural gas treatment unit
compressor stations production platform
power station
Figure 19. Concept of cycled natural gas production, use and CO 2 sequestration technology.
CONCLUSION
Recent studies of methane hydrates (natural as well as artificial) have shown following trends: 1. Total number of resources is decreasing (down to 2500 trln.m 3), but commercial prospects of gas production from gas hydrate deposits are growing. 2. Discovery of new phenomenon – gas hydrate self-preservation, explains hydrate existence in permafrost at unequilibrium conditions and open new commercial prospects for storage and transportation of natural gas in hydrate form at atmospheric pressure. 3. Natural gas production cost is estimated from 25 to more than 200 USD/ 1000 m 3 depending on production technology, hydrate reservoir properties and location (onshore and offshore). 4. Transportation of natural gas in self-preserved hydrates by marine carriers could be more economically feasible than by LNG carriers. 5. Gas hydrates are of considerable geohazard when drilling and production of oil and gas in permafrost regions. 6. Natural methane hydrates could be great source of methane for global worming if sea level change, but there are no visible reasons for this. 7. Methane hydrates could be of great geohazard for deep water oil and gas production due to submarine landslides along contact between hydrate-containing and underhydrate sediments. 8. New technologic concepts of natural gas transport in hydrate form open new prospects for deep water natural gas production and CO 2 sequestration unified into one energy-saving technology. 9. Construction of gas hydrate storages can solve the problem of natural gas supply to remote small consumers.
149 2.6.5 REVIEW OF GAS HYDRATE ACTIVITIES IN DIFFERENT COUNTRIES
(data represented by Japan Oil, Gas and Metals National Corporation, Korean Gas Corporation and VNIIGAZ, Gazprom, Russia)
1) United States
The United States government is committed to ensuring clean, dependable, and affordable energy for today and into the future. Methane hydrates represent a potentially significant new source of energy that may provide a sound economic and environmental future as conventional resources are depleted. The volume of natural gas trapped in hydrates in the United States (at or beneath the sea- floor, and in permafrost zones in Alaska) is estimated at more than 320,000 trillion cubic feet (tcf). Hydrates are attracting interest because demand is rising for natural gas while reserve replacement from conventional geological formations declines. Annual U.S. gas consumption is expected to reach 30 tcf by 2015, up from about 22 tcf in 2000. So, production of just one percent of the estimated hydrate resource would meet U.S. natural gas demand for the next 100 years. The Methane and Hydrate Research and Development Act became law in May 2000, authorizing $50 million in federal funds for research over five years.
The U.S. Department of Energy (USDOE) in partnership with the U.S Geological Survey (USGS), industry, academia, and other government agencies, are working to ensure a long-term supply of natural gas by developing the knowledge and technology base to allow commercial production of methane from domestic hydrate deposits by the year 2015. USGS and USDOE are committed to participating in international research programs to advance the understanding of natural gas hydrates and the development of these resources for future energy demand.
2) Japan
Japan, like many other countries with little indigenous energy resources, imported oil and gas accounts for 99% of Japan's total primary oil and gas supply. High import dependency is one reason why the government of Japan has been caring out a very ambitious research program to develop the technology needed to recover gas from oceanic hydrates. Methane hydrate bearing formations are estimated in Nankai Trough, Okushiri Ridge (Offshore Hokkaido), Offshore Okachi-Hidaka, etc. in Japan. In 1999-2000, the Japan Oil, Gas and Metals National Corporation (JOGMEC-old name: JNOC), with funding from the Ministry of International Trade and Industry (MITI; Presently Ministry of Economy, Trade and Industry abbreviated as METI), drilled a series of gas hydrate test wells in the Nankai Trough off the southeastern coast of Japan and discovered distribution of methane hydrate in sandstone layers. Japan Geological Survey (JGC) assessed the resources as 4-6 TCM (1992). There is no commercial natural gas production from gas hydrate-bearing formation.
In 2001, METI has started "Japan's Methane Hydrate Exploitation Program", a 16-year program in which methane hydrate is defined as a future energy resource that is expected to exist in large amounts offshore around Japan. In the program, Mallik is regarded as an important project in collecting necessary data and parameters in preparing future successful offshore gas production from hydrates. The current plan included the following: - Selection of methane hydrate gas field from the prospective areas and its economic evaluation. - Production test of gas from the chosen methane hydrate gas fields. - Establishment of technology for economic production. - Establishment of development system that is environmentally friendly. Significant efforts to assess gas hydrates include the collaborative 1998 and 2002 Mallik gas hydrate research well programs. In early 2004, multi-well drilling was carried out in the Nankai Trough area and the results are under investigation at present.
3) Canada
If a future global supply of energy is stored in gas hydrates, then an immense potential occurs in Canada, a northern nation bounded by three oceans. Canada is also the world's third largest producer of natural gas, the most environmentally friendly fossil fuel. Expected North American
150 growth in demand for natural gas provides Canada with opportunities for economic and export growth, while contributing to commitments to a sustainable environment and a vibrant economy in northern communities. Methane Hydrates are being evaluated as a potential natural gas source through a new unified research program led by Natural Resources Canada. Canada has a long history of methane hydrate research that begins in the 1970's. Subsequently the most significant efforts to assess gas hydrates include the collaborative 1998 and 2002 Mallik gas hydrate research well programs.
The total in-situ amount of methane in hydrates of Canada is estimated to be 0.44~8.1 × 10 14 m3. This is compared to a conventional Canadian in-situ hydrocarbon gas potential of ~0.27 × 10 14 m3. They have a Earth Sciences Sector (ESS) Program to use methane hydrate as fuel of the future. ESS program means national program to make narrow the scientific and technological knowledge gaps in the sustainable development of Canada's natural resources. The National Energy Board and NRCan's Energy Sector report methane hydrates as a volumetrically significant and environmentally friendly resource by including methane hydrates as a new source of supply. Volumetric methane hydrate assessments on Canada's Atlantic and Pacific oceanic margins and the Mackenzie Delta region are conducted. Information on the characteristics, stratigraphy and sedimentology of Canadian methane hydrate occurrences and their resource potential and development risks will be disseminated to targeted industry and government audiences, and will be made publicly available in various formats. ESS Program Plan indicates a total of $9.2 Million CDN over five years (March 31, 2006). ESS contributes to a policy roadmap for the creation of a multi-agency strategy to stimulate private- sector development of gas hydrates, in collaboration with other NRCan sectors, other Government Departments and other stakeholders.
4) Russia
Methane hydrate resources in Russia are estimated as 10~100 TCM on land and 100~1,000 TCM offshore (hypothetical resources). There is some scientific discussion about natural gas hydrate reservoir production at Messoyakha gas field (north of West Siberia) during the last 30 years, but no direct indications on natural hydrate decomposition during production. The reservoir is situated at the low boundary of the thermodynamic Hydrate Stability Zone in this region, so there were well log indications of hydrates formed around the well bottom due to gas withdrawal during well testing, but still no evidence of natural hydrate existence in quantities able to affect production history.
Methane hydrates are discussed in Russia in 2 directions. One is a potential natural gas resource, the other is a factor complicating well drilling and operation in permafrost and offshore regions. Having large conventional natural gas resources and proved reserves, Russia pays low attention to hydrates as a potential natural gas source. But some accidents at northern wells during drilling through permafrost and under-permafrost layers caused by possible hydrate decomposition resulted to some research efforts on studying shallow intra-permafrost hydrates at the north of West Siberia. Self-preserved methane hydrates can exist in shallow permafrost from a depth of first meters and form free gas accumulations generating blowouts when drilling through. This research trend is planned to develop in future as well as offshore hydrate-containing sediments as foundation for oil and gas production platforms in polar seas.
