D E C E M B E R 2 0 1 6 • VO LU M E 6 8 , N U M B E R 1 2
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slb.com/GeoTesting *Mark of Schlumberger. Copyright Š 2016 Schlumberger. All rights reserved. 16-TS-185700
CONTENTS Volume 68 • Number 12
14 GUEST EDITORIAL • ASSESSING THE PROCESSES, TOOLS, AND VALUE OF SHARING AND LEARNING FROM OFFSHORE E&P SAFETY-RELATED DATA With the US Bureau of Safety and Environmental Enforcement as a cochair of the steering committee, SPE held a 2-day summit in April to discuss the development and implementation of an industrywide safety-data sharing framework. This article summarizes the conclusions of the summit and lists the near- and long-term next steps to be taken to retain the momentum gained during the summit.
19 TECHNOLOGY UPDATE • NEW METHOD ADDS VALUE TO WOLFCAMP POROSITY, ORGANIC-MATTER MEASUREMENTS A new method that analyzes scanning electron microscope images of formation samples has been successfully used to measure porosity and total organic carbon in the west Texas Wolfcamp Shale.
28 PORES TO PREDICTIONS: NANOSCALE CLUES TO LARGER MYSTERIES Companies are beginning to explore the frontiers of unconventional rock: the matrix of tiny pores that is the source of oil and gas. The potential benefits of studying at the pore level are great, but it is a daunting challenge to understand what goes on in a place where the minute features are at the edge of what can be observed and measured.
34 MORE OIL, MORE WATER: HOW PRODUCED WATER WILL CREATE BIG COST PROBLEMS FOR SHALE OPERATORS If crude oil prices see a rebound, US shale producers will respond by drilling and completing more wells. But the associated produced water volumes could drive up their operating expenses.
40 MANAGEMENT • TAPPING THE VALUE FROM BIG DATA ANALYTICS Leveraging hidden insights from mining data can help enterprise users make better, smarter decisions and reduce operational costs. It is imperative to view technology platforms as a combination of technology, delivery, and price model that supports an enterprise user adoption quickly vs. the traditional technology-only initiative.
An Official Publication of the Society of Petroleum Engineers.
Within this rock is a network of pores holding organic material (green), which can produce oil and gas and are connected to inorganic pores (blue) that can store oil, water, or gas, with unconnected pores nearby (red). Source: University of North Dakota Energy & Environmental Research Center/Ingrain.
DEPARTMENTS 6 8 10 12 16 22 38 74 75 76
Performance Indices Regional Update President’s Column Comments Technology Applications E&P Notes SPE Events SPE News Professional Services Advertisers’ Index
Printed in US. Copyright 2016, Society of Petroleum Engineers.
TECHNOLOGY FOCUS 42 RESERVES/ASSET MANAGEMENT Greg Horton, SPE, Retired, and Barbara Pribyl, SPE, Reserves and Resources Manager, Santos
43 Integrated Asset Modeling: An Approach to Long-Term Production Planning
45 How Visualization Technology Is Maximizing Uptime 47 Overcoming Technical-Assurance Challenges in Executing Parallel Megaprojects
49 Unconventional Risk and Uncertainty: What Does Success Look Like? 51 PRODUCTION AND FACILITIES Ted Frankiewicz, SPE, Engineering Adviser, SPEC Services
52 Determination of H2S Partial Pressures and Fugacities in Flowing Streams 54 Production-Optimization Strategy Using a Hybrid Genetic Algorithm 56 Qualification of Composite Pipe
Behind every winner is a great nomination
59 BIT TECHNOLOGY AND BOTTOMHOLE ASSEMBLIES Graham Mensa-Wilmot, SPE, Drilling Engineering Senior Adviser, Chevron
60 New Rotary-Steerable System Delivers High Dogleg Severity, Improves Penetration Rate
62 Bending Rules With High-Build-Rate Rotary-Steerable Systems 64 Improvements in Root-Cause Analysis of Drillstring Vibration 66 WATER MANAGEMENT Syed A. Ali, SPE, Consultant
67 Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing in the Permian Basin
70 Solving Produced-Water Challenges With a Novel Guar-Based System 72 Produced-Water Reinjection—Case Study From Onshore Abu Dhabi
Nominate a colleague for outstanding work in the E&P industry. Now until 15 February, the Society of Petroleum Engineers is accepting nominations for outstanding work in the E&P industry. Visit www.spe.org/go/NomAwards for more information on nominating a colleague today.
The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt.
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7/11/16 11:34 AM
SPE BOARD OF DIRECTORS OFFICERS
SOUTH AMERICA AND CARIBBEAN
2017 President Janeen Judah, Chevron
SOUTH, CENTRAL, AND EAST EUROPE
2016 President Nathan Meehan, Baker Hughes
SOUTH ASIA AND THE PACIFIC
2018 President Darcy Spady, Broadview Energy
SOUTHWESTERN NORTH AMERICA
Vice President Finance Roland Moreau, ExxonMobil Annuitant
WESTERN NORTH AMERICA
Anelise Quintao Lara, Petrobras
Matthias Meister, Baker Hughes
Salis Aprilian, PT Badak NGL
Libby Einhorn, Concho Oil & Gas
REGIONAL DIRECTORS AFRICA Adeyemi Akinlawon, Adeb Konsult
Andrei Popa, Chevron
Motivate Inspire Educate Nominate
TECHNICAL DIRECTORS DRILLING Jeff Moss, ExxonMobil
CANADIAN Cam Matthews, C-FER Technologies
EASTERN NORTH AMERICA
HEALTH, SAFETY, SECURITY, ENVIRONMENT, AND SOCIAL RESPONSIBILITY Trey Shaffer, ERM
Joe Frantz, Range Resources
GULF COAST NORTH AMERICA J. Roger Hite, Inwood Solutions
MID-CONTINENT NORTH AMERICA Chris Jenkins, Independent Energy Standards
MANAGEMENT AND INFORMATION J.C. Cunha
COMPLETIONS Jennifer Miskimins, Colorado School of Mines
MIDDLE EAST
PRODUCTION AND FACILITIES
Khalid Zainalabedin, Saudi Aramco
Hisham Saadawi, Ringstone Petroleum Consultants
NORTH SEA
RESERVOIR DESCRIPTION AND DYNAMICS
Karl Ludvig Heskestad, Aker BP
Tom Blasingame, Texas A&M University
NORTHERN ASIA PACIFIC
DIRECTOR FOR ACADEMIA
Phongsthorn Thavisin, PTTEP Dan Hill, Texas A&M University
ROCKY MOUNTAIN NORTH AMERICA Erin McEvers, Clearbrook Consulting
AT-LARGE DIRECTORS
RUSSIA AND THE CASPIAN
Khaled Al-Buraik, Saudi Aramco
Anton Ablaev, Schlumberger
Helena Wu, Santos Ltd.
JPT STAFF
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Glenda Smith, Publisher
SPE PUBLICATIONS: SPE is not responsible for any statement made or opinions expressed in its publications.
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PERFORMANCE INDICES WORLD CRUDE OIL PRODUCTION+‡ THOUSAND BOPD
HENRY HUB GULF COAST NATURAL GAS SPOT PRICE‡ 6
O PEC
APR
MAY
JUN
JUL
Algeria
1320
1320
1300
1320
Angola
1840
1865
1870
1876
4 3
Ecuador
555
556
550
545
Indonesia
840
845
851
845
4000
4100
4120
4130
2
Nigeria Qatar Saudi Arabia1 UAE Venezuela TOTAL
330
310
1980
1880
1537
1537
1537
1537
10240
10340
10540
10670
2595
2670
2820
2840
2400
2300
2280
2220
34762
34783
35363
35368
SEP
JUL
JUN
OCT
285 1850
AUG
330 2100
1 MAY
2570
APR
4415
2570
MAR
4405
2550
FEB
4355
2320
2016 JAN
4475
Kuwait1
DEC
Iraq
Libya
USD/million Btu
NOV
Iran
5
WORLD CRUDE OIL PRICES (USD/bbl)‡
MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
Brent
38.21
41.58
46.74
48.25
44.95
45.84
46.57
49.52
WTI
37.55
40.75
46.71
48.76
44.65
44.72
45.18
49.78
THOUSAND BOPD NON-OPEC
APR
MAY
JUN
JUL
Canada
3429
2811
3112
3652
China
4036
3973
4034
3938
Egypt
494
493
490
482
Mexico
2210
2207
2213
2193
Norway
1666
1607
1480
1763
10450
10440
10453
10254
1005
992
898
970
Russia UK
REGION
APR
MAY
JUN
JUL
AUG
SEP
OCT
437
408
417
449
481
509
544
41
42
63
94
129
141
156
203
188
178
186
187
189
183
90
95
91
94
96
92
87
384
391
389
390
379
386
391
US
8947
8882
8705
8685
Other2
12082
12382
12537
12551
TOTAL
44319
43787
43922
44488
Total World
79081
78570
79285
79856
USA
WORLD ROTARY RIG COUNT†
Canada Latin America Europe Middle East Africa Asia Pacific
90
91
87
82
81
77
77
179
190
182
186
194
190
182
1424
1405
1407
1481
1547
1584
1620
INDICES KEY +
Figures do not include natural gas plant liquids.
1
Includes approximately one-half of Neutral Zone production.
2
From the October issue of JPT, the “Other” line item also includes Argentina, Australia, Azerbaijan, Brazil, Colombia, Denmark, Equatorial Guinea, Gabon, India, Kazakhstan, Malaysia, Oman, Sudan, Syria, Vietnam, and Yemen. Monthly production from these countries was listed individually in previous JPT issues. Ongoing work on the US Energy Information Administration (EIA) website is disrupting the regular updating of these countries’ production numbers. Additional annual and monthly international crude oil production statistics are available at: http://www.eia.gov/beta/international/.
Quarter
Supply includes crude oil, lease condensates, natural gas plant liquids, biofuels, other liquids, and refinery processing gains.
3
† Source: Baker Hughes. ‡ Source: EIA. Numbers revised by EIA are given in italics.
6
TOTAL
WORLD OIL SUPPLY AND DEMAND3‡ MILLION BOPD
2016 4th
1st
2nd
3rd
SUPPLY
96.50
95.53
95.51
96.26
DEMAND
94.26
94.18
95.29
96.04
JPT • DECEMBER 2016
BroadShear OFF-CENTER TOOL JOINT SHEAR RAMS
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Distinguished by shear ability. BroadShear rams now make it possible to shear any part of the drillstring above the BHA, including tool joint hardbanding and off-center tubulars—components long considered unshearable. Designed to stringent Bureau of Safety and Environmental Enforcement (BSEE) regulations, BroadShear rams bring enhanced security and dependability to marine drilling, so you can maximize safety in offshore operations.
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cameron.slb.com/BroadShear BroadShear is a mark of Schlumberger. Š 2016 Schlumberger. 16-DRL-177836
REGIONAL UPDATE AFRICA Z ExxonMobil will drill its first exploratory well offshore Liberia this month, the company announced on 18 October. A deepwater well is planned on the Liberia-13 Block, which is about 50 miles off the coast of the West African country. Liberia has no oil production at present. Z Solo Oil plans to spud the Ntorya-2 appraisal well in Tanzania next month. The drilling pad is a mile southwest of the 2012 Ntorya-1 discovery well, which was tested at rates of 20.1 MMcf/D of gas and 139 B/D of condensate. An independent report estimated the discovery to hold 153 Bcf of gas in place, of which 70 Bcf is considered a gross best-estimate contingent resource. A gross best estimate of more than 1 Tcf of gas in place has been made for the Ntorya prospect as a whole, in which the company has a 25% interest.
ASIA Z North Caspian Operating Company (NCOC) made its first two oil shipments from the giant Kashagan field offshore Kazakhstan on 14 October, the country’s energy ministry announced. Gas shipments have also begun. After field startup in 2013, production was quickly suspended until recently because of pipeline technical problems. October oil production was estimated at 75,000 B/D and November/ December output is expected to rise to between 150,000 B/D and 180,000 B/D. The NCOC consortium that developed and operates Kashagan under a production sharing agreement (PSA) includes Eni, Shell, Total, ExxonMobil, and KazMunay Gas, each of which holds a 16.81% interest in the PSA; China National Petroleum Corporation (CNPC) (8.4%); and Inpex (7.56%).
AUSTRALIA/OCEANIA Z BP has decided to abandon drilling plans in the Great Australian Bight offshore southern Australia, an area in which prospective drilling has long been contested by environmentalists. The decision “is an outcome of our strategy and the relative competitiveness of this project in our portfolio,” said Claire Fitzpatrick, managing director for Australian exploration and production at BP. The regulatory process
8
was not a factor in the decision, and the company’s view of the region’s potential has not changed, she said. Wood Mackenzie has reported that the Bight could hold 1.9 billion BOE of resources, and the spending level of BP’s drilling program there had been estimated at AUD 600 million. BP said that Statoil, its minority partner in four Bight exploration licenses, has accepted the decision.
EUROPE Z Faroe Petroleum has made discoveries at the Njord North Flank in the Norwegian Sea at water depths of approximately 1,060 ft. The exploration well NF-2 6407/7-9S encountered a gross oil-bearing reservoir of 334 ft and a gross gas condensatebearing column of 515 ft. The sidetrack well NF-3 6407/7-9A encountered separate gas-bearing columns of 639 ft and 459 ft. Preliminary estimates indicate a collective discovery of 1.9 million BOE to 28.3 million BOE. The company has a 7.5% interest in the wells, which are operated by Statoil (20%). Engie (40%), DEA (30%), and VNG (2.5%) hold the other interests. Z Total’s 30/4-3 S wildcat well has made a discovery on production license 043 in the northeast section of the Martin Linge field offshore Norway. The well found gas and condensate in three formations, and the Norwegian Petroleum Directorate reported good reservoir quality. A maximum gas flow rate of 2.4 MMscm/D through a 48/64-in. nozzle was attained in a production test. Preliminary estimates indicate a discovery of 2 MMscm to 11 MMscm of recoverable oil equivalents. Total (51%) operates the field with additional stakes held by Statoil (19%) and Petoro (30%).
MIDDLE EAST Z Kuwait Energy has started production from the Faihaa-2 well in the Block 9 concession of the Basra Governorate in southern Iraq. The well was spudded on 3 January, and production testing began on 23 September at an initial rate of 9,583 B/D of oil per day from the Yamama-A formation. Commercial production began on 1 October at a stabilized rate of 5,600 B/D. The company is the operator with a 60% revenue interest in the concession. Partners Dragon Oil (30%) and Egyptian General Petroleum (10%) hold the remaining interests.
Z DNO has completed three new production wells at the Tawke field in Iraq’s Kurdistan region. The Tawke-31 well was to be brought on line following acid stimulation. The Tawke-33 and Tawke-34 wells were also being prepared for startup. A fourth well, Tawke-37, was spudded in mid-October. The four wells are expected to increase field capacity by 10%. Third-quarter field output averaged 109,159 B/D. DNO is the operator with a 55% stake in the field. Genel Energy (25%) and the Kurdistan Regional Government (20%) hold the other stakes.
NORTH AMERICA Z BHP Billiton reported finding oil in multiple horizons at the Caicos exploration well on Green Canyon Block 564, about 100 miles offshore Louisiana in the deepwater Gulf of Mexico. The company is the block’s sole interest owner. A further move to appraise the area is planned this month, with drilling to begin on the adjacent Wilding prospect. In March, BHP Billiton encountered hydrocarbons at the Shenzi North-ST3 well in the Green Canyon area, although results were not disclosed. “We continue to be optimistic around the opportunity for a commercial development in the area,” said Steve Pastor, BHP’s president of petroleum operations, at a London investor briefing.
SOUTH AMERICA Z Total said the northwest section of the supergiant Libra prospect offshore Brazil holds 3 to 4 billion bbl of oil, according to an investor presentation on its website. The company said that wells drilled in the vicinity of the Libra pioneer well, which is close to the northwest section, also show “excellent” productivity. Total has a 20% interest in the prospect, which is operated by Petrobras (40%), while China National Offshore Operating Company (20%) and CNPC (20%) hold the remaining interests. Z CNPC likely has 3 to 4 Tcf of proven natural gas reserves in an energy block it operates in southern Peru, Peruvian President Pedro Pablo Kuczynski said on 18 October. The company bought the rights to explore Block 58 in Peru’s southern Amazon region from Petrobras in 2014. At the time, the block had proven reserves of about 2 Tcf. JPT
JPT • DECEMBER 2016
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RISK AND REWARD
To Be Leaders of Integrity, We Must Earn Trust Janeen Judah, 2017 SPE President
Our reputation is earned. The public has high expectations, and we must strive to deliver perfection in our operations. But of course, we work in an unpredictable and imperfect world. Sustainability and environmental awareness require small development footprints and controlled production streams. As engineers, we often try to argue with logic and facts, when emotions and media buzz are what really drive the conversation. Benjamin Franklin said that “it takes many good deeds to build a good reputation, and only one bad one to lose it.” Today’s financial pressures leave little margin for error. All of us pay when anyone in our industry makes a mistake, and we pay forever. How do we preserve our license to operate in a world that distrusts our industry? A recent column in the Houston Chronicle, which we would all expect to be energy-friendly, admitted that our industry has “always fulfilled a critical societal need by providing affordable energy that spurs economic development.” But “those benefits have been overshadowed by catastrophic events and a warming planet.” The article was accompanied by photos of oil-covered cleanup workers from the 1989 Exxon Valdez oil spill. We can never outrun our past.
If our industry doesn’t develop a workable solution for orphan wells, a solution will be imposed on us. Source: Railroad Commission of Texas.
I have a special concern about operating in a safe and environmentally responsible manner. When I was president of Chevron’s Environmental Management Company, we dealt with the end of life issues with all aspects of our industry— offshore platforms, pipelines in the Gulf of Mexico, remediated refinery and service station sites, and Superfund sites. Environmental management doesn’t generate revenue, and every quarter I had to go to Chevron’s executive committee and report the charges against Chevron’s financial reserves for environmental cleanup. After yet another unhappy report, I remember one of the executive vice presidents leaning over to ask me, “What would it take to stop this?” My reply was simple: Just keep it in the tanks. Without releases, no cleanup. Small footprint operations save money. And in a time when concern about use of fossil fuels is growing in North America and Western Europe, our past actions affect our social license to continue to operate. Any discussion of environmental issues always brings up the question on global climate change, which is a hot political issue in some, but not all, parts of the world. SPE has commissioned a work group to look into what, if any, position SPE should take on this issue. The task force is charged with identifying what it considers to be the key aspects of climate change and public perceptions of climate change that may impact SPE and our ability to deliver our mission and serve our members’ interests. This does not mean taking a position on whether or not climate change is happening; merely that with the level of public discourse it is prudent for SPE to consider how we may be affected by public perceptions. The task force members have been asked to review what, if anything, analogous professional organizations have done in relation to climate change. They also are expected to develop a strategy for SPE’s reaction in response to the key aspects of climate change, which would best serve, protect, and move forward our mission. By definition, as the Society of Petroleum Engineers, we are pro-fossil fuels. However, environmental pollution should be minimized from all sources, not just those that are politically unpopular, like us. Environmental responsibility means taking responsibility for the entire life cycle of our operations, including the cleanup and repurposing at the end. We can develop our assets sustainably with an eye to the end of life. Sustainable develop-
To contact the SPE President, email president@spe.org.
10
JPT • DECEMBER 2016
ment includes small footprints and full life cycle management of our waste streams. As an industry, we should take responsibility for our impacts. Operators should be held accountable for eventual abandonments. Plugging and abandoning “orphan” wells is a currently hot issue in mature basins. In the United States, the pattern is often that big operators initially drill and produce a field, then the field or well is sold down the food chain to smaller and smaller operators who have lower operating costs and can give vital engineering attention to the low-volume fields. Often, as a well nears its economic life, it may be sold out to a financially unstable operator, and when economics change, the unstable operators go under. The wells are orphaned, sitting idle and unplugged. I believe that if our industry doesn’t develop a workable solution for orphan wells, a solution will be imposed on us. Is public education the answer? We have a strong tide against us. Engineers believe in facts. I believe that if only the public understood how hydraulic fracturing—and other engineering processes—work, they would understand and come over to our side. Sadly, many in the general public are not interested in facts or understanding; they are unlikely to be persuaded by anything that originates with the oil industry. Media outlets tell stories, usually through pictures, and images of big fires, oil spills, or flaming water from faucets tell a story sure to capture public attention. The “facts” often come later, if at all, once the sensationalism dies down. Anti-industry groups created “fracking” with a “k” and have branded it in a way that it gets applied to activities not remotely related to hydraulic fracturing. Our actions, and our interactions with people at the local level, have to speak for us, and that’s where the catastrophes overwhelm our public education efforts. Negative views of the oil industry are not universal—many countries view energy development as progress and increased standards of living. Billions of people around the world want basic energy access—an electrical grid, safe cooking and heating fuels, and efficient transportation. Should they be denied what we have? There will always be people who hate the oil industry but drive an electric car, powered by electricity from coal. We can earn our reputation as responsible citizens who care about the world around us and help raise living standards for people all over the world. The Deepwater Horizon explosion in 2010 was the industry’s worst environmental incident. Earlier this year, BP’s total cost for the Macondo incident was reported as about USD 60 billion, greater than the entire market capitalization of ConocoPhillips, Eni, or Statoil. One incident, one management failure, could wipe out most oil companies. A few months ago, Hollywood released the movie Deepwater Horizon, with a major star and backer, telling the story of the Deepwater Horizon/Macondo accident from the workers’ perspective. I had seen the trailer on YouTube and fully expected to see the usual Hollywood depiction of our industry—redneck rig hands shown drunk and smeared with oil, evil money-hungry management, and everyone as not caring about our employees, the environment, or safety.
JPT • DECEMBER 2016
I was surprised to see that though there is money-grubbing management (portrayed by the perennial villain, actor John Malkovich), the film does a good job of telling the tale from the perspective of the rig workers. The filmmakers got many of the technical aspects of the blowout wrong—for a technical analysis, see SPE Distinguished Member and University of Texas petroleum engineering professor Eric van Ort’s online review at www.theconversation.com. But what the public will remember is the massive explosion, the months-long oil spill, and the perception that we just don’t care. As I walked to my car thinking about the film, I was shaken by the fire and the workers’ terror. But the word that rattled in my head as I drove home was integrity. A key cause of the Macondo accident was lack of true integrity to their stated values of safety and environmental responsibility. If we really believed that safety and environmental stewardship are our top priorities, then we would practice it always. We would praise, not punish, those who hold true to our stated values of integrity. I know that doesn’t always happen, and I have experienced the misalignment between stated corporate goals and actual management behavior. But to be leaders of integrity, we must hold true to our stated values or our industry won’t be here anymore. Our trust must be earned. JPT
Volunteering looks good on you. In the new SPE League of Volunteers, giving back suits you well. As a volunteer for SPE, you provide the energy that makes our Society work. When you join and give back, you are supporting your peers and the future of E&P, as well as enhancing your leadership and collaborative skills, and expanding your professional profile as you showcase your knowledge and talents to the industry. Engage. Support. Contribute. Learn more and join us at www.spe.org/volunteer.
Share your story: #SPElov
11
COMMENTS
EDITORIAL COMMITTEE Bernt Aadnøy, University of Stavanger Syed Ali—Chairperson, Consultant Tayfun Babadagli, University of Alberta
The Supply/Demand Balance John Donnelly, JPT Editor
William Bailey, Schlumberger Mike Berry, Mike Berry Consulting Maria Capello, Kuwait Oil Company Frank Chang, Saudi Aramco Simon Chipperfield, Santos
Layoffs have slowed, some companies posted profits in the third quarter, and there is even talk of a coming oil shortage that would cause oil prices to spike. But there is generally no consensus on what the oil market has in store over the next 1–2 years. At a recent industry gathering in London, Saudi Arabia’s Energy Minister Khalid al-Falih said the market was recovering from its severe 2-year decline, with global supply and demand becoming rebalanced, which will raise oil prices. “We are now at the end of a considerable downturn,” he said. But whether OPEC can reach, or keep, a production agreement is unclear. Although North American unconventional output has been unprecedented over the past few years, OPEC’s course of action over the next year “will define whether the industry will experience a slow and smooth recovery to a sustainable price equilibrium, or a period of underinvestment leading to a volatile and high oil price,” says consultancy Wood Mackenzie. “Even if the recent provisional deal produces minimal results, OPEC Gulf countries will ultimately need to cut production if operators expect prices to recover in the next 3 years.” Third-quarter company earnings were mixed, with some service companies and operators finally posting profits after severely cutting costs. Shell and BP reported third-quarter profits after shedding jobs and slashing expenses, rebounding from 2 years of losses. Both companies said they believe supply and demand are coming back into balance and expressed cautious optimism about 2017. But profits at ExxonMobil, Chevron, Statoil, and other majors were not as positive. Halliburton finally turned the corner on profitability in the quarter but other service companies such as Schlumberger did not. Many oil executives are warning that the lack of investment caused by the downturn will lead to a severe oil supply shortfall in just a few years and, with it, a sharp price increase. That also may suggest that they believe that the oil price recovery will be so gradual that it will not spur any rapid rise in upstream spending. But although upstream investment has fallen sharply, a supply shortage is not necessarily imminent. Much of the upstream spending that has been curtailed, says Amy Myers Jaffe, an energy expert and executive director for energy and sustainability at the University of California at Davis, was from high-cost, frontier projects such as the Arctic. With budgets tight, spending may be directed instead to surer plays such as the Permian Basin in west Texas, with a focus on existing fields, which will lead to first oil production more quickly. Investment continues to flood into the Permian, and the US Geological Survey last month upgraded its reserve estimates for the Wolfcamp shale in the Midland Basin portion of the Permian. If OPEC continues to worry about losing market share and operators become more disciplined in their upstream spending, the shortfall may not materialize. JPT
Alex Crabtree, Hess Corporation Gunnar DeBruijn, Schlumberger Mark Egan, Retired Mark Elkins, Retired Alexandre Emerick, Petrobras Research Center Niall Fleming, Statoil Ted Frankiewicz, SPEC Services Stephen Goodyear, Shell Omer M. Gurpinar, Schlumberger A.G. Guzman-Garcia, Retired Greg Horton, Retired John Hudson, Shell Morten Iversen, Karachaganak Petroleum Leonard Kalfayan, Hess Corporation Thomas Knode, Contek Solutions Sunil Kokal, Saudi Aramco Marc Kuck, Eni US Operating Jesse C. Lee, Schlumberger Douglas Lehr, Baker Hughes Silviu Livescu, Baker Hughes Shouxiang (Mark) Ma, Saudi Aramco John Macpherson, Baker Hughes Graham Mensa-Wilmot, Chevron Stéphane Menand, DrillScan Badrul H. Mohamed Jan, University of Malaya Zillur Rahim, Saudi Aramco Eric Ringle, FMC Technologies Martin Rylance, BP GWO Completions Engineering Robello Samuel, Halliburton Otto L. Santos, Petrobras Luigi A. Saputelli, Frontender Corporation Sally A. Thomas, Retired Win Thornton, BP plc Xiuli Wang, Baker Hughes Mike Weatherl, Well Integrity, LLC Rodney Wetzel, Chevron ETC Scott Wilson, Ryder Scott Company Jonathan Wylde, Clariant Oil Services Robert Ziegler, Weatherford
To contact JPT’s editor, email jdonnelly@spe.org. 12
JPT • DECEMBER 2016
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GUEST EDITORIAL
Assessing the Processes, Tools, and Value of Sharing and Learning From Offshore E&P Safety-Related Data Roland Moreau, ExxonMobil Annuitant In 2014, the US Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE) approached SPE regarding a proposed collaboration opportunity to develop a voluntary industrywide near-miss data-sharing framework. The goal of this framework was envisioned as a resource to enhance the industry’s ability to capture and share key learnings from significant near-miss events with the objective of identifying and mitigating potential high-consequence risks. While the scope of this collaboration initially focused on only near misses, further discussion of the desired outcome resulted in increasing the scope to include a broader range of data that have learning value to help the industry to achieve improved safety performance. Further, in the spirit of continuous improvement, a related objective was identified to bring government and industry together to make a safe industry safer, and to enhance public confidence in the industry. SPE and BSEE agreed to cochair a summit steering committee that included representatives from SPE, BSEE, exploration and production (E&P) operators, service companies, the US Bureau of Transportation Statistics, the Center for Offshore
Safety, American Bureau of Shipping, and the International Association of Oil and Gas Producers. During the planning process of the summit, it was agreed that the scope of a data collection and reporting framework would start with the US Outer Continental Shelf (OCS). Additionally, a secondary objective was to consider how existing processes might be leveraged with an overarching objective to extend influence beyond the US OCS to align with other systems and requirements globally. In considering industry alternatives for developing a safety-data management framework, caution was advised to avoid creating an additional layer of reporting expectations over and above the current requirements by regulators and industry associations. During the summit, Vice Admiral Brian Salerno, the director of BSEE, shared his perspective on the importance of industrywide safety-data collection and sharing. He also encouraged the E&P industry to demonstrate to the public how a safe industry could be made safer through more open data sharing. The discussions, expert opinions, and suggestions offered by the group of safety-data management subject mat-
Roland Moreau, SPE, serves as the Vice President, Finance, on the SPE Board of Directors and recently retired from ExxonMobil after 34 years of service, having spent much of his career in various management, leadership, and technical positions in the production, development, research, and refining business sectors. He served as the Health, Safety, Security, Environment, and Social Responsibility Technical Director on SPE’s Board of Directors from 2011 to 2014. Before joining ExxonMobil, Moreau also worked for 5 years in the naval nuclear industry. He holds a BS degree in mechanical engineering from Worcester Polytechnic Institute and an MBA in finance from Fairleigh Dickinson University. He is currently enrolled in a certified financial planning program at Rice University. Moreau remains active on various SPE initiatives in the HSSE-SR area and serves as chair of the HSE Now (www.spe.org/hsenow) Editorial Advisory Committee.
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ter experts during the summit were captured in a technical report that was posted on the SPE website for comments, then approved by the SPE Board of Directors in September 2016. The report SPE 182847-TR is available to SPE members in OnePetro: https://www.onepetro.org/ general/SPE-182847-TR?_ga=1.114120711 .1050945655.1469542814.
Summit Objectives SPE held the 2-day summit in April 2016 to discuss the opportunities, challenges, and processes needed for developing and implementing an industrywide safety-data sharing framework. The summit objectives were as follows: ◗ Establish a pathway to address opportunities and challenges of industrywide safety-data management processes. ◗ Identify how BSEE and SPE may collaborate to add value to existing and future processes. ◗ Leverage strategic processes (new and existing) to address opportunities and gaps focused on the collection, analysis, and dissemination of data, including major incident and precursor data. ◗ Encourage and facilitate continuous feedback and learning in support of ongoing safety management systems and programs. ◗ Consider how existing processes might be leveraged with an overarching objective to extend influence beyond the US OCS, and align with other systems and requirements globally.
Capturing the Data The steering committee drafted a proposed future state designed to capture
JPT • DECEMBER 2016
Definition and boundaries for barrier testing and inspection failures Data reporting/review/analysis o Precursor data identification o Metadata o Data categories (e.g., causal factors and areas for improvement) o High-consequence events (actual or potential) o Safety-incident classification methodology o Decision for issuing alerts o Cyber security and cyber physical safety Testing and inspection criteria o Define the elements of operation and specify their role in testing and inspection (e.g., well drilling, production) o Define the roles of the stakeholders across the life cycle and their proposed reporting requirements from manufacturer to operator o Clarify requirements to record data on failures regardless of barrier status o Evaluate the benefits of developing a list of reportable failures o
Data and Metadata Definition
Data Collection
Data Quality Control and Analyses
Information Dissemination and Learning
Action ◗
Fig. 1—Safety-data discussion process.
specific data related to health, safety, and environment hazards to enable analyses, learning, and ultimately action to improve barrier integrity and eliminate or reduce the risk of incidents. The proposed future state was also proposed as a voluntary program geared toward learning and was not intended to measure the performance of the E&P industry or a specific company. To help structure the summit discussion, a data process flow chart (Fig. 1) was developed to address the following five topics: 1. What data should be shared? 2. Who should share data and from where? 3. What should be the data collection process? 4. How should the data be reviewed and analyzed? 5. How should learning and action occur? Some of the challenges and boundaries addressed included the following: ◗ Identification of any gaps and subsequent resolution methods ◗ Ensuring confidence that there is a safe data-sharing environment ◗ Discussing the current barriers for providing information ◗ Determining the breadth of safety metrics and of truly critical data for good risk-based management decision making ◗ Addressing voluntary participation, confidentiality, protection from legal discovery, protection of source data, and laws and government regulation
Setting the Context Shared learning from incidents and events that occur in an industry is a key factor in the continual improvement in health, safety, security, and environmental performance. This is particularly important for the prevention and mitigation barriers associated with major hazards. Important aspects of an effective shared learning system explored during the summit were the following:
JPT • DECEMBER 2016
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Identification of prospective valueadded shared data Data collection processes, tools, and responsibilities, including data confidentiality and protection Data review and analysis needs and expectations, including the types of analyses and independent review processes Dissemination of information and learnings, including report quality, publication, and alert framework
Industry and BSEE Next Steps Upon conclusion of the summit, it was agreed that a number of near- and longterm next steps could be undertaken in parallel with the objective of retaining the momentum gained during the summit so that change could be enacted as efficiently and effectively as possible. The following list was provided to facilitate future action. Pilot Program ◗ Pursue a volunteer pilot implementation program with willing operators, service companies, and equipment manufacturers to “test run” a consolidated industrywide safety-data management process based on the results of the summit discussions. ◗ Use pilot program results to determine if the “right” data are being collected to allow for riskbased decision making. Workshops, Summits, Forums Develop a schedule of proposed future summits and technical workshops on specific subtopics that support the technical report, such as, ◗ Data collection and analysis to improve barrier management o Standard industry definitions for hardware and human barriers o Reporting hardware barrier successes
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Networking and Collaboration ◗ Use SPE Technical Sections and other groups, as appropriate, for ongoing networking on safety-data management and risk management. ◗ Establish a data framework and culture (both industry and regulator) that encourages open reporting, protect and secure the identity of the submitters, protect businesssensitive information, and promote sharing of safety-data and learnings. ◗ Leverage SPE’s online publication HSE Now, SPE PetroWiki, and other industry publications to share articles of interest related to improved safety-data management, analysis, and reporting processes. ◗ Assess the benefits of establishing an SPE Technical Section as a global forum to allow members to network on the topic of safety-data sharing. ◗ Seek opportunities to integrate safetydata sharing and related topics into existing SPE workshops, conferences, and training programs. JPT
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TECHNOLOGY APPLICATIONS Chris Carpenter, JPT Technology Editor
Electrical-Submersible-Pump System Baker Hughes introduced the CENtrilift PASS slimline electrical-submersiblepump (ESP) system, designed to help operators optimize production and reserves recovery while lowering lifting costs in small-diameter wellbores or wells with restricted space owing to casing patches or complex completion designs. The system incorporates an extended-range pump that operates at flow rates from 2,500 to 50 B/D, mitigating the need to change out pumping systems as production rates decline (Fig. 1). The pump’s optimized flow path also improves ESP system reliability by preventing solids buildup and abrasive wear in the pump. The system manages gas entrained in the production stream or gas slugs that break out of the reservoir. When the ESP is deployed in a horizontal or deviated orientation, gravity cups shift to block the pump-inlet ports on the high side of the intake where the gas accumulates, preventing the gas from entering the pump and venting it into the annulus. When the ESP is installed in a vertical orientation, the production stream bypasses the gravity cups and mechanical vortex gas-separation technology diverts gas away from the pump and into the annulus. For applications that only require mechanical gas separation, the system includes a vortex gas separator. ◗ For additional information, visit
www.bakerhughes.com.
Dual-Barrier HP/HT Riser System Aquaterra Energy and Plexus Holdings have developed a lightweight, dualbarrier high-pressure/high-temperature
(HP/HT) riser system that can be deployed by a jack-up to enable an alternative to semisubmersible installation for HP/HT well operations (Fig. 2). The technology is suitable for shallow water depths up to 150 m. By uniting Aquaterra Energy’s HP/HT riser system and Plexus’ wellhead-engineering technology, an inner riser string is installed inside a conventional high-pressure riser to span the gap between a drysurface blowout preventer and a wet subsea tree. It provides 20,000-psi capability and uses metal-to-metal gastight seals on both the external and internal riser string. The system also eliminates the issues associated with surface wellhead developments that contain elastomeric seals, particularly those located between the mudline and surface. In comparison with semisubmersible mobile units, new-generation, heavyduty jack-up drilling units can now undertake drilling, completion, intervention, and abandonment activities at lower day rates and reduced risk. Moreover, they can potentially mitigate the heavy loading implications and weather constraints often associated with semisubmersibles. ◗ For additional information, visit
www.aquaterraenergy.com.
Fig. 1—The FLEXPumpER extended-range pump, part of Baker Hughes’ CENtrilift PASS ESP system.
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Fig. 2—Aquaterra Energy and Plexus Holdings’ dual-barrier HP/HT riser system.
Stage-Cementing Tool The Weatherford SwageSet Pack-Off Stage Tool (POST) reduces the risks associated with stage cementing, such as lost circulation and casing-by-casing annular (CCA) gas migration, which are frequently encountered in high-pressure and high-temperature wells. The tool uses a high-temperature-rated, expandable metal and elastomer packer to create an effective, qualified gas-tight barrier between casing strings (Fig. 3). This provides zonal isolation and well integrity and enables proper cementing. When expanded, the packer element forms a seal with a near-zero extrusion gap that is International Organization for Standardization (ISO) 14310 (V0) gas tight and
JPT • DECEMBER 2016
CAMShale FRACTURING FLUID DELIVERY AND FLOWBACK SERVICE
Monoline* flanged-connection fracturing fluid delivery technology reduces installation time by more than 60%, Eagle Ford Shale.
More stages. Less cost. Integrated reliability. The CAMShale* fracturing fluid delivery and flowback service provides seamless delivery of hydraulic fracturing fluid from the pumping service provider’s missile trailer to the wellbore, integrating the entire high-pressure surface completion system through flowback and well testing. An operator in the Eagle Ford Shale reduced hydraulic fracturing costs by approximately USD 2.7 million per month and achieved 100% valve reliability with this integrated service, which uses only Cameron equipment, maintenance programs, work procedures, and a multiskilled crew. Find out more at
cameron.slb.com/CAMShale * Mark of Schlumberger. Š 2016 Schlumberger. All rights reserved. SUR-1232
Fig. 3—Weatherford’s SwageSet Pack-Off Stage Tool.
rated up to 350°F. Additionally, the stagecementing subsection is internally and externally qualified as ISO 14998 (V0) gas tight. The packer element also includes a slip system with hold-down slips that prevent upward movement of the casing after setting, and independent ratchet systems that hold the packer and slips in place. As a result, the risks of packer-element movement inside the casing as well as failure of the casing to support the secondstage cement are reduced. By incorporating V0 gas-tight elements throughout, the tool helps to prevent CCA gas migration, avoid future workovers, and reduce safety and environmental risks. ◗ For additional information, visit
www.weatherford.com.
Fig. 4—Untreated 40/70 sand (left) and 40/70 sand treated with FloPRO proppant (right).
Multifunctional Proppant FloPRO from Preferred Sands is a multifunctional proppant developed to enhance proppant transport for slickwater fluids while improving the hydrocarbon mobility into the proppant pack and reducing respiratory crystalline silica during the operations. By adding small volumes of N2 gas to the proppant-laden slurry, the proppant attaches to the gas bubbles, leading to reduction in apparent specific gravity (Fig. 4). The tailored coating also reduces water blockage, which leads to an increase in the relative permeability to hydrocarbon. Additionally, FloPRO has proved effective in reducing the generation of respirable airborne particles down to 10 to 30 µg/m3 throughout the proppant lifecycle. It was applied in more than 30 fracturing and refracturing treatments in various North American formations. The wells featured a wide range of operational conditions, including low- and high-rate slickwater treatments for vertical and multistagefracturing horizontal wells. The proppant resulted in a 25 to 100% increase in estimated ultimate recoveries, and most wells produced with higher oil cuts compared with the offset wells (some wells showed a 255% increase after producing for more than 200 days). In multistage horizontal refracturing operations,
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Fig. 5—Vertechs’ fully dissolvable WIZARD bridge plug.
FloPRO has led to efficient re-estimation for the toe stages in wells with lateral lengths up to 10,000 ft. ◗ For additional information, visit
www.preferredsands.com.
Dissolvable Bridge Plug Vertechs introduced the WIZARD, its line of fully dissolvable metal bridge plugs (Fig. 5). The plugs are fully customizable to suit specific applications. The packing element, slips, and plug body are 100% dissolvable, thereby reducing health, safety, and environmental concerns. Inserts are available for high casing grades. Dissolvable bridge plugs
with nondissolvable slips can experience debris blockage of the well and resulting nonproductive time. The antipreset feature effectively mitigates any risk in the plug-running phase. The WIZARD uses layer-molding technology to control rate of dissolving (ROD) and surface hardness. According to the downhole environment (for example, downhole fluid type, salinity, and temperature), a dissolvable metal with a specific ROD can be selected. Successful pressure tests of the plugs have been conducted for 368 minutes at 250°F and 10,000 psi. JPT ◗ For additional information, visit
www.vertechs.com.
JPT • DECEMBER 2016
TECHNOLOGY UPDATE
New Method Adds Value to Wolfcamp Porosity, Organic-Matter Measurements Joel Walls, Ingrain, Tiffany Rider, Ingrain; and Stephanie Perry, Anadarko
A new technique that analyzes scanning electron microscope (SEM) images of formation samples has been used to measure porosity and total organic carbon (TOC) in the Wolfcamp Shale of the Delaware Basin in west Texas. The technique’s application has led to methods and findings that can be used to ◗ Determine oil-in-place values, which are a key factor in enhanced oil recovery and reserves determinations ◗ Improve petrophysical models for log interpretation
(a)
Better understand submicron porosity in mudstones and other tight samples In particular, the technique was able to identify where the porosity was hosted and quantify the porosity in organic matter (OM), which cannot be specifically determined by standard laboratory methods. The technique was successfully demonstrated in a project undertaken by Anadarko and Ingrain that compared SEM-image porosity and OM content with standard helium porosity and TOC data from pyrolysis. ◗
Tests were conducted on as-received plug sample end trims. Solid OM, porosity, and porosity associated with OM (PAOM) were computed from the SEM images. These values have been compared with pyrolysis-based TOC, bulk volume (BV) oil, and total porosity as determined using the Gas Research Institute (GRI) method.
Case Study Focus, Methods The case study focuses on stratigraphy that is dominated by microporosity, with permeability ranging from nanodarcies to millidarcies, and is related to
(b)
Fig. 1—(a) One of 10 SE2 images per sample. (b) The same image is shown with color shading for OM (green), PAOM (blue), and mineral-associated porosity (red). Source: Ingrain.
JPT • DECEMBER 2016
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3
(a)
12
(b)
2.5
10 2
BV Oil (vol%)
Dry-Helium Porosity (% of BV)
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8 y=1.9647x−0.1694 6
R2=0.9123
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SEM-Image Porosity, Clay Corrected (vol%)
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Fig. 2—(a) A crossplot of clay-corrected SEM porosity compared with dry-helium porosity. (b) SEM-image PAOM from as-received plug samples, compared with GRI BV oil from as-received plug samples. Source: Ingrain.
the deposition of argillaceous, siliceousdominated turbiditic sequences (diagenetic overprinting). The stratigraphy includes carbonaceous-dominated basal debris flows in a variable slope to basin setting through time. The project consisted of 42 as-received 1-in.-diameter plug sample end trims. Archimedes bulk density was measured on as-received samples. To aid with subsample selection for SEM imaging, five X-ray fluorescence (XRF) measurements were acquired along the vertical axis of the plug end trim, perpendicular to bedding. Bulk TOC and mineralogy were computed from homogenized powder, using Fourier Transform Infrared Spectroscopy (FTIR). All SEM subsamples were polished with an argon-ion-beam milling system. Images of the polished areas, approximately 1 mm by 0.5 mm, were captured using a SEM secondary electron (SE2) detector at a resolution of 250 nanometers (nm) per pixel. Next, a series of images at a resolution of 10 nm per pixel were acquired simultaneously, using SE2 and back-scatter electron detectors. Both types of images are required for accurate quantitative analysis. These SEM images were acquired perpendicular to bedding, along the vertical axis. Representative samples were also imaged at 5.0 nm and
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2.5 nm resolution. Most of the additional porosity detected by the higher resolution images was found to be associated with OM. The multiple resolution images were used to compute final OM and porosity values. The porosity was further analyzed and separated into PAOM and mineral-associated porosity (intergranular plus intragranular). Fig. 1a shows an example of a 10-nmresolution SE2 image from one sample. Fig. 1b shows the same image with colors indicating OM, PAOM, and mineralassociated porosity.
Results LECO1 is a traditional pyrolysis-based lab method that measures TOC. LECO TOC in weight% was multiplied by 2 for comparison to SEM OM content in volume%. The exact ratio depends on OM composition, maturity, and bulk rock density and could be lower or higher than 2 for any sample. In general, there was good agreement between the LECO TOC and the SEM-image-based OM content. Similar results have been reported for Eagle Ford shale samples by Capsan and Sanchez-Ramirez (URTEC 2461642). The porosity observed from SEMimage analysis was lower than dryhelium porosity for most samples, and
the difference was greater for samples with higher clay content. Also observed was a direct correlation between BV water (from Dean-Stark extraction on preserved samples) and the clay volume (from XRF and FTIR). A crossplot of these two values has a near-zero intercept, which suggests that most of the water is associated with the clay. Preserved samples with no clay had essentially zero water content. The data also shows that half or more of the dryhelium pore volume is clay-associated water in the preserved samples. A conclusion can be drawn from the correlation between BV water and clay content that clay-bound-water (CBW) porosity can be determined directly from the dry-clay volume. For these samples, the relationship is approximately “CBW porosity is equal to total clay volume times 0.2.” The CBW porosity was computed for each sample, using this relationship, and was added to the SEM-image porosity. The results seen in Fig. 2a showed similar values to dryhelium porosity.
1An
acronym for Laboratory Equipment Corporation, manufacturer of the carbon analysis instrument used in this TOC measurement application.
JPT • DECEMBER 2016
The PAOM from as-received plug samples compared well with GRI BV oil, suggesting that most oil is held in the organic pores and that most of the organic porosity was resolved and quantified (Fig. 2b).
Discussion Clay minerals in-situ are always associated with a considerable quantity of water. This water takes two main forms, adsorbed and internal. The internal water is very tightly bound between the clay platelets and is not removed by the standard lab cleaning and drying procedures, such as Dean-Stark extraction. The water adsorbed on the outer surfaces of the clay particles is removed during Dean-Stark extraction and is counted as part of the total pore space, along with any capillary-bound or free water. Different clay species hold different amounts of adsorbed water. For example, smectite will bind 50 times more water on its surface per gram of clay than kaolinite (SPE 131350). Chitale (AAPG Search and Discovery 40487) published a summary of the apparent “clay porosity” for four clay types, kaolinite, chlorite, illite, and smectite. These values provide a means to compute the CBW porosity in shales, assuming that the volume fractions of the four clays are known. The CBW cannot be resolved from SEM images and is counted as part of the clay mineral volume, not as part of the porosity. Therefore, the SEM porosity can be considered as porosity available for free water or hydrocarbons. Clay in these samples is about 25% smectite and 75% illite with small amounts of chlorite and kaolinite, as determined by FTIR. The weighted average CBW porosity is equal to about 0.21 times total clay volume, using Chitale’s published clay porosity for different clay species. This agrees quite well with the value of 0.20 from the slope of BV water vs. total clay. The computed CBW porosity, when added to porosity from SEM imaging, gives an approximate total porosity that compares favor-
JPT • DECEMBER 2016
ably with helium (GRI) total porosity (Fig. 2a).
Conclusions For the Wolfcamp formation samples studied, the following are observed: ◗ There is good agreement between traditional pyrolysis-based LECO TOC and the SEM-image-based OM content. ◗ The porosity observed from SEM-image analysis is lower than dry-helium porosity for most samples, and the difference is greater for samples with higher clay content. ◗ SEM images do not resolve the CBW, so it is counted as part of the clay mineral volume and not part of the porosity. ◗ There is a direct correlation between BV water and the clay volume. ◗ CBW porosity can be computed directly from the dry-clay volume. ◗ SEM-image porosity is comparable to oil-filled porosity. ◗ The computed CBW porosity was added to SEM-image porosity. The results were in close agreement with GRI total porosity. JPT
References AAPG Search and Discovery 40487 Simplified and More Accurate Clay Typing Enhances the Value Added by Petrophysical Evaluation of Shale and Tight Gas Sand Plays by V.D. Chitale. SPE 131350 From Oil-Prone Source Rock to Gas-Producing Shale Reservoir—Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs by Q. Passey, K. Bohacs, and W. Esch et al. URTEC 2461642 Using Core Data, Digital Rocks, and Source Rock Kinetics To Reduce Hydrocarbon Storage Uncertainty in Unconventional Reservoirs: Application to South Texas Organic Rich Mudstones by J. Capsan and J. Sanchez-Ramirez.
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E&P NOTES
Calculating Reserve Estimates Even for Solar Power Projects Stephen Rassenfoss, JPT Emerging Technology Senior Editor
Compared to oil in the ground, the sun looks like a limitless energy source. Making comparisons of the two by calculating the equivalent of barrels of reserves for a solar project seems like an odd notion. But experts in reserves accounting say that it can and should be done, and are working on a way to do so. An arm of the United Nations (UN), with support from SPE, is working to adapt the system now used to track reserves of oil and minerals in the ground to apply to renewable power sources such as the wind and the sun as part of a long-term effort to cover other sources of energy. “Until now there was not a framework for the solar industry to make decisions similar to what we do for oilfield development,” said David MacDonald, the chair of the UN group leading the effort. He said they are “working on ways to compare renewables and nonrenewables.” While MacDonald is vice president of segment reserves at BP, when he presented a paper (SPE 181623) about the project at the SPE Annual Technical Conference and Exhibition in Dubai he was speaking as the chair of the UN Econom-
ics Commission for Europe Expert Group on Reserves Classification. It is working with the SPE Oil & Gas Reserves Committee, of which he is a former member. What makes this leap possible is the fact that energy does not produce itself. Whether it is oil or wind, money, equipment, and brainpower are required to turn a natural resource into a marketable energy product. These projects have an estimated capacity and lifespan, the value of what they produce varies over time, and there is a significant degree of uncertainty about how things will play out. Just as importantly, MacDonald said there is a need. A renewable reserve estimate would allow an investor with a diversified portfolio of energy assets to compare fuel and renewable energy holdings, or an economic minister could account for the capacity of the country’s energy infrastructure and weigh the economics of alternatives. A report by the Solar Energy Industries Association acknowledges that “the valuation of solar energy projects is a complex subject and is a source of tension
A renewable reserve estimate would allow an investor with a diversified portfolio of energy assets to compare fuel and renewable energy holdings. Source: Texas A&M Engineering Extension Service.
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between regulators, developers, and debt and equity investors.” The renewable project is not really aimed at answering that question. Its goal is to create a bridge between different energy sources with a calculation that compares their productive capacity. The UN Framework Classification (UNFC), which was used initially for oil reserves and mineral valuations, has been extended to biofuels, geothermal, and nuclear power. A government committed to reducing carbon emissions may be willing to pay a premium for green energy, but could use the reserve calculation to evaluate if a proposal offered the energy needed to grow, and estimate the likelihood of a proposed development delivering on what was promised. The UN system is closely related to the Petroleum Resources Management System (PRMS) developed by the SPE Oil and Gas Reserves Committee, which is among the industry groups that has supported the UN program. “The UNFC and PRMS reserve reporting systems are aligned closely and will likely align even more closely with the next revision of the SPE reserve system,” MacDonald said. They share a goal of making it possible to compare energy resources in a world where there are many reserve accounting systems reflecting differing development histories and views on how best to regulate and manage resources. Both the UN and SPE systems make estimates based on a project analysis, whether that effort is aimed at developing an oil field or an array of wind turbines. While a reserve estimate brings to mind oil in the ground, the reserve calculation is really a measure of how much oil
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can be produced based on a range of factors, beginning with what is technically possible to what price it is likely to command on the market. Renewable project reserves will also be based on what nature offers, as seen on maps showing the prevailing winds or the average amount of sunlight in an area, and the capacity of the equipment installed over its expected lifespan, adjusted for a range of factors that are uncertain. A lot of the calculations come back to what is “economically viable.” While the simplest measure is whether the project can generate a big enough profit to justify the investment, it also depends on what is politically and environmentally acceptable. The UN group recently completed a document determining the specifications for the renewables project. Its goal is to
create a bridging document to deal with significant differences when calculating a comparable measure. For example, solar and wind are typically used to generate kW-hr of power, which can be converted into the energy equivalent of a barrel of oil, but is harder to store than crude oil. Uncertainty is also a significant element in renewables projects as it is for fossil fuels. Even with the best diagnostic tools, reservoir performance can veer from what has been predicted as can the performance of solar panels. Both require dealing with fluctuating financial and energy markets as well as unpredictable shifts in regulations and environmental concerns. Like oil reserve estimates, these projects can be classed based on the level of uncertainty, from nearly sure things, often called proven reserves, all the way
to early stage developments lacking financial backing, which are similar to recent discoveries with no development plan in place. This detailed thought process can highlight the strengths and weaknesses of a project before “a decision is made on whether or not to go forward,” MacDonald said.
For Further Reading SPE 181623 UNFC: Expanding the Influence of PRMS Beyond Petroleum by D. MacDonald, BP et al. https://www. onepetro.org/search?q=SPE+181623+&peer_ reviewed=&published_between=&from_ year=&to_year=&rows=10 Valuation of Solar Assets. 2013. Solar Energy Industries Association. http://www.seia. org/sites/default/files/Valuation-of-SolarGeneration-Assets.pdf
Oil Market Surplus Could Grow in 2017 Joel Parshall, JPT Features Editor Surplus production in the oil markets is likely to grow in 2017, and long-term oil prices will track with costs and not revert to the margin-inflated patterns of the shale boom. These were the separate conclusions of two energy economists and market analysts who spoke on oil, gas, and geopolitics at the Deloitte Oil & Gas Conference held in September in Houston. “Rebalancing is maybe a little further away than we would have all liked it to be,” said David Knapp, chief energy economist and senior editor for global oil market analysis at the Energy Intelligence Group. “We think there was still a surplus in the third quarter,” he said. “A number of the other agencies, OPEC, IEA [the International Energy Agency], EIA [the US Energy Information Administration] don’t agree with that. And even more negatively for the price, we see those surpluses continuing into next year. So rebalancing later rather than sooner. Lower for longer and longer and longer, maybe, as some would say.” Kenneth Medlock, energy and resource economics fellow at Rice University’s Baker Institute for Public Policy
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and senior director at the school’s Center for Energy Studies, called attention to oil price and cost patterns that have held generally since the 1960s.
Costs, Prices Normally Linked “One thing that’s remarkable that you see is costs tend to move very, very well with price,” he said. “There is only one period in history where in per-barrel terms those costs disconnected. That’s from 2010 to 2014. What did we see? We actually saw massive rent matriculating to the upstream sector … the amount of capital that was flowing into the upstream, rig utilization rates over 92%, things that had never happened before.” That trend, which corresponded with the North American shale oil boom, was “not sustainable,” Medlock said. Demand growth in response to lower oil prices has been “disappointing,” Knapp said, citing the negative effect of the stronger US dollar and the withdrawals of consumer fuel subsidies by financially strained oil-producing countries. Noting the September reports of OPEC, IEA, and EIA, along with his own analysis, he said, “Now there are three of us
who see surpluses coming back in 2017 and one [EIA] that doesn’t.” Knapp pointed to the shale oil expansion in the US, rather than OPEC policy, as the direct cause of the oil price decline that began in 2014.
Saudis’ New Thinking Saudi Arabia’s long-range thinking about its oil reserves has changed, reflected by the influence of Deputy Crown Prince Mohammad bin Salman and the kingdom’s Vision 2030 blueprint, Knapp said. The plan to launch an initial public offering (IPO) for a portion of Saudi Aramco is part of the change, as is the kingdom’s perception that a long-term global policy and political shift against oil and fossil fuels has become more likely in the wake of the 2015 Paris climate agreement. Any Saudi support for oil prices will be driven by the short-term goal of enhancing the IPO valuation, Knapp said. “Saudi Arabia is worried about being remembered as the country with the largest stranded asset in the history of the world, and that’s what the problem might be,” he said. “Well, what do they
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do about it? They produce as hard as they can, as fast as they can. Once the IPO is over, I think you’re going to see [the] Ghawar [field] produce way over its maximum efficient rate.”
Global Energy Demographics Medlock analyzed global energy markets demographically, noting that the world population of 7.4 billion people can be divided into 1.3 billion people in developed countries, 4.8 billion people in the developing world, and 1.3 billion people in places with little development who live
in energy poverty (a lack of household access to electricity). Future energy market growth will be tied to demand growth driven by the 6.1 billion people in societies that are economically developing or advancing out of energy poverty. “When you’re talking about development for 6.1 billion people, that’s something that the world has not ever seen,” Medlock said. Energy policy in the developed countries and their shift toward renewable energy sources such as solar and wind, which chiefly fill residential and com-
mercial uses, are minor factors in the global energy market. “Economic development is not built on the back of residential and commercial demand,” Medlock said. “It is built on the back of industrial growth. That is a different scale.” Industrial processes require high-density energy sources, he noted, and this ensures a continuing demand for oil, gas, coal, and nuclear energy. In the coming 15 to 20 years, “oil and gas is going to play a major role in meeting the projected energy demand,” Medlock said.
Developing Countries Will Lead Energy Demand Growth Joel Parshall, JPT Features Editor The world’s developing countries will lead economic growth and consume an increasing share of energy production globally over the next quarter-century, said Rob Gardner, manager of economics in corporate strategic planning at ExxonMobil at the Deloitte Oil & Gas Conference in Houston. For his presentation, Gardner drew data and analysis from The Outlook for Energy, A View to 2040, a report published by ExxonMobil (www.exxonmobil. com/energyoutlook). “We see economic growth shifting to larger than 50% shares in the developing world,” Gardner said. Energy demand is expected to grow by 25% from its 2014 level by 2040, and “roughly 50% of world energy demand will be consumed in 12 countries,” he said. Those countries are China, India, Brazil, Egypt, Indonesia, Iran, Mexico, Nigeria, Saudi Arabia, South Africa, Turkey, and Thailand.
Oil Remains Primary
Carbon Intensity Falls by Half
Oil will remain the world’s primary fuel through 2040, although changing little as a percentage of the global energy mix, Gardner said. The use of natural gas will grow more than that of any other energy source, driven especially by growth in the electric power generation and industrial sectors, while coal’s share of the energy mix will decline. Smaller growth will occur in the use of nuclear power and renewable energy sources. Oil and gas will represent between 55% and 60% of the energy mix over this span, he said. The developed countries, those of the Organization for Economic Cooperation and Development (OECD), will continue to grow economically but use less energy because of efficiency gains and will become less carbon-intensive because of a changing energy mix, Gardner said.
Worldwide, carbon emissions will peak and plateau in this period while beginning to decline in the OECD countries, and global carbon intensity will fall by half, he said. Global oil supply will grow by 20% to approximately 112 million B/D by 2040, with North America, Russia, Saudi Arabia, and Iraq playing major roles, Gardner said. “What we’ve seen, though, over the last decade plus is a real transition away from what we would consider the conventional supply type, the conventional crude and condensate,” he said. “NGLs [natural gas liquids], tight oil, deep water, oil sands, that’s where a lot of the future supply is going to come from that we’re going to need to operate with globally. The world is in a period of abundance, so there is a significant supply source that we’re drawing on.”
Moving Closer to True Picture of the Fugitive Methane Problem Trent Jacobs, JPT Senior Technology Writer The US shale sector has proudly touted the fact that it has helped reduce the nation’s carbon dioxide output to an 18-year low by producing the natural gas that is displacing coal use in power generation. But if government regulators and some environmental groups are applauding the
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transition from the most carbon-intensive fuel source to the least, they are holding back on a standing ovation. The reason is that a raft of scientific studies published over the past few years shows that too much natural gas is being lost into the atmosphere at differ-
ent points all along the supply chain— potentially canceling out the climate benefits of utilizing gas over coal. But environmental researchers and industry alike have had trouble defining the true scope of this problem, termed fugitive methane emissions, because
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A valve station on a natural gas pipeline in the Marcellus Shale of Pennsylvania. Researchers in the US may be approaching a solution for determining how much natural gas is seeping into the atmosphere. Source: Getty Images.
of the disparity in data gathered from oil and gas sites through aerial flybys vs. surface observations. These are, respectively, known as top-down and bottom-up measurements. As a percentage of gross production, bottom-up studies show methane losses may average around 1.5% while estimates from top-down studies range anywhere from 2% to 17%. The goal for a number of producers is to get those numbers down to less than 1% in order to mitigate the negative impacts of methane, which is at least 25 times more effective at trapping heat in the atmosphere than carbon dioxide.
Potential ‘Breakthrough’ Karen Olson, the director of strategic solutions at Southwestern Energy, the third-largest producer of natural gas in the US, announced that researchers may be close to reconciling top-down and bottom-up measurements earlier this month at a workshop organized by the International Energy Agency in Austin, Texas. Without elaborating, she told attendees, “We’ve actually had a breakthrough and now have a correlation based on actual measurements from onsite vs. the flybys.”
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Olson was presumably referencing a new “peak emissions” hypothesis that emerged from a multimillion-dollar methane emissions study funded by the Research Partnership to Secure Energy for America (RPSEA). Southwestern along with three other operators participated in the project, which was led by researchers from the Colorado State University and the National Oceanic and Atmospheric Administration. The full findings are expected to remain unpublished until early next year, but the hypothesis contends that the emissions averages generated using aerial data are higher because they are based on methane that was emitted during short-lived events that took place in the morning. These episodic bursts of emissions are believed to occur as the morning shift arrives to start up or adjust production equipment. So while aerial measurements may be accurate, this new concept suggests that to get a truer average of daily emissions rates, the temporary nature of these morning events must be fully understood and taken into account. If this idea holds up, then it could be an important factor in determining how the industry and other groups look at top-
down and bottom-up data in the future. It may also mean that the experts can go back to all the data already gathered to see if they now tell a more accurate story.
Too Many Measuring Methods Desikan Sundararajan, a senior researcher of environmental management at Statoil, highlighted in his remarks at the workshop what life as a scientist working on this problem has been like without such a correlation. He found that there are more than 300 research papers on the subject of fugitive methane emissions and said “the beauty of it is that not a one of them agrees with each other.” Sundararajan explained that one of the reasons for the disparity between a number of top-down studies has been that the researchers are using too many different instruments to take measurements; typically the ones they are most familiar with. There is also an apparent tendency amongst the researchers in this area to be the first to publish a new, first-of-itskind approach, he added. “That does not help the industry, it does not help the stakeholders or the policy makers,” Sundararajan said, stressing that there needs to be more congruence with how methane emission data are gathered.
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Iran Opens Field Investment to Global Bidders Joel Parshall, JPT Features Editor Iran’s national oil company is offering investment opportunities in 50 fields to global bidders, its first effort to do so since the 2015 pact with world powers that lifted nuclear-related sanctions against the country. Following an announcement by the Petroleum Ministry on 16 October that it would invite foreign companies to bid on field projects, the ministry the next day disclosed that 29 oil fields and 21 gas fields would be offered for bidding. International companies were given a 19 November deadline to submit applications, and the announcement of companies that qualify for bidding is slated for 7 December. The bid round is expected to open in January or February of next year. Iran’s objective is to attract between USD 70 billion and 100 billion in foreign investment in its upstream oil and gas sector, and the country hopes to raise between USD 20 billion and 30 billion of that from the initial group of fields it has listed.
10 to 15 Priority Fields It is unlikely that all 50 fields will be tendered at once. “Practically, NIOC [the National Iranian Oil Company] does not have the contracting personnel to handle the bid process, the negotiation, and
execution of all 50 projects at the same time,” said Syd Nejad, chief executive officer and managing partner at NAFT Energy. “We expect a group of 10 to 15 high-priority fields to be tendered in the first round.” Nonetheless, the qualification process now under way will likely clear qualifying companies to bid on the remainder of the 50 projects as they are offered in subsequent rounds, Nejad said. Iran is giving priority to borderarea fields jointly operated with other countries. Production at these fields fell when international sanctions were imposed on Iran in 2011–2012, and NIOC believes that these fields can be returned to higher production relatively quickly. An example is the West Karoun fields that straddle the Iran-Iraq border. Iraq has fast-tracked development at the fields, which have provided more than half of the country’s increased production over the last 7 years. Another priority is the South Pars gas field, where Iran hopes to boost gas and condensate production to the levels achieved by Qatar on its side of the border. The field’s oil layer is yielding 300,000 B/D of production for Qatar but is still undeveloped in Iran.
Iran Petroleum Contract The field projects that Iran announced would be offered for foreign investment are expected to fall under the Iran Petroleum Contract framework that the government approved in August. Operating companies would bear all capital expenditures (capex) up to first or targeted incremental production and recover costs from production proceeds going forward, with up to 50% of oil production and 75% of gas production allocated for cost recovery. From 1995 to 2010, Iran operated under a buy-back contract system in which operators’ exploration and production capex were considered a loan to the state. After achieving first or targeted incremental production, operators were compensated by government annuity payments over the life of the field. Of the international companies believed to be applying for bidding qualifications following Iran’s latest announcement, many were active in the country between 1995 and 2010. Companies in this category include Shell, Total, Eni, Statoil, CNPC, Lukoil, and others, Nejad said. A number of newcomers are also believed to be submitting applications, including Petronas, Petrobras, Pertamina, Maersk Oil, Petro SA, and Repsol, he said.
Extending the Life and Performance of Drillpipe With Wear Band Technology Trent Jacobs, JPT Senior Technology Writer Drillpipe doesn’t last forever, but a Houston-area startup company says it has developed a way to make it last significantly longer. WhiteHorse Technology calls its service product wear bands, which is an adaptation of a technology invented in the 1930s called hardbanding. Hardbanding is a welding process that is still used today to protect steel tool joints from excessive wear and tear by coating them with a sacrificial metal material.
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Wear bands are different in that instead of being welded, they are applied with a lower-temperature thermal spray system. This makes it possible to add a protective layer of metallic coating to the midsection of a drilling pipe without negatively impacting its metallurgic properties—an application breakthrough that WhiteHorse claims no other firm does. The company reports that its wearbanded pipe experiences lower downhole friction and also allows for a greater
weight-on-bit to be used, which results in faster drilling speeds. Wear bands are also set apart from hardbanding in that the latter technology typically is used to apply a relatively thin layer of protective coating. “But what we discovered is that you can continue to make passes, maybe 100 or 200, and build things into different shapes, forms, and thicknesses,” said Karma Slusarchuk, the founder and chief executive officer of WhiteHorse.
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She explained that by building cylinder-shaped bands around the middle of a pipe, its service life can be extended to at least 2 years, and up to 5 years in less-abrasive formations. By comparison, Slusarchuk said it’s common for drillpipe to survive less than a year in horizontal drilling where gravity pulls the middle of each pipe section down a few inches, enough for it to make contact with the formation or the casing. As the pipe turns or is tripped out, that sagging portion will eventually erode to the point where it cannot be used again. Most operators rent their pipe, but when a section is rejected due to wear, they are typically charged the full price for a replacement. And while drillpipe costs can fluctuate, WhiteHorse has priced its wear band treatment to be below what most operators pay for replacements. The tool of the trade for the company is a thermal spray system that simultaneously creates four wear bands around the pipe using a high-strength iron material called HH-1. The process begins by feeding two HH-1 wires into an arc-welder which melts the material on contact. As the pipe rotates on a lay, compressed-air guns send atomized specs of the molten metal flying onto it. In a few minutes, the pipe is cool to the touch and ready to be hauled out to the rig. Each wear band’s peak is about an eighth of an inch high, a foot wide, and separated by another foot—providing up to 8 ft of protection and friction reduction. WhiteHorse says its HH-1-coated pipe has been run in and out of more than 500,000 ft of wellbore in North Dakota’s Bakken Shale. The company’s primary client there is XTO, ExxonMobil’s shale subsidiary. Slusarchuk said the shale driller has leveraged the coated pipe’s lubricity property to reduce its lateral section drilling time from 6 days to 4 days. And since the HH-1 material reduces torque and drag, the drillers have been able to turn the bit much faster, accelerating from an average of 170 rev/min to 240 rev/min. “And the only change they made was in adding the bands,” Slusarchuk said. How WhiteHorse acquired the patent rights to this technology also explains
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A section of drillpipe undergoes a thermal spray treatment to create protective and friction-reducing wear bands. Source: WhiteHorse Technology.
A worker moving a treated drillpipe with four raised wear bands. Source: WhiteHorse Technologies.
how XTO became its first client. A company called WearSox is the original developer of this thermal spray technology which it used to protect drillpipe for ExxonMobil’s record-breaking extended reach drilling program in Sakhalin Island, Russia. