Improving the Exploration Process by Learning from the Past 8

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-'N’O — \9.(a& Ima ■%VAin ItJf *Ux> Exploration Process by Learning from the Past

Rica Maritim Hotel, Haugesund 29th-30th September 1998

NORSK PETROLEUMS FORENING/NPF NORWEGIAN PETROLEUM SOCIETY DISCLAIMER

Portions of this document may be illegible in electronic image products. Images are produced from the best available original document. ; CONTENTS

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• FUTURE EXPLORATION CHALLENGES ON THE CONTINENTAL SHELF...... 1 • MANAGING RISK WORLDWIDE - GLOBAL PORTFOLIO MANAGEMENT AT SHELL EP...... 3 • A LOOK TO THE PAST TO AVOID OLD TRAPS IN THE FUTURE...... 7 • BP PREDICTION ACCURACY IN PROSPECT ASSESSMENT: A 15 YEAR RETROSPECTIVE...... 9 • MANAGING RISKS, NORWEGIAN CONTINENTAL SHELF...... 13 • EVALUATION OF WELL RESULTS - A FIND PROJECT...... 17 • VOLUMES BEFORE AND AFTER EXPLORATION DRILLING...... 21 • PROBABILITY OF DISCOVERY AND THE REASONS FOR DRY WELLS...... 25 • THE LESSONS FROM THE FIND PROJECT - SUGGESTIONS FOR AN IMPROVED EXPLORATION PROCESS...... 27 • MIDDLE TO UPPER JURASSIC SYN-RIFT DEVELOPMENT ON THE HORDA PLATFORM, LOMRE AND UER TERRACES, NORTHERN NORTH SEA; IMPLICATIONS FOR PROSPECTIVITY... 31 • EXPLORATION POTENTIAL EAST OF TROLL, AFTER DRY WELL 32/4-1...... 33 • EXPLORING THE BARENTS SEA SHELF - HOW NORSK HYDRO APPLIES EXPERIENCES...... 37 • THE EXPLORATION EXPERIENCE FROM THE MIDGARD TO THE KRISTIN FIELDS...... 41 • THE NORWEGIAN SEA AND THE 15™ CONCESSION ROUND, CHALLENGES IN A NEW EXPLORATION AREA...... 43 • MAKING EXPLORATION PAY - TECHNOLOGY, HISTORY, DISCIPLINE...... 45 • FROM BASIN MODELLING TO BASIN MANAGEMENT; REUSE OF BASIN SCALE SIMULATIONS...... 47 • QUICK MAPPING OF BASIN MODELING RESULTS - A KEY FOR QUANTIFYING PROSPECT SENSITIVITIES...... 51 • HYDRODYNAMIC ACTIVITY AND TILTED OIL-WATER CONTACTS IN THE NORTH SEA...... 53 • RESERVOIR CHARACTERIZATION USING 4C SEISMIC AND CALIBRATED 3D AVO...... 57 • FROM SEISMIC TO BIOMARKERS - THE VALUE OF ADDITIONAL DATA IN CONTINUALLY REFINING GEOLOGICAL MODELS...... 61 • EXPLORING MATURE AREAS; THE ROLE OF TECHNOLOGY...... 63 • MANAGING SUBSURFACE KNOWLEDGE; THREE INITIATIVES IN BP...... 67 • AN EVALUATION OF PREDICTION, IN LIGHT OF RESULTS IN SOME OF THE 15™ ROUND LICENCES...... 71 • FUTURE CHALLENGES IN EXPLORING THE REMAINING HYDRO CARBON POTENTIAL OF THE NORWEGIAN CONTINENTAL SHELF...... 73

NPF/inmroving the Exploration Process by learning from the past page 1 A

The NPF Conference: Improving the Exploration by Learning from the Past

Gunnar Berge, NPD

Title: Future Exploration Challenges on the Norwegian Continental Shelf

The hydrocarbon resources on the Norwegian Continental Shelf (NCS) are estimated to be

12,8 bill. Sm3 oil equivalents (o.e.), comprising 6,6 bill. Sm3 o.e. oil/NGL , and 6,2 bill. Sm’ o.e. of gas. These estimates include discovered and produced resources, those related to fields with potential for increased recovery, and undiscovered resources. Approximately 2,3 bill.

Sm3 o.e. (18 %) are produced, significant resources still remain to be discovered; 3,3 bill Sm3 o.e. (26 %), with a range between 2 and 6 bill. Sm3 o.e. Approximately half of the undiscovered resources are located in licensed acreage, which means that future challenges also are related to exploration in these areas.

The discovery rate on the NCS remains high, at 48 %, with 37 new discoveries during the last three years. The value of these resources will depend on future oil prices.

Future exploration challenges are different within the different areas on the NCS. Certain areas, such as the North Sea, have a long and successful exploration history, and production is well established. In other areas, such as the More and Voring Basins, exploration activity is at a very early stage.

The NPD calculates that the greater part of the undiscovered resources are located in the western and northern area of the North Sea. Compared with past discoveries, the size of the majority of future discoveries is likely to be moderate. In the North Sea many installations currently have free capacity, and this will increase in the future. One major challenge is to discover additional resources near existing infrastructure both in open and licensed acreage.

The NPD calculates that approximately 65 % of the North Sea’s undiscovered resources are located in licensed acreage. In the eastern North Sea the potential is limited based on present data, and no major discoveries have been made. Current exploration activity in the area is low, and the evaluation of new play concepts presents a challenge in these areas. There is significant uncertainty related to undiscovered resource estimates in the Norwegian

Sea is. The results of five wildcat wells in recently allocated areas are encouraging with regard to distribution and quality of reservoirs. The wells have proven gas in these basins, and the results are encouraging for the possibilities of finding liquid hydrocarbons. A careful evaluation of these drilling results is required both by the industry and the NPD, before new exploration strategies are developed in these basins.

A further challenge is to discover additional resources in areas where existing discoveries, which are currently considered uneconomic, can be integrated together to comprise a profitable development concept.

The Norwegian resource management challenge has been to achieve a balance of gas supply to the market, gas for injection to improve oil and condensate recovery and to maintain oil/condensate production. This has so far been successful, with an average recovery rate today estimated as 43 %. Injection of gas in the larger fields will continue, and an increasing number of fields currently in production planning will have gas injection as a part of their development strategy. Increased demands for gas for injection and for sale of gas may result in production of too much gas from fields where there is a dependency between liquids and gas. This may necessitate an undesirable reduction of production of liquid hydrocarbons from these fields. To avoid this, and to meet future requirements with respect to the sale of gas, exploration for more gas will present a further challenge to the industry. This means that the

NCS will remain an attractive exploration area in the next century. 3

NPF Conference Expanded Abstract Haugesund, September 29-30,1998

MANAGING RISK WORLDWIDE - GLOBAL PORTFOLIO MANAGEMENT AT SHELL EP

by Mark S. Leonard, Shell EP International Ventures Inc. and Freddie Ozkaynak, Shell EP International Ventures B.V.

In 1997, Shell spent over $6.8 billion US in capital expenditures and exploration expenses while producing 2.3 MM BO/d and 8 BCF/d of equity oil and gas. In addition, Shell EP International Ventures (SEPIV) evaluated more than 200 opportunities in over 80 countries (almost 40 in which we have current operations) in order to add to our profitable reserve base. Key success factors for Shell has been presence of local Operating Companies (“Opcos”) that are fairly autonomous, with the ability to pursue exploration opportunities within their own sphere of governance and approved budgets. So, how does a large multinational EP company do global portfolio management on all these opportunities while still recognizing the governance of the local Opcos?

At Shell EP, in the world outside of Shell U.S. and Shell Canada, we do this by using a common methodology to characterize various risks and then scoring each of the opportunities with a standardized series of parameter screens. All opportunities are depicted graphically together so that each group can see how their opportunity compares with others. Investment decisions are made with this knowledge.

This sounds easy in theory, but especially with operations around the globe, it is difficult to implement in practice. For Shell, it required that the basic work process (opportunity evaluation and maturation) be well defined and implemented, that parameter screens are clear and easy to use, and that the global EP strategy is well understood.

Initial prototyping of this methodology was done in ourmost upstream organization, SEPIV, which is responsible for new business development outside of the areas in which Opcos already exist. The global strategy and the work process were developed, understood, and implemented by the entire SEPIV group. Four strategic themes were created and communicated. Every theme is made up of plays and various projects within each play (Fig. 1). Plays and projects falling outside of the original themes were monetized.

06/04/98 - 6:02 A6/P6 Page 1 ► Play 1-1 • Project 1-1-a Deepwater • Project j-1-b • Project 1-1 -c - Play I-2 ► Project l-2-a ► Project l-2-b EP Gas »Play IM ' ♦ Project ll-1-a • Project 11-1-b

MRH/CIS * Play HI-1 ! * Project III-1*a • Project IIM-b »Play HI-2 • Project lll-2-a

EP Oil Focus »Play IV-1 • Project IV-1-a • Project lV-1-b * Play IV-2 • Project IV-2-a • Etc.

------——mu ■in .— im ———— ' 1 SEPIV Figure 1

The work process is defined to be an “Opportunity Funnel” (Fig. 2) with many opportunities put in up frontwith far fewer investment decisions exiting the end of the funnel. Work groups, and indeed the whole organization, are organized around this process with key individuals often moving along with a given opportunity to Final Investment Decision (FID) to mitigate “hand-off” risk. Key to success is a firm understanding of the opportunity evaluation and maturation processes occurring as opportunities move down the funnel and reach decision milestones.

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Figure 2

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All opportunities are logged in a database and assigned to an “Opportunity Coordinator” who ensures movement through the funnel. It was immediately recognized that the shape of the front of the funnel is controlled by how quickly opportunities are evaluated and either rejected or passed along. Three sets of screens were devised to shape the funnel and optimize staff time.

The first screen, the “Quick Look”, is designed to be done in less than half a day and consists of just five parameters, such as scope and strategic fit. About 35% of the opportunities are rejected by this screen. Next, the “Evaluation” screen, consisting of eight more detailed parameters, including assessments of net present value and technical, commercial (doability) and HSE risks, is performed. This may take several days. Almost 75% of the remaining opportunities are rejected here. The final screen is a 25-parameter set that incorporates a variety of economic runs to assess price risk and assessments of the competitive environment and ultimate marketability. After each screen, two-dimensional plots are made to depict the portfolio of opportunities (Fig. 3). The plays, screens, and attractiveness parameters

Project Key RETAIN to Play

>» 05 Project within i Play, not Key NEW Project not PLAY within Play

LOW MEDIUM HIGH Project Attractiveness

SEPIV

Figure 3 are a reflection of company aspirations as well as the business environment and therefore require updating. The screens also provide a basis for comparing different types of opportunities such as gas, oil, exploration, brownfield developments, pipelines, etc. Of course, no set of screens is perfect, so viable opportunities can - and do - get rejected occasionally requiring modification to the parameters.

These plots are analyzed and discussed before rejecting an opportunity. At this time, a forum is called to decide whether or not to resource a team to “mature” the opportunity, by preparing a negotiating mandate for obtaining a deal while refining

06/04/98 - 6:02 A6/P6 Page 3 6 the economic model based and further commercial inquiries (e.g. Tax, Legal). An expected monetary value is calculated and Value Creation Expectation plots are generated to show the portfolio mix by expected profit, probability of success, and strategic theme of projects at Final Investment Decision (FID). (Fig. 4)

Prob. of Success CUM. RISKED GROSS VALUE c

E 20-50%

CO o CUM RISKED COSTS 0 1 CUMULATIVE COSTS

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Figure 4

This is analyzed to understand how the balance of risk and strategy changes over time. The impact of a new opportunity on the global portfolio is reviewed in light of the strategic resource (staff and money) requirements. Additionally, our reward system is partially based on the value creation scorecards and milestone targets that are tracked.

SEPIV has been very pleased with this process and in June it was formally introduced to the Opcos with fairly good success. In the last two months we have had several opportunities and 10 maturation teams from Opcos using the process.

What have we learned thus far? First, the key to getting acceptance of the process is to make it simple to understand and use. We have simplified the original process and provide immediate support when requested from the Opcos. Secondly, the initial technical probability of success is about right for the projects on which we have data. Peer reviews to ensure consistency in evaluation have been important. The commercial probability (doability) has been overestimated. Slippage of milestones appears to be due to overly optimistic planning which discounts political realities. This can erode profitability tremendously if large upfront investments are made. Finally, the very process of making the strategy, portfolio, and resource allocation decisions transparent to all staff helps to focus and align the organization.

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A Lookto the Past to Avoid Old Traps in the Future Mike L. Brown , Lars Fosvold and A. John Garza, Mobil Exploration Norway Inc. David M. Cook, Mobil Technology Company, Dallas, USA

Introduction The key component that has most influence in Several studies of the results of Mobil ’s the estimation of hydrocarbon volumes in an worldwide exploration drilling success and failure have shown that historically we have undrilled prospect is the bulk rock volume tended to underestimate the uncertainty in (BRV). This represents the gross volume of rock between the proposed hydrocarbon-water contact estimating recoverable hydrocarbon volumes for and the top reservoir surface. This parameter exploration prospects. This has resulted in the overestimation of the mean (expected value) often has the largest uncertainty, as it is based on the inexact science of seismic interpretation, discovery volumes on a worldwide basis. Simply depth conversion and degree of fill estimation. stated, in the past, Mobil have not found as much oil and gas as we predicted. To learn from the past and improve our future pre drill predictions, a different approach to A second conclusion from the Mobil analysis has estimation of BRV has been introduced within shown that in terms of prospect risk we are recent years in Mobil. In order to reflect the large reasonably good at predicting the number of uncertainty, and the large variation in minimum successes. We made the number of high risk and maximum possible values, a lognormal discoveries that were predicted. But we tend to distribution for BRV in the Monte Carlo underestimate the probability of success in low simulation of hydrocarbon volumes is now used. risk prospects. In fact it can be shown that many variables in Prospect Volumes nature are lognormally distributed. Analysis of In the period 1987-96, Mobil worldwide North Sea field sizes suggest they can be best discovered only half the volumes of approximated by a lognormal distribution. Figure hydrocarbons we as explorers predicted. Figure 1 2 shows the Field Size Distribution for Tertiary indicates the problem, showing the pre drill discoveries in Norway and UK. Field Size prediction and post drill technical discovery Distributions such as these, and other reality volumes, summed by year, for all Mobil checks, are used to help constrain the range of participated wells during the period. This volume pre drill prospect volume estimates. This underestimation is not just a Mobil problem. The approach is valid in a mature basin, where there recent NPD sponsored 1997 FIND study, titled have been many tests of similar prospects; such ’Volumes Before and After Exploration as in the Tertiary play in the North Sea. Drilling ’, has demonstrated a similar outcome here in Norway.

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NPF Conference Haugesund September 1998 Improving the Exploration Process by Learning from the Past 8

In 1996 two key guidelines were introduced in Mobil worldwide to improve the quality of our !□ Predicted No. of Discoveries M Aetna! No. of Discoveries I pre drill volume estimates. Lognormal 250 i------distributions are used consistently to represent the range and uncertainty in bulk rock volume, and Field Size Distributions, where available, are used to constrain the prospect volumes. Secondly, local peer review of prospect parameters, volumes and risks has led to more consistent prediction of pre drill volume estimates. All Wells High Risk Low Risk (Risk <30%) (Risk >30%) Figure 3 shows the first results after introduction Figure 4. Risk Analysis Mobil Discoveries and Dry WeDs (1987-1997) of the new guidelines. The figure compares individual pre drill estimates and post drill discovery volumes of Mobil participated The problem of underestimating the probability technical discoveries, during the period 1996- of success in low risk prospects is being mid 1998, and indicates that we are now able to addressed in Mobil. In the Norway office we provide a more accurate representation of the have the luxury of access to both the FIND potential hydrocarbon volumes. database, and a UK well based database on success/failure statistics by geologic play (Figure 5). These studies allow us to ’reality check ’ the Comparison of Pre to Post DrQ Volumes Dbcoveries honouring the bw guidelines prospect risk, prior to drilling. to* M VdUas (EV)

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Figure 3. MobQ Pre and Post Drill Discovery Volumes (1996• 1998)

FlgureS. Prospect Sacctss/FaQurt Analysis by Geologic Play Prospect Risk Figure 4 shows analysis of pre drill prospect risks on some 200 (technical and commercial) discoveries drilled by Mobil during the period Conclusions 1987-1997. The predicted success rate for the In Mobil we feel that the exploration process has low risk prospects (pre drill risk greater than improved since applying the new approach, and 30%) is significantly worse than the actual we can now more accurately provide success rate. We make more low risk management with a better estimate of future discoveries than predicted. This implies that we discovery volumes and risk. Secondly we are are undervaluing prospects which have a now able to capture the full range of uncertainty. relatively high probability of success. The data Learning from the past through historical shows however that we do make as many high analysis of successes and failures, coupled with risk discoveries as predicted. peer reviews, and lessons learned sharing, have played an important role in improving our pre drill estimates.

NPF Conference Haugesund September 1998 Improving the Exploration Process by Learning from the Past R

NPF Conference ‘‘Improving the Exploration Process by Learning from the Past” September 29-30,1998, Haugesund, Norway

BP Prediction Accuracy in Prospect Assessment: A15 year Retrospective

Francis G Harper, BP Exploration

BP started using a consistent approach to risk and uncertainty assessment in prospect evaluation in the late 1970 ’s. Analysis of the accuracy of predictions started in the early 1980 ’s. Because of some changes to the method of assessment in the early years, this review commences with the dataset for 1983 and looks at the experience of the 15 years since then. The main attributes that were analysed were those of predicted risked reserves (against volumes discovered), prospect risk (by comparing summed chance factors with the number of discoveries) and predicted volumes (by comparing volumes in discoveries with their predrill estimates). All volume analyses use the most recent estimate of volumes discovered which in many cases differ significantly from those made at the time of discovery. Attributes that were not analysed so rigorously, mainly due to data limitations, include those of predicted phase and volumetric components.

- - Predicted -----All Discoveries Economic Discoveries

300 400 500 Sequence of Targets drilled

Figure 1. Accuracy of Risked Reserves Estimates: Cumulative Net Risked Reserves Estimates against Net Actual Reserves

As shown in Figure 1, throughout the period under study, the aggregate volumes discovered were close to the aggregate volumes predicted as risked reserves although, if the analysis is restricted to economic discoveries only, total discoveries are reduced to 90% of prediction. During the 1980 ’s when the average volumes targeted per well were modest, the accuracy of predicted risked reserves was generally poor with aggregate success depending on a few large discoveries. During most of the 1990s, to with fewer wells targeting larger volumes, however, success has been more regular with discovered volumes comparable to aggregate prediction. Although total discoveries were comparable to the risked reserves, it does not follow that the separate risk and reserve estimates were associated with similar accuracy.

- - Predicted -----All Discoveries Economic Discoveries

300 400 500 Sequence of Targets drilled

Figure 2. Accuracy of Risk Estimates: Cumulative Net Chance Factors (Predicted Discoveries) against Net Actual Discoveries

Figure 2 shows that, although the average risk in drilled prospects has remained effectively constant throughout the period, the chance of making a discovery has consistently been underestimated and the technical success rate has been significantly higher than predicted. However, many of these discoveries have been uneconomic, usually because they have been too small to be commercial. If these are excluded the success rate generally drops below that predicted although the high success rate of the last 4 years has brought the aggregate number of economic discoveries close to prediction.

Figure 3 looks at the prediction accuracy in estimating volumes as opposed to risks and the cumulative prediction curve comprises only those volumes (unrisked) in prospects which became discoveries. Aggregate discoveries are substantially less than those predicted although this is primarily due to the inclusion of those discoveries which are uneconomic - if these are excluded the disparity is far less. In the last 100 wells (4 years) the predicted marked increase in average field size per well has not been matched by the actual field sizes and this represents a significant volume overestimation - in the case of risked reserves, however, this is effectively offset by the underestimated chance factors. H

- - Predicted in All Disc. ----- Actual in All Disc.

300 400 500 Sequence of Targets drilled

Figure 3. Accuracy of Reserves Estimates: Cumulative Net Predicted Reserve Estimates in Discoveries against Net Actual Reserves

In the case of phase prediction, an oil bias is apparent in some areas where both phases are known to be present (ie, if gas is predicted, gas is found; if oil is predicted, gas is occasionally found instead).

In volumetric calculations, the assessment of BRV contributes most of the variance in the prediction and most of the difference between prediction and outcome. The ranges of several of the parameters tends to be too tight and the range of the resulting reserve estimate is therefore also tighter than is appropriate. During the 1980s, communication of the results of these analyses was made by the distribution of centrally compiled reports; the existence of the exercise and the feedback mechanism was probably at least partly responsible for the subsequent improvements in prediction accuracy. In the 1990's, as BP’s organisation has evolved into a more federal structure, the central compilation of prospect evaluation data no longer takes place to the same extent. Relative accuracy of prospect predictions is maintained, however, by a number of mechanisms, notably the peer assist process by which prospect evaluations by one business unit are often critically reviewed by an experienced team drawn from other business units.

"Managing Risks, Norwegian Continental Shelf (NCS)" by Senior Vice President Tor Fjaeran

By definition Risk Management is a continous process to identify, analyse, optimise and control areas of uncertainty, including measures to reduce the probability of negative events and the consequences of these events. In our company we prefer to use the term Uncertainty Management, not only to include the risk of a project (or prospect), but also to include the upside potential, or "Opportunity". Opportunity is then defined as the probability for a positive event times the consequence, expressed as an increase in NPV.

The story of the Sleipner A concrete support base that sank under construction in Gandsfjord is an example of the extremes. It demonstrates in the first place the extreme risks involved in our business, but it also demonstrates, through the successful rebuild of the concrete support base and the development of the Sleipner field almost according to original schedule, that the Norwegian Offshore industry are able to manage such challenges.

There are a lot of factors affecting Risk or Uncertainty Management (see Fig. 1). In this presentation we will focus on the risks/uncertainty involved in managing the subsurface. In the early exploration phase, Uncertainty Management is of primary importance. During the early phases of exploration in a new province, discoveries are often made more by accident than by design. That is because there is simply insufficient geological information for a thorough evaluation. This has perhaps led to the often-quoted dictum that "Geologists have to be optimists". A geologist may indeed be an optimist, but that is not to be considered an essential professional qualification. Instead, he or she, should take a dispassionate view of the known facts and apply relentless logic in extrapolating from the known to the unknown. It is a descriptive science, for he or she cannot change the nature of the rocks beneath the sea-bed. It is also an imaginative science for the geologist must develop elegant conceptual hypotheses covering the complex range of circumstances responsible for the accumulation of oil and gas, and than invite the investor and the engineer to test them by drilling. The geologist is entitled to come forward with drilling proposals to test his or her ideas only to the extent that he or she has thoroughly investigated all available information. Another requirement is to record and document his or her studies, because each successive hypothesis is built on the results of its predecessor. Lastly, there is an obligation to publish results, as the industry benefits from this form of co-operation between its members, notwithstanding their competitive relationships. In this respect, presentations given at this seminar, i.e. the results of the FIND project, hopefully will add valuable information to the industry and so, contribute to improved Uncertainty Management..

After more than 30 years of petroleum activity on the NCS it is fair to say that the industry, in general, has reached a level of high quality in managing risks. Several factors are important here:

- the NCS is a province which have demonstrated and still demonstrates an interesting hydrocarbon potential - the authorities have demonstrated flexibility and a high level of competence - a high degree of co-operation and openness in the industry - that the NCS has served as an interesting "technological laboratory" for testing new conceps and methods

In the future these factors will be essential to allow a continued high quality level of Uncertainty Management. Still there are many challenges to master, both as a consequence of evolving activities in new "frontier" deepwater areas in the Norwegian Sea, and also because of increasing complexity in the considerable remaining potential in more "mature" areas in the North Sea and the Haltenbanken/Dpnna area.

Industry co-operation is already established through the Deepwater Programme, to identify, analyse, optimise and control the different challenges in deep water areas (related to partly unknown geology, seafloor conditions, meteorological and oceanographic conditions, deepwater drilling challenges and field development). This programme, which is established between the current operators in the deepwater M0re/V0ring area, is chaired by Statoil. Today the Uncertainty Management challenge in the North Sea is related to smaller (marginal) subtle traps/prospects and fields in an infrastructure driven environment. Extensive databases allow the explorationist to identify and create more and more sophisticated play models, but this also creates, in general, the need for more sophisticated Uncertainty Management. The NCS has been in the forefront and one of the most interesting petroleum provinces for testing or improving new technologies. This has been beneficial for better managing risks.

An example of this is the work recently published by two Statoil Geologists Per Arne Bjprkum and Paul Nadeau in their paper on "Temperature Controlled Porosity/Permeability Reduction, Fluid Migration, and Petroleum Exploration in Sedimentary Basins" (1998). This paper demonstrates relationships which should improve exploration results in the future. Their findings, mainly from the NCS, indicate that internally sourced quartz cementation and clay diagenesis are important processes operating in the subsurface. Their integrated models for sandstone and shale diagenesis predict an exponential increase in the risk of overpressure, seal failure, and hydrocarbon remigration with increasing temperature. The NCS data for oil resources as a function of reservoir temperature was used to evaluate this inference. The data show that 90 % of discovered resources occur at temperatures less than 120°C. It is important to note that approximately 45 % of NCS exploration wells are drilled to depths with temperatures greater than 120°C. A world wide sampling of oil fields from basins with geothermal gradients ranging from approximately 20°C to 80°C per km also shows similar results. Therefore, the models indicate that reservoir temperature is an important exploration risk parameter. Modelling these processes can also be used to evaluate the potential for remigrated hydrocarbon plays, both at the basin scale as well as the prospect level, which can be particularly valuable during the early phases of petroleum exploration.

The time aspect is a critical factor in the pre-licence phase of exploration. ("Right amount and type of data at the right time"). Constructive and open communication with the authorities is therefore important. To meet the industry's need for future planning, the concession policy should be open and predictive implying new concession rounds to be announced at a suitable and known frequency. Improved data quality and reduced exploration costs are key elements in the co-operation models established for 3D seismic acquisition in open areas. These models should be further developed. In all phases of exploration and development the aim should be to acquire and use the right type and amount of data at the right time. In this respect, it is important to an IS international company operating on the NCS to handle any change in the political and fiscal regime at an acceptable and manageable risk level, not only related to the operations on the NCS itself, but also related to, and in competition with other petroleum provinces.

Fig.l

Managing Risks STATOIL Factors affecting the Risk Management process

Markets

Health, Contractors, subcontractors Environment (HSE) Sub surface ("Mother Earth")

NPF Conference: Improving the Exploration Process by Learning from the Past

Ofstad, K., Kullerud, L. and Helliksen, D., NPD

Evaluation of Well Results - a FIND-project

The Forum for Exploration Technology Co-operation, FIND, is established with the objective to stimulate industry co-operation on the Norwegian Continental Shelf (NCS). Four projects have been initiated by the Forum, of which “Evaluation of Well Results” is one.

In previous industry studies comparing well prognoses to the results after drilling, it is revealed that the oil companies are pessimistic with respect to discovery probability, and overestimate resource volumes. In order to understand the factors which are critical for resources estimation and discovery probability, the NPD invited the oil companies to the project: “Evaluation of Well Results".

20 companies on the NCS participate in the project. The evaluation is a comparative study of well prognoses versus results in order to use the past experience in future exploration. The project comprises 195 wildcat wells, including all those drilled on the NCS between 1990 and 1997. Ten of the wells are drilled in the Barents Sea, 40 in the Norwegian Sea and 145 wells in the North Sea. The operators have reported their own well data according to an agreed list of data types, as follows: • Cultural data • Structural elements, trap type, play, source rock • Probabilities (reservoir, trap, charge) • In place resources (oil, gas, oil/gas) • Reservoir parameters, reservoir thickness, BRV, N/G, etc The NPD’s definitions of trap types, plays and structural elements have been applied during the analysis. The data types, which make 114 parameters, are all considered to be critical factors for future exploration success. For each well one or several prospects- and one or several cases- have been reported. This means that one well may have several prognoses, but only one result. The different companies ’ assessments of their dry wells are also reported. All the data have been submitted to the NPD, who co-ordinated the project.

The data are acquired from: • 15 operators • Approximately 100 licences • 86 discovery wells • 109 dry wells • 285 prospects; 222 oil, 32 gas, 21 oil/gas, 10 no prognosis • 101 technical discoveries, 51 oil, 38 gas, 12 oil/gas • 183 dry prospects

The results show that HCPV in 70 % of the technical discoveries proved to be lower than the minimum probability estimate prior to drilling. It has proved to have been a significant problem for the companies to collect data for this project, and it is clear that many lack necessary archive routines or historical databases required for such analyses. Prospect and discovery data are incomplete. This explains certain inconsistencies with respect to these parameters for a number of prospects and discoveries in this and the two following papers. However, the data are adequate to provide valid statistical results, and some of these will be presented in the two following presentations. The statistical analyses are performed by the Norwegian Computing Center.

In order to observe future developments and improvements the project will be continued, incorporating new analyses in the future. Establishing effective reporting routines for prognoses before drilling and results after drilling a wildcat well will be considered. uo % io

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Volumes Before and After Exploration Drilling Lars Fosvold, Mike Brown, Mark Thomsen - Mobil Exploration Norway Inc. Karl Ofstad, Lars Kullerud - Norwegian Petroleum Directorate Knut Heggland - Norwegian Computing Center

Introduction This presentation discusses the analyses of the pre- and post-drill hydrocarbon pore volumes and geological parameters reported in the FIND (NPD FIND Project) database and the conclusions that can be drawn from these analyses. The focus of the FIND study concerns the industry ’s ability to predict remaining resources on the Norwegian continental shelf. Post-drill hydrocarbon volumes and input volumetric parameters have been compared with the most likely pre-drill prospect parameters in order to investigate how well the industry have predicted discovery sizes. This is unfortunately not a story of great success, but rather a display of great expectations, which in most cases were not met.

Methodology Hydrocarbon Pore Volume (HCPV), rather than recoverable hydrocarbon volumes, of pre- and post-drill data was compared in order to concentrate on the geological factors involved and avoid the influence of surface and production engineering issues. Hydrocarbon Pore Volume is defined as follows:

Hydrocarbon Pore Volume = Bulk Rock Volume * net/ gross * porosity *(1-Sw)

Bulk Rock Volume (BRV) is a function of area of closure and hydrocarbon column. BRV depends upon reservoir thickness, geometry and fault properties, which in turn control spill points. Using seismic and well data, reservoir thickness and geometry can be estimated for prospects and discoveries. In prospect evaluation, nearby wells provide the only direct information and the analysis of BRV has to depend significantly on the indirect method of seismic interpretation to obtain reservoir thickness and geometry. Various sources of uncertainty are inherent in seismic interpretation, such as velocity modeling, jump correlation across faults and horizon tracking. These uncertainties contribute to large uncertainties in BRV estimation.

Reservoir properties for prospects are generally estimated from nearby wells or from analogue geological settings. The three petrophysical parameters used in the equation for Hydrocarbon Pore Volume (net/gross, porosity and water saturation) are all three related to geological properties. Such properties are in practical terms very difficult to predict, and they are therefore estimated by analogy through depositional and facies modeling using available well data and general knowledge. Although this can be a very efficient process when applied correctly, it is an indirect method that inherently introduces uncertainties.

The analytical methodology applied in this study consists of several statistical tests. First, paired comparisons of the most likely pre- and post-drill HCPV and volumetric parameters were performed. Then followed a simple analysis of the number of results that fell within the predicted ranges for the individual parameters. This was done in order to investigate the validity of the pre-drill ranges. In addition, statistical tests of the difference between results and most likely prognosis were performed in order to investigate if there were differences in the dataset due to the effect of various geological elements.

The following potential effects were looked at: - Probability of discovery - total and individual probabilities for trap, reservoir and charge - Hydrocarbon phase - oil, gas and oil with gas - Trap type - according to definitions used in the FIND database - Geologic play - according to definitions used in the FIND database - Distance to nearest well and depth to reservoir - 2D vs. 3D seismic used for prognosis

NPF Conference - Haugesund, Norway 1 September, 1998 Improving the Exploration Process by Learning from the Past - Discovery vs. failure for reservoir thickness, net/gross and porosity

Due to a limited dataset, it has not been possible to investigate cross effects in detail; e.g. trap type and phase, but general comments have been made where appropriate.

Results As Figure 1 indicates, there is on average a general tendency to overestimate HCPV. The same conclusion can be made for all related parameters, except porosity. There is, however, a large scatter in the data which underpins the inherent uncertainty in attempting to estimate hydrocarbon volumes in prospects. The wider result distribution as compared to the prognosis distribution in Figure 2 indicates that the industry as a whole has estimated a too narrow range of outcomes for this parameter. This is again shown in Figure 3, demonstrating the wide scatter of post drill net/gross results and the narrow range of pre-drill estimates.

Figure 1. HCPV - prognosis (X- axis scale = SM3) versus result (entire dataset).

Prognosis (Sm3)

Figure 2. Histograms comparing results and prognosis of HCPV (entire dataset)

NPF Conference - Haugesund, Norway 2 September, 1998 Improving the Exploration Process by Learning from thePast Comparison of results versus the difference between prognosis and results again shows the tendency to overestimate and to apply too narrow ranges of possible outcomes. This can be seen in Figure 4, which shows that volumes for small prospects are overestimated and that volumes for large prospects are possibly underestimated. Figure 5 is a plot of the number of results that fall within the predicted ranges for the individual parameters. This again shows the tendency the industry has for placing too narrow ranges (minimum and maximum values) on possible outcomes.

NZQ HCPV Results (Sm3)

Figure 3. Histograms comparing results and Figure 4. Plot of HCPV results (X-axis scale = SM3) prognosis of net/gross (entire dataset). versus HCPV difference (result-prognosis)

In range Outof range

HC column Water saturation Reservoir thickness Porosity

Net/Gross

i------1------1------1------1------1

0.0 02. 0.4 0.6 0.8 1.0

Figure 5. Bar chart showing number of results falling inside and outside of predicted ranges of outcomes.

The analyses demonstrate that the industry ’s predictive ability is no better or worse for high versus low risk prospects or for oil versus gas prospects. Furthermore, the predictions are equally bad for different trap and play types. Depth to reservoir, distance to nearest well, or utilizing 3D versus 2D seismic data do not seem to

NPF Conference - Haugesund, Norway 3 September, 1998 Improving the Exploration Process by Learning from the Past increase the industry ’s ability to make accurate predictions. However, for individual parameters, although no clear effects can be demonstrated, the data indicate tendencies to do better in certain circumstances. For example, there are indications that the industry predictions for hydrocarbon columns are better for gas reservoirs, possibly due to DHI effects. Also, there may be a reason to think that predictions are somewhat better in regions of longer exploration and drilling history. This is demonstrated in Figure 6, a box plot of HCPV differences for various play types (A box plot shows a variable distribution in terms of quartiles and they are useful for checking differences between comparable distributions and to identify outliers in distributions). Two play types (L-M Jurassic, Halten Terrace and U Triassic-M Jurassic, Tampen Spur) have differences not significantly different from zero, and they are both in regions with a long drilling history.

1.0- Underestimation

‘Media

Ovefestimation

UJur, Paleocene, UT-MJur, Halten Central NNS Tampen Terrace Graben Spur

Figure 6. Box plots of HCPV difference (results-prognosis, Y-axis scale = loglO) for various play types (n = number of data points for each play type).

Linear regression analyses of HCPV differences on individual parameters show that BRV is clearly the most important variable in explaining the differences in HCPV pre- and post-drill, and that differences in hydrocarbon column height account for most of the prediction error.

Conclusions and Recommendations - Most likely volumes are overestimated. - Industry puts too narrow ranges on possible outcomes for volumes and reservoir property parameters - In areas with a longer exploration and drilling history, industry is better at predicting volumes - Bulk Rock Volume is the most important parameter to get right.

Possible remedies to rectify the situation of predicting more than we find include expanding the range of the pre-drill parameter distributions when calculating volumes for a prospect. For example, uncertainties related to seismic interpretation and depth conversion are larger than perceived, and need to be accounted for. Also, correct prediction of depositional model and facies type does not necessarily lead to correct predictions of petrophysical parameters. Therefore, we should have a more open mind concerning the range of possibilities for each volumetric parameter. This should lead to better volume and petrophysical parameter predictions in our prospect portfolios. We do not know as much as we like to think we do.

NPF Conference - Haugesund, Norway 4 September, 1998 Improving the Exploration Process by Learning from the Past .25

PROBABILITY OF DISCOVERY AND THE REASONS FOR DRY WELLS

Audun Ovretveit, Norsk Hydro, Lars Kullerud, Kari Ofstad, Norwegian Petroleum Directorate and Knut Heggland, Norwegian Computing Center

ABSTRACT

The operators have reported probabilities of trap, charge and reservoir, and the total technical probability of discovery for the prospects to the FIND database. The reasons for dry prospects are compared with the predicted probabilities. The comparisons are based on a "Dry prospect form" which the operators for the dry prospects have reported. An evaluation of selected play models will be performed, and presented.

The lessons from the FIND project - suggestions for an improved exploration process

KJ. Skaar (Statoil), A.M. Spencer (Statoil), P. Alexander-Marrack (A/S Norske Shell), G. Stele (Statoil)

Like the previous three lectures at this conference, this paper is based on the FIND project "Evaluation of well results". Here we tiy to summarise the main findings with the aim of making suggestions for an improved exploration process. This paper does not intend to give answers to all the challenges we as explorationists are facing, but to give some practical suggestions for improvements.

The petroleum exploration process can be illustrated by Figure 1. Evaluation of open acreage results in application for licences which hopefully leads to licence awards. As hydrocarbons can only be discovered by (expensive) drilling, the crucial decision is where to drill. The well proposal should take into account regional evaluations of petroleum systems, plays, and prospects and be based on a detailed evaluation of the prospect selected for drilling, concluding with where to locate the well and the well prognosis. The outcome of exploration drilling is either a dry well or a discovery of a certain size. The sources for the data reported into the FIND database are shown in Figure 1. The arrows indicate the importance of bringing what we have learned from the well back into a re-evaluation of the petroleum systems, plays and the licence prospect portfolio.

Concepts of petroleum systems, plays and prospects provide a useful framework for ideas. A sedimentary basin can contain one or more petroleum systems (or none!), which again can be split into separate hydrocarbon plays. A play can be defined as a family of fields, finds, drilled unsuccessful features, prospects, leads, and postulated (unmapped) prospects that are known or conceived to share the same gross reservoir, hydrocarbon charge system and regional seal. Evaluation of hydrocarbon plays is regarded as the best way of assessing the prospectivity of a region and will also assist in prediction of resources and their rate of discovery. This leads on to the essential step in the exploration process: the mapping and evaluation of prospects. When evaluating a single prospect for volume prediction and estimation of probability of discovery, one should bear in mind two important aspects. Of the factors involved in the volume calculations (area x thickness x net/gross x porosity x saturation x shrinkage/expansion x recovery), rock volume is enormously important. The rock volume involves reservoir thickness and area, the latter being directly related to the hydrocarbon column. Of the factors involved in the probability estimation (e.g. reservoir x seal x source at play level and reservoir x trap x source at prospect level), it is important to remember that the probabilities of all of them have to be 1.0 to make a discovery.

From lecture 2, with respect to prospect resources vs discovered volumes, a main conclusion is that hydrocarbon pore volumes are overestimated. This is reflected by a strong overestimation of rock volume and hydrocarbon column height, overestimation of thickness and saturation, and poor estimation of net to gross ratios. In fact, error in prospect rock volume can explain 70% of the resource prediction errors. Often the reason is a confusion of "total prospect" volumes with "segment" volumes being explored by the well. Improved understanding of the uncertainty in prospect volume could be achieved by division of some 28 prospects into areal segments and, sometimes, vertically into reservoir segments. Such an exercise can help answer the question of how many exploration/appraisal wells are needed to prove up the total prospect volume, information which is needed to be able to evaluate the commercial value of the prospect. Incorrect estimation of hydrocarbon column can be explained by an overestimate in hydrocarbon charge volume, by shallow spill or leak points that are missed or by incorrectly mapping the structure. Improved understanding of the prospect could sometimes be achieved by carrying two or more geological/geophysical models through to the end stage in the evaluation, where they can be weighted according to how likely each is. Further, Figure 2 illustrates that multiple resource volume calculations should be made to be able to answer essential questions regarding a prospect proposed for drilling. One interesting aspect here is that prediction of the hydrocarbon column expected in the well is often missed out in the documentation (or never calculated?). This factor is a unique value that links the prospect evaluation together with the well location, and is the easiest parameter to compare pre- and post-drill.

From lecture 3 the conclusions on probabilities and finding rates are not all that bad on average: a prediction of 23% compared to a finding rate of 27%. However, finding rates show large variations between areas and plays which are not reflected in the predictions. A useful check on how well we understood the separate risk elements pre-drill is, in case of a dry well, to compare the post-well reason for dryness with the values assigned before drilling to the individual probability parameters. This study shows that most often they compare well with the lowest probability parameter. There are individual cases, however, where the main pre-drill risk was not understood and the well should probably not have been drilled. A main challenge is to understand and communicate how prospect probabilities and prospect volumes are related. To understand this correctly is crucial when it comes to commercial evaluation and hence the decision to drill or not.

In any exploration strategy, drilling the right prospects in the right play and exploring prospects in the right order to maximise outcome and information is essential. This requires that approved methodology is used, and that the prospects have been assessed consistently from one area to another, from one play to another and from one year to another. To assist in achieving these requirements, it is recommended to have a permanent “peer assist” team to review the evaluation work before prospects are approved for drilling.

Experience from the FIND project is that there often is a “Berlin Wall” between pre- and post-drill documentation. Figure 3 illustrates this challenge: to have a seamless chain of data sources in reporting at the different stages in the evaluation. The “FIND data” should be assembled - pre-drill in the Drilling Programme and post-drill in the Completion Report - and inconsistencies should be explained in the Dry Well or Discovery Evaluation Reports.

As a final issue, the importance of understanding the cycle of exploration for a play should be emphasised. The cycle is illustrated in Figure 4 by an “S-curve”. Before a play is proven, a main target should be to keep the number of dry wells at a minimum. Once we realise why and how the play works, drilling the right prospects in the right order will determine the steepness of the curve. As the steepness of the curve tapers off, we have to know when to leave the play, i.e. “when the play is played out”. The petroleum exploration process tf ;^,jw/WMS^'>C'V'V' W- *~f~. #*• *V- J~ V vy^r-^v »!**>“>• F >-X^3Y"T'tX % Sz-

Licensed acreage evaluation Acreage evaluation Which prospectto drill? Appraisal of well result

Petroleum System f

Exploration strategies FIND - Presentation No. 4 Fig.l

Resources: multiple volume calculations

!m fr. £- >''>* ♦<.«*•>» «• JO Jo- fcw V w¥~- »*- p, %.<% «? ?t SX 5^ t5 V

Suggestions: Exploration well - measure resources proven location by well - compare like resources before and after drilling - multiple volume calculations before choosing well location - assess how many wells needed to prove resources

Volume

FIND - Presentation No. 4

Fig.2 3o A seamless chain of data sources

faluati

Exploration Well 4,Memo'tl

programme report

forecast report

FIND - Presentation No. 4

The cycle of exploration for a play: “S-curve

Field size zero medium small Finding rate zero higher varies Cumulative volume Sector 2 3 (x106Sm3) 1000

Number of prospects drilled Main exploration questions: size of prize? Up _ how many wells before first discovery? ||§} Steepness of curve? ii# FIND - Presentation No. 4 ^ * Fig.4 34

Middle to Upper Jurassic syn-rift development on the Horda Platform, Lomre and Uer Terraces, Northern North Sea: Implications for prospectivity.

Hans Christian Briseid 1, Tom Dreyer2, Roald Faerseth1, Kjell Ove Hager2 and Audun Groth1

1: Norsk Hydro U&P, Vaakero, Oslo 2: Norsk Hydro U&P Research Centre, Sandsli, Bergen

This paper addresses the syn-rift development of the Bathonian - Ryazanian succession on the eastern margin of the Viking Graben, encompassing the Horda Platform and the Lomre-Uer Terraces.

The objective is to show how the understanding of a presumably mature area of exploration has developed through it's exploration history. Recent work has increased the understanding of the syn-rift succession in this area, and the focus of exploration has changed accordingly. In short, this involves a shift from the search of obvious targets at the crests of rotated fault blocks towards a search for more subtle traps and reservoirs of syn-rift origin.

The middle to upper Jurassic succession (Viking Group) was deposited during a period of active extension in the North Sea and consists of shallow marine deltaic sediments derived from the Norwegian mainland. These clastic wedges built outinto a basin deepening to west where they interfingerd with coeval mudstones. In front of these deltaic systems sandy gravity flows were deposited. A number of exploration wells, several of them successful, have been drilled in this area, and because the existing play model has been structural highs with the Brent Group as the main target, most of the wells are drilled on such structures. However, since these structures became uplifted during the syn-rift period, the stratigraphy observed on structural highs are notrepresentative of the syn-rift succession. The seismic data indicate that the thickness of the syn-rift package increases downflank from the highs. Stratigraphic variation can also be documented from wells where specific intervals are absent or condensed relative to nearby wells. This probably reflects differential movement of individual fault blocks causing the footwall of the fault block to become either subaerially exposed or emerge as an intrabasin submarine high. Although sand has been encountered in most of the wells in a more basinward position, the sands are thin and laterally restricted, and there is good reason to expect thicker sand units in a downflank position. This assumption was confirmed by well 35/11 -8s, the first well drilled with a syn-rift prospect as the main target. This well was drilled in a downflank position and proved the presence of 130 m turbidite sandstone with very good reservoir properties.

Detailed geological mapping has provided a high-resolution geological model for the syn-rift strata in the area of interest. Such detailed mapping has proven to be critical for an optimal evaluation of prospectivity. In order to achieve this geological understanding, emphasis is made to the integration of detailed 3D seismic mapping, sedimentology, sequence stratigraphy, biostratigraphy and structural geology. The challenge is to combine these data into a coherent model to understand the timing of faults and thereby the basin physiography as this controls accommodation and sediment dispersal patterns.

The Jurassic extension commenced in late Bajocian and evolved under conditions of increased extension which in some areas continued into the earliest Cretaceous. In general, N-S striking faults, inherited from the Permo-Triassic rift-episode were most important during the early rift-stage but NE-SW striking faults became increasingly important throughout the rift-episode. The rifting occurred through a series of tectonicor rotational tilt phases separated by periodes of tectonicquiescence. The rifting was also diachronous in different areas of the basin. Hence, tectonic subsidence within the basin is episodic and spatially complex. The Nordfjord-Sogn 30. detachment zone running approximately E-W along the transition between the Uer Terrace and the Horda Platform separates two areas with distinct differences in tectonic regime. The Horda Platform is almost unaffected by Jurassic stretching whereas the areas north and west of this detachment zone is dominated by closely spaced normal faults trending N-S and NE-SW, making up a series of half-grabens that defines terraces stepping out towards the rift interior.

Based on sedimentological, biostratigraphical and seismic data the syn-rift succession is divided into five megasequnces (H, K, F, S and D, broadly corresponding to the main lithostatigraphic units). These megasequnces are furthermore subdivided into a total of 20 sequences. The oldest megasquence (H) in the study area reflects initial fault-block rotation and upwards deepening with stepwise drowning of the Brent Group system. It is generally shale-prone without development of deep-water environments within the study area. The following megasequence (K) records the stepwise progradation and rapid retreat of the "Krossfjord" deltaic system during a period of relative tectonicquiescence. The deltaic progradation only affected the central and eastern parts of the rift shoulder and no major basinal deep-water sands have been found. Megasequence (F) encompasses the stepwise progradation and complex, tectonically-related backstepping of the largest deltaic system of the studied succession, the "Fensfjord" delta. This late Callowian phase of pronounced fault block rotation initiates the main tectonic rifting phase in the syn-rift succession and terminated the coastline regression and created local intra-graben highs with some sand reworking. A major transgressive event marks the onset of megasequence (S). During the tectonic quiescent period that followed, the progradation of the "Sognefjord" longshore delta took place. Renewed block faulting halted and subsequently reversed this prograding trend. Deep-water sands were deposited both during the early transgressive phase and the later tectonic phase of this interval. The youngest sequence (D) commences at the Oxfordian-Kimmeridgian transition and is characterised by accelerated subsidence and intense structural deformation that led to development of local depositional systems flanking intra-graben highs and an increase in the rate of relative sea-level rise. By middle Volgian times these highs appear to have become fully submerged, and the entire area was subsequently mudstone-dominated. 33

Exploration Potential East of Troll after Dry Well 32/4-1

Philip Goldsmith - Phillips Petroleum Company Norway

In February 1996 a group comprising Phillips (operator), Statoil, Norsk Hydro and Total, were awarded PUZOS in Norwegian Northern Nc rth Sea Quadrant 32. Prosper* Alpha was drilled in 1996, by well 32/4-1, but encountered no hydrocarbo is. Failure was attributed to lack of hydrocarbon migration, previously recognised as the principal risk for the licence. 18 months of subsequent studies have been aimed at quantifying migration and fault seal risk in more detail, to evaluate the potential of the remaining prospects. This paper summarises those studies and highlights how the group has learned from the well result in assessing migration and seal risk

Pre-drilling Geological Model Within PUZOS four prospects were recognised in Oxfordian sands of the Sognefjord Formation. These are well defined for exploration purpo ses on the extensive 2D seismic data. Prospect Alpha is a footwall ulusuie, to the east of Troll East well 31/6-5, with 60m of relief and a maximum area of 33km, and Is adjacent to the East of Troll Fault Zone (ETFZ), a series of linked north-south faults approximately dividing Quadrants 31 and 32. Prospect Beta, with 140rr of closure and an area of 68km 7 , lies to the east of Alpha in the hanging wall of the Oeyoarden Fault Zone (OF7) and relies on cross-fault seal against Basement. Prospect Gamma is a low relief, four-way-dip closure, with 35m of closure and an area of 51 km2, lies to the east of well 31/6-3 and on an alternative migration retie to Alpha and Beta. Prosper* Theta , with 24nm of closure and an area of 113km2, lies to the east of Gamma and to the south of Beta and, like Beta, relies on cross-fault seal on the OFZ, but against Mesozoic sand rich facies as well as Basement. In Phillips’ licence application Prospects Alpha and Beta were assigned moderate and high exploration risks respectively, and yielded viable economics due to piuximily lu infrastructure or their large size. The principal risk factor at Alpha was migration, while at Beta there was additional cross-fault seal risk. Prospects Gamma and Theta were regarded as a leads because of small size and high seal failure risk respectively. RMS Amplitude extraction, performed at the Top Sognefjord seismic event, showed amplitude attenuation (dimming) over Troll East, due to the presence of gas. it was concluded that similar dimming at Prospect Alpha could be related to hydroca tons, but not gas, as there Is no flat spot as in Trail. Dimming at Prospect Beta, was evaluated to be related to lithological changes. AVO modelling on Alpha and Beta confirmed that only liquid-fill (oil or water), rather than gas-fill, was possible. Consequently the chance of finding oil was put at around 3 to 1, The principal exploration risk for all the prospects in PL205 was recognised to be migration. A number of regional IKU uun-piupiletaiy studies were available prior to the licencing, but none covered the iron area and PUZOS specifically. Migration into PL205 from the Troll Field, which is apparently full to spill, was seen as a strong possibility. Migration modelling using 2D software was attempted, during the Round, but the results were inconclusive There is a dry well, 31/6^3, on the apparent direct migration route from Troll East to PL205, and this was seen as a major negative factor in risk assessment. Initial 2D mapping of the migration route lacked data resolution, so the possibility of migration, north of the obvious spill-point at the southern end of the Troll East Fault (TEF), could not be ruled out. If this were possible the most likely subsequent migration route was evaluated to be initially into Prospect Alpha, with overspill into Prospect Beta. Prospects Gamma and Theta were regarded as no better than I Bads at this stage due to the size of Gamma and the very high cross-fault seal risk at Theta. However, pot sible migration towards these structures could not be ruled-out on our original depth maps.

Well 32/4-1 Results Well 32/4-1 was drilled in the fourth quarter of 1996 on Prospect Alpha and encountered good quality, but wet, Sognefjord Formation reservoir. Seal is present, but the prospect is clearly not on a migration route, since there were no indications at all of hydrocarbons in cuttings, core or on mud or wireline logs. The well tops were encountered close to prognosis and drilling terminated in Basement at around 3200m. Summary of Post-drillinu Studies During 1997/98 a range of specialised studies aimed at understanding tha migration risk in more detail have been conducted. The work conducted included reconnaissance geochemical studies, cetailed hydrocarbon migration studies and fault seal analyses.

Reconnaissance Studies 1) Synthetic aperture radar satellite images showed no evidence of active mauiu-seeps. 2) Seabed geochemical dat a analysis indicated the widespread presence of thenmoaenically derived oil and condensate micro-seepage. This probably results from cap-rock leakage above Troll with up- dip migration in the Tertis ry strata. 3) Residual hydrocarbon analysis on "dry" wells, showed that traces of light hydrocarbons were present in wells 32/4-1,31/6-3 and below the GWC in 31/6-6. Wc know that the 32/4-1 result is from mud contamination and the Troll East well results are coincident with those of Horstad and barter (1996) for other Trnil well? and also point to a contamination origin.

Migration Studies 4) New structure mapping und depth conversion incorporating the Troll East 3D survey, which was kindly made available to the partnership by the Troll Group was used to define potential migration routes from Tiull East and within PL205. 5) Palaeo-structural modelling was conducted using 2D and 3D structural restoration to remove the results of Tertiary tilting using Geosec 2D and Locace 2D initially, followed by full surface restoration using SDMove . These models were calibrated with: i) Palaeobathymetr/ estimates from quantitative foraminiferal analysis in key wells

II) Apatite fission track thcrmochronology, vitrinite reflectance and 1D geohistory modelling, lo determine uplift.

iii) Well log sonic ve ocity analysis, to determine uplift. This major piece of work demonstrated that only modest amounts of Tertiary uplift have occurred on the Horda Platform. A north south line through Troll West represents the hinge line for monoclinal tilting, eastwards of Troll towards the west, with uplift at the present coastline of around 1500m (+/-25Qm) and around 600m at well 32/4-1. 0) Migration modelling was conducted by 1KU. Tne group utilised part of a regional hydrocarbon migration model, which hcluded the PL2Q5 and Troll Field areas. Volumetric inputs and timings were modelled with Phillies' sliuclute maps. 7) AVO modelling and analysis of prospects Gamma and Theta, to determine the likelihood for the presence of gas.

Fault Seal Studies

8) Fault rock characterisatio i from cores and fault seal analysis was conducted on the TEF and the East of Troll Fault Zone (EiTFZ),

9) seismic modelling of potential lithologies along the OFZ was conducted to evaluate their effects on fault seal. Seismic charac.er changes approaching the fault are suggestive of changing lithology and possible development of coastal plain facies. These may result in better seal potential than the normally high net to gros:. ratio of the Sognefjord Formation. 10) Fault seal analysis was conducted using a shale smear approach for the modelled hanging wall and footwall lithologies on the <\X>FZ. and on the TEF and ETFZ nn the migration route Based on the work of Lindsay et al. (1593) and Lehner and Pilaar (1997), shale (or coal) smearing always seals at displacements of up to seven times bed thickness, and in coal measures has been demonstrated 35

to seal at displacements of up to 70 times the bed thickness. Fur this study smears up to 7X bed thickness are regarded as continuous and between 7x & 70x are regarded as potentially discontinuous. Cataclasi> and diagenesis are not accounted for, but would in mease seal potential, in the earlier work these factors were taken into account, but a minimum shale smear of only 2x bed thickness was used.

Summary of Results - Migration from Troll and Prospect Seal Migration in Troll EastTroil East was probably only full to spill around late Pliocene. Palaeo-structure maps indicate that 31/6-3 would have been charged by spill any earlier. This is also indicated by the palaeo-OWC on Troll, which has a tilt of 0.3° to the west. Palaeo-structural modelling indicates an overall Tertiary tilt of 1.2°, with the largest tilt of O.C° occurring during the Pliocene. Regional migration modelling studies concluded that If It occurs at all, migration could only have taken place since the latest Pliocene, after most of the Tertiary structural tilting. It is only with the present-day structure that alternative migration routes are potentially viable. Bull: gas arid )!I could oe migrating up-dip. The iron bast oil column is very thin and possibly not present in the east of the field. The present-day oil column is tilted (Horstad & barter 1996), which is possible evidence for an active flow to the east. It is possible that the all Is migrating In 'Streams", by-passing large areas of the fi sld and thereby being undetected by most well penetrations. Migration modelling by IKU also indicates that more hydrocarbons may have passed through Troll than are now present In the Field or attributable to cap-rock leakage, and these could be trapped in up-dip structures.

Migration Past the Troll East Fault (TER The Troll East 3D structure map sttop Sognefjord indicates four possible migration routes from Troll Field: i) Around the southern tip t-f the TEF. However, this would fill the dry structure tested by well 31/6-3. ii) At a fault segment linkage point to the south of well 31/6-2. The saddle in the hanging wall is probably too deep.

iii) At a fault linkage to the north of well 31/6-2. The saddle may be too deep here also, but Is within mapping sensitivity. Leed.s RDK show probable cross-fault communication here, based on well 31/6 2 lithologies. In-house analysis tends to confirm this. Oil, by-passing well 31/6-2, could possibly miyiale this way. The Tef will have zones of discontinuous smear in the fault linkage area to the north of well 31/6-2, based on the lithologies from this well. These are present above and below the existing GWC. However, leakage across the TEF above the GWC is viable as there is closure on the hanging wall between the main fault and the linked fault down to around the same level as the GWC of Troll Cast, so leakage could occur above Hie GWC at the fault as the hanging wall and footwall would be in effedive communication. Onward migration would by-pass well 31/6-3. iv) Around the northern tip c f the TEF. Direct spill avoiding well 31/6-3 is possible via this route, but would probably be of gas. Well 31/6-6, near the eastern tip of this route from Troll, has only gas.

Migration Through the East tif Troll Fault Zone fETFZ)

Hydrocarbons by-passing well 31,6-3 would migrate into a fault linkage zone in the ETFZ where offsets are low. Initial studies show that, with 32/4-1 as the footwall lithology and 31/6-3 as the hanging wall lithology, this fault will leak. In-house shale smear analysis tends to confirm this, but with 31/6-3 lithologies on both sides sealing is likely.

Migration Beyond the ETFZ Structure mapping now demonstiates a clear migration route from the ETFZ towards Prospect Gamma. Prospect Alpha is dearly off the rrute and this explains the dry hole.

Aie there any hydrocarbons in Prospect Gamma? pvi properties ot i roll oils indicate that any oil migrating up-dip would result in gas coming out of solution and the development of gas caps or gas-only accumulations in structurally see led closures, such as Prospects Alpha and Gamma. Any oil would then bypass beneath such closures. Inperfect cross-fault seals, as might be found in Prospects Beta and Theta, might result in the loss of such a gas cap and therefore gas would not be detected on seismic, but hopefully the oil would be retained. AVO modelling was conducted using well 32/4-1 and analysis was performed on seismic data crossing both Prospects Gamma and Theta. This eonfimieU llie earlier studies on Alpha and Beta, which indicated that gas should be visible by AVO analysis, but that there is no evidence of gas in these prospects.

Oevgarden FauK Zone OFZ) In order to match the different seismic character near the OFZ three lithology models were tested using proprietary synthetic and inversio i modelling tools. In each model coal, coal plus mud and mud layers were added lu the 32/4-1 well synthet c seismogram, to attempt to match the seismic data at the OFZ. All the models produced better than a 75% correlation for amplitude and shape, with the coal model giving the highest correlation. These models were then used as input to in-house fault seal analysis, using a shale smear approach. All of the modeled lithologies have a high probability of sealing. Migration from Prospect Theta to Beta would rely on filling of Theta down to Its spill-point. It is considered very unlikely that this could occur. Prospect Beta relies on fault seal mainly against Basement. Tertiary denudation and post-glacial uplift are likely to have generated pervasive stress-ielease fractures, but the regional nigh lateral compressive stress, orthogonal to the fault, may help to keep it sealed.

Revised Prospectivity Assessment As a result Of these studies the dry hole at Alpha is explained. The future licence activity is still being decided by the Group in the light cf these studies.

Lessons Learned i) We believe that the Troll petroleum system is too large and complex to be modelled accurately enough to define if it Is potentially only just full to spill or spilling hydiuvaibons eastwards. Despite this, detailed, regional, basin modelling should be regarded as essential and should be completed prior to licencing even in a mature area. ii) Attention should be paid to PVT properties. Together with the AVO analysis this has done more to improve our understanding of risk than any of the other studies.

ill) Access lu 3D data Is critic,;l for structural analysis of subtle migration routes. However even with the 3D data it is not possible to be certain where migration would occur from Troll East, if at all. iv) Well to seismic correlations, and data polarity, should be very carefully assessed. Original top Sogneljord Amplitude anomalies are probably lithology changes within the Heather Formation. Without this the analogies with Troll East, for presence of hydrocarbons, do not exist. v) Fauli rock characterisation and detailed laull-plane Juxtaposition sections should be produced to assess fault seal risk. Although the non-uniqueness of the inputs in exploration areas makes the results herd to assess, this technique can aid in quantifying fault seal risk. Exploring the Barents Sea Shelf - How Norsk Hydro applies experiences

Stig-Morten Knutsen, Jan Harald Augustson and Pal Haremo* Norsk Hydro Exploration Harstad, P.O.Box 31, N-9401 Harstad, Norway 'Norsk Hydro Exploration Vaekere, P.O.Box200, N-1321 Stabaek, Norway

Since hydrocarbon exploration started in the Barents Sea with the 5th concession round in 1979, 53 wells have been drilled (Figure 1). No commercial discoveries have so far been made; one exception is (or may be) the Snohvit field in the Hammerfest Basin, which was discovered in 1984-1985.

A key issue that should be adressed when exploring and evaluating the Barents Sea Shelf is what factors of an effective hydrocarbon system have not been working in the area. If such a factor or factors are identified, how, and where, should further exploration take place, or not take place.

Illustrating the experiences Hydro has gained in the Barents Sea Shelf, five tested playmodels will be used as examples. The playmodels range stratigraphically from rocks of The Palaeozoic to The Cenozoic, and geographically from the platform areas in the east to the margin in the west.

The five playmodels are localised in different areas on the Barents Sea Shelf and are tested by one well each (Figure 1, Table 1). In the so far northernmost exploration well, Tertiary structural traps were tested by well 7316/5-1 in the Vestbakken volcanic province in 1992. In the northeasternmost part of the Hammerfest Basin, a Lower Cretaceous submarine fan was tested by well 7122/2-1 in 1992. Along the southern margin of the Loppa High, in the Asterias Fault Complex, a Lower Cretacous wedge was tested by well 7120/2-2 in 1991. Jurassic rotated fault blocks have been tested by several wells in the Barents Sea. Well 7219/9-1, drilled in 1987-1988 in the Bjornoyrenna Fault Complex has been selected to represent this playmodel. The Palaeozoic carbonates on the Loppa High was tested by well 7120/2-1 in 1985.

All of the playmodels proved the presence of reservoir. Three of the playmodels, tested by wells 7219/9-1, 7120/2-1 and 7120/2-2 had oil shows, the first two indicating thick fossil oil columns. Well 7122/2-1 had no oil shows, and the westernmost well 7316/5-1 proved in minor volumes of gas, dominated by methane.

One of the experiences Hydro made was that the presence of reservoir is not the most critical factor in the Barents Sea Shelf area.

The extent of the oil shows, at least in the areas surrounding the Hammerfest Basin, also implies that the source rock concept seems to have worked. The lack of oil shows in well 7122/2-1, in an area where a mature source rock interval is divided from the reservoir by only a 10 meter interval is, however, intriguing (Figure 2). Further, in this well free oil available for migration is today present in the source rock i.e. the Hekkingen formation, but has not yet been expelled (Figure 2). No pressure barriers could be found when the well was drilled. One hypothesis for the puzzle in well 7122/2-1 is that the lack of migrated oil in the Lower Cretacous fan overlying the mature Hekkingen Formation was due to gas already filling the reservoir, and that the gas then prevented the oil migration to the reservoir. Since the Lower Cretaceous fan was empty when drilled, the gas must have been naturally drained, possibly during uplift and erosion. The oil in the source rock, however, has not yet managed to get to the very adjacent reservoir, hence this is an indication on that drainage may be fairly recent. 39

The lack of trap, or seal, is often suggested to be a devastating factor for finding oil in the Barents Sea Shelf area. In several cases oil filling and later drainage have been demonstrated (e.g. Augustson 1992). Two such wells are 7219/9-1 and 7120/2-1. Figure 3 illustrates the relationship between heavy oil (C15+) and porosity in the carbonate reservoir interval in well 7120/2-1 on the Loppa High. The plotted signature, showing a decreasing heavy oil saturation with increasing porosity, is diagnostic for drained reservoirs. Thus, the initial sealing capacity of traps related to some of the play models does not seem to be a critical factor. However, the fact that gas discoveries have been made, i.e. well 7316/5-1 and in the Snohvit field area, tells that at least some types of traps can cap the gas, and therefore also should be able to trap oil.

To Norsk Hydro the exploration in the Barents Sea Shelf, as illustrated by the examples quoted above, has acknowledged the importance of the time factor. Both the long term sealing and the timing of different phases of hydrocarbon generation and migration versus trap formation must be evaluated for each type of play model. In the Barents Sea area the three main factors of a hydrocarbon system; the trap, the reservoir, and the source, must be integrated with the fourth factor: time.

In a broader perspective these factors ends up with the puzzle to understand the structural evolution of the area. According to Norsk Hydros opinion it is especially important to understand the pros and cons of Late Neogene tectonical movements. Traps that so far have proven to be sensible to leakage should be avoided whereas play models related to stratigraphic traps and salt related traps could have interesting potential. Norsk Hydros view is, however, that the main exploration focus should be in areas where the structural evolution favours late oil generation and migration, and to areas where the Tertiary structural evolution is represented by the most complete stratigraphic intervals. This will provide a better understanding of the periods when it is suggested that large parts of the Barents Sea Shelf was exposed to erosion, i.e. the Tertiary and especially the Late Neogene. It is likely that this can prevent situations as given by the case history from well 7122/2-1. Areas with the most complete and preserved Tertiary, and especially Late Neogene intervals, is also more likely to have trapped hydrocarbons more efficiently and over a longer period of time than areas exposed to, maybe, several phases of uplift and erosion. Thus, the possibility for an effective seal in certain areas coincides with increased possibility of optimum timing of generation and migration of hydrocarbons.

References: Augustson, J. H. 1992. A method on classification of oil traps based on heavy oil content in cores with relevance to filling and drainage of Barents Sea oil-bearing structures. In: (Eds. Vorren et al.) NPF Special Publication 2, pp. 691-702.

Table 1: Wells and tested playmodels discussed

Well, year drilled Location Play model Critical factor(s)

7316/5-1, 1992 Vestbakken volcanic province Tertiary rotated fault blocks Source/Timing/Seal? 7122/2-1, 1992 Hammerfest Basin (NE) Lower Cretaceous fan Migration/Seal ? 7120/2-2, 1991 Asterias Fault Complex Lower Cretaceous wedge Migration/Seal ? 7219/9-1, 1988 Bjornoyrenna Fault Complex Jurassic rotated fault block Seal 7120/2-1, 1985 Loppa High (S) Paleozoic carbonates Seal 34

OD Hydro operator □ Hydro partiera r~1 Hydro non operator ('"•I Seismic areas # Weis discussed

[~7l2gg? « 171220-1 1

HA2214.FH7

Fig. 1 Location map ha2213 • 08 88 f17»0Z7-08

The lack of oil shows traces-' from mature Minimum • CI5+ and expelling Hekkingen Fm. porosity for saturation is almost drainage — SCO ppm he mysterious I — 5000 ppm he — 10% porosity

Filled reservoir

5000 ppm

* 10- Ha2218.fh7

traces 27.08.98

TOC (%) EOM (in 1000 ppm) % HC of EOM Core porosity (%)

Fig. 2 Distribution of heavy (C15+) oil in the Knurr, Fig. 3 Drainage of oil from reservoir drilled by Hekkingen, Fuglen and Sto Fms in well 7122/2-1. well 7120/2-1 4(

The Exploration Experience from the Midgard to the Kristin Fields

Hans Chr. Ronnevik Vice President Exploration Saga Petroleum ASA

The resource growth history and the large unexplored areas place the Norwegian Sea as the prime exploration area on the Norwegian Shelf. This was not the situation at the time when exploration started in 1980 and during most of the long period of slow reserve growth from 1985 to 1995. However, the

Nome discovery sparked a renewed interest in the area.

The proven resources in the Norwegian Sea are passing the predrill expectations estimated by area yield methods in the late 1970 ’s. To date the high estimates of those days cannot be regarded as unrealistic.

The discoveries in the Norwegian Sea are in general larger than the predrill estimates.

The main lesson learned is a change of perception through action and not in tools, methods or theories.

The general structural setting and kinematics history has been known since the predrill phase and the changes of perception are linked to subtle factors related to reservoir and source rocks.

Improvement in exploration will always be related to acceptance of uncertainty as the room of possibilities and the fundamental acceptance of learning as a bottom up process. The learning process can be enhanced by increasing the ability to integrate unfiltered unconformities from a diversity of methods.

J:\EU\U12480\hci\DI98-026.DOC 1 Mill. Sm3 o.e. 98082402.EXA.HCR.SHoe Norwegian 1980

1981

1982

1983

Sea 1984

1985

Resources

1986

1987

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and 1990

1991

Discovery 1992 Year

1993

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1996 History

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Mill. Sm3 o.e. 43

THE NORWEGIAN SEA AND THE 15th CONCESSION ROUND, CHALLENGES IN A NEW EXPLORATION AREA

Pal Haremo, Audun 0vretveit and Nils Telnass, Norsk Hydro

ABSTRACT

By opening of the Norwegian Sea for exploration drilling in 1994 and the announcement of blocks in the 15th concession round, the authorities initiated an exciting race aimed at disclosing the commercial hydrocarbon potential of this virgin exploration area. Based on knowledge acquired through considerable exploration effort in the last decades, in the North Sea, along Mid-Norway and in the Barents Sea, Norsk Hydro early decided to be an offensive participant in the coming exploration campaign in the Norwegian Sea. Throughout the late eighties and the early nineties, Norsk Hydro, by extensive interpretation of regional seismic data and development of regional , geological models, was establishing a solid Norwegian Sea knowledge base and a strong position among oil companies participating in the 15th round in this area.

The first blocks that were announced in the Norwegian Sea exhibited several play models that generally were expected to have a high risk, but with enormous volume potentials. The number of blocks announced, in the 15th concession round, and the wide geographical distribution made it clear to Norsk Hydro that the company could not participate in all areas. This made the process of ranging play models as well as risk dispersion an integral part of the company's strategy in the 15th round. The technical evaluation of the different exploration areas thus formed a cornerstone when the company ranked the different blocks.

One important conclusion from the technical work carried out prior to the 15th round application is that considerable parts of the Norwegian Sea must be regarded as gas prone with very high risks connected to oil prospectivity. The best possibilities for oil is thought to be positioned on the flanks of basins. High risk is generally also related to the reservoir concept in the Norwegian Sea. To be able to identify play models with high possibility of reservoir sand is regarded as critical for success. Generally it is regarded to be less risk attached to trap concepts in the area.

The licenses awarded, to Norsk Hydro in the 15th concession round reflect in a good way the priorities of the company. At present Norsk Hydro is encouraged by the 15th round Norwegian Sea drilling results. The final result, which decides whether our priorities have been optimal, remains unanswered until more of the play models within the basin has been tested.

MAKING EXPLORATION PAY -

TECHNOLOGY, HISTORY, DISCIPLINE

Stuart J. Moncrieff Manager, Geoscience Technology Mobil E&P Technology, Dallas, Texas

ABSTRACT

Making money in the exploration business should be easy. Today's tools and technologies are far better than yesterday ’s; revealing structure, stratigraphy and sometimes reservoir properties and pore fluid ■ content with unprecedented clarity. Industry’s technologies and processes are sufficiently good in 1998 that it's often possible to very reliably assess the value of an undrilled portfolio of prospects and to bid what it’s worth. Once exploration rights are acquired, all that remains is to drill out the portfolio and produce the economic return. It all seems relatively simple.

Unfortunately, the exploration business doesn’t always work out this tidily or profitably. Three keys to exploration performance are technology, history and discipline.

New technologies are vital to operational and financial success. I will briefly show two important technologies that facilitate Mobil’s exploration decisions around the world ... neural networks and basin simulation.

No assessment of the performance of an exploration process or technology may be made without historical data. Analyzing exploration history can yield a clear and unbiased view of technical and business performance and improve future processes and investment decisions. Historical analyses require a long-term commitment to excellent record keeping.

All investments, from determinations to shoot seismic through decisions to drill wildcats should be based on the value they are expected to add and aimed at the decisions they will drive. Historical data can and should play a vital role in deciding whether or not to invest and how much ?

Good business decisions require an understanding of the limitations of technology and an accurate view of prospect and play risk and potential; a view rooted in reality and undistorted by “rose colored glasses ”. Good business decisions should more often be “No I I’m not going to drill that prospect I”.. and less often “Yes ! Go get a rig I”.

While not a guarantee of success, the appropriate use and integration of today's wide array of technologies, the use of historical data to improve predictions and learn important lessons from the past and lastly firm discipline in using technology, knowledge and information should make exploration pay off.

EXTENDED ABSTRACT FOR THE CONFERENCE ON IMPROVING THE EXPLORATION PROCESS BY LEARNING FROM THE PAST, NPF, HAUGESUND, SEPTEMBER 1998

FROM BASIN MODELLING TO BASIN MANAGEMENT REUSE OF BASIN SCALE SIMULATIONS Arild Skjerv0y (Conoco Inc.), 0yvind Sylta (IKU), Kate S. Weissenburger (Conoco Inc.)

BRIEF DESCRIPTION OF STUDIES: Norske Conoco carried out its first SEMI study in 1990 as part of the 13th Round evaluation and addressed specifically the risk associated with hydrocarbon charge in block 30/12 prospects in the Northern North Sea. The first phase of the study addressed the total regional drainage area relevant to the prospects in the block, the kitchen area volumetries and fill-spill relationships to surrounding proven fields and discoveries. Detailed maps of Block 30/12 and contiguous areas were used in a second phase of SEMI modelling and evaluation for more rigorous detail analysis of migration paths within and in the vicinity of the block. The study also included one of the earliest documented attempts on the Norwegian shelf to quantify saturation-dependent expulsion from the source rocks and also investigated volumetric sensitivities to two distinctly different migration scenarios related to the direction of expulsion flow from the source rock (Skjervpy and Sylta, 1993). This early study revealed hitherto unappreciated risks such as the likelihood of prospects being situated within migration shadows and difficulties with coexistence of certain prospects. The study provided a better understanding of expected petroleum phase in the event of discovery.

A second study took a fully integrated approach to the Northern North Sea blocks on offer in the 14th Round (1992-93) to obtain a rigorous assessment of the various opportunities on offer and their petroleum systems related risks. The study area encompassed the Norwegian shelf between 60 and 62 degrees N. Conceptually, the study featured many of the basic approaches developed during the earlier modelling exercise (source rocks, expulsion, etc.) but it took advantage of improved Information Technology capabilities, improved and integrated modelling tools and better records management. Here again, a calibrated regional model was used as input to a second phase of migration modelling employing detailed, block-specific maps in the prospective areas. The study provided a data-constrained framework for prospect evaluations and served as a key component in the ranking process of the then-available opportunities.

The third study was designed to evaluate a specific opportunity on offer in the Northern North Sea in the 15th Round. The study was closely related to the history and volumes of the Troll field. As before, the past work was used as building blocks to accomplish the evaluation. In this instance the regional modeling results from the 1992 study were reused in combination with the detailed mapping of the subject blocks. Hence, the basics of the volumetric inputs remain the same. However, by now SEMI had developed several new features that allowed testing of uncertainties such as those resulting from shallow leakage out of traps due to insufficient cap rock capacity, uncertainties in seismic mapping that influence spill directions and easy scanning of how important variables influence the amount of oil and gas trapped.

The change in computing paradigms during the time period over which these studies were conducted was also important. The first study was conducted with a minicomputer, and graphical output had to rely on expensive plotters that slowed down the analysis of the migration simulation results. Thus it was only possible to treat one or two simulation runs in a working day. The 15th Round work was performed on a workstation that allowed for much quicker graphical feedback by use of on-screen graphics. This made it possible to assess the results of more simulation runs in a single working day in spite of the much larger models that were run.

Ongoing studies lying within the 60 and 62 degrees N area have built upon the regional calibrated model developed in conjunction with the 14th round evaluations. Adjustments to the regional model have been made in order to reflect advances in our understanding of source rock facies, in-reservoir and in-source rock liquid cracking behavior, and the relationship between overpressure development, cap rock integrity and hydrocarbon expulsion and migration. As in earlier studies, the regional model has been calibrated to the currently known hydrocarbon accumulations and is being used as a framework for detailed block specific evaluations. A somewhat mechanistic but nonetheless significant improvement associated with our current projects is related to new visualization techniques. These have enhanced our ability to communicate modelling results and uncertainties and thus promoted even tighter integration of the modelling with ongoing risk assessments (Fig.2).

STRENGTHS OF THE APPROACH: This approach to basin modelling seems to be most effective in moderately and well-explored areas where the trapped petroleum volumes and proportions of gas versus oil can be used as calibration data. Nevertheless, migration modelling exercises have significant merit in most exploration situations because:

1 40 a) They serve as a powerful geoscience vehicle for bringing together the various elements required to achieve a regional geological framework and a better understanding of the key controls on the petroleum system(s). b) They may result in identification of new elements of risk, additional potential or prospect interrelationships that would otherwise not have been recognized. c) The results can provide a valuable foundation for developing exploration strategies, work programs and contingency plans that are anchored in a more fundamental understanding of the key controls on the petroleum system.

The sequence of studies described above portrays an evolution toward a quantitative (volumetric) approach to basin modelling. The approach has evolved in tandem with industrial developments of improved and probabilistic quantitative integrated prospect analysis tools. An embryonic version of such a tool is described by Snow et al. (1993). Consequently, it is now possible to numerically express the uncertainties associated with basin modelling results, such as charge constraints, hydrocarbon phase, and prospect interdependencies. This has served to link basin modelling evaluations yet more tightly with the risk analysis process.

LIMITATIONS: The methodology has limitations, many of which are related to fundamental geological processes that are still subject to controversy and research. Some of these include: • Secondary migration process and efficiencies (including microtrap losses, rerouting, vertical migration, additional gas losses) • Factors controlling seal efficiencies • Quantitative approaches to source rock facies delineation in three dimensions • Understanding and numerically expressing both fundamental expulsion mechanisms and the components initially generated from kerogen (e.g. initial amounts of gas) • Secondary cracking in the reservoir and the source rock • The role of pressure and faults (conduits or barriers to fluid flow) in controlling hydrocarbon migration

FUTURE: The integrated SEMI approach continues to be applied by Conoco in Norway for regional evaluations as well as for field-specific evaluations. It has recently also been applied in West Africa and will be applied in other basins in the world, with the objective to provide added insights to petroleum systems.

The future of basin modelling seems to trend more towards the modelling of real 3-dimensional grids. Key limiting factors will be the resolution of the available geological data and having access to sufficient computing power to be able to process dynamic 3-D models containing tens to hundreds of millions grid cells through geological time. To model basin systems effectively using this approach requires up-scaling of processes that are often both poorly understood and seismically unresolvable. We consequently expect in the future that the pseudo-3D approach will continue to be refined, to start being used in tandem with 3-D software and represent the preferred cost-effective method of fluid flow modelling, especially at the regional and sub-regional scale.

LEARNINGS FROM THE PAST: • The above studies identify petroleum systems related uncertainties, risks and relationships of prospects. The key uncertainties that characterize one prospect may be surprisingly different from those of another, even within the same geological province or play trend. Premature generalizations should be avoided. • Basin Modelling studies can be used as cost- and time saving building blocks in later evaluations. Upgrades occur for areas that included new data or in the overall model for a new technology or improved methodology. A future “basin management ” approach to exploration can thus be envisaged. • There have been significant technological improvements in terms of the development of more fully integrated tools. The above studies reflect an evolution from a) several parallel evaluations and models needing integration at the end (first study) to b) full integration of most basin modelling within one computer tool as well as extensive reuse of maps, methodologies and results from previous studies. • Basin modelling has now achieved status as an integrated element of prospect and play analysis, as opposed to that of an “out-sourced ” specialist study. Further integration will be achieved when basin modelling tools are more dynamically linked with tools used in routine interpretation and brought even closer to the work face. • By providing a Petroleum Systems context for exploration results, quantitative basin modelling is one of our more powerful vehicles to learn from the past.

2 REFERENCES: Skjerv0y A. and Sylta 0., 1993: Modelling of Expulsion and Secondary Migration along the Southwestern Margin of the Horda Platform; In: Dore A.G. et al. (Editors), Basin Modelling: Advances and Applications. Norwegian Petroleum Society Special Publication No.3. Elsevier, Amsterdam, p.499-537.

Snow, J.H., Dore', A.G., Dom-I.opez, D.W.., 1993: Risk Analysis and Full-Cycle Probabilistic Modelling of Prospects: A Prototype System Developed for the Norwegian Shelf. In: Dore' ctal. (eds.) Quantification and Prediction of Hydrocarbon Resources. Norwegian Petroleum Society, Elsevier, Amsterdam

Sylta 0., Hagen H. and Borgc H„ 1996: Constraining Exploration Risk by Migration Modelling - The East of Troll Case. Oral presentation at the 58 ,h EAGE Conference and Technical Exhibition - Amsterdam, The Netherlands, 3-7 June 1996, Extended Abstract(L004).

closed system open system

migration from expulsion into closed Cretaceous transition carrier bed Into open carrier

Eig. 1. Example of Expulsion/Migration Scenario. This scenario, previously referred to as the “Base Cretaceous Migration Scenario ”, will not allow petroleum migration from the Viking Group into the Brent Group within the “closed” (highly overpressured) system. Petroleum migrates up and/or bedding parallel within the source rock until the fluid potential differential between the Brent Group and Viking Group becomes conducive to fluid transfer into Brent sands. See Skjervpy and Sylta (1993) for discussion of alternatives and volumetric implications. Note that the transition zone shifts location through time.

Fig. 2. Migration and trapping in Brent at 2 Ma. Trapped oil is green, trapped gas is brown. Warm colours show high flow rates. Modeled transition zone barriers plotted as white lines. Notice how oil enters the carrier at the transition zone.

3 So

MODELLING, REUSE AND INTEGRATION ; v \1992 1995 Recent*,; . FEATURES ' . " " ^ audv - Study * . . studies Reuse of Calibrated Reqional Study No No 92 study As required Used in prospect/opportunitv rankinq Indirectly Yes Indirectly If relevant Input to suqqested work proqram Yes Yes Yes Yes Used in probabilistic prospect evaluation No Yes Yes Yes Effective scanninq of sensitivities No No Yes Yes Generation & Expulsion Modellinq Separate Separate 92 results In SEMI** Primary and Secondary Miqration Scenarios Two Two One One SEMI Multi-layer Miqration No No No Yes SEMI Fault and Fracture Properties Modelling Open or Open or Open or Semi- Sealing Sealing Sealing permeable Pressure Modellinq Separate Separate Separate In SEMI** Seal Integrity (Hydraulic Failure) Not relevant Separate Not relevant In SEMI** Seal Capacity (Capillary Pressure) Relations Calibration Separate In SEMI" In SEMI** Parameter GOR Yes Yes Yes Yes CGR No No No Not vet Bo (Gas formation volume factor) Yes Yes Yes Yes Bo (Oil formation volume factor) No Yes Yes Yes

Table 1. Some aspects of Petroleum Systems Analysis in the study area. Elements of improvement from 1990 to 1998. *Recent studies also include ongoing work. **In SEMI = modelled in SEMI as a function of geological parameters.

Fig. 3. Example of exploration considerations facilitated by Migration Modelling. Sufficient volumes of petroleum migrate into the area, but the B and C structures have a high risk of being in a migration shadow. Coexistence of B and C is also problematic. The A structure depends on the existence of a sealing fault. From Skjervpy and Sylta, 1993.

4 51

QUICK MAPPING OF BASIN MODELLING RESULTS -

A KEY FOR QUANTIFYING PROSPECT SENSITIVITIES

Christian Zwach, Norsk Hydro, Torbjom Throndsen, Institute for Energy Technology and Jo Bergan, Norsk Hydro

ABSTRACT

1D and 2D-basin modeling is applied today in the oil industry to define critical geological factors in exploration areas. Different scenarios of the geological history can then be tested and evaluated such as the effect of individual source rock richness or the impact of heat flow evolution on the timing of hydrocarbon generation in drainage areas.

Mapping of these results allows principally to study regional trends of such critical factors and e.g. to calculate hydrocarbon volumes that were available for migration into prospective structures. In addition, the comparison of several scenarios within expected or known parameter ranges leads to a quantified picture of the pre-drilling risk of a hydrocarbon prospect.

However, such mapping procedures rely often on a huge amount of data (horizon maps for backstripping) and a long working process (decompaction of layers, etc.), especially when e.g. the timing of generation and expulsion of hydrocarbons should be evaluated. Available data and time constraints limit therefore often the routine application of such working tools in prospect evaluations.

Norsk Hydro has been developing in-house tools for mapping basin modeling results since 1992. These tools have been applied successfully in the past to calculate potential volumes of generated and expelled hydrocarbons of source rocks.

Newly versions of our mapping programs and tighter links with commercial basin modeling software allow us to grid these 1D and 2D basin modeling results much quicker and to apply therefore basin modeling on a more routine basis in prospect evaluation. They enables us today to map accurately basin modeling results such as expulsion volumes from source rocks and - due to the speed of the calculations - to run statistic simulation given defined distributions of input parameters within very restricted time frames (hours to days).

We will show 1) examples of how our mapping routines of basin modeling results define quantified prospect sensitivities and 2) how such routines open ways for a more integrated work flow in exploration processes. We are convinced that such tools will have a great impact in quantitatively risking hydrocarbon volumes and phase predictions.

53 Hydrodynamic activity and tilted oil-water contacts in the North Sea.

Hugh Dennis 1, John Baillie1, Torleif Holt 2 and Dag Wessel-Berg2. ‘Enterprise Oil Norge Ltd, Stavanger, Norway. 2IKU Petroleum Research, Trondheim, Norway.

INTRODUCTION

Learning from known hydrocarbon traps is a key element where dz/dx is the dip per unit length of the OWC ; dP/dx in improving the exploration process, especially in maturing is the horizontal pressure gradient in the aquifer; and p„ - areas where creative models are needed to find new prospects. Ph is the density difference between the water and hydrocarbon phases. In the central North Sea tilted oil-water contacts (OWCs) are observed in several traps in the Cretaceous chalk and Palaeocene sandstone. These are thought to be caused by hydrodynamic activity in the aquifers as the Central Graben It is important to recognise that it is horizontal pressure continually de-waters. New heterogeneity modelling work gradients which tilt OWCs ; it is not a frictional effect of can be used to improve the understanding of tilted OWCs water movement. In fact, the actual flowrate of aquifer in these traps, to explain dry wells and thus lead to improved water beneath a tilted OWC is usually extremely small risk analysis in exploration. compared to say, water-drive during field production. Moreover, very small pressure fluctuations can produce suprisingly large OWC tilts. Using the above formula, an aquifer pressure gradient of just 5 psi/km around a medium The ability of hydrodynamic pressure gradients to tilt OWCs was first documented by Hubbert (1953) and many global gravity oil field will induce an OWC tilt of about 12 m/km. examples have since been described (Hubbert, 1967; Dahlberg,1995). Megson (1992) and Thomasen & Jacobsen (1994) suggested that hydrodynamic flow could be CENTRALNORTHSEA responsible for southward tilted OWCs observed in Danish Regional pressure variations occur in both the Palaeocene chalk fields. The application of the hydrodynamic model and the Cretaceous chalk in the central North Sea. Both to the Norwegian chalk fields has been the subject of further formations are continuous and relatively unfaulted, and a recent discussion (Megson, Japsen and Caillet, 1998). hydrodynamic environment is thought likely to exist. Tilted OWCs are observed in several fields in both formations, with tilt directions consistant with the regional pressure The concept of tilted OWCs in the North Sea Palaeocene trends. sandstones has not been previously published. Heum (1996) and others, have suggested hydrodynamic processes in some Jurassic fields in Norway, although without reference to One chalk example is Norway ’s Valhall/Hod field, where any tilted OWCs. oil was discovered in 1994 in a low “saddle” area between the two main proven structures (Figure 2). Prior to drilling, this area was identified on 3D seismic data as a stratigraphic The common term “OWC” is used in this paper to be trap (Campbell and Gravdal, 1995). Upon drilling, however, synonymous with “free water level” as they are usually the prospect was found to be in pressure communication close to one another. However, it is recognised that the with the Hod field to the south ; a new hydrodynamic model principle applies strictly to the free-water-level only (this can now be applied to explain the trap, with a southward distinction can become important when dealing with long OWC tilt similar to the trend in Denmark. transition zones, such as in the chalk). We use the term OWC for simplicity. Tilted OWCs also occur in the overlying Palaeocene sands further north. In the Palaeocene, the regional hydrodynamic It is worth noting that the hydrodynamic principle applies flux is north-westwards, along the axis of the original also to tilted gas-water contacts (but not to gas-oil contacts). depositional fan. Locally, the direction of OWC tilt in Palaeocene fields can vary. An example is the Pierce field in the UK sector, where the log and virgin pressure data HYDRODYNAMIC PRINCIPLES from 12 appraisal wells suggest a marked westward tilt to the OWC (Figure 3). Within the context of this paper, hydrodynamic activity is defined as the lateral movement of groundwater through an aquifer. In a hydrostatic environment, there is no horizontal component to the movement of groundwater, whereas in a MODELLING TILTED OWCs hydro dynamic environment, variations in internal pressure In a homogenous aquifer, with a uniform horizontal pressure cause horizontal flow. Where these pressure variations gradient, a tilted OWC is planar. However, no aquifer is coincide with trapped oil, the depth of the free water level homogenous. Variations in permeability and thickness serve will also vary, resulting in a tilted OWC (Figure 1). to disrupt the hydrodynamic flow and the aquifer pressure gradients, and thus the OWC geometry. The effect of such heterogeneity has been investigated by the use of both The tilt of an OWC can be expressed in simple mathematical laboratory sand-box experiments and computer simulations. formas : dz/dx = dP/dx p~- ph 54

Laboratory Experiments REFERENCES Figure 4 shows the laboratory set-up of the flow apparatus. Campbell, S.J.D., and Gravdal, N., 1995. The prediction of high The apparatus consisted of two glass plates (67cm by 47cm) porosity chalks in the East Hod Field. Petr. Geoscience, v.l, which contained a porous medium of glass beads (70-100 p. 57-69. pm diameter). Fluid flow was controlled by two eight Dahlberg, E.C., 1995. Applied Hydrodynamics in Petroleum channel peristaltic pumps and entered/exited the apparatus Exploration. 2nd edition, Springer-Verlag. via 16 ports on each side. Oil and water were simulated using CaCIVwater solutions mixed with isopropanol and Heum, O R., 1996. A fluid dynamic classification of hydrocarbon entrapment. Petr. Geoscience, v.2, p. 145-158. iso-octane. Hubbert, M.K., 1953. Entrapment of petroleum under hydrodynamic conditions. AAPG Bull., v.37, p. 1954-2026. In Figure 5 the results of a simple 2D experiment are shown. Hubbert,M.K., 1967. Application of hydrodynamics to oil The geometry represents a simple dip closure with aquifer exploration. Proc. 7 th World Petroleum Congress, v.lb, p.59 flow from left to right. The trapped “oil” is in a state of 75. equilibrium, and has a tilted OWC. When the aquifer flow Megson, J.B., 1992. The North Sea chalk play : examples from was increased, the dip on the OWC also increased. Eventually the Danish Central Graben. Geol. Soc. Special Publication No. the OWC dip exceeded the maximum dip of the top seal, 67, p. 247-282. and all of the oil was flushed out (this is a situation that may explain some of the dry wells drilled on low-relief Megson, J.B., Japsen, P. And Caillet, G. 1998. Discussion: structures in the central North Sea). “Overpressure and hydrocarbon trapping in the chalk of the Norwegian Central Graben ” by G Caillet et al. Petr. Geoscience, v.3, p.32-42. Computer Simulations Thomasen, J.B., and Jacobsen, N.L., 1994. Dipping fluid contacts in the Kraka Field, Danish North Sea. SPE 28435, 69th Ann. Computer simulations were run in parallel with the laboratory SPE Tech. Conf., p. 763-772. experiments. Figure 6 shows a simulation similar to the Wells,P.R.A., 1987. Hydrodynamic Trapping of oil and gas in the physical experiment described above. The OWC is again Cretaceous Nahr Umr Lower Sand of the North Area, Offshore seen to tilt in to the right. The sinuosity of the OWC is Qatar. SPE 15683, 5th SPE Middle East Oil Show, Bahrain. caused by constriction of the water flow directly beneath the trapped oil. This has the effect of locally increasing the pressure gradient, which in turn produces a local steepening of the OWC.

In Figure 7, a thin low-permeability column was inserted HYDROSTATIC HYDRODYNAMIC through the model, simulating the effect of a partial barrier, (Flat OWC) (Tilted OWC) such as a geological fault. The OWC is seen to step down SECTION across the “fault” and dip gently on either side.The fault gives the illusion of sealing - there is a different OWC on A B C AS C each side of it. In fact, the whole system was in pressure GOC GOC/* communication, and the change in OWC was purely a result OWC/ \ of hydrodynamic flow across the fault. Such a phenomenon 4= Water Flow was suggested by Heum (1996) to explain OWC variations in the Jurassic Ula field.

CONCLUSIONS The presence of a tilted OWC can change the way a field is appraised and developed, and can even affect platform locations. There is evidence of tilted OWCs occurring in the central North Sea ; in such cases, an understanding of the OWC geometry and its response to aquifer heterogeneity PRESSURE vs. DEPTH becomes critical for effective exploration, appraisal and development drilling. The experimental work described above is continuing, and is designed to help reach a better understanding of tilted OWCs. The application of these OWC models in the Pierce field is helping to identify areas of previously un-mapped oil and to ensure that development wells are correctly targeted to maximise oil recovery. OWC

ACKNOWLEDGEMENTS The authors wish to thank their colleagues at Enterprise Oil and IKU for their help and useful advice. The views expressed in this paper are the authors ’ own, and do not necessarily reflect the views of their respective companies. Fig. 1. The effect of hydrodynamic behaviour on oil and gas accumulations. (After Wells, 1987 ) 55

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Fig, 2. Cross-section through the Pierce Field. Log and Fig. 3. Cross-section through the Valhall and Hod fields. pressure data from 10 appraisal wells indicate a westward The free-water-level is shown dipping at 15m/km towards tilted OWC in the Palaeocene sandstone reservoir. The the south, caused by an aquifer pressure gradient of 7 psi/km. average dip of the OWC is c. 90m/km. This value is consistent with regional virgin pressure data, and corresponds to an average water velocity of 3 mm/yr. in a 1 md. aquifer. Oil was found in the saddle area in 1994.

Fig. 4. Laboratory apparatus. The glass panels measure Fig. 5. Physical model. The geometry represents a simple 67cm by 47 cm, and contain a packing of glass beads. Oil dip closure with aquifer water flowing from left to right. is introduced into the system and then hydrodynamic flow The trapped oil is in a state of hydrodynamic equilibrium, is regulated using the 16 valve ports at either end of the and has an OWC tilted in the same direction as the water apparatus. flow.

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Fig. 6. Computer simulation. The simulated geometry is Fig. 7. Computer simulation with fault zone. A low similar to that shown in Fig.5., with aquifer flow from left permeability column through the centre of the model to right. The OWC dips to the right. The sinuosity of the represents a partially sealing fault. The OWC steps OWC is caused by constriction of the water flow beneath downwards across the fault, giving the illusion of a fault the trapped oil. This locally increases the pressure gradient seal. which, in turn produces a local steepening of the OWC.

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Reservoir Characterization using 4C Seismic and Calibrated 3D AVO L. Sfinneland*, J.O. Hansen, G. Hutton, M. Nickel, B. Reymond, C. Signer, B. Tj0stheim, H.H. Veire, Schlumberger Geco-Prakla

Introduction 3D velocity model is used to sort and stack the selected wave-modes relative to their common reflection point. A It is wellknown that the ratio of p-wave velocity and s-wave generalized AVO-decomposition of the seismic response velocity (Vp/Vs) in porous media is sensitive to both lithology from these reflection points can be established. In particular and type of pore fluids. As a consequence both these effects the Vp/Vs ratios are computed from the converted modes influence the AVO-response. Extensive well-log information is and used to establish the calibration of the 3D AVO (figure therefore needed to calibrate for the lithology effect if AVO- 2) cubes in much the same manner as is done with well-logs analysis should be used for mapping of porefluids. Our paper [2]. All results from the 4C analysis can be transformed and presents a procedure for using seabed 4C seismic profiles to adapted to the 3D surface datum so that consistency is calibrate the lithology effect and thereby enable porefluid map maintained with the 3D common earth model (figure 3). ping from 3D AVO. Such a methodology is attractive at the 3) The objective of the final step is to map the pore fluid distri exploration or appraisal stage when the well-control is limited. butions. Data inputs are 3D AVO cubes and along the sea The potential of the procedure is demonstrated on a case-study bed profile, Vp/Vs- and multimode AVO-sections. The of a Late Paloecene fan system from the North Sea. classification enables to combine all these data into a set of fluid indicators and map them over the prospect area (figure Procedure 4). By statistically combining these fluid indicators maps with the structural closures as defined by the 3D interpreta The procedure is highlighted in figure 1 and consists of three tion a further assessment on the uncertainty can be made. basic steps: Finally the fluid volumes are estimated. 1) First the stratigraphic facies is characterized from the 3D seismic cube. This information is captured in volume Conclusions attributes computed between key interpreted horizons. The attributes used in the stratigraphic analysis are based on a Accurate modelbased processing are required for consistent spectral representation of the seismic signal in 3D. Both integration of 4C seabed data and 3D surface data. The poten vertical and lateral facies changes can be defined by seismic tial of seabed 4C data combined with 3D surface seismic can classification. The output from this first phase are maps of provide a powerful tool for discriminating lithological and fluid stratigraphic objects within a given layer. From these response in reservoirs. The case study has demonstrated this objects we interpret submarine distribution channels and potential. In figure 2 the result of the calibrated AVO inversion fans based on their shapes. Supported by well-control (two of the fluid distributions are presented. The validation of the wells in the case study) the lithology of these fans are asso results are also demonstrated by comparing the predicted fluid ciated with sands of different reservoir quality (shaly sands distributions with the geometric constraint (structural closure). and coarse sands). The output of this step is a set of litho logic objects. 2) The 4C seabed data is processed in a model consistent man References ner to improve the discrimination between lithological and fluid effects on the seismic response. A novel modelbased [1] Spnneland, L„ Veire, H.H., Hansen, J.O., Modelbased processing technique is used [1], A 3D common earth AVO Inversion, EAEG 58th Conference, Amsterdam 1996 model is established and data are processed consistent with [2] Foster, D.J., Keys, R.G., Reilly, J.M. Another perspective this model. When processing the 4C seabed data an apriori on AVO crossplotting, Leading Edge, September 1997.

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From Seismic to Biomarkers - The Value of Additional Data in Continually Refining Geological Models.

Nigel Mills, Rolando di Primio, Sven Hvoslef, Daniel Stoddart, Ingar Throndsen and Mike Whitaker. Saga Petroleum ASA

ABSTRACT

The discipline of Geology, in its widest definition, involves understanding mechanisms occurring over a vast range of scales from Plate Tectonics to Molecular and Elemental Analysis of both organic and inorganic mixtures. Without studying the full range from regional geology to molecular chemistry we can not possibly expect to understand and accurately describe the Petroleum System which is a prerequisite for prediction and risking in Petroleum Exploration.

Within the field of Petroleum Geology the largest scale of investigation, at least within one petroleum province, is usually extensive seismic collection and interpretation. At the other end of the spectrum we evaluate the organic and inorganic constituents of the rock matrix, the pore system of both reservoir and source rocks and where fortunate enough to find them we are also able to analyse pore fluids (hydrocarbons) in great detail (molecular and elemental scale).It is precisely this great range in scale that provides us with both the challenge and the possibility to continually develop our understanding of subsurface processes. This is becoming more and more essential in order to find the continually more elusive petroleum accumulations. Integrating the many disciplines and scales in a dynamic manner, having an eye for the anomalies and daring to make decisions and redefine “accepted ” models or theories, is the key to successful exploration in both mature and virgin areas. All too often, though usually decided by economics, we tend to perhaps subconsciously divide activities into essential and additional (luxuiy). We would question the traditional view of this and the division into these groups and would warn against cutting out studying the details which often also incur only minor relative expense.

This paper discusses the value of continually adding both new types of data and critically, new data points to existing “state of the art” models in order to build a better understanding of the processes from Generation to Accumulation (and in some cases partial or total Destruction). It shows how generating “additional data” and treating it as building bricks, or as parts of a jigsaw puzzle, may provide powerful thrusts in understanding complicated geological scenarios. Any model that does not take into account and adequately explain observations and “anomalies ” at all of these scales is by definition incomplete and potentially misleading and expensive.

Examples will be given from the Northern North Sea, Southern North Sea, Norwegian Sea and the Barents Sea, showing the value of “additional data” of different types (additional data may mean higher intensity of a data type already available in the well or introduction of a different, non traditional data type or simply a new application/treatment of existing data/technology). These examples include:

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i) Petroleum Population Studies - how having confidence in the interpretation of Petroleum Population Studies (based heavily on biomarkers and isotopes) can necessitate taking a new look at established structural interpretations or help in ranking several possibilities with consequent alteration and improvement in the understanding of migration routes. The main example will show how a strong conviction that petroleum population studies can be used as an exploration tool even in mature areas (obtained by continually refining the migration model in the area and testing it against drilling results) resulted in upgrading acreage facing a “drill or drop ” decision. The petroleum population based migration model convinced the licence to drill in an area previously considered to have a high risk of being in a “migration shadow” (due to earlier assumptions of most likely migration routes and well results) and the first well discovered hydrocarbons, allowing retention of the area and subsequent discovery of more hydrocarbons. ii) Kinetics - detective work to understand one of the most unusual oils discovered offshore Norway (Southern North Sea) illustrates how attacking “anomalies ” and generating additional data (in this case laboratory derived oil generation kinetic parameters) helped to explain this oddity. The explanation arrived at for the observed oil characteristics resulted in potentially reduced risk for source and maturation for one of the play models in the area and may open new possibilities. An example from an area in the Norwegian Sea will be given in the publication showing how laboratory derived kinetics for oil destruction better describe the observations than “global/default ” parameters. iii) PVT - a presentation of how phase envelope shapes and relationships theoretically may be interpreted in terms of maturity, migration/uplift and mixing is followed by brief examples from the Norwegian Continental Shelf. This type of data, which has traditionally been the domain of the petroleum engineer and production geologist, may provide a “first pass ” or a valuable supplement to traditional techniques for evaluating these phenomena. The examples are taken from the Central Graben, the Viking Graben and the Barents Sea. iv) Biostratigraphy - two examples will be given to show the implications of high(er) resolution biostratigraphy. In one case, due to curiosity as to the age of a thin sand (initially interpreted as Brent sand) close to the major BCU series of unconformities, together with the availability of core material, “additional ” (i.e. over and above the “routine well programme”) palynological analyses were performed in an exploration well on the Tampen Spur. This resulted in the discovery of a younger (Cretaceous) sand, opening the possibility for a new play in the local area. The second example shows how high resolution biostratigraphy performed on a pilot hole which was intended to be side-tracked as a producer revealed a potentially much more complicated geological scenario than had been previously envisaged. Indeed it was suggested from the data in the single well that the relative layer caked model that had been proposed for the reservoir unit was probably highly faulted with the clear implications this would have for a horizontal producer. Consequently a new observation well was drilled, confirming the geological complexity and resulting in the fact that a relatively modest expenditure on detailed biostratigraphy had avoided drilling a very costly and almost certainly inefficient producer.

Ultimately, this type of “additional information” can be critical in deciding whether or not to apply for acreage or, when in possession of acreage, ranking available prospects. In addition, some of these data types can be extremely helpful in the planning and development stage in order to optimise activity or avoid making costly mistakes. The examples presented will also show how important it is to generate enough data points of high quality to feel confident that the real picture is emerging.

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EXPLORING MATURE AREAS: THE ROLE OF TECHNOLOGY D.E. Krol, V.J. Noual and P.J.T. van Maren Shell Expro UK

More than 30 years after the discovery of the first hydrocarbon accumulations in the UK sector of the North Sea (UKCS), the area has developed into one of the most prolific hydrocarbon provinces of the world. Over 500 accumulations have been proven with a cumulative discovered volume of some 45 BBoe (Fig. 1). Discovery size has declined each decade to the current range of 8-64 MMbbls. Creaming curves show similar trends whether analysed per play or per province (north, central, south). It is therefore fair to say that the UKCS should now be considered a mature area.

To exploit the remaining window of opportunity of the existing infra-structure new technologies need to be rapidly deployed to unlock the remaining near facility potential - undiscovered and marginal undeveloped volumes. At the mature stage in which exploration is currently in the UKCS, only the most sophisticated tools will be able to contribute to the addition of ever smaller, riskier or more difficult (HPHT) reserves. 3D seismic only is no longer sufficient to unravel the complexities associated with some fault patterns or with some mass flow reservoir distribution. High resolution 3D seismic data has proved instrumental in improved understanding of Tertiary turbidite distribution around old fields. Pre-Stack Time and Depth Migration have contributed to a better structural definition of prospects underlying steeply dipping diapirs (Fig. 2). In some cases this has revealed that marginal discoveries had significant upsides. Quantitative interpretation techniques (e.g. A VO, seismic inversion) are successfully used to image very low acoustic impedance reservoir sandstone units, invisible on reflectivity seismic (Fig. 3). Acquisition techniques such as OBC 4 Components are now being applied with early striking results in imaging fields overlaid by a gas chimney. Basin modelling techniques applied to the HPHT environment of the CNS have successfully predicted pressures in excess of 6000 psi and have contributed to drilling safer and more cost-effective HPHT wells. Integration of sedimentological analysis and chemo-stratigraphy, if possible in combination with oil fingerprinting techniques, is being used to provide a sound stratigraphic framework for biostratigraphically barren reservoir intervals (Fig. 4).

Innovative drilling techniques (multi-lateral wells, partly drilled with coiled tubing, underbalanced drilling) will be applied to unlock the relatively low-permeable reservoirs of both northern and southern North Sea prospects (Fig. 5). ERD wells (10 km) from existing platforms and long-distance sub-sea tie-backs (>50 km) of both HP/HT fields and low energy fields requiring artificial lift are now considered feasible making the development of small and remote hydrocarbon accumulations economic (Fig. 6).

New practices have been identified for exploration well design, and appraisal and development project procurement in mature areas. Fast-track developments require parallel instead of sequential working routines, new procurement practices and innovative commercial approaches to meet the aspirations of all stakeholders. CONFIDENTIAL______13.VIII.98 CONFIDENTIAL 27.VII.98 in

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Managing Subsurface Knowledge:

three initiatives in BP

The world entered the information age a couple of decades ago with the advent of cheap computing. The days of measuring seismic horizons with a ruler, and depth converting with a calculator, are now long gone. The modem interpreter is either drowning in data or swimming in information, depending on the technology and the data/information management processes. However to excel in the modem business we need to move beyond information, and to start to work with knowledge. Knowledge is information filtered through human experience; information with a value attached. Information makes action possible, knowledge tells you which action to take.

In the modem knowledge industries, ‘what we know ’ is as much of an asset as ‘what we own ’. This is especially true in the subsurface sciences, where the knowledge and experience of the staff is key to a company ’s success. Most of this knowledge is acquired on the job, rather than through formal training, and has real dollar value in the business. However, the trend to increasingly devolved and autonomous business units poses a real threat to the use of knowledge in a large corporation. In the BP Organisation, for example, the discipline specialists are dispersed around the company in small multi-disciplinary team. So a sedimentologist may find herself working with a reservoir engineer, a drilling engineer, a seismic interpreter and a processor. She will feel a great sense of identity with the business challenges, and will focus her work towards the need of the business customer. At the same time she may begin to feel a separation from other sedimentologists. She may start to worry that the solutions and ideas she generates are made in isolation, she may feel a growing insecurity in her technical delivery, she may feel “I’m doing my best, but there could be a better way”.

How can we retain the focus and drive of a multi-disciplinary team, and give our sedimentologist access to the combined knowledge base of her colleagues? Or to put it in a more generic way, How can a global organisation make effective use of it’s collective knowledge? Or is it likely to dissolve into a collection of small independent companies?

The theories of knowledge management are very popular at the moment, as they seem to provide an answer to the problem of the fragmented federation. Knowledge

r T management in a company often takes one of two roads; a technology route based around the creation of knowledge warehouses and databases, or a people route based around the behaviours of seeking and sharing knowledge. BP has been addressing knowledge management now for a couple of years, and is focusing on the ‘people ’ route. As our CEO, John Browne, said in his Harvard Business Review article,

“In order to generate extraordinary value for shareholders, a company has to learn better than its competitors and apply that knowledge throughout its businesses faster and more widely than they do. The way we see it, anyone in the organization who is not directly accountable for making a profit should be involved, in creating and distributing knowledge that the company can use to make a profit. ”

Knowledge is hard to manage; it lives in people ’s heads and is very hard to put onto paper. In fact you can argue that any attempt to capture knowledge is doomed to failure, as the act of capturing degrades the knowledge to information by taking it out of context, and by removing the human aspect. In this talk I would like to describe three components of our drive to find and apply the knowledge of the organisation, while still honouring the concept of knowledge as a mental attribute.

The first initiative, now a few years old, is the ‘Peer Assist’. This is a mechanism by which one business unit can call in knowledge from elsewhere, and apply it in their own business context. It is a mechanism for ‘learning before doing ’; for applying hindsight in advance, and it takes the form of a meeting of anywhere between 3 hours and 3 days (depending on the scale of the problem).

Imagine you are a team leader, and you have just been given a new challenge; one which you have never faced before. What is your immediate reaction? The automatic human reaction is to dive into the problem; to ‘get stuck in ’. You can see this reaction in your children when you give them a new computer game. Do they read the manual first, or do they jump straight into the game? If they are anything like my kids, they jump straight in, and only read the manual when the game breaks down. It’s the same with adults, particularly in an action-oriented business like the oil business. Yet although it does not matter if your computer game breaks down, it is more serious if your prospect fails.

It is becoming established procedure now in BP that the team leader, facing the new challenge or difficult decision, should call a peer assist. He will look for others in the business who have faced a similar challenge, or made a similar decision. He will contact them, and ask them for help. He will send some briefing material describing his business context, and ask them to attend a meeting (either a real meeting or a ‘virtual’ meeting). He will describe the challenge, open himself and his staff to questioning, and invite feedback and advice from the assisters.

The concept of a peer assist is great, but how can you identify the right people to help? The global organisation is vast, and you need to access a breadth of experience, not just pick ‘the usual suspects ’. So the second initiative I would like to describe is a knowledge directory. This serves to extend our existing personal networks so that we 64 benefit from greater diversity. Our initial hope had been that the company Intranet would provide the means of finding ‘the people with the knowledge ’ through home pages or local site pages. However the Intranet, like the Internet, is an organic phenomenon and hard to control or influence. We are now introducing a company wide directory, linked to information already available in the mail system, which can act as a ‘yellow pages ’ for interests and skills.

This directory is the ‘Connect ’ database. It is housed on the Intranet, and linked to the email system. It is smart enough to know who you are, so when you log in it has your default details (name, location, phone number) ready. However to be really useful it needs to hold more valuable and personal information than mere phone numbers. So connect contains requests and prompts for people to fill in a list of their experience, their contacts, what they know, who they know, their photograph, and so on. The user can input all this information from their desktop, through their web browser. The directory can be searched for people, for names, and for knowledge.

A third area of focus in BP at the moment is on the Communities of Practice. Communities of practice are informal networks dedicated to sharing knowledge among practitioners. They tend to spring up spontaneously, driven by the need of the members for operational knowledge., rather like in-house professional societies. They thrive on communication, and the mutual trust and respect of the participants. They are recognised as the experts within the company. They are best placed to define common codes of working practices, replacing functional managers in this regard. !o

The concept of communities of practice arose in Xerox, where the community of repair and support staff found great power in sharing tips and hints. The Xerox definition is as follows;

A community of practice is a group of professionals within a corporation who are informally bound to one another through their exposure to a common class of problems and common pursuit of solutions. Members within the community of practice freely exchange knowledge which creates an even greater resource base of knowledge.

Communities of practice are strengthened by face-to-face meetings, and they thrive on communication tools such as electronic discussion fora and desktop video conferencing, as well as occasional meetings and conferences. The “Question and answer forum” is a powerful tool, allowing a member of the community to drop a question into the forum and receive answers from around the world. The replies build up as a ‘threaded conversation ’ in a shared mail folder, allowing people to build on previous answers.

Communities of practice are the natural unit for sharing best practice; lessons are learnt by the community, shared within the community, and applied by the community. They also generate loyalty, trust, and a form of dual citizenship; “I am a member of the Bruce Project Team, and I am also a member of the sedimentologist community ”.

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By using these three initiatives (among others) BP is promoting the exchange and re use of knowledge; not by managing the knowledge directly, but by providing the human environment in which knowledge exchange will flourish.

Nick Milton, BP Knowledge Management Team 71

NPF conference: Improving the Exploration process by learning from the past.

~ Christian Magnus, NPD: An evaluation of prediction, in light of results in some of the 15th Round licences.

The 15th Round in Norway heralded a renewed interest in exploration, as some of the structures identified in the deep water areas of the Norwegian Sea were the largest since the beginning of the exploration history of the North Sea.

The first results from drilling of deep sea prospects in the Voting and More Basins are now available to the industry. We are thus in a position where we are able to evaluate the industry ’s resource assessments prior to drilling in a virtually unexplored petroleum province, and compare prognoses with the results after drilling. In the present paper we have chosen to focus on the 217 and 218 licenses in the Voting Basin, as they represents the area of highest interest in the 15th Round. The deep waters of the Voting and More Basins were for a long time considered too hostile as exploration environment to both the government and the industry. Few companies had experience from deep water wells in such an environment. There was also much justified scepticism to the economic feasibility of the prospects mapped in the deeper water areas of the Norwegian Sea. There are abundant intrusive and volcanic rocks, particularly in the western areas. Intrusives of Early Tertiary age are evident as giving rise to distinct seismic reflectors over large areas. The thermal history of the basins were considered by many to be unfavourable to both source rock maturity and reservoir quality. The basins had later since been subjected to folding, uplift and erosion and the retention of hydrocarbons was seen as a major risk factor. In addition, parts of the Tertiary sequences that had not been eroded were anicipated to be porous sediments that could pose a threat to borehole stability. The two Esso operated wells on the Utgard High, and the shallow IKU boreholes in the area, which were considered central to the understanding of the reservoir potential of the Nyk High and Verna Dome area, were available to most of the companies, although the seismic correlation to the prospects in the Vgring Basin were far from straight forward. Some data from the wells had already been published before the round, and data from the ODP/DSDP boreholes were available. Few wells on the Haltenbanken and other areas of the Tr0ndelag Platform were considered relevant to the remote basins in the deeper waters .

The Utgard High wells had thin or low quality reservoir sands and were in fact the only exploration wells in the Vpring Basin prior to the BP operated well on the Nyk High. The thick sand found at Nyk and Verna was anticipated by geophysicists from the University in Bergen, although their interpretation aroused little attention when it was published.

The companies with a long history of research in the Voting- and More Basins had a leading edge in the intensified period of exploration prior to application for the 15th round blocks. They had time to cope with the problems of for example, correlations from wells of the Haltenbanken area and out in the basins. The “newcomers ” had little time for regional mapping and concentrated their efforts on prospect evaluation. The attractiveness of the size of some of the structures however, made other factors such as the presence of source rock and reservoir of secondary importance. The reservoir was considered to be deep marine clastic turbidites of Upper Cretaceous age. Interpretation of top reservoir was a seemingly easy task as the flatspot on the Luva prospect in the BP operated licence is truncated against high amplitude reflectors which were traceable over this part of the Vpring Basin. Top reservoir could conservatively be picked by the extent of the flatspot providing small but, as it turned out, to be more correct estimates. Many interpreters picked the top of the high amplitude reflectors above the flatspot/shale intersection as a direct hydrocarbon indicator, giving a larger reservoir volume. None of the companies were in complete agreement as to the age of the important reflectors in the remote parts of the basins. The difference in interpretation is more pronounced for the Base Cretaceous (or top of the only well known source rock). To many of those who had been mapping the region for years it seemed more likely that the Base Cretaceous was very deep and buried deeper than the oil window, even before the deposition of reservoir rock and seal. It became necessary to postulate an unknown oil prone source rock of Cretaceous age. Natural gas was considered as the most likely reservoir fluid by those who interpreted a deep Base Cretaceous. However the size of some of the traps gave a positive NPV even for prospects where the presence of reservoir sand was dubious, and where there was low probability of charge by an oil prone source rock. Companies with a shallow Base Cretaceous were more inclined to rely on the existence of an oil prone source rock in the Nyk and Verna blocks. The companies who interpreted the direct hydrocarbon indicators to reflect gas over water and who almost rejected the possibility of oil, found negative NPV, but applied (for partnership) anyway. The reasons were upside potential, prestige and the additional value of first hand information. The companies which had a long history of research in the Norwegian Sea generally gave prognoses closer to the well results. They agreed on a general low chance of success for oil. Their play models turned out in general to be close to the results. Still, the general tendency in the mapping performed by the companies and the NPD is that the rock volumes were to large, net to gross to low, and that the evaluation of the oil potential of the region was optimistic. 13

Future challenges in exploring the remaining hydrocarbon potential of the Norwegian Continental Shelf.

Authors: Ranch Grung Olsen, Sigmund Hanslien, Statoil.

The total remaining hydrocarbon potential of the Norwegian Continental Shelf is assessed to be in the order of 11 billion Sm3 o.e. in addition to the 2.3 billion Sm3 o.e. which has been produced to date. Of the remaining resources it is estimated that 4.7 billion Sm3 o.e. is yet to be found. To put this in perspective; the current ratio between discovered oil resources and production is 15 years, this ratio will increase to between 25 to 30 years if the yet-to-find potential is realised. In order to replace the current production exceeding 3 mill, barrels a day the equivalent oil reserves of two Nome fields will have to be found or added by EOR from existing field every year. On the other hand the discovered gas resources are sufficient to sustain the current production level for more than 70 years.

The future oil price is probably the single most important factor influencing the exploration activity on the NCS. As recently demonstrated there is a definitive risk of a low oil price environment in the years to come, and a main challenge is to maintain the NCS as an attractive place to explore and produce oil under such circumstances. Using two measures - reserve replacement ratio and cost per barrel of proven reserves added - it is demonstrated that the NCS in terms of reserve additions has been very competitive in a global context in recent years. On the list of the twenty largest oil and gas discoveries worldwide from 1995 to 1997 Norway is represented by three major gas fields. The level of development costs and fiscal terms are other critical factors defining how attractive the NCS will be as an exploration target in the future.

In the mature areas of the North Sea and Haltenbanken, exploration geologists and geophysicists will be challenged to develop new play concepts and to continue to search for small and subtle traps near existing or planned infrastructure. An almost continuous 3D coverage on a regional scale combined with the rapid developments in information technology has made it possible to visualise the subsurface with much better precision than before. Low cost development schemes have led to smaller and more complex reservoirs becoming economically viable and therefore potential targets for the explorationists.

Major new oil discoveries will depend on success in our frontier basins. Voting looks promising as a potential new gas province, however, the presence of major oil accumulations is yet to be proven. Large 3D seismic surveys have become the norm as the primary exploration tool also in frontier areas of the Norwegian Shelf. The challenge is to extract the maximum of information from seismic and integrate this with the often scarce well data in order to improve our understanding of the potential hydrocarbon systems of the basins, generate the different play models and test these out by systematic data acquisition and analysis.

Over the past few years we have experienced a tremendous development in cost effective 3D seismic acquisition. The volume of data available to the seismic interpreter has exploded, not only in terms of area coverage and density but also in terms of different data volumes of the same data set. Sophisticated seismic analyses, which previously were laboursom and therefore carried out on single lines only, can now be performed on the entire data volume. Prediction of lithology and fluid directly from seismic data are becoming routine and increase the demand for more detailed and better quality petrophysical well log data and analysis for calibration. This trend is expected to continue. Furthermore, acquisition of ocean bottom 4C seismic to obtain shear wave data will likely accelerate as costs are reduced and processing techniques are improved.

The more precise imaging of the subsurface provided by extensive 3D seismic coverage provides excellent opportunities to advance our understanding of the geological processes which control the formation of oil and gas accumulations. Systematic mapping of features related to migration and leakage of fluids in the subsurface is an example of this. Detailed mapping of larger scale depositional systems to understand reservoir architecture and trapping mechanisms is another.

Successful exploration will require effective integration of different types of data and the ability to visualise these. Therefore, in order to fully utilise the vast amount of data in the time available, the interpreters will need efficient, integrated interpretation platforms consisting of powerful computers, compatible software packages and shared data bases. The rapid development in technology which we have experienced in the past, will with no doubt continue. This means that competence building, both for the individual and the organisation as a whole, will be a major challenge and will require a lot of management attention. The increased need for specialised skills demand careful composition of multi-skilled exploration teams and good work processes in order to secure quality results. The successful explorationist will be the one who is able to fully utilise this new technology and combine this with a sound understanding of the geological processes which control the formation of oil and gas accumulations. Remaining Resources Norway Million Sm3 oil equivalents Resource/Production Ratios - Oil

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