5) South Korea
In Korea, there were 2 national R&D projects on the exploration of methane hydrates. One has been carried out by the KOGAS (Korea Gas Corporation) and KIGAM (Korea Institute of Geoscience and Mining) with total budget of 3 million (US) dollars for 5 years from 2000 to 2004, covering 12,000L-km 2D seismic surveys in the way of reconnaissance over 40,000 km 2 area. The other was performed by KNOC (Korea National Oil Corporation) and KIGAM with total budget of 1.8 million (US) dollars for 3 years from 2002 to 2004. KOGAS and KNOC have obtained promising results in its search for methane hydrate in the seabed of the East Sea around Korea Peninsula. It is believed that significant amount of methane hydrate exists below the seabed of the East Sea within the declared Korean territory.
Korean Government intends to lead the project by stage with the ultimate goal of the methane hydrate production in 2015. For 3 years from 2005 to 2007, it is expected that the budget will be about 65 million dollars, of which the share will be 57 million dollars by government and 8 million dollars by
151 KOGAS. For the first stage of 3-year project starting in 2005, its objective is the confirmation of methane hydrates existence over the "Prospect I" on the basis of the compiled results of the previous works, along the additional high resolution seismic surveys and drilling. For the 2nd stage from 2008 to 2011, it will be practical the same as the 1st stage with only difference of the target area of "Prospect II" . During the final stage, if the economic reserves would be positively defined, intensive studies will be focused on the development & production techniques to put the prospect potentials on a solid foundation for the commercial utilization. The government will take the initiative of the first stage works, supporting the R&D of KOGAS, KNOC, and KIGAM is expected to join the project with its matching fund. In the 2nd stage, a consortium will be formulated consisted of the institutions involved in the 1st stage and private companies at home and abroad.
6) India
India, like Japan, has also initiated a very ambitious methane hydrate research program leaded by GAIL (Gas Authority of India Ltd.). In March of 1997, the government of India announced new exploration licensing policies, which included the release of several deep water (>400m) lease blocks along the east coast of India between Madras and Calcutta. Recently acquired seismic data have revealed possible evidence of widespread methane hydrate occurrences throughout the proposed lease blocks. Also announced was a large methane hydrate prospect in the Andaman Sea, between India and Myanmar, which is estimated to contain as much as six trillion cubic meters of gas. The government of India has indicated that gas hydrates are of "utmost importance to meet their growing domestic energy needs".
7) Germany
Beginning in 2004, the Ministry for Education and Research (BMBF) and the German Research Council (DFG) will launch the second phase of EOTECHNOLOGIEN, with special emphasis on "Methane in the Geo/Biosystem". Its five research areas will be: (1) Methane in gas hydrate provinces, (2) Climate impact of methane, (3) Gas hydrates as GeoBio-Systems, (4) Natural hazards, and (5) Structure and properties of gas hydrates. Of special importance in this context are two methodological thrusts. The first is the monitoring component, which encompasses geochemical properties and secular temperature variations especially in permafrost settings and their influence on atmosphere and climate. The second is the modeling component, where gas hydrate occurrence in time and space (3-D/4-D) will be addressed. Here, interdisciplinary investigations will study the physics, chemistry and microbiology utilizing evolving natural, experimental and virtual laboratories, taking due consideration of (1) basin evolution- (2) subsurface water flow, (3) biogenic and thermogenic gas generation and (4) partition and phase behavior in the system water-gas-oil.
8) United Kingdom
There are not any formal estimates of U.K. Natural Gas Hydrate resources and any production plans in the U.K. Some R&D activity has been concerned with methods of forming natural gas hydrates for possible transportation options.
9) Pakistan
Gas hydrates potential has been identified off the coast of Makran. The resource is known to be distributed along 700 km of the coastline of Pakistan. At the moment there is no plan of recovering gas from this resource.
ACKNOWLEDGEMENT
This contribution has been prepared with partial support from European Commission, INTAS Project 03-51-4259. Special thanks for Dr.Art Johnson from Hydrate Energy International, USA and Mr. Suzuki and Mr. Tsuji from Japan Oil, Gas and Metals National Corporation for providing by useful information about gas hydrate R&D. CONCLUSIONS TO PART 2
152 The main conclusion of our work is that, being aware of the challenge the upstream industry has to face in order to meet the demand growth for natural gas, we anticipate this segment of the industry to be able to cope with this challenge.
