VOLUME 04 ISSUE 04-JUNE 2011 VOLUME 04 ISSUE

OILFIELD TECHNOLOGY MAGAZINE JUNE 2011 www.energyglobal.com

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Too Good to be Green June 2011 Volume 04 Issue 04 ISSN 1757-2134 contents

| 03 | EDITORIAL COMMENT | 49 | DRILL BIT SOLUTIONS Leading suppliers; Century Products, NOV Downhole and Varel, provide details of advanced drill bit technologies. | 05 | WORLD NEWS | 55 | THE MANY SHADES OF GREEN Kelly Harris, BWA Water Additives, UK, takes a look at screening tests | 10 | THE ARCTIC HEATS UP in order to find more environmentally friendly chemicals. Climate change may be opening up the Arctic to an exploration boom, but other factors may be shutting it down. Oilfield Technology | 60 | SPOTLIGHT ON: ANTISCALANTS Correspondent Gordon Cope takes a look at these factors. Michael Hurd, Kasia Millan and Dr. Mohan Nair, Kemira, USA, offer a supplier’s view of antiscalants in oil and gas markets. | 16 | THE RUSSIAN RIDDLE Ekaterina Kozinchenko, Jake Leslie Melville, Hege Nordahl and Adrian Del Maestro, Booz & Co., UK, contribute their perspective on | 64 | A NOVEL APPROACH ensuring the long term success of Russian oil and gas. Siv Howard and John Downs, Cabot Specialty Fluids, Scotland, describe how cesium acetate brine could make a novel | 21 | CREATING INVESTOR OPPORTUNITIES high-performance drilling, completion and workover fluid. Kevin Forbes, Epi-V, UK, explores the opportunities for private equity investors in the upstream services sector, which is set for the next phase of industry investment. | 69 | ADDRESSING CHALLENGES WITH INNOVATION Dave Allison, Neil Modeland, Bart Waltman and Kirk Trujillo, , USA, consider innovations in fluids, completion designs | 25 | THERE ARE LIMITS... and equipment to address HPHT stimulation challenges. Kristofer Tingdahl, dGB Earth Sciences, USA, addresses the limitations of seismic interpretation. | 73 | UNDER PRESSURE | 31 | SHARPENED VISION Asad Mehmood, Weatherford International Ltd, Pakistan, discusses Henning Trappe, Gerald Eisenberg-Klein, Juergen Pruessmann, TEEC, the use of drilling control systems to navigate narrow pressure margins Germany, discuss the use of CRS analysis on seismic data to improve and access deep drilling targets. the view of reservoir structure and lithology.

| 38 | A MOVE TO IMPROVE | 76 | SOUTH CHINA SEA Rusty Petree, Drilformance, USA, looks at ways of improving drilling Mohd Hairi Abd Razak and Fuad Mohd Noordin, , Malaysia, efficiency at the bit. and Mohd Nur Afendy and Rahmat Wibisono, , Yemen and Malaysia, present an example of the planning and execution of coil tubing (CT) operations on platforms too small to accommodate all | 43 | PEERLESS PERFORMANCE the required equipment. Charles Douglas and Josh Passauer, Smith Bits, a Schlumberger company, USA, consider a new bit optimised for shale, saving | 80 | AD INDEX significant rig time in the Haynesville Play.

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Copyright© Palladian Publications Ltd 2011. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK. FREE E-ARTICLE TO INCREASE PRODUCTION TODAY

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pec will meet in Vienna, Austria, on 8 June 2011 and increasing economic development worldwide are for its 159th Ordinary Meeting. For the first time placing intense pressure on an already creaking supply Osince December 2008, when the group set chain. The very fact that isolated weather events or political its production target at 24.85 million bpd, there is a upheaval can impact commodity prices to quite such an genuine possibility that this figure may at last be set extent as we have witnessed in recent months/years is a for an increase. Although purely speculative, reports testament to how finely balanced the ‘system’ has become. indicate that an increase of between 500 000 bpd and The oil and gas sector is a case in point with the market 1.5 million bpd is on the cards. In reality, Opec members lurching from being comfortably supplied in early January have been actively flouting production targets all along to a sharp rise in oil prices from sub US$ 100 to US$ 125 with an actual current production total, due to member in the space of a few weeks on the back of events in the ‘non-compliance’ of closer to 26.3 million bpd, in spite Middle East. The effect has contributed in no small part to of Libya’s 1.4 million bpd of lost production. However, the rise in global inflation and the threat of an end to the what is important is the apparent recognition, should an global economic recovery as analysts forecast even greater increase be confirmed, that Opec is awake to the spectre prices hikes over the course of the next 12 months. of demand destruction and the impact of consistently For Opec at its forthcoming meeting, the actual level high oil prices on the recovering global economy. of any increase in production, be it 1 million bpd or higher, Whilst prices have already dipped is largely immaterial, as it will inevitably be quickly soaked amidst the speculation, the impact of such a meagre up by global demand. What is important is that the cartel increase would be symbolic rather than medicinal as is seen to be reacting sympathetically to an escalation in demand for crude oil is forecast to escalate further the current price of crude oil. By showing intent to address during the second half of 2011. The same issues face rising oil prices its efforts will go some way to defusing the key commodities across the spectrum be they oil, wheat growing clamour from the renewable energy lobby intent or gold, in that there is a fundamental tension between on the substitution of fossil fuels with alternatives such as falling supply and rising demand. Whether the cause is wind, solar and nuclear energy. the unprecedented economic growth not just in China, This month’s issue begins with an article by but across many emerging Asian nations, the Fukushima Contributing Editor, Gordon Cope that looks at the Arctic nuclear crisis in Japan or the now extended period of frontier as the largest remaining region of untapped oil unrest in the Middle East, the reality is that this type of and gas reserves and an effective illustration of how the price volatility is likely to become the norm rather than industry is pushing back every conceivable barrier in its a temporary blip. The dual effects of a rising population quest to meet future oil and gas demand. O T

James Little Managing Editor: james.little@oilfieldtechnology.com Anna Scordos Deputy Editor: anna.scordos@oilfieldtechnology.com Rod Hardy Advertisement Director: rod.hardy@oilfieldtechnology.com Ben Macleod Advertisement Manager: Palladian Publications Ltd, ben.macleod@oilfieldtechnology.com 15 South Street, Farnham, Surrey GU9 7QU, UK Contact Information >> Chris Lethbridge Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992 Business Developmentchris.lethbridge@oilfieldtechnology.com Manager: Website: www.energyglobal.com Production: Peter Grinham peter.grinham@oilfieldtechnology.com Anna Scordos OILFIELD TECHNOLOGY SUBSCRIPTION RATES: Annual subscription £80 UK including postage/£95/e130 overseas (postage airmail)/US$ 130 USA/Canada (postage Website Editor: airmail). Two year discounted rate £128 UK including postage/£152/e208 overseas (postage airmail)/US$ 208 USA/Canada (postage airmail). [email protected] SUBSCRIPTION CLAIMS: Claims for non receipt of issues must be made within 3 months of publication of the issue or they will not be honoured without charge. Laura Cowell APPLICABLE ONLY TO USA & CANADA: Eight issues of Oilfield Technology Magazine (ISSN 1757-2134) are published in 2011: February, March, April, June, August, Subscriptions: September, October, December, by Palladian Publications Ltd, 15 South Street, Farnham, Surrey, GU9 7QU, ENGLAND. US agent: Mercury International Ltd, laura.cowell@oilfieldtechnology.com 365 Blair Road, Avenel, NJ 07001. Periodical postage paid at Rahway, NJ. Subscription rates in the US: US$ 130. Victoria McConnell POSTMASTER: Send address corrections to Oilfield Technology c/o Mercury International Ltd, 365 Blair Road, Avenel, NJ 07001. Reprints / Administration: victoria.mcconnell@oilfieldtechnology.com Publisher: Nigel Hardy Because every water-sensitive formation is different

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// Statoil // Visund South: fast-tracking nicely inbrief USA Statoil is pushing forward with its first fast-track project, with the aim Lawmakers in Texas have passed a first fast-track project, Visund South, of cutting the time from discovery to bill requiring disclosure of most of the which is expected to come onstream production in half. chemicals used in . next year. The template is the first to have Although the industry has voluntarily Visund is an oil and gas field been built from a standard catalogue begun sharing frac fluid details in in blocks 34/8 and 34/7, 22 km for subsea equipment. This will response to public concerns about northeast of the Gullfaks field in form the basis for the continuing hazards relating to the chemicals, the the Tampen area of the Norwegian development and use of the new law will make it mandatory for North Sea. standard catalogue in the fast-track all Texas wells. The law still exempts Onstream in spring 1999, this portfolio. chemicals deemed ‘trade secrets’. development encompasses a floating The company has been working production, drilling and quarters closely with the supplier industry to platform. The subsea-completed wells develop standard equipment for this AMERICAS The Atlantic basin is expected to see on the field are tied back to the floater part of its field development portfolio. an above-normal hurricane season with flexible risers. Oil is piped to This means that it can start to build this year, according to the seasonal Gullfaks for storage and export. The equipment more quickly and develop outlook issued by NOAA’s Climate Visund field began producing gas and smaller finds more efficiently. Prediction Center; a division of the exporting it to continental Europe on It has taken less than a year to National Weather Service. The seasonal 7 October 2005. build the Visund South structure average is 11 named storms, whilst Statoil submitted the plan for from the signing of the contract the 2011 hurricane season can expect development and operation of for subsea equipment with FMC. to see 12 - 18 named storms, with the Visund South in January. It has now Subsea 7 will carry out the actual possibility of 3 - 6 of those becoming built the first seabed template for the installation on the seabed. ‘major hurricanes’.

// OPEC // // Centrica // WORLD Raising output? Mothballs gas field Realm Energy International Corp. has contracted Halliburton’s Consulting and Project Management team to work with With oil demand predicted to rise this Centrica has mothballed its Realm Energy to significantly expand the year, it has been reported that OPEC’s oil South Morecambe gas field, which technical evaluation and ranking of the ministers will discuss raising production supplies 6% of the UK’s gas annually, highest potential shale deposits found in quotas for the first time in almost four following through on a statement of emerging prospective basins globally. years. intention made last month in response to The last time that OPEC producers increased taxes. NEW ZEALAND chose to raise output quotas was in The UK government’s decision New Zealand’s new environmental September 2007, when 522 000 bpd was to raise offshore drilling taxes had protection laws dealing with its added to the market. It is expected that apparently made the field uneconomical. exclusive economic zone, (much of raising the quotas to 1 - 1.5 million bpd Centrica claims that the site will be which is earmarked for oil exploration) will be discussed at a meeting in Vienna brought back into operation once the will come into effect in July 2012. The this month. wholesale gas price reaches a level Environmental Protection Authority will The violence in Libya has caused where it becomes economical again. be responsible for issuing consents a net 1.4 million bpd to be removed UK Chancellor George Osborne under the new law; monitoring and from the market. This is despite a raised a supplementary tax on oil and enforcement of activities within the EEZ, production increase by Saudi Arabia. As gas production in his Budget from 20% situated 12 - 200 nautical miles offshore the maintenance season for European to 32% in an effort to raise £2 billion to and the Extended Continental Shelf, refineries comes to an end, a rise in fund a cut in fuel duty. Centrica claims which extends further than the EEZ. demand for crude oil during the summer this raised the effective rate of tax on the is expected. South Morecambe field to 81%.

OILFIELD TECHNOLOGY June 2011 05 world news

// Noble Energy // // Petronas // Discovery Expanding exploration diarydates Noble Energy, Inc. has announced Malaysia’s Petronas is making a discovery at the Santiago bold moves to intensify its efforts 30 August - 1 September exploration prospect in the deepwater in unlocking potential resources. 3P Arctic 2011 . The well, located in Shamsul Azhar Abbas, Chairman at Halifax, Nova Scotia, Canada 6500 ft of water on Mississippi Canyon Petronas, has recently suggested that E: [email protected] Block 519, was drilled to a total depth the company is poised to explore small www.3parctic.com of approximately 18 920 ft. Open hole and medium sized oilfields that are as logging identified approximately 60 ft yet undiscovered in the region, with the 6 - 8 September of oil pay in a high quality Miocene aim of raising crude oil production by SPE Offshore Europe reservoir. Noble Energy is the operator at 1.7 billion bbls. Aberdeen, Scotland Santiago with a 23.25% working interest. “Geology-based assessments E: [email protected] Santiago is the third discovery in the suggested that Asia’s mean www.offshore-europe.co.uk/palladian company’s Galapagos project, in addition undiscovered oil resources is in the order to the prior successes at Santa Cruz and of about 50 billion bbls,” he said. “These 25 - 28 September Isabela. Total gross resources discovered undiscovered resources would translate MEOS 2011 in the larger Galapagos project, including into a resource base one-and-a-half Bahrain the Santiago well, are estimated by times the combined proved reserves in E: [email protected] Noble Energy to be 130 million boe. Indonesia, Vietnam and Malaysia today,” www.meos2011.com Approximately 75% of the discovered he claimed at the 16th Asia Oil and Gas resources are oil. Conference this month.

4 - 6 October OTC Brazil // BP // Settling Deepwater Horizon claims Rio de Janeiro, Brazil E: [email protected] www.otcbrasil.org BP has announced that it has rendered them ineffective in preventing reached agreement with MOEX the accident. MOEX has concluded that entering into a settlement with BP is in 30 October - 2 November Offshore 2007 LLC and its affiliates, Mitsui Oil Exploration Co., Ltd and its best interest. The agreement is not ATCE MOEX USA Corp. to settle all claims an admission of liability by any party Denver, USA between the companies related to regarding the accident. E: [email protected] the Deepwater Horizon accident. Under the settlement agreement, www.spe.org/atce MOEX, which had a 10% interest MOEX USA Corp., the parent company in the Macondo well, has joined BP of MOEX Offshore 2007, will pay BP 7 - 11 November in recognising and acknowledging US$ 1.065 billion. BP will immediately World the findings by the Presidential apply the payment to the US$ 20 billion Houston, USA Commission that the accident was trust it established to meet individual, E: [email protected] the result of a number of separate business and government claims, as www.worldshalegas.org risk factors, oversights and outright well as the cost of the Natural Resource mistakes by multiple parties and Damages. 4 - 8 December a number of causes. Like BP, The parties have also agreed to 20th World Congress MOEX Offshore has also recognised mutual releases of claims against each Doha, Qatar and acknowledged the conclusions other. BP has agreed to indemnify MOEX E: [email protected] of the US Coast Guard that, among for compensatory claims arising from www.20wpc.com other things, the safety management the accident. BP’s indemnity excludes systems of both civil, criminal or administrative fines and and its Deepwater Horizon rig penalties, claims for punitive damages, had significant deficiencies that and certain other claims.

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// Shell // Upgrader Expansion Project // Total // Aquires interest in Qatari offshore block

Shell has announced the successful processes bitumen from start of production from its Scotford the Muskeg River Mine and Jackpine Total has announced that it has signed an Upgrader Expansion Project in Mine, for use in refined oil products. agreement with CNOOC Middle East Canada. The 100 000 bpd expansion Production capacity at the (Qatar) Ltd, a wholly-owned subsidiary of takes upgrading capacity at Scotford Project is now CNOOC International Ltd, to acquire a 25% to 255 000 bpd of heavy oil from the at 255 000 bpd. Engineers will focus interest in Qatar’s Block BC (pre-Khuff) Athabasca oil sands. on improving efficiency and adding exploration license. CNOOC Middle East “This start-up is an important capacity through debottlenecking. (Qatar) Ltd will continue to be the operator milestone for our heavy oil business,” Design and engineering work also with a 75% interest. said Marvin Odum, Shell Upstream continues on the proposed Quest Located 130 km east of the Qatari Americas Director. “It adds new carbon capture and storage project at coast, the offshore block covers an area of capacity from an important source of the Scotford Upgrader. Quest could 5649 km2, with water depths ranging from oil in a world requiring more secure capture and store underground some 15 to 35 m.

energy.” 1 million tpy of CO2. A final decision The Block BC Exploration and This is the first commercial to begin construction could come in Production Sharing Agreement (EPSA), production from the upgrader 2012, once all regulatory approvals entered into with the Government of the expansion. The Scotford Upgrader are in place. State of Qatar, stipulates that 2D and 3D seismic surveys will be conducted and that // Marathon// Shale at least three exploration wells will be drilled // ExxonMobil // by 2014. Angola strategy assets purchase Commenting on Total’s participation in the Block BC EPSA, His Excellency Dr Mohammed Bin Saleh AI-Sada, Qatar’s The Offshore Technology Conference Corp. has announced Minister of Energy and Industry said, “We (OTC) presented ExxonMobil that it has reached a definitive would like to welcome our long time partner, Development Co. with a special agreement with Hilcorp Resources Total, into the Block BC EPSA, and we wish citation for the development and Holdings, LP to purchase its assets them and CNOOC all success with the implementation of the ‘Design in the core of the Eagle Ford shale exploration activities, which we believe are One, Build Multiple’ strategy that formation in Texas in a transaction always enhanced when quality companies successfully delivered large-scale valued at US$ 3.5 billion. Along with such as Total and CNOOC join efforts.” deepwater projects offshore Angola other transactions expected to close “The farm-in transaction is another on Block 15, which achieved peak by the end of this year, Marathon’s step forward in the partnerships forged production of over 700 000 bpd of Eagle Ford acreage position is with and CNOOC, and oil with the aid of two tension leg expected to more than double to reflects Total’s commitment to expanding platforms and five of the world’s 285 000 net acres. its exploration and production operations largest floating production, storage and In addition to the six rigs currently in promising geological basins”, stated offloading vessels. under contract related to this Christophe de Margerie, Chairman and Chief The projects in Block 15, acquisition and two in Marathon’s other Executive Officer of Total. approximately 90 miles off the coast Eagle Ford acreage, Marathon has Present in Qatar since 1936, Total has of Angola, established industry five drilling rigs on order and expects a 100% interest in the Al Khalij field, a 20% benchmarks for completion time and to be operating at least 20 drilling rigs interest in North Field Bravo (NFB) block and unit development costs for deepwater in the Eagle Ford within 12 months of a 10% interest in the Qatargas 1 liquefaction projects of their size and complexity. To closing this transaction. As a result, the plant. The Group also has a 24.5% stake date, over 1 billion of the 5 billion bbls company expects to grow production in the Dolphin Energy Ltd company and a discovered on the block have been from its total Eagle Ford acreage 16.7% stake in Qatargas 2 Train 5. Total’s produced. Current production is position to a peak of approximately Qatari production averaged 164 000 boe approximately 500 000 bpd. 100 000 net boe per day by 2016. per day last year.

OILFIELD TECHNOLOGY 08 June 2011

THE ARCTIC HEATS UP

he Arctic is one of the most desolate places on oil (90 billion bbls), could be found there. “I think Earth, starting at a latitude 66˚ 33N, it covers the USGS survey is conservative,” says Dr. Benoit Tsome 21 million km2, or 6% of the planet’s Beauchamp, a professor of Geoscience at the surface. One third is land and two thirds sea; for much University of Calgary and the Director of the Arctic of the year, it is shrouded in darkness, ice and raging Institute of North America. “They did a good job blizzards. of the Beaufort Sea and the Mackenzie Delta, but But the Arctic is also a land of tremendous bounty. downplayed the potential of the Sverdrup Basin in Whales feast on abundant sea life, polar bears hunt the Canadian Arctic Islands and the Baffin Bay basin the shores for seals, and herds of caribou wander the between Greenland and Canada.” vast tundra. Beneath the surface rests immense fuel Recently, the search for oil and gas in the far north reserves; according to the United States Geological became a lot easier. Due to rising temperatures, the Survey (USGS), more than 400 oil and gas fields, area of the polar region subjected to permanent sea ice containing 40 billion bbls of oil, 1136 trillion ft3 of has begun to shrink, from an annual summer minimum natural gas, and 8 billion bbls of natural gas liquids of 9 million km2 in the 1990s to 6 million km2 in 2007; have been identified and developed, mostly in the some scientists predict a total clearance of ice by 2040. West Siberian Basin of Russia and on the North Slope The retreat has not only opened up northern shipping of Alaska. lanes, it has extended the period of seismic offshore And much more remains to be found. In a 2008 research and drilling by several months. study, the USGS assessed all potential sedimentary The result has been a resurgence in oil and gas basins north of the Arctic Circle and estimated that exploration not seen since the 1970s. Infield Systems, approximately 30% of the world’s undiscovered gas a London-based consultancy, estimates that capital (1670 trillion ft3) and 13% of the world’s undiscovered expenditure in the Arctic region should increase steadily

10 Climate change may be opening up the Arctic to an exploration boom, but other factors may be shutting it down. Oilfield Technology Correspondent Gordon Cope takes a look at these factors.