These are the main grounds for this statement.
1. There is still a lot to discover : gas exploration is not mature and stakes are high that a lot of gas still has to be discovered in many areas. 2. Development architects are ready to develop and implement new concepts for gas discoveries in difficult environments like arctic, deep offshore, deep and tight reservoirs. 3. Improvements of the industry performance in the treatment of gas containing acid components will contribute to the needed supply growth, as well as the decrease of gas flaring which still has to be carried out in some places (this last point might represent around 5% of today’s production). 4. Gas to liquids technology will be more and more applied because it will allow the monetisation of new gas reserves by opening the whole market of environmentally friendly oil products for transportation and petro-chemicals. 5. In addition, gas upstream is very likely to play a very important role in the fight against Green House Gas emission by providing to sequestration solutions for CO2 emitters like power generation for example.
Finally, the industry is already pushing the boundaries of conventional gas production : Methane Hydrate could come into the gas balance by 2015.
153 APPENDIX 1: Members of the Committee
Chairman: Colin Lyle, Gas Market Insights Ltd, UK Vice Chairman: Vladimir Yakushev, VNIIGAZ, OAO Gazprom, RUSSIA Secretary: Adam Hinds, Centrica, UK
Members:
Anatoliy Andriyevskyy, NaftoGaz, UKRAINE Arata Nakamura, Japan National Oil Company, JAPAN Barry Jones, Australian Petroleum, AUSTRALIA Branislav Tomovic, NIS-Naftagas, YUGOSLAVIA Boris Vrbanac, INA – Petroleum Industry of Croatia, CROATIA Djaouid Bencherif, Sonatrach, ALGERIA Dominique Copin, Total, FRANCE Eduardo Abriata, Repsol, ARGENTINA Eike Benke, Ruhrgas, GERMANY Esmaeel Bakhtyar, NIGC, IRAN Francois Labaune, Gaz de France, FRANCE Homayoon Saremi, NIGC, IRAN Ivan Pagac, Moravske Naftovedoly a.s, CZECH REPUBLIC Ivica Brkic, NIS-Naftagas, YUGOSLAVIA Jeong-Hwan Lee, Korea Gas Corporation, KOREA Jozef Levoca, Nafta a.s., SLOVAK REPUBLIC Jozef Pagac, Nafta a.s., SLOVAK REPUBLIC Joon Kim, ChevronTexaco, USA Hwan Park, Korea Gas Union, KOREA Leonid Serednytsky NaftoGaz, UKRAINE Leopold Brauer, OMV Aktiengesellschaft, AUSTRIA Lucian Stancu, Romgaz, ROMANIA Mahdjouba Belaifa, Sonatrach, ALGERIA Mansoor Motlagh, NIGC, IRAN Marie-Francoise Chabrelie, CEDIGAZ, FRANCE Mark Howard, BP, UK Mike McAllistair, ChevronTexaco, UK Mirko Lukic, INA Petroleum Industry of Croatia, CROATIA Miro Durekovic, INA Petroleum Industry of Croatia, CROATIA Mohamed Dasri, Petronas, MALAYSIA Munhie Hwang, SK-Enron, KOREA Nahum Schneidermann, ChevronTexaco, USA Naushiev Tanbai, Kaztransgas, KAZAKHSTAN Peter Reichetseder, E.ON Ruhrgas, GERMANY Rebecca Hyde, Centrica, UK Ricardo Morck, Repsol YPF, ARGENTINA Scott Wieslaw, The Oil and Gas Institute, POLAND Shinichi Suzuki, Japan Oil, Gas and Metals National Corporation, JAPAN Stanislaw Rychlicki, University of Mining and Metallurgy, POLAND Taizo Uchimura, Japan National Oil Corporation, JAPAN Torsten Hole, Statoil, NORWAY Yves Tournie, Total, FRANCE Zul Nurani, ExxonMobil, MALAYSIA
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