11 throughout this decade, rising to over US$ 7 billion annually buildings to collapse,” says Beauchamp. “Right now, engineers through 2017. don’t know what the effect will be, and industry doesn’t like to x In Alaska, has announced a plan to spend at least deal with such large unknowns.” US$ 768 million exploring 2000 km2 on the North Slope over the next several years. Development of this region’s Politics as usual offshore continental shelf (OCS) has been estimated by In addition to geological and meteorological considerations, the American Petroleum Institute to have the potential navigating Arctic waters will require a steady hand when it to produce 10 billion bbls of oil and 15 trillion ft3 of gas, comes to social, sovereign and environmental issues. generating almost US$ 200 billion in government revenues over the next four decades. The Arctic has a permanent population of 4 million residents in Alaska, Northern Canada, Greenland and Russia. Most of x In Russia, the immense Shtokman field, with reserves of over 24 billion boe, is tentatively due onstream in 2016. them are aboriginal people, and their emphasis is on preserving CGGVeritas and JSC Geotech Holding have announced a their environment and livelihoods. For the last several years, joint venture to supply ice class vessels to shoot 2D and 3D Shell has attempted to drill licences held in the Beaufort Sea and seismic in Arctic waters to delineate further targets. Chukchi Sea (a body of water between Alaska and Russia that and BP have formed a joint venture to tap into Arctic regions may hold as much as 30 billion bbls). Aboriginal groups objected previously reserved for Russian companies. to Shell’s programme, and late last year, a federal Environmental x Several companies have announced plans to institute and Appeals Board judge ruled that the Environmental Protection continue exploration in Greenland, which has a potential Agency (EPA) had not adequately evaluated the effect of drilling for over 50 billion boe in its offshore waters. Cairn drilled emissions on nearby aboriginal villages, and repealed two EPA three wells in 2010, one of which showed signs of oil, and permits. Shell, in turn, announced it would postpone drilling until plans to drill another four during the 2011 season. Shell and the issue was resolved. Statoil have been awarded two large exploration blocks in Environmental groups are adamantly opposed to Arctic West Greenland totalling more than 20 000 km2. drilling, and may have good reasons to be worried. BP’s x In the Canadian Beaufort Sea, Shell and Exxon have spent almost C$ 1.8 billion in the last two years meeting Gulf of Mexico deepwater drilling disaster last year (in which lease obligations, and hope to drill an offshore well on the 11 crew members were killed and almost 5 million bbls of oil continental shelf within five years. were released), highlighted the diffi culties of countering a major spill even in an accessible, warm climate. Experts painted a Problems glum picture of the ability to respond to a similar spill in an Arctic There are many challenges facing Arctic exploration and accident. Retired Admiral Thad Allen noted that only one of three development. First and foremost is the harsh climate; winter US Coast Guard ice breakers is currently operational. The daily averages hover near -30 ˚C, and total darkness can stretch drill-staging community of Barrow, Alaska has no ability to house for six months. the hundreds of extra workers needed to handle a spill, and Secondly, the Arctic is gas prone; about three times as limited ability to handle emergency aircraft. Harsh weather and much undiscovered reserves are considered to be gas, the rest ice fl oes would further complicate remediation efforts. is oil and natural gas liquids. Current markets for natural gas The National Oil Spill Commission, appointed by the in North America are depressed by the glut of shale gas. This White House after the BP disaster, also iterated these concerns, surplus has already cast doubt over the viability of the recently saying that much more offshore research was necessary to approved Mackenzie Gas Pipeline (MGP), a C$ 16 billion ensure the ability to overcome the challenges imposed by the project designed to ship up to 1.9 billion ft3/d from the onshore extreme Arctic environment. “Before the spill, there was talk of Mackenzie Valley fi elds 1200 km south to markets in Alberta, BP and Exxon drilling a subsea well in the next fi ve years,” says and the Alaska pipeline, a proposed US$ 35 - 40 billion project Beauchamp. “They were also seeking to remove a drilling clause to send 4.5 billion ft3/d of stranded gas in the Prudhoe Bay fi eld that called for their ability to drill a relief well in the same season. to the lower 48 states. Now, I don’t think removal of that clause will fl y at all. Industry The trend toward rising temperatures is not without its will have to come up with serious plans to control any disaster downside, either. “Climate warming is a blessing and a curse,” fi rst.” says Beauchamp. “With less sea ice, you can navigate in the There are also many sovereignty issues to be sorted out. The Northwest Passage (NWP) and the Beaufort Sea, which aids NWP is a convoluted channel that passes between Canada’s in seismic exploration and commercial traffi c, but you are also mainland and its Arctic Archipelago. For centuries, seafarers getting bigger, faster icebergs that scrape the ocean bottom seeking a shortcut from Europe to Asia have sought an ice free much deeper, which means you have to bury pipelines quite route, to no avail. Now, climate warming has opened the NWP deep to avoid damage.” completely for months at a time, creating an opportunity to Climate change also complicates drilling. “During the fi rst safely transit the sea route. round of exploration in the 1970s, the industry used some clever Unfortunately, there is no international agreement on who devices to drill, such as building artifi cial ice islands by spraying can use the passage, and when. The United Nations Convention sea water in the cold conditions so that they could land large on the Law of the Sea (UNCLOS) allows free travel of vessels planes and install huge rigs,” says Beauchamp. “Now, there is through certain bodies of water that transect jurisdictions some question if such devices would still actually work, and (such as the Strait of Hormuz and the Strait of Gibraltar). companies may need to bring in steel-reinforced ice platforms at Individual nations, however, control passage through internal much greater expense.” bodies of water (such as the Mississippi River in the US). When Onshore infrastructure can also suffer. “Climate warming UNCLOS was being created in the 1970s, Canada pushed for can destabilise the permafrost, causing roads to buckle and the latter designation. “As a sovereign water, Canada can say

OILFIELD TECHNOLOGY 12 June 2011 Be master of the Arctic

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*VW`YPNO[(RLY:VS\[PVUZ(SSYPNO[ZYLZLY]LKwww.akersolutions.com/subsea no to vessels carrying nuclear waste, or insist on The Arctic Council, an international body that has traditionally double-hulled vessels carrying crude,” says Dr. Rob Huebert, been used to communicate concerns between five main aboriginal the Associate Director of the Center for Military and groups and the eight nations that rim the Arctic (Norway, Strategic Studies at the University of Calgary. Sweden, Finland, Russia, Denmark’s Greenland, Canada, the The US and EU disagree with Canada, however, and US and Iceland), has taken a further step forward and created argue that the NWP is an international strait. “If the NWP is an international treaty that will divide search-and-rescue considered an international strait, then the ability of Canada responsibilities among the nations and co-ordinate emergency to control shipping is limited,” says Heubert. “You can have response efforts. military vessels and nuclear powered subs, as well as the In the longer term, the industry will design exploration right to military flyovers.” and production hardware designed to deal with harsh Arctic “There is also an environmental aspect to control of the conditions. Seabed Rig, based in Stavanger, Norway, in NWP,” says Beauchamp. “International laws are less enforced conjunction with Statoil, is developing a remote controlled rig than Canadian laws. It would be more difficult to control the that would sit on the Arctic seabed, well away from ice. The rig dumping of wastes.” would be remotely controlled through an interactive 3D interface Unlike the Antarctic, which is not claimed by any nation, located on a surface vessel above. The rig is sealed to prevent there are five nations that claim sovereignty over parts of contamination of the surrounding water, and has zero-liquids the Arctic: Canada, the US, Denmark (Greenland), Russia discharge during operations. and Norway (known as the Arctic 5). Several disputes over Numerous shipbuilders around the world, including Teekay international boundaries remain to be solved. In 1825, in Vancouver and FLEX LNG in the UK, are working on building Russia and Great Britain established the north-south floating LNG plants capable of handling 75 - 100 million ft3/d boundary between Alaska and British North America as of gas. Designed to circumvent the long, expensive process of the 141st meridian of longitude. After the US purchased building a liquefaction plant on land, the self-propelled vessels Alaska from the Russians and Canada became independent, can pre-treat, liquefy, store and offload LNG. Such vessels are however, a disagreement arose over where the boundary ideally designed to produce remote gas fields in the Arctic during actually rested offshore. Each country covets a pie-slice of ice-free months, then move out during inclement winter weather. territory that covers some 21 000 km2, and may hold as much Changing economics may also make Arctic pipeline projects as 1.7 trillion m3 of gas and 6 billion bbls of oil. more viable. “I’m cautiously optimistic about the MGP,” says Beauchamp. “Shale gas is the big bogeyman; many people think The near future that we won’t need the MGP or Alaska pipeline for a long time. Over the next few years, research may begin to dispel some But I think that the industry may have already picked the low of the concerns regarding the Arctic. The region, which is hanging fruit of shale gas. The growing oilsands production will 30 times the size of Texas, has only a few thousand wells in soon need that gas.” total; it may be far more oil-prone than geoscientists expect. In addition, an untapped source of energy may eventually During a recent Arctic technology conference, representatives come to the fore in the Arctic. Gas hydrates are complex water from Total SA postulated that exploration in deeper waters ice structures in which methane is trapped. Geoscientists reckon and around the rims of basins might find oil that was that there are several thousand trillion ft3 of methane trapped displaced by such giant gas reservoirs as the Snøhvit field off in hydrates around the world, with significant concentrations in Norway, and the supergiant fields in the Yamal Peninsula/ Arctic permafrost and seafloor sediments. For the last several Kara Sea off northern Russia. years, the US National Research Council, the Geological Survey of Industry and nations are working to find solutions to Canada and other researchers have been conducting experiments above-ground problems. Experts note that aboriginal at the Mallik field in the Mackenzie Delta. Their studies have reluctance regarding oil and gas production depends on shown that hydrates can be produced in commercial amounts how companies approach communities. “You can’t make from conventional gas wells. blanket statements in regards to aboriginal attitudes and development,” says Huebert. “When you look at the Canadian Conclusions side of the Arctic, you have aboriginal groups that are Although many obstacles remain, the Arctic is still the largest favourably oriented, such as the Aboriginal Pipeline Group remaining region of untapped energy, and is relatively free of pushing for construction of the Mackenzie Valley Pipeline, political restraints that place most of the world’s energy supplies which is a reflection of the homework that BP and Exxon did off limits to IOCs. “In 10 years from now, I see significant oil and there. The Greenlanders are also really looking forward to gas production in the Beaufort, the Russian high Arctic, and off oil and gas development; the Danes and Greenlanders have Greenland,” says Huebert. worked out an agreement that will see independence talks Dr. Beauchamp agrees. “Other regions with the potential for large move ahead when they reach a certain degree of prosperity.” conventional discoveries have warlords and terrorists and unfriendly In 2010, Russia and Norway announced that they governments,” he notes. “The Arctic is under Canadian and US had resolved a 40 year old Arctic boundary dispute, jurisdiction, which have stable governments and regulations. That encompassing 170 000 km2, to their mutual satisfaction. makes the Arctic less risky and more appealing.” O T Canada and the US also launched a joint expedition survey in order to map the Arctic’s North America continental shelf. Notes Not only will it ascertain the extent of the OCS, the data will 1. Dr. Rob Huebert is the Associate Director of the Center for Military and Strategic Studies at the University of Calgary. also help resolve the maritime boundary between the two 2. Dr. Benoit Beauchamp is a professor of Geoscience at the University of countries. Calgary and the Director of the Arctic Institute of North America.

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ZZZFXGGFRP ‡  The Russian riddle Ekaterina Kozinchenko, Jake Leslie Melville, Hege Nordahl and Adrian Del Maestro, Booz & Co., UK, contribute their perspective on ensuring the long term success of Russian oil and gas.

inston Churchill once described Russia as ‘a riddle, Geographically, Russia sits strategically between the large wrapped in a mystery, inside an enigma.’ That energy demand centre that is Europe, and the rapidly growing W remark still resonates with Russia’s foreign investors demand centres of China, India and other Asian economies. It – particularly with those involved in the energy sector. Today remains very important geopolitically. Russia stands at a major crossroads with regards to the What is less clear is how well prepared Russia is to face evolution of its oil and gas industry. What is undisputed the array of challenges to further develop its energy resources; is that the country boasts some of the world’s largest a growing fiscal burden, ongoing investor concerns about the hydrocarbon reserves, and is the largest oil and gas producer. regulatory framework, inconsistent government intervention in

16 the energy sector, overlaid as a costly place to do business remote and frontier basins under difficult conditions, such from an expatriate perspective. An additional concern relates as offshore Arctic. The industry needs to further develop the to the age and the types of fields both in production, and technical capabilities required to deliver large capital projects those still to be developed. Can the oil and gas sector meet in both the upstream and downstream segments. Developing the growing technical and operational challenges in accessing these capabilities – often by working side by side and in the country’s additional hydrocarbon reserves? collaboration with international companies that have the New oil and gas developments in Russia are increasingly requisite expertise – will be key for the long term success of complex, with operators having to explore and produce in the sector and critical in enabling domestic players to increase

17 It appears that international oil companies (IOCs) have been expressing growing confidence in Russia. This year alone has witnessed the announcement of the BP Rosneft alliance (yet to be completed) focusing on exploration opportunities in the Arctic South Kara Sea, as well as Total’s US$ 4 billion investment to acquire a 12% stake in the gas producer Novatek. Similarly, Shell announced a strategic alliance with the Russian gas giant towards the end of 2010, signalling its continued interest in Russia after the events of 2006, when the super major was forced to cede majority control of one of its flagship projects, Sakhalin II. Investor confidence in the Russian energy sector is not just limited to the oil majors. Wintershall (the upstream subsidiary of BASF) has a long history of co-operation with Gazprom. Indeed the two companies have three gas-marketing joint ventures, as well as production joint ventures in Russia and Libya. They also recently signed a memorandum of understanding on joint development of gas Figure 1a. Proven gas reserves by country, 2009. fields in West Siberia and the North Sea. Source: Booz & Company research. …but there are challenges ahead Despite the renewed interest of the international oil majors, West Siberia, the country’s most prolific oil province, is in sharp decline due to basin maturity and the lack of sufficient investment in existing infrastructure and new project developments. Partly for this reason, and as illustrated in Figure 2, oil production after a decade of substantial growth now appears to be plateauing. As a result, energy companies are having to develop new prospects in frontier territories, driving up their costs significantly. Figure 1b. Top 10 oil producers, 2009. Growing capital project capabilities will be a production, build local infrastructure, and to execute fundamental hurdle for the industry expansionist strategies overseas successfully. Looking across the whole oil and gas value chain, there are a number of major capital projects under development by The size of the prize is truly significant… Russian companies, both at home and abroad, as illustrated The importance of Russia as a major hydrocarbon basin in Figure 3. cannot be over emphasised. As illustrated in Figure 1a, Their ability to deliver these projects in a timely and Russia boasts the largest gas reserves in the world - cost-effective manner depends upon two major factors. First, representing nearly a quarter of global resources - and Russian companies will need to have core project delivery competes with Saudi Arabia as the largest global oil capabilities, including diligent project scoping and concept producer, (Figure 1b). development, use of new technology, risk management, Russia remains the major gas supplier to Europe, and rigorous project planning, appropriate contracting strategies, is also a large crude supplier. Despite recent economic and a decision driven project delivery model. Second, they woes, its importance is undiminished. More than 80% of will need to manage and understand the operating context the country’s crude oil exports go to Europe and Eurasia, in light of difficult new frontier operating environments and while nearly half of gas exports by pipeline go to Germany, local content requirements, as well as expertise in stakeholder Ukraine and Italy alone. The political turmoil that is management of government and local partners. All in all, sweeping the Middle East and North Africa has served to the project organisation and governance set up needs to reinforce the importance of Russia as a major hydrocarbon be tailored to the delivery challenges and operating context supplier. (including appropriate contracting strategies and capability

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© 2011 Halliburton. All rights reserved. levels). Specifically, the Russian oil and gas industry needs Options for developing the key capabilities to strengthen technology development and improve capital Given the challenges facing the Russian oil and gas project delivery capabilities, such as: sector, Russian oil and gas operators have three main x Front end loading: scoping, planning and detailing of strategic options: design and concepts, to avoid re-work: stakeholder x Partnerships. Working closely with IOCs and management for approvals. collaborating on research and development is a lExecution: contracting strategies, risk management, viable and popular option. Examples of such joint project control (design freeze, quality, plan and cost, ventures would include Gazprom’s collaboration with decision gated maturation), commissioning – stakeholder Statoil and Total in the Shtokman development in management for licence to participate. order to access advanced Arctic technologies. Part lTransition/handover to operations: production and of the rationale underpinning the alliance between BP resource (capability) ramp up and operating model – and Rosneft was to establish an Arctic technology stakeholder management for licence to operate. centre to develop innovative technologies for the safe x Developing or assembling these capabilities will require exploitation of the Russian Arctic shelf. According setting up a delivery, governance and stakeholder to recent press commentary, Gazprom is also management model that takes into account operating considering shale gas joint ventures in North America context, contracting strategy, access to capability, local in order to learn the technology. It is possible the gas content and regulations, JV configurations and enabling giant will enter the US shale gas market in the next effective decision making (clarity on accountabilities six to 12 months collaborating with smaller and more and decision rights) and delivery both during project well-established players. execution and during operations. x M&A. Acquiring the required capabilities in capital construction is another option. , for example, recently announced it was interested to work alongside North American companies in shale gas and ‘shale oil’ technologies. x Centres of excellence. This route involves establishing internal learning centres where best practice is captured and best in class processes and methodologies are developed. TNK-BP, Lukoil and Transneft have all respectively pioneered the creation of internal capital construction centres of excellence. Conclusion Figure 2. Russian oil production, 2000 - 2009. Source: BP Statistical Review of World Energy Churchill concluded his famous June 2010; Booz & Company research. comment on the riddle of Russia by noting that ‘the key [to solving it] is Russian national interest.’ That interest, happily, is the same as the interests of the global energy industry, as well as those of consumers in Europe and Asia: with the right sets of capabilities in place, foreign energy companies present the best path forward for Russia to develop and capitalise on its incomparable oil and gas reserves, and to ensure abundant supplies for these key markets in future decades. O T

Note Founded in 1914 by Edwin Booz, Booz & Co. is a global management Figure 3. Source: BP Statistical Review of World Energy June 2010; Booz & Company research. consultancy, working with businesses, governments and organisations.

OILFIELD TECHNOLOGY 20 June 2011 CREATING INVESTOR OPPORTUNITIES

Kevin Forbes, Epi-V, UK, explores the opportunities for private equity investors in the upstream services sector, which is set for the next phase of industry investment.

echnology has been crucial in supporting the sourcing and production of hydrocarbons since the modern age of oil and gas exploration began. T These technologies are developed to reduce capital expenditure, improve reservoir recovery, access new hard-to-reach reserves or minimise the environmental impact of exploration. Each requires signifi cant fi nancial capacity to develop, commercialise, test and position in order to achieve market adoption. Parke A. Dickley, the petroleum geologist, once famously wrote of oilfi eld exploration in the 20th century: ‘Several times in the past we thought we were running out of oil and gas, whereas, actually, we were only running out of ideas.’ Over the next few years, ideas in the form of innovative oil and gas technology will be more important than ever as the sector faces a raft of notable challenges.

The industry need The ongoing need to make the extraction of challenging conventional reserves more cost-effective creates a fertile environment for new technologies to emerge. Progress in this area is helping the industry to exploit reserves that had previously been uneconomical; building future value for their owners.

21 However, one of the barriers remaining is changing To position companies to bring game-changing technologies non-conventional reserves into cost-effective, efficient to market, initially, they require capital investment to allow for prospects. Accessing this new oil requires intensive drilling product development, qualification and commercialisation - and new completion methods, which in turn necessitate overcoming the challenges of industry adoption. significant capital investment. Epi-V has successfully invested A notable challenge for new companies is to define potential in technologies such as the i-Tec I-FRAC ball drop activated applications and markets for a given technology. Epi-V works fracturing sleeve; that are helping to unlock these resources closely with management teams to chart all conceivable industry efficiently. These new, innovative technologies will be vital if the opportunities and how the technology can bring most value to industry is to meet energy demand, which is predicted to grow the industry operators. In many cases, technology companies by 40 - 50% to 2035 by the International Energy Agency (IEA). commercialise ineffectively as a result of failing to appreciate For emerging fast moving services businesses, the industry the adverse implications of changing current operator workflows climate is bringing considerable new growth opportunities to or target applications that have low value to the operator. The the fore. These opportunities include technology that is able to broader perspective of an experienced, specialist investor can cost-effectively address the difficulties posed by deepwater, bring insight into the true commercial opportunities. This stage geologically complex reservoirs and unconventional reserves, should assess the feasibility, use, development time and markets such as shale gas. for the given technology, and consider additional applications Moreover, with oil prices above US$ 100 and the industry that can speed adoption, identity value from an operator’s increasing its capital expenditure by 11% this year, 2011 is as perspective and, ultimately, create a profitable business. good a time as any to back oil and gas services, as the sector Strategic market positioning can then be taken to the enters its next significant spending cycle, with notable capital next level, with the company actively engaging with its target investment expected. customers having understood their requirements. By aligning Entrepreneurial technology-driven oil and gas services technology with customer requirements, the business can then businesses are highly attractive to a specialist investor, such build persuasive marketing and brand strategies. as Epi-V, where, through a mixture of growth capital, industry There are also more practical issues to take into account. How insight and commercialisation competence, it can turn potential does the business translate the founder’s science and innovative into a flourishing company of significant strategic value to the IP into a development programme to create robust products? industry. Does the company manufacture or outsource? What facilities are required? How will the business cope with geographic The shale challenge distribution? How will management recruit and manage a diverse The swift rise of shale gas and oil is just one of many workforce to meet growth targets? In the midst of all this change, segments of the oil and gas industry that is creating significant the business must take an objective and disciplined approach opportunities to invest in groundbreaking innovations that to funding and cash flow, as this is the lifeblood of any new optimise production and drive process efficiencies. business. Experienced investors can provide significant support Shale’s extremely low permeability and the extraction to guide emerging businesses though this process. challenges this created meant that it was previously considered Combined, these stages allow a technology-led oil and gas completely uneconomical. However, the combination of services company to find its market, perfect its proposition and horizontal drilling, hydraulic fracturing and high tech build a presence that allows for rapid adoption and profitable multi-stage completions is allowing us to realise some of the business growth. potential of these vast reserves, with greater than 50% of US rigs now drilling horizontal wells and more than 150 drilling in Ideas transformed into successful companies one basin alone. Innovation and technology will become increasingly central to The challenges this market poses are both technical and the fortunes of oil and gas exploration businesses as companies economic, and they are placing strategic premiums on new explore resources in ever more challenging environments. The technology capable of maximising reservoir contact and inflow opportunities for investors and investee companies alike are performance, while improving efficiency and reducing time and significant, so long as the proposition is well positioned in the costs. marketplace. Epi-V is looking at a broad range of businesses with In seeking funding, businesses should look to potential technology that, when applied to this market, will address partners with deep industry experience, not just funding. The specific process challenges. These include maximising industry is very competitive and traditionally slow to embrace economic reservoir contact for the well and improving drilling new technologies, and financial backing alone is simply not and completion efficiency safely. enough to gain competitive advantage. Emerging oil and gas services companies should seek both An investor’s active approach investment and the alternative viewpoint that an experienced As mature participants in the upstream services sector, Epi-V investment partner can bring to its companies to help them has witnessed a number of technologies with potential to exploit realise their growth potential. When commercialisation is effective, these new high value growth markets. upstream oil and gas services businesses can seize opportunities. The organisational maturity of the majority of ambitious, By identifying specific market opportunities and working technology-led oil and gas services companies means that closely with management to fully exploit their technology in investment alone is not enough. To access new growth areas, that space, it’s possible to turn a nascent technology into a funding should be considered as only one requirement in a significant growth business that drives innovation for the entire company’s long-term growth strategy. industry. O T

OILFIELD TECHNOLOGY 22 June 2011 'HOLYHULQJLQQRYDWLRQLQRLOßHOGFKHPLVWU\ :HRIIHUDODUJHVHOHFWLRQRIJURXQGEUHDNLQJFKHPLFDOH[WUDFWLRQ DQGSURFHVVVROXWLRQVIRUWKHRLODQGJDVLQGXVWULHVZKHUHZDWHU SOD\VDFHQWUDOUROH8WLOL]LQJRXUH[SHUWLVHRXUFXVWRPHUVDUH DEOHWRLPSURYHWKHLUHIßFLHQF\DQGSURGXFWLYLW\WKURXJKRXWWKH HQWLUHRLOSURGXFLQJYDOXHFKDLQ)URPGULOOLQJDQGGULOOHGVROLGV WUHDWPHQWFHPHQWLQJDQGZHOOVWLPXODWLRQWRSURGXFWLRQDQG HQKDQFHGRLOUHFRYHU\DQGUHßQHU\ZDWHULVWKHFRQQHFWLRQ

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OT_21-24_June2011.inddOT_JuneOnline.indd 1 24 08/06/201107/06/2011 09:0916:45 Kristofer Tingdahl, dGB Earth Sciences, USA, addresses the limitations of seismic interpretation.

ew would argue against the premise that seismic interpretation tools and their ease of use have Fimproved significantly over the last few years. From advances in attribute analysis to fault mapping and horizon picking, seismic interpretation has made substantial advances in developing geologically consistent 3D representations of the subsurface. Interpreters today can also enjoy a highly visual graphics environment on which to rigorously interpret their geological data and maximise its value for future reservoir management decisions. This being said, however, seismic interpretation today still comes with certain limitations, which are manifested in a number of ways. For example, many geological models, often containing gigabytes of data, still remain highly generalised. All too often, it is just kilobytes and megabytes of data, including just a few mapped horizons, from which important interpretations are derived. The result is that huge amounts of potentially valuable seismic information are being lost. There is also often a lack of understanding of the full structure of the seismic data, a lack of integration across the workflow and a manual-focus to interpretation activities.

25 automatic fault detection and defi nition and the accurate structural modelling of both fi elds and prospects. While conventional interpretation workfl ows might only require a limited number of key horizons to be mapped, however, it has become clear to us that, by automating horizon tracking and creating a denser set of horizons, interpreters can extract more geology from their seismic data. A dense set of auto-tracked horizons can help guide well correlations, generate an improved insight into the depositional environment, interpret systems tracts, and improve the chances of fi nding stratigraphic traps where oil might be Figure 1. The HorizonCube process and the impact it can have on all elements of the seismic found. interpretation workfl ow. Furthermore, in comparison to standard workfl ows where the low frequency model is often considered to be the weakest link, having a dense set of horizons can result in a much more detailed model being built to be put forward for . By interpolating well data along the dense set of horizons, detailed geologic models can be generated that are fully consistent with seismic measurements. This is the rationale and thinking behind the dip-steered auto-tracker dGB Earth Sciences has developed, known as the HorizonCube.

Building the HorizonCube The HorizonCube is a new plugin which is part of the company’s Figure 2. The power of high density horizon tracking for chronostratigraphic correlation. All tracked OpendTect seismic interpretation events are assigned a relative geological age displayed with a corresponding colour. software, where a dense set of correlated 3D stratigraphic surfaces are developed into a set of continuous, In this way, users are unable to gain a clear picture of the data’s chronologically consistent horizons through an advanced depositional history, and horizons and faults often have to be algorithm. All correlated 3D stratigraphic surfaces are assigned a picked and edited manually. relative geological age. Against this context, there is a clear need for today’s seismic Figure 1 outlines the process as well as the impact interpretation software to generate improved quantitative rock the HorizonCube can have on all elements of the seismic property estimations and clearer defi nitions of stratigraphic interpretation workfl ow, from well correlation to inversion to traps, create more accurate and robust geological models, and sequence stratigraphy. extract more value from the terabytes of high resolution seismic To create a HorizonCube, all the user must do is input data. dip and azimuth cubes, at least two mapped horizons, and This article will look at how these challenges are being met (optionally) mapped fault planes. Horizons are then created through a new automated horizon tracking tool and an improved either in a model-driven way (through stratal or proportional graphics-focused environment. slicing, for example) or in a data-driven way via a dip-steered, 3D chronostratigraphy auto-tracker. The importance of horizons The auto-tracker algorithm tracks the dip/azimuth fi eld to Horizons – the term used to denote the surface in or of a rock generate horizons that are typically separated by one sample at or a particular layer of rock that might be represented by a the starting position. The dip/azimuth fi eld is smoothed, reduces refl ection in seismic data – have always been central to seismic the impact of random noise, and allows the user to control the interpretation. Seismic horizon interpretation can result in detail that needs to be captured by the horizon tracker.

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AVO sensitivity CMP gather & P G section CRS gather & P G section

CRS

TEEC +49 (0) 511 7240452 Burgwedeler Str. 89  www.teec.de 30916 Isernhagen, Germany [email protected] for example, demonstrates the difference between the HorizonCube and the conventional workflow in regard to not only the quality of the model but also the quality of the Acoustic Impedance (AI) inversions. The simple model uses only top and bottom horizons to guide the well interpolations (a). The detailed model uses 19 additional horizons (d). The simple low-frequency model (b) does not fully honour the seismic while the detailed model does. The inverted results which are driven by the input models reflect these differences (c & f). In this way, operators can get a lot more geology out of their 3D models and highly accurate low frequency models can be used to create geologically correct AI and Elastic Impedance (EI) cubes through the use of Deterministic and Stochastic Inversion plugins. A clearer image of reservoir geometries can also be Figure 3. The difference between the HorizonCube and the conventional workflow in regard to not only the obtained. For example, Figure 4 quality of the model but also the quality of the Acoustic Impedance (AI) inversions. shows the thickness maps of the depositional sequences Another advantage is that smoothed dip fields are more with and without HorizonCube interpretation on a field, offshore continuous than amplitude fields, that are used by conventional Abu Dhabi. auto-trackers that pick amplitudes and/or trace similarities and In this case, one of the main challenges of the seismic then stop when the constraints are no longer satisfied. The interpretation was the poor quality of the 3D data, where, due to result is a series of patchy horizons rather than continuous, this poor quality, the automated tracking of chronostratigraphic chronologically consistent horizons as is the case here with unit boundaries was not possible using conventional tracking HorizonCube. Horizons with watertight intersections at the faults methods (amplitude and phase responses were too indistinct for are also generated through the HorizonCube by automatically the tracker to trace for any distance in a consistent manner). stopping against mapped fault planes. Through HorizonCube, however, it was possible to create a Figure 2 demonstrates the power of high density horizon dense set of auto-tracked horizons and seismic-based maps of tracking for chronostratigraphic correlation. To facilitate depositional cycles and system tracts – in this case, reflecting correlation, a random line created from the 3D volume through sediment build-up on the reef surface. the wells and a dense set of horizons is auto tracked. All tracked events are assigned a relative geological age displayed with a Well correlation and seismic/well data integration corresponding colour with an interactive slider used to add or Two of the biggest challenges in seismic interpretation today are remove these chronostratigraphic events. the ability to effectively use seismic data to aid well correlation The process highlights in detail how events are correlated and to support this through the integration of well-based between the wells and aids in the understanding of how rock sequence stratigraphy with seismic sequence stratigraphy. properties vary laterally. For example, the sandy shelf-edge To this end, the densely tracked horizon mapping and the facies observed in the right well correlates with a shaly, interactive slider of HorizonCube allows interpreters to correlate toe-of-slope facies in the well on the left. and update well markers and horizons in order to improve well correlation. It allows the interpreter to reveal the spatial evolution The benefits of HorizonCube of the sedimentary succession by visually moving forwards and So what are the benefits of the new HorizonCube? backwards in geological time, highlighting in detail how events Firstly, the auto-tracked horizons allow a detailed and are correlated between the wells and aiding in the understanding accurate low frequency model to be developed. Figure 3, of how rock properties vary laterally.

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Trade house TMK TMK-Premium Service ULTRATM Premium Connections 40/2a, Pokrovka Street, Moscow, 105062, Russia 40/2a, Business centre Pokrovsky Dvor, 8300 FM 1960 West, Suite 350 tel.: +7 495 775-7600, fax: +7 495 775-7601 M. Kazeyny side-street, Moscow, 105064, Russia Houston, TX 77070 E-mail: [email protected] tel.: +7 495 411-5353, fax: +7 495 411-5363 Tel: 281.949.1023 www.tmk-group.ru E-mail: [email protected] Toll free: 888.258.2000 surfaces corresponding to the flooding surfaces and base level falls of sequence stratigraphy. The packages range in scale from the sequences and para-sequences of seismic stratigraphy down to the limits of the resolution of the logs. The analysis is carried out using the CycloLog software package from Enres International and is deployed by consultants with extensive experience in this method. The combination of this innovative approach to the stratigraphic analysis of well data with dGB’s SSIS technology offers clients a powerful means of building a stratigraphic and hence depositional framework.

The importance of an accessible, intuitive workflow HorizonCube can only be fully effective, Figure 4. The thickness maps of the depositional sequences with and without HorizonCube however, if interpreters move away from interpretation on a field, offshore Abu Dhabi. the manual-focused and limited graphics environments of the past and operate in an environment where workflow processes are more accessible and intuitive. It’s with this in mind that dGB has teamed up with the Japanese company Wacom, a world leading manufacturer of pen tablets and digital interface solutions, allowing seismic interpreters using HorizonCube to interact directly with the tablet in their editing and visualisation activities (see Figure 5). This allows for the drawing of horizons, faults and objects within a highly user-friendly and graphics-focused environment, with the interactive pen display allowing the user to directly work with the pen on the screen and thereby making the process of analysing data much more efficient. This is due to the perfect hand-eye co-ordination of the pen display and the fact that the user works exactly at the point Figure 5. Seismic interpreters can use HorizonCube to interact on the screen where he wants the cursor. directly with the tablet in their editing and visualisation activities. To this end, HorizonCube can be used for sequence stratigraphy interpretation where the horizons are used to mark sequence boundaries and faults can be directly Furthermore, in partnership with third-party specialists, drawn into the data set. The result is a highly innovative but dGB now offers the stratigraphic framework analysis of practical tool. associated well log data, as an add-on to its Sequence Stratigraphic Interpretation System (SSIS). Generating a different perspective Here, the stratigraphic analysis of well logs is conducted Seismic interpretation today is all about generating a interactively with the seismic data analysis, adding to both the different perspective on the geological and stratigraphic robustness and resolution of the resulting chronostratigraphic aspects of data volumes and squeezing maximum geological scheme. value out of this data. In particular, dGB offers unconventional, data-driven With applications, such as HorizonCube, and attribute analysis of well logs with which it can either QC partnerships with companies such as Wacom, where preferred well log markers for consistency with its SSIS dGB is using its experience in the photography, graphics, results, or build a completely new log-based framework, and fashion design industries and applying it to seismic based on sequence stratigraphic principles. interpretation, the company is seeing how seismic Like seismic data, well logs carry geological information in interpretation has the power to innovate and the overcome attributes that are unseen in conventional displays, and that limitations of the past. are therefore unexploited for stratigraphic interpretation. Geoscientists will finally be able to enjoy the full benefits Based on linear predictions, the transforming of a facies- of knowing the complete structure of their reservoir data, sensitive log (such as GR) reveals depositional patterns leading to geologically sound rock-property predictions, - correlatable from well to well - even across lateral facies effective well correlation and more geological information variations. These define packages of strata, bounded by from seismic than ever before. O T

OILFIELD TECHNOLOGY 30 June 2011 SHARPENED VISION

Henning Trappe, Gerald Eisenberg-Klein, Juergen Pruessmann, TEEC, Germany, discuss the use of CRS analysis on seismic data to improve the view of reservoir structure and lithology.

hree ingredients are required to obtain a good resolution numerical computer power. Modern depth imaging by prestack of our hydrocarbon reservoirs from reflection seismic depth migration (PreSDM) provides the most accurate methods Tdata. These are an imaging method that is able to collect for a combined realisation of the two imaging steps, the focusing and relocate the reflections pertaining to a specific reflector, of all reflections from a single subsurface structure, and their an accurate set of data dependent parameters that steer the relocation to the original position in depth. imaging process, and, hopefully, good data. Especially in complex geology, however, these PreSDM Highly accurate imaging methods are available today, methods are very sensitive to the signal-to-noise ratio of the but quite often cannot fully exploit their strengths. Data seismic data, and even more to the velocity depth model. Model noise and irregularities deteriorate both the determination of building has thus become the most crucial and costly step in accurate imaging parameters, and the actual imaging process, depth imaging, since PreSDM requires an accurate and even thus requiring effective ways to increase the robustness of more consistent global field of imaging velocities. Here again, imaging and lithology prediction. Such effective measures are the data quality has a strong influence on the model building demonstrated by recent strategies of the Common Reflection process. Surface, or CRS method that enhance the subsurface resolution The CRS approach now offers a preconditioning of seismic in both, the prestack domain of measured data, and poststack data that strongly raises the signal quality, and optionally domain of stacked data. compensates for irregularities in the spatial distribution of During the last decades, the determination of the seismic seismic recordings as well. The main idea of this CRS strategy imaging parameters, and the actual imaging process have is to collect and focus seismic reflection events belonging to seen a steady development to more and more sophisticated a local common subsurface structure, the so called common numerical methods that went hand in hand with the increase of reflection surface, before entering further imaging or reservoir

31 characterisation steps. As an example, Figure 1 illustrates the effect of CRS focusing by PreSDM sections of low fold 3D seismic land data. Further advantages of this CRS data preconditioning for imaging in time and depth, model building and reservoir studies are outlined in the following, after a closer look at the CRS imaging principles.

CRS method CRS focusing is characterised by both a high resolution, and a general robustness. Dense local measurements of seismic data parameters are collected from each imaging point into so-called CRS attribute volumes providing the high resolution. The robustness with respect to local parameter errors is based on the local independence of the measurements, in contrast to the mutually dependent estimates of PreSDM imaging parameters in a global model. Another advantage is the high number of contributions that are used in CRS focusing of individual reflections events, leading to a strong suppression of noise. This multiple contribution, the so called fold, is a consequence of the general CRS subsurface assumptions of local reflector elements with dip and curvature in the subsurface. In the seismic data, the seismic reflection produced by one of these complex reflector elements is certainly not confined to a specific common mid-point (CMP) of the shot and receiver pairs, but extends across many neighbouring CMP locations. Collecting the contributions from all these CMP locations amounts to a much larger stacking fold than in conventional CMP stacking using one CMP location at a time only. Figure 1. Kirchhoff prestack depth migration of CMP gathers (top) versus CRS gathers (bottom). Note the improvement of sedimentary The CRS contributions to a certain image point are reflections and salt boundary. collected along a hyperbolic time surface for zero-offset stacking, that was presented by Mann et al. (1999) and Jäger et al. (2001) following initial work by Gelchinsky (1988). Corresponding to the complex reflector geometry, a complex set of stacking parameters is required to define this time surface, comprising the wavefield dip α, and the wavefield

curvatures RNIP and RN at the surface. They are related to hypothetical wavefronts from a point source at the normal incident point (NIP) on the reflector, and from an exploding reflector, respectively. This is indicated in Figure 2 (top) for the case of 2D seismic data. The advantages of CRS stacking as opposed to conventional NMO/DMO stacking were illustrated by Hubral et al. (1999) in the schematic display of Figure 2 (bottom). The high fold and the increased S/N ratio of the CRS stacked section are attributed to the better fit of the CRS travel-time approximation (green) to the actual reflection times (blue) in a much larger area of the offset and CMP domains. CRS stacking obviously collects a much larger portion of the actual reflection. Stacking along the full CRS travel time approximation provides a CRS stack, whereas partial stacking in small offset and CMP intervals is used to produce CRS Figure 2. The CRS stacking attributes comprise the emergence angle gathers with an enhanced signal contents. α and the wavefront curvatures RNIP and RN at the surface, which can The main factor assuring the high resolution of the CRS be related to hypothetical experiments with (a) a point source, and (b) stack is the automatic estimation of an optimum set of the exploding reflector, respectively, in the subsurface (top row, after stacking parameters, the so-called CRS attributes, at each Jäger et al., 2001). The fit of (c) DMO and (d) CRS stacking surfaces point of the image. Due to this detailed attribute search, CRS (green) to the CMP/offset-dependent travel times (blue) are illustrated imaging is a computationally intense method, especially in for an anticlinal model (gray, bottom of graph), showing a large area with excellent fit for CRS stacking (bottom row, after Hubral et al., 3D applications. This advance in seismic processing can 1999). thus be regarded as another consequence of the increased

OILFIELD TECHNOLOGY 32 June 2011 power of modern computers, just like the evolution of new depth migration techniques.

Increased CRS fold for noise suppression in low fold data Seismic imaging generally faces problems when dealing with extremely low-fold or sparse seismic datasets. In order to obtain a good image in those cases, the redundancy of the data must be identified and exploited to the highest degree. Obviously, CRS imaging is well suited for this task by tracing seismic reflections through large portions of prestack data. This CRS imaging strength at sparse data has been illustrated by the depth sections of Figure 1 with strongly improved 3D PreSDM results from CRS gathers. A more systematic investigation on CRS stacking in low-fold data was presented by Gierse et al. (2007) starting from 3D seismic land data with a fold of 15. Acquisition at an even lower fold of eight was simulated by omitting every Figure 3. DMO reference stack of original 15-fold land seismic second shot line or every second receiver line, respectively, and data (left), versus CRS stack of reduced 4-fold data (right). Note the finally acquisition fold was reduced to four using both types of preservation and enhancement of structural resolution. omissions. For each configuration, CRS zero-offset stacks were obtained by full CRS stacking. Figure 3 compares the reference NMO/DMO stack from the original 15-fold data to the CRS stack of the final 4-fold data. CRS imaging fully compensates for the loss of acquisition fold, providing an image that is even superior to the conventional full-fold result in many areas. CRS imaging thus represents a processing option for 3D surveys acquired at low fold due to limited access or economic reasons. An additional advantage of CRS processing is observed in Figure 3 where the data is partly interpolated into the muted near surface zone by CRS using data from neighbouring inlines.

CRS gathers for enhanced prestack applications The previous CRS imaging examples have shown that CRS stacks of good quality may be produced for low-fold data, and then used for further processing in poststack time or depth migration. A much larger potential for improved imaging, however, lies in prestack applications of the CRS processing producing CRS gathers. The construction of CRS gathers makes use of the dense CRS attribute volumes that comprise local kinematic measurements for each point of the image, thus providing a detailed and accurate kinematic description of the seismic Figure 4. Original shot gather (top), and associated geometry- events in the data: this information can be used for mapping preserving CRS shot gather (bottom). seismic data to any existing, or new prestack trace geometry. Event data from original traces in the vicinity of a target trace is mapped to that target trace by dip-consistent partial CRS stacking, based on the CRS attributes. The CRS data mapping may be used to solely decrease the noise level in the existing data traces by considering exactly these input traces as target traces of the trace extrapolation. Each initial data trace is then replaced by an extrapolated CRS trace at the same location as shown in Figure 4, which obviously preserves the original shot geometry in the CRS shot gather but increases the signal-to-noise ratio by partial CRS stacking. CRS shot gathers with preservation, or enhancement of the original shot geometry are well suited for shot-based depth migration techniques like wave-equation PreSDM or RTM. Alternatively, new geometries can be introduced for Figure 5. Moveout corrected CMP gather (left), geometry-preserving reconstructing shots and target traces away from the existing CRS gather (middle), and CRS gather with offset regularisation (right).

OILFIELD TECHNOLOGY June 2011 33 data configuration, or for regularising the data geometry in workflow. Commonly the first step to depth is the fast derivation CMP/offset domain. Figure 5 compares an original CMP gather of an initial velocity model in depth from processing parameters from 3D land data with corresponding CRS gathers. Geometry of the time processing. The traditional Dix conversion of stacking preservation as performed in the CRS shot gather construction velocities into a starting model in depth is restricted to mainly flat of Figure 4, leaves the irregular data distribution in the structures since stacking velocities do not contain any useful dip CMP/offset domain untouched but enhances the signal contents information (Dix, 1955). (Figure 5 middle). Regularised CRS gathers with a uniform The CRS attributes, on the contrary, comprise an explicit dip CMP/offset coverage (Figure 5 right) may interpolate the seismic measurement. Inversion of CRS attributes by grid tomography reflections in large data gaps and even reconstruct seismic into a velocity depth model thus well reconstructs the dipping features like air waves. These CRS gathers are well suited for trends. This was demonstrated in a case study of CRS depth CRS-AVO investigations, and for Kirchhoff prestack migration in imaging in salt geology by Pruessmann et al. (2008), using 3D time or depth as shown in Figure 1. seismic data from the coast of the Gulf of Mexico. In this case study, the velocity model from CRS tomography followed the CRS based depth imaging workflow seismic depth structures much better than the Dix model from Both the CRS gathers, and the event information in the CRS stacking velocities (Figure 6). attributes may be used to design a complete depth imaging The costly refinement of the velocity depth model that uses iterative PreSDM with subsequent moveout analysis in depth gathers, can as well be shortened significantly by migrating CRS gathers. The flatness of the depth gathers as a measure of the model accuracy is more clearly visible in the CRS depth gathers with a high signal-to-noise ratio. The CRS depth imaging workflow finally produces a depth image with superior resolution of the near surface sediments, a better definition of the salt body, and much clearer sub-salt reflections in comparison to the result of the conventional workflow (Figure 7).

CRS characterisation of reservoir structure Based on the local optimisation of the CRS attributes the CRS processing may reveal local details that have not been present in previous stack sections. This is shown for a suspected gas-water contact, which is clearly outlined after CRS processing but much less in a conventional stack (Figure 8). Figure 6. Dix model (left) versus CRS tomography model (right) with Another example of structural reservoir characterisation respective CRS poststack depth migrated sections. from Eisenberg-Klein et al. (2008) compares time slices of 3D

Figure 7. Final prestack depth migration from conventional depth imaging flow (left), and from CRS flow (right). Note the improved definition of the salt body.

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www.drilformance.com +1 832 875 2512 +1 403 801 1442 coherency volumes calculated from a conventional prestack time migration, and a poststack time migration of a CRS stack (Figure 9). The slice of the conventional prestack time migration shows a strong noise contamination in some areas, while the CRS processing removed the noise and highlighted the faulting. Prestack time migration on CRS gathers provides a similar suppression of noise but was not considered in the work by Eisenberg-Klein et al.

CRS-AVO and reservoir lithology Besides structural investigations at reservoir level, CRS processing may also contribute to the lithology prediction, e.g. in impedance inversion of high quality CRS images, or by AVO investigations at CRS gathers as illustrated in Figures 10 and 11. For 3D land seismic data from a gas storage site, three moveout-corrected CMP gathers with standard amplitude-preserving preprocessing are shown at locations A, B and C, respectively (Figure 10 top). The noise contamination is obvious, producing a patchy amplitude distribution. Furthermore, acquisition irregularities had caused a varying offset coverage with several trace gaps. In the corresponding moveout-corrected CRS gathers, regularisation in the CMP-offset domain has filled the trace gaps by event-consistent data contributions from neighbouring CMP locations (Figure 10 bottom). Uncorrelated noise has been largely removed, revealing seismic reflections that were partly or fully buried in the noise before. Correlated noise, however, has not been eliminated as is demonstrated by the ground roll at location A. In general, the CRS gathers exhibit a good reflection continuity allowing a first rough evaluation of the offset-dependent amplitude behaviour. The most obvious feature is provided by the high reflection amplitude in the upper part of the CRS gather at location B. An increased amplitude level may also be recognised in the corresponding CMP gather, but due to the noise-induced fluctuations it does hardly stick out from Figure 8. Stack from conventional processing (top), and CRS the average amplitude distribution as represented at location C. processing (bottom). The suspected gas-water contact is much better The CRS gather at location B, on the contrary, does not only resolved by CRS, forming a horizontal line through the centre of the ellipse. show this strong amplitude increase very clearly but also its confinement to large offsets. Based on the CMP and CRS gathers discussed before, AVO analyses in the un-migrated domain produced the shallow vertical sections through the gather locations A, B, and C displayed in Figure 11. These sections contain the product (P*G) of the AVO attributes intercept (P), and gradient (G). The conventional result in the top row of Figure 11 clearly shows the noise contamination which is increasingly harmful when approaching minimum fold near zero time. In the whole section, the reflection information is completely hidden by the noise influence which is much stronger than any trends of the reflection amplitude. The CRS-AVO result in the bottom row of Figure 11 shows a strong noise reduction, now revealing the reflected structure forming an anticline. Most parts of the section show blue colours corresponding to the wet trend of water-saturated sediments, or decreasing amplitude with offset. The red colour mainly appears at anticline reflections at medium time where the gas-bearing Figure 9. Time slices at 1256 ms through coherence volumes reservoir is located. This colour corresponds to an increase of calculated from conventional prestack time migration (left), and reflection amplitude with offset, and indicates the presence of poststack time migration of the CRS stack (right), demonstrating gas. This effect is especially strong near the top of the anticline the noise suppression and associated fault enhancement by CRS processing. as confirmed by the CRS gather of Figure 1 at location B, and

OILFIELD TECHNOLOGY 36 June 2011 decreases at the flanks. As a result, the CRS approach provides a robust AVO analysis with meaningful results at data where conventional AVO completely fails.

Conclusions The CRS method that was originally developed as a generalised seismic stacking technique in time domain, has developed into a universal tool for robust parameter estimation and model building, enhanced lithology prediction and reservoir analysis, and high resolution poststack and prestack migration in time and depth, for 2D/3D land and marine data. The extension of the CRS stacking range over several CMP locations and over the full offset range strongly increases the fold, allowing a stable determination of the stacking parameters, the so-called CRS attributes, for each point of the image. These densely sampled attribute volumes represent a highly detailed event description of the seismic data for high-resolution applications in imaging and beyond. Figure 10. CMP gathers (top) versus regularised CRS gathers The increased fold of the local event description, and the (bottom) from 3D land seismic data across a gas storage. Note the associated increase of the signal-to-noise ratio in CRS imaging CRS signal enhancement in general. At location B, the increase of is effective in both land and marine data of various fold. amplitude with offsets is highlighted by the CRS result, and trace gaps Especially in low-fold data, CRS imaging uses the are filled. redundancy of the event information to a maximum extent in order to reveal reflections and faults that are mostly buried in noise in the associated conventional time and depth images. CRS may thus be regarded as a versatile complement of sparse 2D or 3D seismic acquisition in surveys with limited access, or severe cost restrictions. A powerful approach to combine CRS processing with modern prestack imaging techniques is the partial CRS stacking into so-called CRS gathers. CRS partial stacking reduces the data noise in prestack time or depth migration, and CRS data regularisation minimises the migration noise in these processes. CRS data regularisation in shot domain is well suited for wave-equation depth migration and RTM, whereas regularisation in CMP/offset domain improves Kirchhoff prestack migration in time and depth, but also AVO analysis, or simply the manual stacking velocity analysis in poor data. A comprehensive CRS depth imaging workflow comprises both the model building, and the prestack and poststack depth migration. In a first step, the detailed event information of the CRS attributes is inverted by grid tomography into a reliable starting model of the velocity in depth. Dip is well honoured in this model, in contrast to conventional models from Dix inversion of stacking velocities. The reliable starting model, and the improved model update on CRS-based depth gathers effectively reduce the model building time and cost. The final depth migration of CRS gathers increases the general resolution, and especially improves the definition of salt bodies and sub-salt reflections. The structural reservoir analysis strongly benefits from the high resolution of CRS imaging, and from the local optimisation of the CRS imaging parameters. Coherency measures from CRS images show a significant noise suppression revealing the fault systems in noise zones. A similar noise suppression is observed in CRS-AVO analysis, which allows to expand AVO to deeper targets and noise zones especially in land data. Further CRS tools are available, thus composing a complete processing chain from initial CRS residual statics until the final Figure 11. Conventional AVO (top) versus CRS-AVO (bottom): product CRS reservoir studies, a chain that is steadily expanded by new section of AVO intercept and gradient across a gas storage with developments. O T indication of gather locations A, B, C of Figure 10.

OILFIELD TECHNOLOGY June 2011 37

38 A move to

or more than 50 years, drillers have utilised technologies that enable them to drill directionally and through difficult formations. While the benefits provided by these Ftechnologies are extremely compelling, the rate of innovation remains surprisingly slow. A study conducted by McKinsey & Co. estimates the average time from idea to 50% market penetration is over 30 years for oilfield technologies in general, compared to less than seven years for consumer products.

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OILFIELD TECHNOLOGY 40 June 2011 In another area of the same trend, the operator typically required three to five production bits to drill to TD. After selecting Drilformance PDC solutions, the first well took two production bits and 200 hours of drilling time, compared to 343 hours on a previous well, resulting in savings per well estimated at over US$ 200 000. Additional wells have realised similar performance gains.

Bone Springs Trend, New Mexico The operator was looking for a bit that could beat their best bit run to date (close to 80 ft/hr) and drill the Figure 3. A comparison of Drilformance’s PDC bit performance with two competitor bits, demonstrating entire interval in one run to reach Drilformance’s significantly lower drilling time and higher ROP. kick off point. Using an 8 ¾ in. DF613R2 PDC bit, the rig drilled the entire vertical section in one run at 89 ft/hr for an 11% gain over the previous best record.

Eagle Ford Shale Trend, South Texas The operator’s goal was to drill an entire production hole interval, which contained multiple sections including tangent, curve and lateral, with one bit to a planned TD of approximately 16 400 ft. No bit had drilled the entire section on a well of this length in this area. The operator selected an 8 ¾ in. DF513R bit for the operation. The bit’s stable, aggressive cutting structure allowed the entire interval of approximately 12 000 ft to be drilled, reaching TD with no problems. The bit held angle in the tangent and maintained 13 deg/100 ft build rates in the curve, with Figure 4. Average drill out run (metres) drilled, Willesden Green Field, sections of the curve sliding at over 60 ft/hr. The operator Alberta, Canada. confirmed that the Drilformance drill bit achieved the best results for that rig to date. Results of another operator in the Eagle Ford Shale trend for three wells drilled on the same pad using competitor bits on two Cardium Trend, Alberta wells and a Drilformance DF513R bit on the other well are shown An operator had been looking for a bit to drill the vertical and below: curve section in one run in the Willesden Green Field. To this x The Drilformance bit drilled the interval 24 hours faster than point, no other bit had successfully completed the interval. The the best offset run on the pad, and reached TD in 56 hours. operator chose an 8 ¾ in. DF516R and drilled the entire 1832 m x The Drilformance curve ROP average was more than 50 ft/hr interval to casing point, saving valuable rig time. The dull was and lateral ROP average was more than 100 ft/hr. 1-2-CT compared to competitors’ previous attempts that had This example highlights the DF513R’s directional and rate of resulted in bits being pulled and found damaged beyond repair. penetration capabilities. Drilformance bits tend to stay on target, resulting in fewer corrections and more time rotating with better Recent breakthroughs ROP. On this pad, the Drilformance run resulted in approximately Drilformance’s design philosophy is to push the limits of what 10% less time sliding compared to the competitor offset run, can be drilled with PDC systems, while maintaining optimal (Figure 3). performance across the wide range of applications. The Drilformance Advanced Technology Development team has Marcellus Shale Trend, Pennsylvania created PDC systems that focus on the driller, emphasising An operator was looking to optimise results in the surface hole, steerability and control, in addition to high penetration rate and curve, and lateral intervals. A 12 ¼ in. DF513 was utilised to durability. drill the surface hole 50% faster than previous methods. The Recent advancements include the Heli PathTM radial spiral challenge for the curve and lateral sections was to find a bit that structure, coupled with a Compact UnibodyTM design and could achieve the desired build rates in the curve and still get Opti TracTM modelling, providing both stability and directional high ROP in the lateral section. An 8.75 in. DF513R was utilised control. Shadow PathTM enhances bit shoulder durability while to drill both intervals to TD in a single run. The bit achieved extending PDC cutter life. Rhino ArmorTM provides maximum excellent build rates in the curve and showed a 40% increase in protection on all critical surfaces, minimising erosion from ROP versus previous competitor offset runs. high solid mud systems. Cryo EdgeTM PDC cutter technology

OILFIELD TECHNOLOGY June 2011 41 providing the optimal angle of attack for the cutter edge. Drilformance’s Cryo Edge PDC cutters consist of a single piece of tungsten carbide substrate bonded to a high quality PDC compound. Cryo Edge is a combination of proprietary manufacturing process and materials, which include a precise angular micro-bevel applied to each cutter before insertion into the bit pocket. This calibrated displacement impacts the shear potential of each cutter, permitting a more aggressive profile to maximise depth of cut with each revolution.

Accel DrillTM: next generation drilling Drilformance has integrated all of its current technologies into Accel Drill, providing step-change advances in drilling capabilities. For example, Accel Drill incorporates Drilformance’s Dynamic NutationTM system, which enables longer intervals to be drilled faster, particularly in tough formations. Adamas BaseTM advanced materials are Figure 5. An aggressive cutter profile engages the most demanding incorporated in high-wear moving components of the system formations with ease, while the patent-pending Shadow Path work for significantly increased tool life. Drilformance’s sharing system enables longer cutter life by reducing heat build-up. Accel Drill system bit-to-bend length is 10 in., as compared to conventional directional assemblies having typical bit-to-bend lengths of 3 - 6 ft. Accel Drill’s shorter bit-to-bend length reduces unnatural lateral stresses associated with conventional assemblies, and significantly increases dogleg severity capability. The combination of these advances means complex geometry wells can be drilled from surface casing to TD without tripping out of the hole to change BHA assemblies. Consistent reliability and notable increases in versatility and ROP contribute directly to bottom-line drilling economics.

Measurable productivity is the name of the game Unconventional and complex geometry well economics are driven by increases in operational efficiency. Operators and directional drillers are using manufacturing-style approaches to achieve reliable, predictable and low cost results. Rather than relying on instinct or tried and true approaches, increasingly we turn to field data to determine ‘what’s really working.’ Drilling programmes have reached Figure 6. Superior directional control and stability is achieved by a stage of maturation such that different bit technologies Opti Trac modelling and the patent-pending Heli Path radial structure on the bit face. have been tried in different zones and formations, and steerability, durability, elimination of sliding, improved ROP, and impact on NPT can be directly observed and measured. provides excellent impact resistance, abrasion resistance Both operators and directional drillers now benefit from and thermal stability. data driving smarter, more economic drilling decisions and quicker technology adaption. O T Rhino Armor Drillers who seek to maximise their PDC intervals require both strength and durability. Drilformance utilises proprietary Rhino Armor hard facing to achieve maximum protection for PDC systems. Precise temperatures and application width are enforced in the application to prevent delamination and maximise fracture resistance. Material volume is augmented SIGN UP to Energy Global’s RSS feeds to receive up-to-the-minute on the bit shoulder and gauge to provide additional news alerts protection to high-wear surfaces.

Cryo Edge The principle behind the architecture of the cutter is to www.energyglobal.com/sectors minimise fracturing and increase thermal resistance by

OILFIELD TECHNOLOGY 42 June 2011 Charles Douglas and Josh Passauer, Smith Bits, a Schlumberger company, USA, consider a new bit optimised for shale, saving significant rig time in the Haynesville Play.

n the fast-paced drilling industry, performance is king. Increasingly, challenging demands are placed on drill bits. And why not? After all, they are the tip of the spear. I Bits are required to drill faster, last longer, and produce better quality boreholes than ever before. But these attributes don’t come easy. Formations are increasingly complex; targets are deeper, hotter and harder to reach. The recent nationwide shale play is spilling across our borders as North American operators are proving the value of shale drilling, and worldwide plays lie just around the corner. Yet while huge shale gas reserves potential beckons operators, there is a constant push for greater efficiency to minimise costs. Natural gas is a commodity, and as a result, operators cannot independently raise prices to offset costs. With prices set by local markets, the only recourse to improve profitability is to attack costs. In the mature arena of well construction, cost reduction is a tough challenge and even significant investments in technology often result in marginal gains. Nevertheless, every so often, perseverance and innovation are rewarded.

Designing the ultimate shale bit A Smith Bits team of field engineers, design engineers and hydraulics experts was assembled to carefully study shale drilling, pulling together their

43 experience and learnings from thousands of wells drilled to date. They considered the operators’ needs together with the geomechanical scenarios they faced. While understanding that there probably would not be ‘one solution that fits all’ situations, they were able to isolate the predominant impediments to shale drilling and borehole quality and address them. The following drilling characteristics of the majority of shale wells were identified: x Over the past few years, shale well profiles have shifted from vertical to horizontal. x Drillers generally use different bits to drill the vertical section, the build (or curve) section and the lateral. x Most shale wells are drilled using positive displacement mud motors and are completed using hydraulic fracturing. x Effective borehole cleaning is a must, especially in the lateral section. x Bit vibration must be controlled to optimise drilling efficiency and bit longevity as well as to avoid damaging LWD/MWD equipment.

Almost immediately, the team concluded that considerable time could be saved if a high performance bit could be designed that could drill the entire well, while delivering acceptable borehole quality and cuttings transport. They Figure 1. DBOS drill bit optimisation system log summarises drilling reached into their toolbox and implemented several challenges for Haynesville operators, and helps with bit selection. proprietary modelling and database programs including: x IDEAS* integrated drillbit design platform shows how the bit behaves as an integral part of the whole drilling assembly. IDEAS-designed, bits go from concept to proven performance in minimum time. x i-DRILL* engineered drilling system design for predictive bottomhole assembly (BHA) modelling identifies solutions that minimise vibrations and stick-slip during drilling and optimise bit performance for any given environment. x YieldPoint RT* drilling hydraulics and hole cleaning simulation program optimises bit hydraulics for the specific well plan being simulated. x DRS* Drilling Record System, a collection of data from 3 million bit runs, helps engineers quickly locate similarities in drilling conditions and bit performance.

The result was the Smith Bits Spear* shale-optimized steel body polycrystalline diamond compact (PDC) drill bit.

Combination of technologies delivers results By combining an aggressive design with a tough steel body construction, engineers produced a bit that could drill both the curve and the lateral in a single trip while delivering high penetration rates and effective borehole cleaning. The benefits of the leading curve section bit, the 6 ¾ in. SDi711, were combined with those of the leading lateral hole performer, the 6 ¾ in. SDi513, to create the new SDi611 Spear. Switching from the traditional matrix body to steel offered increased ductility and allowed the blades to be made much taller and thinner, leading to a dramatic improvement in junk slot area and face volume and providing a larger area for cuttings removal and evacuation from the face of the bit. This, coupled with a unique hydraulic design directed drilling fluid to sweep across the cutting surfaces to keep them clean and minimise the re-grinding that robs energy from cutting 3 Figure 2. Smith Bits Spear 6 /4 in. SDi611 steel body PDC drill bit new rock. Where vibration is predicted, optional MDOC* as specially designed for Haynesville Shale horizontal well drilling. depth-of-cut inserts can be fitted behind the shoulder and

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Magazines iPhone App Website The Brand Figure 3. Comparison of Smith Bits Spear steel body bit profi le (left image) with that of a typical matrix body bit (right image) shows junk slot area increased by 45% as a result of extended blade height, reduced blade thickness and bullet shape body.

gauge cutters. Bit vibration is the principle cause of excessive both the curve and lateral, giving up performance on one section cutter wear and poor drilling effi ciency. or the other depending on the bit chosen. Spear bits proved to achieve target build rates in the To maximise sensitivity to the operator’s needs, Smith Bits curve section by facilitating good tool face control, and fast placed an Advanced Services Engineer (ASE) in the operator’s penetration in the lateral while maintaining desired direction and offi ce as a technical advisor to provide recommendations inclination. In addition, the hydraulic enhancements made to the and support to the operator. ASE engineers have access bit design meant that the blades and nozzles did not pack up to Smith Bits proprietary engineering tools to assist in with shale during drill pipe connections. recommending the ideal bit and provide operational expertise With its short make-up length to ensure desired dogleg for each particular application. The practice of placing technical severity, the new bits have successfully been run under the specialists within operating companies is widespread. Logging following operating parameters with varying BHA confi gurations: and pumping services engineers have proved their value through x PDM speeds ranging from 0.52 rev/gal. to 1.02 rev/gal. deep domain expertise for many years. It follows that drilling x Motor bend angles ranging from 1.5˚ to 2.6˚. experts will provide similar benefi ts. Working with the operator’s x Flow rates ranging from 200 gal./min. to 260 gal./min. drilling engineers and well design specialists, Smith Bits x Weight-on-bit ranging from 2000 lbf to 20 000 lbf. engineers selected two offset wells belonging to the same x Drilling fluid weights ranging from 14.5 lb/gal. to 17.0 lb/gal. operator and with formation characteristics as close to those of the case study well as possible to test the new SDi611 Spear bit. Haynesville shale well example To ensure the best match between the well design and A typical Haynesville drilling program calls for drilling and geomechanical constraints imposed by the formations to be 7 wireline logging a vertical or directional 9 /8 in. intermediate drilled, a DBOS* drill bit optimisation system log plotted from section to the casing point using water-based drilling fl uid. The the best available data, including lithology and mineralogy, and fl uid is then displaced with oil-based mud for drilling the curve unconfi ned compressive strength of the rock is often used. This and lateral sections. Since bottom-hole temperatures takes into account both the curve section and the lateral, and are severe, the use of rotary steerable systems (RSS) and shows engineers that the bit will perform well in both sections logging-while- drilling (LWD) tools is limited and PDM steerable and can help facilitate the decision to drill to total depth without motors are primarily used to build and drill the curve section and a bit trip. lateral. The fi rst offset well was drilled using three PDC bits of Up until now, operators have been faced with a dilemma. another manufacturer. It kicked off at 10 500 ft and drilled curve Previous bit designs were either optimised for the curve section and lateral to a measured depth of 16 324 ft. Penetration rates with strong build tendencies and directional-friendly steerability for the three bits were 23 ft/hr, 39 ft/hr and 31 ft/hr respectively. or they targeted the lateral section with fast, aggressive Offset well number two kicked off at 10 455 ft using the penetration rates. To get the best performance, a bit trip Smith Bits SDi513 Spear bit for the curve and drilled 1012 ft; was required so the best bit could be used for each section. then switched to another manufacturer’s PDC bit to drill 479 ft. Alternatively, the operator could elect to use the same bit for To complete the lateral, the SDi513 bit was used and drilled

OILFIELD TECHNOLOGY 46 June 2011 Under the patronage of His Royal Highness Prince Khalifa bin Salman Al Khalifa Prime Minister of the Kingdom of Bahrain

Society of Petroleum Engineers

17th Middle East Oil & Gas Show and Conference

Conference: 25-28 September 2011 Exhibition: 26-28 September 2011 Bahrain International Exhibition and Convention Centre www.MEOS2011.com

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NEW DATES [email protected] ANNOUNCED Worldwide Co-ordinator

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[email protected] on the case study well. Total savings were estimated by the operator at US$ 365 000. Since the case study well was drilled, the operator has been increasing its use of Smith Bits Spear bits in the Haynesville.

No silver bullet Drilling the shale plays is not a simple task. Each play must be carefully studied to determine its geomechanical properties and formation parameters so the optimum bit can be selected. The fundamental design parameters of the new Spear bits address the most challenging aspects of curve and lateral shale drilling, maintaining a high rate of penetration while delivering an accurate Figure 4. Comparison of case study well with two nearby offset wells of the same operator wellbore trajectory and a good quality highlights single bit run performance of the Spear SDi611 bit (left) in a record-setting run for Haynesville horizontals. borehole so subsequent completion activities can proceed without problems. The Smith Bits Spear design can 4552 ft to total measured depth of 16 498 ft. Penetration rates be fitted with premium ONYX* PDC cutters for hard rock for the three bits were 14 ft/hr, 10 ft/hr and 31 ft/hr respectively. drilling applications. Many years of experience have shown The case study well was kicked off at 10 720 ft and was that bit selection is a science. There is no ‘one-type-fits-all’ drilled entirely with the SDi611 Spear bit to a total measured situation. Drilling engineers find that they obtain the best depth of 16 783 ft. A single bit was used. Penetration rate was performance when the bits are carefully matched to the well 49.7 ft/hr; a Haynesville record. There are a few faster lateral design and the geomechanical constraints presented by the runs, but so far none have been able to drill both the curve and formations to be drilled. O T the lateral at that rate. Considering both the penetration rate gains plus the References elimination of bit runs a total of 124 hours of rig time was saved * Mark of Schlumberger.

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www.energyglobal.com/events DRILL BIT SOLUTIONS Leading suppliers; Century Products, NOV Downhole and Varel, provide details of advanced drill bit technologies. DRILLER: EQUIPPED

Jack Castle, Century Products, Inc., USA, details the company’s range of drilling tools.

oday’s competitive environment demands constant Milled Tooth (MT) bearing design to perfectly attack the various creation and improved application in all areas of formations drillers encounter. Tthe drilling arena, especially in the magnum size bit A six-point stabilisation feature is standard on the Rock Bit range. Century Products, Inc. is a US-based manufacturer line (Figure 1). This allows for better stability, which results in specialising in the development of magnum smoother running parameters and less vibration sized drilling tools. High quality, durable bits to help reduce other potential downhole failures. that offer a high rate of penetration and on Three interchangeable jet nozzles are extended target steering performance is the focus of to aid in the stabilisation as well as provide Century’s R&D. exceptional hole cleaning abilities. The industry’s attention has been directed The Hole Opener line incorporates towards the development of the smaller, PDC stabilisation features as well, which results in bit range. Century is fi lling a void by offering a well-balanced tool machined to exacting a complete range of drilling tools for borehole tolerances. A rebuildable design allows for enlargement from 16 in. – 72 in. With two multiple cutting structures to be inserted into complementary product lines, Hole Openers one body, transforming an otherwise disposable and three cone Rock Bits, engineers are piece of equipment into an asset, (Figure 2). provided with custom designed options to These stabilisation features are critical choose from so drilling plans do not have to be when drilling with larger diameter drilling tools. modifi ed. Inherently these larger sized tools experience The Hole Opener line covers from Figure 1. 36 in. Magnum Rock Bit. severe vibration and have diffi culty maintaining 20 in. – 72 in. and the three cone Rock Bit line minimal borehole deviation. Borehole ranges from 16 in. – 36 in. Both are available in enlargement tools that fall within this range IADC codes ranging from 1-1-5 to 5-3-5 and feature the highest require a dedicated engineering effort to ensure optimal drilling load and energy bearing seal combination in the industry. performance, which yields a high ROP with minimal vibration. They are available with Tungsten Carbide Inserts (TCI) or a As a technology leader, Century continually strives to optimise

49 drilling performance while lowering x Shirttail/leg protection. Hard facing the cost per foot through innovative along with carbide inserts blanket the advancements to the larger size shirttail and leg, providing superior drilling tools. wear resistance. x Interchangeable jet nozzles. Design features Interchangeable jet nozzles with nd nd The correct bit choice is an integral carbide jets from 8/32 to 24/32 . component in the overall drilling An improved hydraulic design performance achieved. There are four has also been incorporated, which is different bearing sizes to choose from, especially effective as the size of the 12.5 in., 16 in., 22 in. and 26 in. and hole increases. For example, a 72 in. three different cutting structures to hole equals 1.05 yds3 of rock for every select, incorporating TCI Conical and foot of penetration. This is equal to the Chisel profiles as well as Milled Tooth. volume of 67.71 ft of an 8 - 4 in. hole. The following information provides an Designs must be modified for magnum overview of innovative features built size products to address these into each bit used on the Hole Opener increased volumes. and Rock Bit lines to eliminate When these bearings are common problems drillers encounter teamed with the latest innovation out in the field: in bit designs, you have a winning combination. These bits are designed Century high load/high to handle the tough, hard over thrust energy bearing formations from Canada to Columbia, Figure 3 features: and the sharper, abrasive formations x Extreme Pressure (EP) lubricant in the Middle East. This high energy and dual reservoir system. bearing design is also suited for the Century Products Cutters use longevity required in the North Sea. the latest in synthetic grease. As much as three times the bit life This, along with the compensator versus non-sealed products can be design, ensures proper circulation expected. is maintained under the most stringent applications. x HSN O-Ring Seals: largest Case study seal area in the industry. HSN x Length: 7456 ft River Crossing. Material is utilised for its wear, x Country: Quebec, Canada. heat compression and chemical x Pipe: 20 in. steel. resistance properties for the x Bore size: 30 in. O-Rings. It has a service range of -40 to +325 ˚F. For the high The Canadian Province of energy required, Century has Quebec, in the French speaking city designed and utilises the largest of Trois Riviers, 88 miles northeast cross section O-Rings for longer of Montreal on the banks of the seal life. St. Lawrence Seaway, served as the x Crowned roller bearings. Premium setting for the 7456 ft River Crossing crowned roller bearings are Figure 2. 24 in. Century Hole Opener. used, which gives the bearing Project of The Year in 2006. the capability to withstand the A 12.5 in. pilot hole was drilled with extreme high loads. the intersect method which employs x Ball bearing cone retention. Ball two drill rigs that start from opposite bearing cone retention is provided ends of the project site and meet as the most reliable method of somewhere in the middle. In effect, cutter retention in the industry. one drill provides the pilot bore for the x Premium silver plated floating other. bearing system. Fully floating Once the pilot bore was completed, thrust bearing system allows for Figure 3. 22 in. replaceable arm and cone assemblies. a 30 in. Century Hole Opener with reduced frictional heat build-up 5 – 22 in. TCI (Tungsten Carbide Inserts) to ensure lower operational cone was attached to the drill system temperatures under high-energy to handle the one pass ream. With the operations. This design facilitates the longer bit life that larger cones, the 30 in. Hole Opener was able to reach down to Century’s reputation has been built around. the 12.5 in. pilot hole. x Gage row protection. Double the number of tungsten carbide inserts that actively cut the gage diameter and The larger cones enabled the drilling company to skip a assists in maintaining tight tolerances and extending in-gage reaming pass and complete the borehole in considerably less bit life. time. The majority of the drill was mainly drilled through bedrock

OILFIELD TECHNOLOGY 50 June 2011 that ranged in compression strength from 4000 to 8000 psi. Century Hole Opener as opposed to running two passes Both shale and limestone rock were encountered. to open the hole to 30 in. Due to the unique design on The reaming process took 400 hours at an average RPM the Hole Opener Bearings and Seals, the Century Hole of 30 and weight on bit between 145 000 – 165 000 lbs. Opener easily achieved 180 hours of operation in the The reaming process was cut in half by using a single hole. O T

LARGE DIAMETER DRILLING: CHALLENGES AND SOLUTIONS

NOV Downhole discusses the company’s solutions in large diameter drilling.

he drilling of deeper oil wells is rapidly becoming more commonplace in today’s oil and gas industry. THydrocarbon sources are less and less at our fingertips, leading the industry to develop new and more sophisticated technologies in order to reach these distant resources. This in turn brings its own challenges, and certainly demands its own solutions (Figure 1). NOV® Downhole has introduced the ReedHycalog® TitanUltra™ drill bit product line designed to overcome the unique challenges of large diameter drilling. Due to the substantial difference between bottomhole assembly (BHA) and hole diameter, extremely high forces can be generated. Lateral and torsional vibrations amplify the magnitude of these forces, affecting ROP and directional control, and can ultimately destroy the bit and downhole tools. Furthermore, bottomhole cleaning and the risk of hole washout make optimal hydraulic design essential for improving borehole quality and drilling Figure 1. The ReedHycalog TitanUltra product line from performance. NOV Downhole is designed to overcome the challenges of Reflecting the design focus on the four fundamental areas of large-diameter drilling with a design focus on improved stability, improved stability, rate of penetration, durability and steerability penetration rates, durability, and steerability. to maximise performance in large diameter applications, lThe nozzle configuration is primarily focused on minimising TitanUltra bits have set world records in deepwater projects the erosion of the borehole. This erosion is usually a major offshore in the Gulf of Mexico, Australia and Russia. problem in large hole applications, where the nature of the lithologies drilled tends to create hole washouts. Stability: ultra-stable bit designs lIncreases directional ability in large hole diameters. The new concept of stability developed for the TitanUltra products, goes beyond the development of the cutting Durability: more durable bit designs structure itself. It also considers new techniques developed for x Bit wear and impact force prediction: proprietary other critical parts of the design such as the bit body and the mathematical modelling ensures designs that resist external forces and formation abrasiveness. secondary components. x Finite Element Analysis (FEA): advanced structural integrity x Cutting structure designs: proprietary mathematical simulations provide reliable bit body structure design to modelling enables the design of extremely high laterally and overcome the most demanding drilling situations. torsionally stable cutting structures. x Blade global asymmetry: the difference in the angle between each one of the design blades, has proven to increase the Steerability: directionally compatible bit designs bit’s ability to mitigate externally created lateral vibrations featuring the semi-active gauge and diminishes build up of whirl energy magnitude. x The TitanUltra designs can be run on bottomhole x Secondary components: new Torque Fluctuation Controllers assemblies that include push or point the bit rotary steerable (TFCs) smooth out torque spikes that may be encountered systems (RSS), as well as mud motors. Field testing has during drilling. demonstrated its directional reliability response in all applications. TitanUltra is the first known 24 in. or larger ROP: aggressive bit designs PDC bit that has drilled more than a 15˚ inclination on an x New cutting structure layout: unique cutting structure RSS through salt lithology in the Gulf of Mexico. spacing and exposure allows maximum ROP while drilling x This new technology incorporates a new gauge smoother and longer intervals. configuration, the Semi-Active Gauge, which gives the bit x Hydraulic design: hydraulic modelling enables designs ability to achieve moderate dog legs and maintain verticality. that efficiently clean the hole and maximise ROP. Other Overall, it has delivered superior borehole quality in these achivements with the new hydraulic design include: large diameter drilling applications.

OILFIELD TECHNOLOGY June 2011 51 The TitanUltra product line has demonstrated great success in deepwater applications while drilling lithologies such as salt and sedimentary, interbedded formations. Extensive field testing over the past year led to three world records in some of the most important deepwater applications worldwide, such as the Gulf of Mexico, Russia and offshore Australia.

Proof of performance: x The 17.5 in. TitanUltra bit set a single-bit run world record in a section of the world’s longest well offshore Russia, drilling a total length of 14 603 ft at a rate 149.2 ft/hr. x In the Gulf of Mexico, a TitanUltra bit set a world record for the longest 24 in. PDC section, drilling 4645 ft at Figure 2. 26 in. TitanUltra World Record – ROP. Bit Dull Grading: 107 ft/hr. This application was also the first known 24 in. 1-1-CT-N-X-I-NO-TD, Offshore Australia. or larger PDC run that drilled more than a 15˚ inclination on a rotary steerable system through salt lithology in the Gulf of Mexcio. Low vibration was registered and the bit Performance advantages was dull graded 1-1-WT-A-X-I-NO-TD. Conventional thinking has held that an increase in blade count x The most recent world record was set in Australia, where leads to a decrease in ROP. However the TitanUltra product a 26 in. TitanUltra bit set an ROP world record by drilling line’s specially designed cutting structure layout provides 3304 ft at the rate of 144.35 ft/hr, cutting 12 hours of performance advantages to increase ROP while using higher drilling time and saving the customer approximately blade counts. US$ 500 000 in rig costs alone, (Figure 2). O T

MAKING THE CUT

Varel International discusses recent advancements in PDC and Roller Cone drill bit technology.

ervice companies in the oil and gas industry are toughness and abrasion resistance to enhance and improve the constantly evolving through deployment of new development and selection of PDC cutter technology for drilling Stechnology to their customers and it is no more evident applications. than in the highly competitive drill bit industry. Companies work diligently to have a flow of constant technology development Cutter toughness deployed to the field. Varel International continues to be a Cutter toughness is the ability to withstand the effects of drilling leader in the field, where rapid evolution of drill bit technology, dynamics. Toughness is related to the strength of the drill bit applications and fierce competiveness keep things very diamond-to-diamond bonding created during the interesting. High Pressure High Temperature (HPHT) sintering of the PDC The company is in the forefront of drill bit and PDC cutter cutter. Historically, test methods in the industry have been technology with research and design facilities both in the US qualitative and have fallen short of providing effective data for and in Europe and is represented in all of the primary oil and gas field cutter selection. basins worldwide. To better measure cutter toughness, Varel has developed its In just the past year alone, Varel has made strides in both patent pending Acoustical Emissions Toughness Test PDC and Roller Cone drill bit technology. Along with (AETT). AETT quantitatively assesses the strength of the supporting its legacy lines, the company has been on the diamond-to-diamond bonding. With this test a load is applied to forefront of PDC cutter testing and cutter qualification, as well the cutters and increased at a constant rate while an acoustic as delivering custom roller cone solutions for specific customer sensor detects acoustic emissions from microcracking in applications. the diamond table. Measuring the energy released during microcracking yields a concrete assessment of the PDC PDC cutter technology toughness. Multiple types and grades of PDC cutters can be cross Cutting edge testing technology cutter qualification compared according to their resistance to load induced In order to achieve success, the company has recently microcracking yielding a highly predictive valuation of impact introduced its testing and qualification standards. Building upon toughness. already successful PDC product lines such as Diamond Edge™ bits, Navigator™ bits and the ToughDrill™ series, Varel has Abrasion resistance developed and deployed two patent pending PDC cutter Abrasion resistance is the cutter’s ability to stay sharp as it testing technologies. These innovative tools measure cutter drills. The primary drawback of traditional abrasion tests is

OILFIELD TECHNOLOGY 52 June 2011 the lack of an accurate simulated geological environment. Performance examples Current tests use a homogenous rock structure, which does not In a recent performance review for drilling in Offshore Southern calibrate how moments of high impact energy affect a cutter’s Thailand, Varel designers delivered proof points of the abrasion resistance. Varel’s second patent pending test, the effectiveness of Vulcan cutter equipped PDC drill bits. Overall Bimodal Abrasive Rock Test (BART), is a laboratory abrasion these bits were able to withstand the highly abrasive formations resistance test which employs an engineered rock sample they encountered, including formations with abundant dolomite with highly abrasive cement cast around upright layers of high stringers. compressive strength granite to measure a cutter’s abrasion Specifically, two separate seven-bladed Navigator series drill resistance. The two rock samples create a load/unload cycle bits earned top remarks from the drilling engineer in charge as to simulate interbedded formations and formation transitions. “the best bit for the deeper section.” The first bit drilled through By recreating this environment, BART provides a more suitable the hard and abrasive Benjarong Formation to TD of 12 215 ft, measurement of abrasion resistance correlating to field delivering superior footage and ROP when compared to closest performance and yields a quantification of a specific cutter’s offsets. applicability to transition drilling. Due to the excellent post-run condition of the drill bit’s When used in combination, AETT and BART testing regimens cutting structure, it was quickly rerun completing 1782 ft for a promise to significantly accelerate cutter development by speeding the qualification of new cutters and by providing more accurate quantification of prototype cutter attributes. These processes aide in the development of new cutter technology and in the selection of the best existing technology. These breakthough standards and testing technologies have led to the establishment of two classes of Varel qualified PDC cutters: Thor™ and Vulcan™ class cutters. The Thor class cutters are engineered to be more impact resistant than standard cutters to address the challenges specific to hard rock applications and interbedded formations. Conversely, highly resistant to abrasion and the heat of drilling, Varel’s Vulcan class cutters are applied in the hardest and most abrasive drilling applications.

Thor cutters The company deploys its Thor class cutters to meet the challenges associated with interbedded lithology and high impact drilling applications where cutter toughness is required. Figure 1. 8.5 VRP 713PDGX Post Run: the second drill bit Drilling through transitional zones often produces significant performance featured (the 8.5 in. VRP713PDGX bit) is shown here drill string vibrations. With maximum diamond particle size after two complete runs, the most recent to section TD in a formation consisted of hard and abrasive dolomitic cemented sandstone, distribution and optimal sintering, Thor cutters have increased dolomitic limestone and dolomite stringers with UCS up to 35 kpsi. toughness while maintaining thermal mechanical abrasion resistance. Before a cutter can enter this classification, it undergoes a battery of tests and evaluation techniques. With Thor cutters, the foundation of the cutting structure is protected, leading to increased ROP and extended drill bit life in hard-to-drill applications.

Vulcan class cutters Varel applies Vulcan class cutters when a high level of thermo-mechanical abrasion is anticipated. Highly abrasive formations generate elevated friction and heat during drilling, and industry standard cutters can crack and wear under these conditions. This class of cutters is manufactured to resist these highly abrasive conditions. With a smaller diamond grain size and an enhanced thermal stability, the cutters resist abrasive wear while maintaining toughness. With Vulcan cutters, abrasion resistance is maximised, leading to longer bit life and higher ROP throughout the interval.

Testing Before a cutter is qualified for Vulcan classification, it is Figure 2. The Acoustical Emissions Toughness Test (AETT) subjected to a rigorous cutter testing methodology; key to quantitatively assesses the strength of the diamond-to-diamond entering this class is a high score in the thermal abrasion test. bonding in PDC cutting elements.

OILFIELD TECHNOLOGY 53 June 2011

OT_49-54_June2011.indd 53 08/06/2011 09:59 Figure 3. 44.00 Roller Cone bit: the largest drill Figure 4. The Bimodal Abrasive Rock Test (BART), is a laboratory abrasion bit deployed in the oil and gas field, this 6000 lbs resistance test which employs an engineered rock sample with highly abrasive drill bit is designed to create efficiencies in the cement cast around upright layers of high compressive strength granite to top hole drilling operations. measure a cutter’s abrasion resistance.

cumulative footage of 3261 ft spanning two runs and an ROP “Drilling with this large diameter bit in the top hole section that was 122% higher than the closest competitive offset. is a more efficient solution. The bit saves the operator time and A second bit, used in hard and abrasive dolomite money through a reduction of tripping to change bits and the cemented sandstone, dolomitic limestone with multiple need for hole enlargement tools,” said Harrington. dolomite stringers, was also noted for its durability and This bit features an advanced cutting structure with longevity. While this 8 ½ in. VRP713PDGX delivered similar optimised row placement, tooth spacing and cutter geometry footage to its non-Vulcan equipped counterparts, the post-run for increased drilling efficiency. These attributes also work to condition and the estimated 79% increase in ROP, once again minimise tooth wear and prevent cutter tracking in a wide variety made this bit a success. A second run with this same bit in a of formations and conditions. separate section delivered a run to TD in the same unforgiving The colossal bit was constructed following strict formation type. manufacturing processes that are designed to be robust and repeatable. These processes are constantly monitored and Pushing the limits with 44 in. steel-tooth roller continuously reviewed to provide the drilling industry with cone drill bit ever-increasing value. Varel has recently expanded the ‘Jumbo’ bit product offering Harrington concluded, “The cutting structure on this bit was to include additional sizes, cutting structures and bearing engineered for specifically for operator’s purpose. The inaugural options for specific top hole requirements. The company has run of this innovative product is scheduled for mid-2011.” O T completed a massive 44 in. steel-toothed roller cone bit for the oil and gas industry. The bit, which weighs in at more than 6000 lbs and is more Energy Global than 22% larger in diameter than any previous roller cone bit, Bringing you the power of information was requested specifically by an integrated global petroleum company in the Middle East. READ about the latest David Harrington, Vice President of Varel’s roller cone developments in the shale technology group, explained how the ultra-large diameter gas sector on Energy Global bit will work to create efficiencies in current field operations by offering a single bit solution to top hole drilling which previously involved drilling a pilot hole and then re-drilling with a hole opening assembly. www.energyglobal.com/sectors

54 OILFIELD TECHNOLOGY June 2011

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Shale_End.indd 1 22/02/2011 15:02 THE MANY SHADES OF GREEN

Kelly Harris, BWA Water Additives, UK, takes a look at screening tests in order to find more environmentally friendly chemicals.

ince the 1972 Stockholm United Nations Conference on the Human Environment, environmental pollution has been considered as a major concern for all industries. Across Sthe globe, a number of governments and regional economic integration organisations have since established programmes for identifying and assessing substances that could cause long term harm. This ‘harm’ is defi ned as substances that are resistant to degradation and accumulate in living organisms where they produce undesirable effects above a certain level of concentration. These Persistent Organic Pollutants (POPs) or Persistent, Bio-accumulating, Toxic substances (PBTs) are classifi ed using a variety of tests and are subject to regulations concerning their use. These tests are dependent on the fi nal destination of the chemical, and knowledge of how the environment will be impacted by its presence is paramount. Once identifi ed, classifi cation depending on specifi c criteria can be achieved. For example: x The OSPAR (Oslo and Paris) Convention for the Protection of the Marine Environment of the North-East Atlantic, aims to prevent further pollution by continuously reducing discharges, emissions and losses of hazardous substances (identified by PBT criteria), with the ultimate aim of achieving concentrations in the marine environment near background values for naturally occurring substances, or close to zero for man-made substances. x The Environmental Protection Agency (EPA) in the USA defines two sets of criteria for PBTs. Fitting into one of which means emission must be controlled, and the other, for it to eventually be banned.

55 xx The Canadian Government has a screening process that which would then disappear completely! A survey of the places substances that are persistent or bio-accumulating currently available products shows that although this target and inherently toxic into three categories depending on the has not been met, some products are definitely moving in outcome of further screening. the right direction. Unfortunately the hunt for ‘low harm’ (i.e. biodegradable) inhibitors has meant that less effective products are sometimes Biodegradation selected due to their perceived ‘green’ qualities. This is in Biodegradation is a natural process by which organic spite of the fact that this lower efficacy may actually result in substances are decomposed by micro-organisms (mainly

increased chemical discharge back to the environment. In an aerobic bacteria) into simpler substances such as CO2, ideal world a very small amount of chemical would be used water and ammonia. At the moment, evidence of partial degradation is enough to meet most criteria and avoid categorisation as a PBT or POP. For measuring biodegradability, the most recognised tests are the Organisation for Economic Co-operation and Development (OECD) series and include purely laboratory-based tests, as well as simulation and field-based tests. The closer a test mimics the environment the less control there is in place and therefore the less reliable the data is. In the laboratory tests, every chance is given for degradation to occur utilising high levels of test substance or, a low ratio of test substance to biomass with a long adaptation period, and a simplified environment. Simulation tests are a good Figure 1. Schematic demonstration of the differences between central point with external factors, such as temperature and laboratory tests and field tests. pH, controlled but a more realistic environment. Within OECD guidelines a series of tests can be undertaken as follows:

Ready/ultimate tests These are rigid screening tests with a high level of test substance (2 to 100 mg/L). They are laboratory tests, however, a positive test means that ultimate biodegradation in the environment will occur. A failure does not mean that the chemical will not biodegrade at all, so instead inherent biodegradability tests may be performed.

Inherent tests These tests have a high capacity for degradation with long exposure times and a high biomass to substance ratio, thus giving the substrate the best chance. Again, this is a Figure 2. Calcium Carbonate Threshold Test - percentage inhibition at laboratory test with a controlled and synthetic environment. specified dose level. A positive result will demonstrate the substrate is inherently biodegradable, but a negative result can still not rule out Table 1. Inherent biodegradability of commonly used scale inhibitors degradation in its final environment. and the new ‘green’ inhibitors Inhibitor type Acronym Inherent biodegradability result* Simulation tests Phosphonates PBTC 17% in 28 days These tests use a low concentration of the chemical and ATMP 23% in 28 days are performed in an environment that closely mimics the HEDP 33% in 28 days real world. A positive result here strongly suggests that Polyacrylates PAA 10% in 35 days a chemical will biodegrade in the natural environment. A negative result will give an indication that the chemical is Phosphinopolyacrylates PPCA 0% in 35 days likely to be persistent. Polymaleic PMA 18% in 35 days By following this process of beginning with the ready Terpolymaleic MAT 35% in 35 days biodegradability tests and moving down the chain, a good Sulphonic acid co-polymers SPOCA 7% in 28 days (OECD 306) understanding of how a substance will behave in the Polyaspartate PASP 83 - 87% in 28 days environment can be obtained. When this information is used Carboxy methyl inulin CMI >20% (OECD 306) in combination with the toxicity and bio-accumulation data, Polycarboxylic acid PCA 68.6% in 28 days (OECD 306) the impact of releasing this chemical into the environment Maleic acid polymer MAP 54.9% in 35 days can be assessed with a high degree of confidence. However, determining if a chemical biodegrades is only half the story, * OECD 302B test unless otherwise stated.

56 OILFIELD TECHNOLOGY June 2011

OT_55-59_June2011.indd 56 08/06/2011 10:04 since all of this is futile if it does not do the job it was much more slowly and be distorted. Often they are much more designed for. rounded in shape which makes them less likely to adhere to surfaces and more easily dispersed throughout the system. Scale inhibitors Water systems are ubiquitous with the chemical process Dispersant industries (CPIs). The mixing, heating, concentrating or Prevents the crystals coming together and forming a large body evaporating of water in these systems will form scale if they of scale. The inhibitor will interact with the surface and repulse are left untreated. other charged particles so that they do not bind. Scale inhibitors are chemical substances, which when added at very low levels will reduce or prevent the formation Industrial Water Treatment (IWT) of scale. There are a vast array available today including In the IWT area the most commonly encountered type of scale phosphate esters, phosphonates (PBTC, ATMP, HEDP), is calcium carbonate, which may occur in three possible crystal polyacrylates (PAA), phosphinopolyacrylates (PPCA), forms – aragonite, calcite and vaterite. When testing for the polymaleic acids (PMA), terpolymaleic acids (MAT), sulfonic efficiency of a scale inhibitor against calcium carbonate scale the acid copolymers (SPOCA), polyvinyl sulfonates, and more following tests can be performed: recently the so called ‘green’ inhibitors polyaspartic acid (PASP), carboxy methyl inulins (CMI), polycarboxylic acids Calcium Carbonate Jar Test (PCA) and maleic acid polymers (MAP). This is a 30 minute homogeneous test which demonstrates the The biodegradability of the current classes of inhibitors threshold inhibitor ability of a product. available in the market is shown in Table 1. Before the push for ‘green’ products very few were actually biodegradable. HEDP and MAT, being above 30%, are only just considered as inherently biodegradable. Looking at the new generation of ‘green’ inhibitors it is clear to see the difference with all four well above what is required to be considered as non-persistent. However, the question remains: are the new class of ‘green’ products effective scale inhibitors?

Scale formation Scale is formed by the increasing concentration of scaling cations, such as calcium and barium with scaling anions, such as carbonate and sulphate. Once the concentration of ions exceeds super-saturation levels, nucleation will occur, which leads to precipitation. What happens at the surface of this crystal depends upon the rates of formation and dissolution of the scale. Generally the rate of formation is greater, thus leading to growth of the crystal. These crystals can then clump together to form larger crystals that will eventually block the system. There are three mechanisms by which inhibitors can work to prevent the catastrophic build up of scale; at the nucleation stage, at the growth stage and fi nally the deposition stage.

Threshhold inhibitor The inhibitor binds with the scale forming ions, but unlike chelants the bound ions must be available to interact with their counter ions. This disrupts the ion cluster at the early equilibrium stages of crystal formation, thus disrupting them before they reach critical size for nucleation. As a result the ions dissociate releasing the inhibitor to repeat the process.

Growth inhibitor This slows the growth of the scale by blocking the active edges of the crystal. Once the inhibitor has bound to the lattice, the crystal will form Table 2. Calcium Carbonate Dynamic Scale Loop Test water chemistry Pilot Cooling Tower Evaporative Unit Test Ion Concentration mg/L This is designed to test both the threshold and dynamic Calcium 350 inhibitor mechanisms against calcium carbonate under heat Magnesium 56 transfer conditions. Sodium 10 077 Calcium Carbonate Jar Test Potassium 283 Here air bubbling is used to facilitate CO2 removal, which Barium 50 moves the equilibrium towards carbonate formation, thereby Strontium 50 increasing the test severity by raising the pH of the test Bicarbonate 1000 solution. Chloride 16 058 A solution containing calcium chloride and Sulphate 0 magnesium chloride is mixed with an equal volume of TDS 27 924 a solution containing sodium carbonate and sodium bicarbonate, which already contains the additive to be pH 7.8 tested. The air bubbled solution is heated at 70 ˚C (158 ˚F) for 30 minutes, after which time the solution is filtered and the Table 3. Barium sulphate test water calcium remaining in solution determined by EDTA titration. Ion Concentration mg/L The higher the amount of calcium retained in solution the Calcium 636 greater the scale inhibition ability of the product. The results expressed as percentage inhibiton against Magnesium 634 dose level are given in Figure 2. At 1 and 2 mg/L dose Sodium 14 760 level HEDP and ATMP are clearly the most effective with Potassium 446 PCA and MAP being the best amongst the ‘green’ scale Barium 120 inhibitors. Once a 4 mg/L dose level has been reached, Strontium 190 a number of inhibitors are capable of 100% inhibition of Bicarbonate 0 calcium carbonate including PCA and MAP but PASP only Chloride 26 930 reaches an 80% level. This may seem like quite a high figure Sulphate 530 but unless 100% is reached calcium carbonate will form and ultimately greatly reduce the efficiency of the plant. TDS 44 246 pH 5.5 Pilot Cooling Tower Evaporative Unit Test This dynamic test is designed to provide a realistic measure of an additive’s ability to control calcium carbonate deposition. The Pilot Cooling Tower Evaporative unit has constant make-up but has no blowdown, so the system water concentration increases with time as evaporation occurs. The system water is circulated over a 316 stainless steel heat exchanger. The heat exchanger is heated by passing hot water through the tube. The surface temperature of the heat exchanger is approximately 70 ˚C (158 ˚F). The evaporative region maintains bulk water temperature at 40 ˚C (104 ˚F), by passing air counter current to the water flow in the cooling tower. The higher the calcite saturation index (SI) that can be reached, the more efficient Figure 3. Schematic diagram of PCT with conditions of operation. the inhibitor. A schematic diagram of the equipment used is given in Figure 3. Initial dose level of additives is 10 mg/L as solids. In Figure 4, PBTC shows what level a good calcium carbonate inhibitor can achieve in this test. Its failure point occurs at a calcite SI of approximately 200. Of the ‘green’ inhibitors, MAP exhibited the best calcium carbonate control, reaching a calcite SI of 285. PCA also fared well with a failure point at 240 calcite SI. Both of these results are a significant increase over that reached by PBTC. PASP however gave a rather poor result failing at a calcite SI of approximately 80. This is less than one third of the level reached by MAP and PCA.

Oil industry Figure 4. Percentage calcium carbonate inhibition versus When considering application in oilfields, performing both the Calcite Saturation Index on an ICW rig. calcium carbonate and the barium sulphate dynamic scale

OILFIELD TECHNOLOGY 58 June 2011 loop tests is required to provide a good indication of inhibitor performance in the reservoir.

Calcium Carbonate Dynamic Scale Loop Test In some ways the dynamic scale loop test is less severe than the threshold static jar test, the inhibitor is replenished therefore keeping it at a constant concentration. In the jar test when a crystal is formed some of the inhibitor is consumed as it binds onto the crystal surface. As inhibitor levels are not replenished, concentration will therefore drop over time. Having a constant inhibitor level throughout the dynamic test ensures that it is the growth inhibition mechanism that is being studied with metal surfaces acting as growth sites. This test is conducted using synthetic Brent water, the water chemistry for which is given in Table 2. Separate solutions containing the anions and the cations are pumped through pre-heat coils at 90 ˚C (194 ˚F) and mixed in a T-piece prior to the 0.1 mm ID 1 m long 316 stainless steel test Figure 5. Dynamic Scale Loop Test Schematic. coil. A schematic representation of this apparatus is shown in Figure 5. During the test calcium carbonate deposition reduces the bore of the test coil causing an increase in pumping pressure. The rate of change in pressure across the coil is monitored with a pressure transducer and data captured for graphical representation later. The test is considered successful if the change in pressure remains below 1 psi (6.895 kPa) over a two hour period. MAT, a commonly used inhibitor, demonstrates that a 2.5 mg/L dose level is sufficient to completely inhibit calcium carbonate scale formation (Figure 6). The ‘green’ inhibitors PCA and MAP also display excellent scale inhibition at 2.5 mg/L. PASP is unable to prevent scale formation at this dose, reaching 1 psi (6.895 kPa) in only 50 minutes. Figure 6. Calcium Carbonate Dynamic Scale Loop Test Results. Barium Sulphate Dynamic Scale Loop Test The water chemistry for this dynmaic scale loop test is given in Table 3 and is equivalent to a 80:20 Troll:Seawater mixture. The anion and cation solutions, this time with with no inhibitor present, are pumped through preheat coils at 90 ˚C (194 ˚F) and mixed in a T-piece prior to the 0.1 mm ID 1 m long 316 stainless steel test coil. Barium sulphate deposition reduces the bore of the test coil causing an increase in pumping pressure. Once a 1 psi (6.895 kPa) change in pressure has been achieved, a third solution containing anions plus inhibitor replaces the anions solution. The test is run for 2 hours unless the additive fails to prevent further barium sulphate scale. Figure 7 illustrates the data for MAT and the three ‘green’ inhibitors PASP, PCA and MAP. At a 4 mg/L dose level MAT was able to stop deposition completely thus leading to no Figure 7. Barium Sulphate Dynamic Scale Loop Test. further increase in pressure. PASP, PCA and MAP were equally efficient at this dose level. This demonstrates that in this test the ‘green’ inhibitors are as efficient as those already performance. A poor inhibitor could potentially do more in common use. damage in the long run as larger volumes of additive are required to control the scale and, therefore, much larger Conclusion volumes are discharged into the environment. The focus of All of these tests demonstrate that PCA and MAP offer a the water treatment industry has therefore never changed significant improvement over other biodegradable products – to produce efficient products that prevent the formation such as PASP, and are also more efficient than their of scale – now there is just an added caveat that they must non-biodegradable counterparts, against calcium carbonate do as little harm to the environment as possible. This study scale. A high result in a biodegradation test is a worthy shows that although the problem has not been completely aim, however it should not be at the sacrifice of overall solved, we are certainly moving in the right direction. O T

OILFIELD TECHNOLOGY June 2011 59 Spotlight on: ANTISCALANTS Michael Hurd, Kasia Millan and Dr. Mohan Nair, Kemira, USA, offer a supplier’s view of antiscalants in oil and gas markets.

60 here was a time not long ago when the needs for However, there is still some debate over what scale inhibitors were pretty well defi ned and the list determines toxicity. Testing in water represents a more Twas not all that long. Manufacturers and suppliers sensitive environment to the dangers of a particular had a basic sales relationship with the operators in order chemistry. Therefore, testing against certain fi sh and to understand the needs in the fi eld. Products were aquatic invertebrates determines a level of ‘aquatic toxicity’ needed to stop barium sulfate and calcium carbonate and helps establish the minimum levels for discharge, scale development in ambient to hot, brackish to brine particularly into a body of water. Biodegradation testing type produced waters. In recent years however, the list of determines the time a particular chemistry will remain conditions has grown in a surprising number of directions in, and be a potential threat to, the environment, with and also includes a wider range of scales. Previously ‘odd’ 28 days being a established initially in the metal and mineral compositions like iron sulfi te or silica North Sea as an acceptable time period in most regulations. scales are now fairly common. Reservoirs with mixed Bioaccumulation determines the ability of a species, waters from water injection for pressure maintenance, again usually aquatic, to accumulate the chemistry within waterfl ood, or just disposal now create a world of scale its tissues. This test also taps into other work done to headaches as the mix emerges from a producing well to determine any other physical, neurological, or genetic fl ow along the seafl oor at near freezing temperatures or at disruption effects from these chemistries. The result is near boiling temperatures from land production comingling a set of data used most often by regulatory agencies to with other production at an initial separation battery to determine the parameters and use limits around which a further compound scaling tendencies. Throw in waxy chemical can be used in the fi eld. This data is also utilised deposits and H2S or CO2 from more complex completions by internal HS&E groups to establish working parameters and biofi lm, which becomes an active part of the scale itself and procedures for oilfi eld workers who handle the from either the reservoir bacteria or surface contamination, products on a regular basis and are far more likely to be and the market for scale inhibitors takes on a whole different exposed than the general public. Levels of acceptability meaning. And, of course, while being compatible with other usually emerge from the testing as some sort of ‘black’ to chemicals being added into the fl ow stream, the scale ‘green’ designations either in these areas individually or inhibitor needs to be environmentally friendly or ‘green’, collectively according to a formula. Improvement in any area which often means different things to different people at of the testing that moves from one level to another higher different times. This article attempts to take a look at the or better level without degrading results in another area is issues in a broad sense and see what technology might be normally seen as a signifi cant improvement and rewarded in available to help solve, or at least better defi ne, the resulting the ‘ratings’ awarded. needs that exist. With that background then it is easier to understand that some aquatic toxicity is diffi cult to avoid with scale Being green inhibitors. For most polymeric versions of scale inhibitor Let’s start at the end of the list with a discussion of what the molecule is too big to bioaccumulate in most species it means to be ‘green’. It is a buzzword that has become so biodegradation is where you look to improve the a part of our jargon overnight, being used by oilfi eld, product in the short term. Kemira’s KemEguard™ scale environmental groups, media, and politicians alike, but control technology was developed to achieve the 60% unfortunately each have a slightly different understanding biodegradability or higher guided by the Norway Sector of what that means. To some it ideally means ‘nontoxic’, of the North Sea regulations, (see Figure 1). One new but then there are those who point out that even drinking product in particular, KemEGuard™ 2593 has a standard water in excess can have the disastrous result of drowning! biodegradation rate of 60% over 28 days as compared with So use limits enter the picture with a debate of how an average of 8 - 10% for typical polymeric scale inhibitors. much is acceptable with most recognising that minimum Thus, the new technology offers a ‘greener’ option with levels are desirable. In the oilfi eld we know that some of similar performance for sulfate scale prevention compared these chemistries we use can be harmful if misused or with its parent technology. mishandled, and accidents and spills do occur, which With toxicity being such a concern though, there needs cause the rest of us to be even more diligent in our use to be a way to keep track of the scale inhibitors in the procedures. But we are also committed to producing system when squeeze treatments are used. Mass balance needed oil and gas and that simply can’t be done without is one way of keeping track of the products that go in and the use of scale inhibitors at some level in the process. are produced back out of a production well. The problem The idea then is to minimise the amount that must be used is that scale inhibitors are tough to measure, particularly against performance while continuing to develop scale at low levels near the Minimum Inhibition Concentration inhibitor technology and other chemicals that are less toxic (MIC) after a squeeze job when timing and accuracy can and provide equivalent or better performance. be critical. This usually requires a sample to be caught,

61 transported, and analysed at a lab in a process that takes hours, if not days to complete. And getting a read on just how much is lost to the formation, how much is produced back quickly, and how much really does the job is particularly difficult when all you have is a snapshot in time.

Tagging Tagging a molecule that is hard to find or measure with something you can easily monitor online is one way of keeping track of it quickly and efficiently. Using appropriately tagged scale inhibitors offers a number of benefits in addition to mass balance and tracking without interference in performance from the ‘tag’ addition. This isn’t a blend of scale inhibitors and something else. Figure 1. % degradation (North Sea testing). It’s an additional molecular structure that’s manufactured into the molecule, in one case into a sulfonated copolymer, in such a way that the two can’t be separated in the formation. Furthermore, the tag is incorporated so that it is uniformly distributed in the polymer backbone, and does not appreciably change the Mw and distribution of the original polymer, so that the polymer’s performance for scale prevention remains unchanged. Blended products tend to adsorb at different rates with reservoir rock or react with reservoir fluids in ways that prevent accurate production of the ratio that was injected resulting in misleading data regarding the actual scale inhibitor. The same is the case with polymers with tags that are not uniformly incorporated into the polymer chain. A regimen of properly and uniquely tagged scale inhibitors allows for online detection, accurate trending of production levels, and better control of the overall treatment, increasing the time between treatments and allowing for better planning when a number of wells are treated Figure 2. Iron contamination at 85 ˚C/pH 5.8. together. It is particularly advantageous when several wells are comingled at a common production station. Setting up online detection with unique tags in each well would allow for optimum planning for both the production facility shutdown and cost-effective group treatment of the individual wells by accurately reading the trends in each well and anticipating the most profitable treatment point in the future for all the common wells, all from a single point at the production station. Development work is continuing, specifically on the leading sulfonated copolymer chemistry offered, and products are now being used in field trials. In the future, the applications for this chemistry will be broadened beyond the offshore work where it is currently targeted.

Figure 3. Percent scale inhibition of BaSO4 at 250 ppm with a soluble iron contaminate.

Figure 4. Static barium sulfate inhibition efficiency 4C, pH 6.5, Figure 5. Barium sulfate inhibition at high temperature. 50/50 Heidrun FW/seawater.

OILFIELD TECHNOLOGY 62 June 2011 Performance issues KemGuard 2705 is the KemGuard 2708, Beyond the convenience of tagging and which has equivalent scale inhibition the benefi t of an environmental product, performance, is non-corrosive, is stable a scale inhibitor still has to perform in to 175 ˚C, and is approved for capillary Introducing the reservoir with the reservoir fl uids and injection applications. The Rice University additives into which it is injected. Additives study found the 2705 and 2708 to be the world’s and environmental conditions can play particularly effective against calcium sulfate havoc with some standard products. anhydrite scales. See Figures 4 and 5. fastest Typical polymeric scale inhibitors can KemGuard scale control agent be precipitated by methanol; common therefore offers a single product that water-wet antifreeze in the oilfi eld. Iron levels can works well across a wide range of affect a variety of scale inhibitors used. temperature and brine conditions wellbore And while biofi lms can form with scales in comparison to phosphate-based and complicate the treatment of both, the and other common chemistries. For biocides used to treat the bacteria may carbonate scales speciality formulations cleanup. also contribute to the consumption or of organophosphates offer performance in interference of the scale inhibitor within the similar temperature and/or brine condition system. For this article we’ll focus on iron ranges. While testing in specifi c brine in the reservoir water, but pay attention compositions under specifi c moderate to reactions of various kinds that might temperature conditions may pinpoint interfere with the performance of a scale other chemistries that work similarly, brine inhibitor under reservoir conditions. compositions rarely remain constant, More often, dosage is pushed to bare particularly in reservoirs with active water minimum to minimise the environmental injection. Having fewer products in the and economic footprint, and that warehouse that work over a wider range makes detection and monitoring more of conditions offers lower inventory costs diffi cult. The low dosage also creates and faster response time when (not if) an environment where the products are conditions change. more susceptible to interferences from additives or contaminates. Iron happens Summary to be one of those contaminates that has The issues presented here are by no come up in recent years in part because of means the defi nitive list, but are the this change in dosage levels, particularly ones where progress appears to be with phosphorous and polyacrylate based accomplished at this point in time. products. As dosage falls to minimum Additive interference will continue to be effective levels, iron appears to have a of increasing concern while reducing The DEEPCLEAN* pill combines more signifi cant effect than fi rst thought. environmental footprint will be critical to solvents and surfactants to Note in Figure 2 the effect of iron at very future products. In the opening paragraph create the world’s first double low levels on a variety of chemistries. a basic sales relationship was mentioned emulsion cleanup pill. Figure 3 then shows that some of that between suppliers and operations, but The unique application of effect is actually mitigated in phosphorous now it is incumbent on manufacturers water-in-oil-in-water products with higher levels of iron. Those and suppliers to introduce new products, technology improves film iron levels are likely to create other techniques, and applications in an effort removal and droplet dispersion, problems in the well however. Polyacrylates to offer new solutions to the needs and can deliver water-wet then tend to fall off in performance as that and issues in the fi eld in concert with tubulars just six minutes iron number continues to rise. Speciality operations and fi eld services. The growing after contact, with lower formulations with a unique polymer can complexity of the reservoirs, fl uids, and chemical concentrations than provide a synergistic effect in performance procedures in the fi eld demand a higher conventional displacements. through offering lower dosage at improved standard of involvement together at all performance, which, in the end, is the levels of the supply chain in order to meet Avoid completion NPT and overall goal of product improvement. the need. Manufacturers often have a future interventions, while Last, but certainly not least is better understanding of the molecule protecting near wellbore the physical environment in which itself and the ability to manipulate that reservoir permeability. the antiscalant should work, looking molecule to achieve the desired effect. specifi cally at temperature and brine. Therefore, effective working relationships Kemira’s sulfonated copolymers chemistry or partnerships are an integral part of the worked well from 4 ˚C in a Scaled Solutions development equation to make sure what study to 175 ˚C at Rice University working is developed does the job. It is no longer with barium sulfate scales in brines that, ‘what do you have for me today’, but ‘what in both studies, had moderate to severe can we do together to solve this problem scale indexes. A further variant of the tomorrow!’ O T www.miswaco.slb.com/deepclean

*Mark of M-I L.L.C A novel approach

64 Siv Howard and John Downs, Cabot Specialty Fluids, Scotland, describe how cesium acetate brine could make a novel high performance drilling, completion and workover fluid.

he success of cesium formate brine as a T well construction and workover fluid1 has raised the question of whether there might be other cesium-based brines with equally useful properties. One candidate examined by the research department of Cabot Specialty Fluids (CSF) is cesium acetate brine. The results of CSF’s initial tests on cesium acetate brine are summarised below.

Solubility and density It was found that the solubility of cesium acetate in water is 89.95% wt at 20 ˚C (68 ˚F), making a brine with a fluid density of 2.336 g/cm3 measured at 15.6 ˚C (60 ˚F). The brine density as function of dissolved cesium acetate salt is shown in Figure 1.

65 It is possible to blend cesium acetate brine with potassium acetate brine to make clear acetate fluids with densities between 1.40 g/cm3 and 2.30 g/cm3. It is also possible to blend cesium acetate and cesium formate brines to make clear monovalent cesium brines with densities up to approximately 2.4 g/cm3. This is a higher density than can be reached with either of the two brines on their own.

Effect of pressure and temperature The effect of pressure and temperature on the density of a 2.246 g/cm3 cesium acetate brine is illustrated in Figure 2. As with other brine systems, increasing temperature decreases the fluid density while increasing pressure increases the fluid density.

Figure 1. Density at 15.6 ˚C (60 ˚F) of cesium acetate brine as function of concentration. Water activity The water activity of cesium acetate decreases with increasing brine density, dropping below 0.10 in brines with densities of > 2.25 g/cm3 brine (Figure 3).

Boiling point The boiling point of cesium acetate brine increases with increasing density, reaching over 175 ˚C at a brine density of 2.36 g/cm3 (see Figure 4).

Freezing and crystallisation temperature The freezing and crystallisation points of cesium acetate brine are less than -30 ˚C over the density range 1.45 - 2.20 g/cm3 (Figure 5), beyond the reach of Cabot’s laboratory refrigeration equipment.

Figure 2. Density of a 2.246 g/cm3 cesium acetate brine as function of pressure for the Thermal stability temperatures 600, 450, 300, 200, 100, and 40 ˚F (315.6, 232.2, 148.9, 93.3, 37.8, Cesium acetate has been tested at temperatures and 4.4 ˚C). up to 232 ˚C (450 ˚F) for periods up to 90 days. Fluid analyses, pH measurements, and density measurements show only small changes in properties at the highest test temperatures. It is known that the primary products of the thermal decomposition of acetate are methane gas and bicarbonate. It was found that at temperatures of < 200 ˚C (392 ˚F) no change in soluble bicarbonate content could be measured in the brine. At temperatures > 200 ˚C (392 ˚F) a slight increase in soluble bicarbonate content was measured in the brine, with a corresponding small drop in pH. This increase in bicarbonate content does not appear to affect the density of the brine.

Elastomer compatibility Five commonly used elastomers and two plastics were tested for one and four weeks at Figure 3. Water activity of cesium acetate brine as function of brine density. 180 ˚C (356 ˚C) and 230 ˚C (446 ˚F)

OILFIELD TECHNOLOGY 66 June 2011 in a 2.20 g/cm3 cesium acetate brine. The results of the test are The results of the testing are shown in Table 3. Neither of shown in Tables 1 and 2. HNBR, VITON®ETP, and FFKM were the metals showed any evidence of localised corrosion, not compatible with cesium acetate brine at 180 ˚C (356 ˚F) and SCC, hydrogen charging, or loss of ductility. higher. AFLAS, EPDM, PTFE, and PPS appeared to be entirely 2. 30 day SCC study at 160 ˚C (320 ˚F) with a 145 psi CO2 compatible with cesium acetate brine for four weeks at these headspace. Four commonly used corrosion resistant alloys very elevated test temperatures. (CRAs) were exposed to the buffered cesium acetate brine. These were S13Cr-2Mo, 22Cr Duplex stainless steel -110ksi, Compatibility with metals 25Cr Duplex stainless steel – 80 ksi, Alloy 718 nickel alloy. Analyses of the samples at the end of the test showed no Modern well construction and workover fluids need to be evidence of SCC. compatible with the martensitic, duplex and high nickel alloy 3. SCC tests on MSS at 177 ˚C (350 ˚F) for 90 days with steels commonly used in well tubulars and packers. These 145 psi CO2 headspace. Triplicates of 13Cr-2Mo-110 and metals are susceptible to Stress Corrosion Cracking (SCC), 13Cr-0.6Mo-110 were tested in buffered cesium acetate particularly at high temperatures and in the presence of acid brine. Analyses of the samples showed no evidence of SCC gases (CO2 and H2S). Some are also susceptible to hydrogen or any other form for corrosion. charging in service. 4. SCC tests on MSS at 177 ˚C (350 ˚F) for 90 days with A lot of corrosion testing has been conducted on cesium 145 psi CO2 and 1.5 psi H2S headspace. Triplicates of acetate brine: 13Cr-2Mo-110 and 13Cr-0.6Mo-110 were tested in buffered

1. Six month SCC study at 170 ˚C (338 ˚F) with 145 psi N2 cesium acetate brine. Analyses of the samples showed no headspace. The metals that were tested were failures but some evidence of minor pitting/fissuring and S13Cr -2Mo and alloy 718. SCC (C-ring and FPB and a small crack in one of the 13Cr0.5-Mo-110 samples. The U-bend), hydrogen charging and weight loss tests were samples were stressed to 100% AYS at room temperature conducted on both materials. An ambient temperature SSRT rather than at test temperature, which could have affected test was conducted on S13Cr-2Mo after the fluid exposure. the result.

Table 1. Results of elastomer testing for 1 – 4 weeks in a 2.20 g/cm3 cesium acetate brine Temperature Mass Volume Test material Exposure Hardness 50% Elastomer type change change TS EAB type time [weeks] [IRHD] mod [°C] [°F] [%] [%] 0 0.0 0.0 93 14.4 28.3 105 180 356 1 0.4 0.2 93 13.1 25.9 108 OK FEPM James Walker 4 0.2 0.3 91 13.3 27.3 115 ® (Aflas )(TFE/P) AF69/90 0 0.0 0.0 93 14.4 28.3 105 230 446 1 -0.7 -0.9 94 12.1 21.0 97 4 -0.8 -1.7 95 13.2 19.9 85 0 0.0 0.0 92 14.7 22.9 84 180 356 1 2.0 -0.8 93 12.3 18.8 86

FFKM 4 3.7 1.5 93 10.9 13.5 68 Some degradation ® ® Parker V8588 (Kalrez Chemraz ) 0 0.0 0.0 92 14.7 22.9 84 over time 230 446 1 8.2 -- 88 -- 6.7 43 4 -7.3 -3.5 94 7.5 7.9 54 0 0.0 0.0 90 8.5 20.4 108 180 356 1 0.7 1.2 90 8.8 20.5 106

Gulf Coast 4 0.6 0.7 91 9.3 20.9 100 EPDM OK Seals EO962 0 0.0 0.0 90 8.5 20.4 108 230 446 1 -0.2 -0.3 92 8.8 20.7 99 4 0.5 -0.7 92 9.3 21.8 105 0 0.0 0.0 90 65 28.0 216 180 356 1 4.0 -1.0 94 13.1 30.8 200

Gulf Coast 4 27.4 5.8 98 -- 59.0 18 HNBR Fail Seals N4007

230 446 ------

0 0.0 0.0 90 8.3 21.8 138 180 356 1 3.3 2.0 92 -- 5.6 24 Base resistant 4 5.9 4.8 97 -- 8.7 9.9 FKM Parco 9130 Dissolving (Viton® ETP) 230 446 ------

OILFIELD TECHNOLOGY June 2011 67 Table 2. Results of PTFE plastic testing for 1 – 4 weeks in a 2.20 g/cm3 cesium acetate brine Temperature Young’s Test material Exposure time Mass Volume Hardness Plastic type mod TS (MPa) EAB type [weeks] change [%] change [%] [Shore D] [°C] [°F] (GPa) 0 0.0 0.0 63 1.4 21.8 227 OK 180 356 1 0.0 0.2 60 1.2 26.1 274

Standard 4 0.0 -0.2 61 1.0 23.1 259 PTFE unfiled 0 0.0 0.0 63 1.4 21.8 227 230 446 1 0.0 -0.2 63 1.0 23.5 270 4 0.0 -0.4 62 1.0 23.5 241

Table 3. Results of 4-point bend tests in cesium acetate at 170 ˚C (338 ˚F) for six months. N2 headspace Coupled / Specimen Test specimen description SCC Observations uncoupled

Alloy 718 Uncoupled NO Surface discolored, darken ~120 X 15 X 5 mm 1 in. bar Uncoupled NO Surface discolored, darken S13Cr-2Mo Uncoupled NO Surface discolored, black surface film 4.5 in. diameter ~120 X 15 X 5 mm pipe Uncoupled NO Surface discolored, black surface film

5. SCC tests on high-nickel alloys at 232 ˚C

(450 ˚F) for 90 days with 500 psi CO2 headspace. SM2550-125, Alloy 825, Alloy 718, Alloy 725, Alloy 935, Alloy 945-140, Alloy 925 were tested in a buffered cesium acetate brine. Analyses of the samples showed no evidence of SCC or any other form for corrosion. 6. SCC tests on high-nickel alloys at 232 ˚C

(450 ˚F) and 30 days with 500 psi CO2 and 5

psi +H2S. SM2550-125, Alloy 825, Alloy 718, Alloy 725, Alloy 935, Alloy 945-140, Alloy 925 were tested in a buffered cesium acetate brine. Analyses of the samples showed no evidence of SCC or any other form for corrosion. Conclusion Our preliminary investigations indicate that Figure 4. Boiling point of cesium acetate as function of brine density. cesium acetate brine has the some desirable properties that could enable its use as the basis of well construction and workover fluids. Its compatibility with CRA, high nickel alloys and some elastomers is a particularly useful feature. Further testing is underway to complete the definition of the properties of this novel fluid. O T

References 1. Downs, J.D, Turner, J.B. and Howard, S.: “A Well Constructed Chemical”, Oilfield Technology magazine, September 2010.

READ about the latest developments in unconventional resources on Energy Global

Figure 5. Freezing and crystallisation points of cesium acetate as a function of brine www.energyglobal.com/sectors density.

OILFIELD TECHNOLOGY 68 June 2011 Addressing challenges with innovation

Dave Allison, Neil Modeland, Bart Waltman and Kirk Trujillo, Halliburton, USA, consider innovations in fluids, completion designs and equipment to address HPHT stimulation challenges.

he industry’s recent forays into unconventional One region that has necessitated handling HPHT formations have presented challenges as never environments is the Haynesville and Bossier Shale Tbefore in terms of dealing with extreme pressure plays in East Texas and North Louisiana. Dealing with and temperature environments. These conditions frac gradients of 1.0 psi/ft (0.07 bar/ft) and bottomhole have pushed fluids, designs, and equipment to the temperatures exceeding 320 ˚F (160 ˚C) has provided very edge of performance capability. This stress, valuable lessons on how to best accommodate the however, has resulted in innovations that have made extreme conditions of these horizontal completions. production from unconventional formations not Applying the knowledge and experience gained from only feasible but also economically attractive. This already-developed HPHT regions can help both article will review developments related to efficiently operators and service companies take the steps producing hydrocarbons from shale, tight sand and necessary to achieve early success. heavy oil reservoirs. High pressure Meeting HPHT challenges in shale Probably the most evident change when transitioning formations to a high pressure reservoir focus is the increase in The challenges in hydraulically fracturing high pressure, the hydraulic horsepower (HHp) needed to properly high temperature (HPHT) formations will inevitably stimulate the reservoir (Figure 1). Since HHp is a direct increase globally as operators work to produce function of pump rate and surface pressure, the same hydrocarbons from deeper unconventional reservoirs. treatment design pumped under increased pressure

69 x Entry friction through perforations and near-wellbore tortuosity. x Pipe friction. x Hydrostatic pressure created by the fluid.

Traditionally, hydrostatic pressure is one of the first components to be addressed by incorporating a weighted fluid system such as calcium bromide. Unfortunately, the typical fluid volumes needed to properly stimulate unconventional reservoirs are massive, often totaling over 1 million gal. (4000 m3). Weighting the fluid with agents in order to increase hydrostatic pressure becomes too costly and operationally too complex for the overall pressure benefit, making this solution impractical. Other techniques to reduce BHTP and fluid friction have been successfully implemented by the completion teams. High pipe friction during stimulation treatments down the long Figure 1. In the Haynesville Shale formation, the hydraulic horsepower capability of the equipment may have to significantly exceed the horizontal wellbores of highly pressured reservoirs have made hydraulic horsepower required to fracture the well. wellbore design more closely tied into completion success than ever before. Where completion treatments were previously designed around wellbore schematics provided by the drilling group, in these HPHT reservoirs the wellbore/casing layout is now being frequently designed around desired fracturing parameters. For example, increasing the casing ID in all or part of a well to reduce friction often comes at an increase of material costs; however, in some instances, the reduction in friction has been significant enough to enable using lower casing grades, providing additional value and savings to the overall project. Another method of lowering pipe friction generated during these treatments is by reducing the treatment rate and compensating by increasing fluid viscosity to provide proppant transport and fracture growth. This approach must be evaluated closely since viscosifying agents and rate reductions can adversely affect the production from some reservoirs, depending on variables such as formation permeability, the possible need Figure 2. Comparative wellhead treating pressure for conventional crosslinked fluid vs the new high temperature high density crosslinked to enhance complexity, and the number of perforation clusters fluid. being treated per stage. An emerging strategy used to further reduce treating pressures, especially in HPHT horizontal wells, is the design would necessitate a HHp increase proportional to the pressure; of perforation intervals called clusters and the spacing of the however, the HHp capability of the equipment needed to deliver clusters being treated with each fracturing stage. Possibly the required treatment may be substantially more. contrary to traditional vertical well applications, by keeping Pumping units designed to function at higher pumping perforation clusters in a horizontal well to 1 ft (0.3 m) of length pressures are typically more limited in pumping rate compared to or less, formation breakdown challenges and overall bottomhole their equivalent HHp counterparts designed to function at lower treatment pressures have been shown to be significantly less in pressures. For these reasons, in the Haynesville Shale play, it some reservoirs. This is attributed to the reduction in is not uncommon for a treatment that requires 24 000 HHp for near-wellbore competing fractures stressing against each other the fracture treatment to necessitate 40 000 HHp of equipment during propagation, as these fractures are typically transverse on location. Because of this situation, close collaboration to the lateral. This situation is more likely to occur with longer and co-ordination by all disciplines involved is important. The perforation intervals. amount of pumping equipment required impacts many facets of In occurrences of closely spaced competing fractures the project such as building the location, equipment and material and high leakoff, it has become common practice to utilise logistics and, ultimately, the project budget and economics. 100 mesh proppant (or similar fluid leakoff control additive) used After addressing the requirement for sufficient HHp to place in small volumes (slugs) or even for several stages to seal off the treatment, the completion design can sometimes be finessed the competing fissures and further reduce treating pressures. to enable performing the treatment at lower treating pressures. Redesigning the perforating scheme can lead to lower treating This can benefit the operator by lowering the risk of screenout pressures and reduce the amount of 100 mesh proppant as well as potentially reducing the pressure ratings needed for needed. casing and well services equipment. The factors dictating the When stimulating multiple perforation clusters during one pressure observed at the wellhead include the following: treatment stage, maintaining high treatment rates per cluster x Bottomhole treating pressure (BHTP). has benefited production due to more effective limited entry

OILFIELD TECHNOLOGY 70 June 2011 fracturing. When designing treatment rates and volumes in Working under extraordinarily tight time constraints, the strategy conjunction with perforation cluster placement, many operators was to re-engineer Halliburton’s proven high density fracturing maintain high injection rates per perforation cluster with lowered fluid system—specifically its thermal stability—to achieve the friction pressure by reducing the number of clusters being required bottomhole treating pressure by taking full advantage fractured per treatment interval. More fracture stages will, of the increased hydrostatic pressure of the weighted stimulation however, have to be implemented under this strategy to maintain fluid system. an equivalent degree of reservoir coverage. There were excellent reasons to base this solution on the proven high density fracturing fluid system. This fluid has been High temperature successfully used since 2004 on numerous high pressure Even though the Haynesville reservoir has bottomhole static deepwater Gulf of Mexico projects to perform some of the temperatures ranging from 280 to 380 ˚F (138 to 193 ˚C), the industry’s deepest fracpack treatments (SPE 11607). temperature of the wellbore environment during treating is While the fluid broke new ground in deepwater wells and dramatically reduced to 150 to 160 ˚F (65 to 71 ˚C) by the possessed adequate density, it was not quite capable of amounts of fluid required to properly treat the unconventional handling the well’s high temperature threshold of 375 ˚F (191 ˚C). reservoir. Taking advantage of this ‘cool-down’ effect is a Working with the original high density fracturing fluid technology, traditional engineering technique utilised by fracture designers. experts overcame the temperature obstacle by ‘folding in’ Often the fluid volume in the early part of the fracturing stage chemistry from a separate proprietary high temperature fracture will be increased to intentionally lower the wellbore temperature fluid, which utilises an optimised carboxymethyl-hydropropyl gel to a level where standard fracturing fluid systems can perform (CMHPG) loading and a tailored oxidiser breaker system. adequately. When stimulating unconventional reservoirs like the The remaining challenge was how to cut pipe friction to Haynesville, completion design teams can take advantage of further lower wellhead pressure. After fine tuning of cool down so that the materials used to create the fracturing the high density base fluid formulation to a density of fluid system can be selected from materials originally intended 12.3 lb/gal. (1464 kg/m3), friction pressure was reduced by for lower temperature environments. This provides greater delaying crosslinking action during pipe transit time to the target confidence in the performance of the fluid while maintaining an zone. In addition, a microemulsion surfactant for improved fluid acceptable cost for the fluid system. recovery in tight gas was added to the fluid system. Even after treating pressures are reduced as much as Finally, the new high temperature, high density fluid system possible and bottomhole treating temperature is lowered, was ready to run in the well. The graph in Figure 2 shows the challenges continue in the HPHT unconventional reservoirs. expected fluid performance in reducing the surface treating Bottomhole temperatures exceed the limitations of many of the pressure as compared to a conventional high temperature industry’s formation evaluation technologies. Those that are fracturing fluid. available are in high demand and command premium pricing. This technology and equipment shortfall can require operators to make assumptions about reservoir quality along the laterals and to work from estimates as to fracture placement and geometry without conclusive information. This has led to production logs, net pressure evaluation, and production comparisons across various completions becoming some of the primary evaluation Low High tools of the stimulation treatment and for optimising the development of HPHT reservoirs. Viscosity Viscosity

Meeting HPHT challenges in tight gas Around the world, operators face a myriad of major tight gas challenges, but few rival a recent Saudi Arabia HPHT stimulation situation: how to perform a proppant frac in deep, tight gas sandstone formations at high bottomhole temperature. In this case, well conditions of over 15 000 psi (1034 bar) bottomhole pressure and 375 °F (191 ˚C) reservoir temperature exceeded the operating limits of the fracturing equipment and fluid available. Halliburton experts quickly determined that the most cost-effective solution was not to incur the time and expense of bringing in specialised high pressure pumping equipment, but to instead develop a specific fracturing fluid that would work with existing equipment to successfully handle the extreme HPHT conditions. Lower surface treating pressures also Whatever viscosity you are dealing with – translates into safer operating conditions. and whatever fl uid – Litre Meter has the meter for the job. Formulating a new solution To derive the necessary fluid chemistry and capabilities, Call +44 (0)1296 670200 Halliburton’s Saudi Arabia stimulation team collaborated with experts at Halliburton’s Duncan, Oklahoma, Technology Center.

www.whatfl owmeter.com Monitoring the temperature profile of a well over its entire producing zone via fibre optic DTS enables more cost-effective analytical methods versus other methods like thermocouples which do not provide a distributed temperature profile along then entire length. The fibre optic DTS measurement provides a much more representative profile of the subcool, reservoir heterogeneities and changing production and injection conditions over time that occur along the lateral.

Monitoring both temperature and pressure The high temperature fibre optic cable can be combined with a fibre optic pressure gauge to obtain both the distributed temperature profile and pressure information with no requirement for downhole electronics. Fibre optic gauges offer the same accuracy and low drift capabilities as proven electronic gauge Figure 3. A high temperature fibre optic system can provide technology but provide pressure data capabilities in high temperature and pressure profiles along the entire wellbore to help temperature SAGD environments where electronic gauges better manage SAGD projects in heavy oil. cannot operate. Monitoring and establishing a temperature profile with Successful application wellbore pressure information enables implementing a number The result was flawless stimulation performance of of different technologies in SAGD projects that can influence the Saudi Arabia’s—and the world’s—first high density, high placement of steam along the horizontal wellbore. These can temperature fracture fluid treatment. To stay within the downhole include the use of dual tubing strings, the relocation of a tubing completion string pressure limitation, the pumping rate was held string along the wellbore, the use of limited entry perforation to a little over 16 bbls per minute. The ~11 000 psi (758 bar) and other more flexible solutions like interval control valves surface treating pressure was only slightly higher than the (ICV) technology that would enable some measure of zonal predicted pressure. While the pump rate was lower than desired, segmentation and control from surface. it was not a limitation to successfully performing the treatment. As specified in the fracture design, Halliburton’s team pumped Fibre optic system experience 80 000 gal. of the high temperature, high density gel system and Fibre optic high temperature cable has been installed by placed more than 150 000 lbs of high strength proppant. Halliburton in nearly 200 steam injectors since 2001. Data from While solving the challenge of effectively and economically the fibre optic DTS have provided insight in fully understanding fracturing under extreme HPHT tight gas sandstone conditions, the completions equipment performance, steam movement the new high temperature, high density fluid system met an even results, and well response. Experience with the DTS has shown greater customer need: providing a proven, cost-effective way that multi-mode fibre typically gives superior performance over to fracture stimulate and validate the reserves of this significant single-mode fibre in terms of accuracy and resolution under Saudi Arabian tight gas formation. Indications are that this SAGD conditions. High temperature fibre pressure gauges have technology may well play an important role in solving similar shown good stability and repeatability. tight gas challenges in other locations around the world. In one project installed by an operator in Canada utilising fibre optic DTS and pressure gauges, the observed uneven Meeting HT challenges in heavy oil projects steam injection profile provided the opportunity to attempt to Fibre optic distributed-temperature-sensing (DTS) systems offer improve the injection performance. Steam was diverted to the cost-effective methods for improving recovery in steam assisted heel zones to increase warming, improve injectivity and build a gravity drainage (SAGD) oilfields producing heavy oil (Figure 3). more uniform steam chamber. With initial indications of some One of the biggest challenges of a SAGD process is achieving warming of these zones, injectivity improved and uniform steam conformance along the horizontal wellbore. steam-oil-ratio (SOR) performance improved about 20%. This is a result of reservoir heterogeneity, production and Evaluation of the ability to develop a more uniform chamber will injection changes over time, and (typically) the limited control take a longer time (CSUG/SPE 137133). of steam placement along the wellbore. Consequently, uneven steam injection and heating can occur in the well and lead to Other applications development of a non-uniform steam chamber. Fibre optic systems have been discussed here relating to SAGD wells are usually operated under subcool control SAGD steam injectors; however, the applications extend to during which the production well is choked back if live steam other thermal applications, e.g., cyclic steam stimulation (CSS), reaches the producer. The proximity of live steam is monitored steam drive and variations, and non-thermal enhanced oil through the temperature difference between the injector and recovery (EOR) processes. The fibre optic systems can be used producer (subcool); however, this temperature difference is to observe behaviour over time and help optimise completions usually not uniform over the well length1. To prevent production hardware and processes to improve performance and reduce of live steam and improve energy efficiency, it is necessary to operating costs. O T limit the production rate based on controlling the subcool in the segment of the well most prone to steam breakthrough, i.e., References steam breaking through to the producer. 1. Gates and Leskiw, 2008.

OILFIELD TECHNOLOGY 72 June 2011 UNDER PRESSURE ASAD MEHMOOD, WEATHERFORD INTERNATIONAL LTD, PAKISTAN, DISCUSSES THE USE OF DRILLING CONTROL SYSTEMS TO NAVIGATE NARROW PRESSURE MARGINS AND ACCESS DEEP DRILLING TARGETS.

n 1998 an operator began drilling in a Pakistan fi eld, The formation consists of hydrocarbon-rich but a high pressure sequence forced them to stop. sandstone and a mixture of limestone and inter-bedded IAll available casing strings were consumed at a shale. The limestone is weak and vuggy, often leading to measured depth (MD) of 3500 m; furthermore, managing costly mud losses. Furthermore, pockets of the high levels of background gas and fl uid losses in the high pressure gas can require days to circulate out, 6 in. hole proved impossible. resulting in excessive non-productive time (NPT); a gas Ten years later, a different operator decided to target slug in the fi rst well precipitated six days of NPT. formations that had not previously been explored. The window between pore pressure and the fracture They believed that managed pressure drilling (MPD) gradient in the formation is quite narrow techniques coupled with the proprietary continuous (0.4 kg/cm2 equivalent mud weight). As such, a slight drop circulating valves would enable drilling through the HPHT in equivalent circulating density (ECD) during pipe makeup intervals to a deeper carbonate sequence. can lead to kicks, well control issues and borehole The projected MD for the well was 5200 m. Drilling instability. On the fl ip side, the use of overbalanced was originally to take place in two phases to overcome drilling techniques to prevent gas infl uxes tends to yield the limitations imposed by the pressure capacity fractures, lost circulation, formation damage and a low (5200 psi) and certifi ed maximum drilling depth (5000 m) ROP. The narrow gradient window has proven impossible of the rig’s mud circulation system. to navigate using conventional drilling technology.

73 Operational detail x Rig-up for the MPD operation entailed installing the RCD, adjustable choke manifold and control unit for the Microflux system, and topping the last set of stands with continuous circulation valves. x The platform incorporated a top-drive system. During drilling, mud flowed normally through the system and across the top of the continuous circulation sub. When the sub reached the table, a mud hose was connected to its side port; the side flapper valve opened to allow mud to enter and the flapper valve on the top of the sub closed so that the top drive could be disconnected. x Pumping continued through the sub’s side port until the next stand of pipe was connected. Mud flow was again routed through the top drive system from the top of the new stand. The auxiliary hose was Figure 1. This Microflux display shows an influx that is being circulated out of the well during the drilling of the disconnected from the 8 ½ in. section. The increase in the outward flow-rate (red) shows the influx. The annular backpressure has been bottom sub, the side port increased to compensate, as has the standpipe pressure. The system allowed the operator to continue drilling valve closed, and the sub while handling up to 50% gas cut in the annular flow. was run in as part of the drillstring. Beneath the formation lies pisolitic limestone; this formation x The Microflux system helped the operators in several had never been explored due to its depth and the difficulty of ways during drilling. Combined with an auxiliary reaching it. pump, it enabled them to maintain a constant level of The operator overcame the obstacles to drilling the annular backpressure, which ultimately contributed to well using MPD techniques. One of the technologies used increasing ROP. It also helped them manage transient was Weatherford’s Microflux control system. The Microflux conditions, such as pump-off, displacement of heavier mud pills, deployment of mud caps, circulation of high system monitors volume in versus out and controls annular gas cut, plugging of nozzles at bit, and swab/surge. backpressure. On the operation, the system proved capable of Furthermore, it detected two major partial loss events detecting and controlling an influx of less than 1.5 bbls within followed by influxes and allowed the influxes to be 2 minutes. circulated out without impacting drilling activities. By maintaining continuous circulation and controlling annular x Max drilling mud weight in the 8 in. section of the and bottomhole pressure in the difficult section of the well, the well was 2.07 kg/cm2. The max recorded circulating operator and Weatherford were able to maintain an average ROP temperature was 121 ˚C (static temperature above of 2.5 m/hr. The system effectively controlled background gas 165 ˚C). from the sandstone/limestone without causing lost circulation. x The technologies used on this operation supplanted Drilling continued even while circulating out as much as 50% conventional mud-logging based flow out monitoring and gas cut. trip/active tank recordings.

System components Conclusion The Microflux system features a rotating control device (RCD), Benefits the two new technologies provided on the operation used to maintain a closed and pressurised annular environment. include minimised non-productive time, the ability to It is also equipped with sensors that monitor annular pressure continue drilling while circulating out up to 50% gas cut and other drilling variables in real-time and an automated and the prevention of kicks, other well-control issues, lost surface choke. During the operation, an auxiliary mud pump was circulation and . The operator reached TD used to increase back pressure, as needed. under extremely challenging circumstances. O T

OILFIELD TECHNOLOGY 74 June 2011 TM

18 – 20 October 2011 All Russia Exhibition Center, Pavilion 75, Moscow

Discover the Arctic’s True Potential at SPE Arctic & Extreme Environments 2011

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Energy & Marine 76 SouthOperations in the China Sea

Mohd Hairi Abd Razak and Fuad Mohd Noordin, Petronas, Malaysia, and Mohd Nur Afendy and Rahmat Wibisono, Schlumberger, Yemen and Malaysia, present an example of the planning and execution of coil tubing (CT) operations on platforms too small to accommodate all the required equipment.

etronas Carigali Sdn. Bhd operates 13 oil and gas fields in the South China Sea, located offshore the Malaysian state Pof Terengganu in water depths from 65 to 80 m. The area has more than 30 platforms, most with small deck space areas and crane lifting capacity of only 5 t. The fields began to experience increased sand production, high water cut and larger skin factor. Well interventions and treatments such as matrix stimulation, water shut-off and sand cleanout were required to sustain production rates. CT well intervention is the most effective method to perform the required treatments; however, when platform space is limited, it is often not practical to accommodate the required facilities onboard. In addition, crane capacity may be inadequate to safely handle the CT equipment. A solution is to deploy a minimal amount of equipment on the platform deck and use a suitable vessel to perform heavy lifting and other support for the CT operations.

77 platforms. Three options were considered: lift boat, work boat, and work barge. The evaluation was based on completing the CT pilot project within three months, chartering the vessel on a spot basis rather than a long term contract. A lift boat is a self-propelled, self-elevating vessel with a relatively large open deck. Like a jackup rig, it is capable of raising its hull clear of the water on its own legs. This feature means that it does not require an anchor pattern for stability and to maintain a safe distance from the Figure 1. Map of PCSB concession with insert of Malong and Penara Platform. platform. This saves the cost of an anchor tug handling supply (ATHS) Table 1. Vessel comparison vessel and avoids the Lift boat Work boat Work barge risk of anchors damaging Anchor pattern Not required Required Required seabed equipment if dragged by tides or Anchor handling tug Not required Required Required currents. A disadvantage Soil investigation Required Not required Not required of the jackup system is the necessity to conduct Deck space Yes Yes Yes a soil investigation prior to Crane Yes Yes Yes installation. Total project cost Most expensive Medium Least expensive Work boats are commonly deployed to assist CT operations Pilot project in East Malaysia, and Petronas often uses them for workover Petronas selected two small platforms for a pilot CT intervention operations. This option would require installation of an anchor project. Platforms in its Penara field are of a lightweight design pattern. featuring a cable-guyed caisson monotower (Tarpon) and a Work barges with the same specifications as work boats topside deck with minimum facilities. First oil from the field was were available at lower daily charter rate (DCR) and shorter in May 2004, and peak production reached 12 000 bpd. The waiting times. Costs for the planned three month project were selected platform had just 180 m2 of main deck and its jib crane evaluated for each of the three technical options. These included had a maximum capacity of 5 t. ATHS vessel costs for the work boats and barges, crane costs if The Malong field was completed in March 2000. The quoted separately from the DCR, fuel, manning and bunkering. selected unmanned minimum-facilities platform was a The lift boat was the most expensive option. Due to lower DCR lightweight optimised jacket structure that supports conductor and faster availability, the work barge was the most slots for production and water injection wells and is suitable only cost-effective option for the project that met the essential for a jack-up drilling rig. The platform houses all the necessary technical and timing requirements. production, well testing, water injection, pig launcher and gas lifting facilities, and is provided with a life support system. It has Work barge assessment 650 m2 of main deck, but taking into account all the fixed surface Throughout the operations, only the coil tubing injector head, facilities, the operations area is insufficient for conventional CT jacking frame and CT control cabin would be erected on the operations. In addition, the jib crane has a 5 t capacity, sufficient platform while the remaining equipment would stay on the barge. only for lightweight wireline equipment. It was determined that the barge must have a minimum 500 m2 deck space without a crane, or 350 m2 with a crawler crane CT support vessel evaluation installed. The heaviest equipment that required lifting to the Petronas performed a detailed analysis to determine the type platform was the 12 t injector head and CT of vessel that would meet the technical requirements and be (BOP) assembly, which required a crane capable of lifting 15 t most cost-effective in supporting CT operations at the selected at 60˚ boom angle for safe operations. A 150 t capacity crawler

OILFIELD TECHNOLOGY 78 June 2011 crane with 150 ft (45.72 m) boom was considered adequate to meet the requirements while minimising the required deck space. The barge needed an eight point mooring system to provide improved stability and facilitate faster disconnect in the event of emergency. Accommodations required sufficient workspace for at least 80 personnel.

Flowback handling system assessment The Penara work programme required a system to separate sand from the return fluid. A sand filter system and a cyclone sand separator were considered. Sands produced in Penara have fine (10 - 40 micron) grain Figure 2. Equipment layout on the barge. size. Filter systems cannot separate such fine sand and were not a viable Health, safety, and environment (HSE) option; however, a centrifugal cyclone system would be able to assessment handle them effectively. The monsoon season in the South China Sea area is between The sand separator was hooked directly into the well, so October and March when there are often strong winds and the platform shutdown system and surface safety valve (SSV) swells in excess of 6 m. It is usual to avoid operating during had to be bypassed. To enable the flowback handling system this season; however, due to other commitments, the work to override the existing emergency shutdown device (ESD) and barge was only available in February. The HSE assessment SSV, a dedicated SSV in the return line and separate ESD control determined that operations should only start in less than 3 m panel were required. swell and 20 knot winds. Weather forecasts were updated hourly To improve cleanup efficiency, water-based gelling fluid was to maximise the time available for crews to stop operations and used to raise the viscosity of the injected fluid. However, sand perform the necessary steps to move away from the platform. separation is more efficient with low viscosity fluids, requiring A special device in the CT reel was deployed during the project a breaker solution to be injected before the separator, which is to allow emergency disconnect and immediate pull-away from capable of destroying the polymer structure of the gel. Facilities the platform if forecasts indicated dangerous conditions within were also required to store sand and liquid effluent. 3 hours.

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www.energyglobal.com/sectors Results: Penara Well 1 from the lower reservoir; however, leaks in the completion Previous bullheading operations unsuccessfully removed wax tubing complicated these operations. The only way to effectively from this wellbore, and another treatment to bullhead solvent squeeze water shutoff chemical was by conveying it with a also proved to be ineffective. A high pressure jetting tool was CT multi-set mechanical packer. After setting the packer, the used to pump different solvent fluids, and was able to reach plug leak could be isolated, enabling the chemical to be squeezed back total depth (PBTD). A final slickline gauge ring run indicated into the lower operation. that the wax had been successfully removed, and the well had CT operations in this well proved unsuccessful. Prior to returned to oil production with encouraging results. reaching target depth, a sequence packer activation procedure was performed to test its functionality and integrity. The setting Results: Penara Well 2 sequence showed that pressure was holding during injection; Bailer runs in October 2007 became hung at 2073 m and upon however, the unsetting sequence showed that the packer retrieval to surface, the bailer recovered traces of sands. The CT could not be released from its position. High pulling force and intervention programme of this well required sand cleanout from multiple packer manipulation were attempted, but after two hung-up depth to PBTD—an interval of approximately 935 m. days of trying, it was decided to release from the packer by Bipolymer gel was conveyed by a special nozzle. In the event of activating an emergency disconnecting tool. The upper portion hard sediment that was not removed by this nozzle, acid could of the disconnecting tool was retrieved to surface. Subsequent be conveyed by a high pressure jetting tool. The programme attempts to fish the packer were unsuccessful, and it remains in was executed as planned, with a CT rate of penetration between the hole. 1 - 3 ft/min. The separator worked effectively to capture produced sands from the wellbore. A small pill of acid had to be Conclusions pumped to enable the CT to reach final cleanout depth. Rough This case study confirms that CT operations can be weather led to one emergency disconnect, in which planned cost-effectively performed with the support of a work barge procedures were successfully implemented. on platforms that cannot accommodate all of the necessary equipment. Thorough planning is required to ensure that the Results: Malong Well technical requirements of multiple types of CT intervention can The production and intervention history of this well indicated be effectively delivered and that operations can proceed safely in that it required water shutoff treatment to block water production potentially adverse conditions. O T

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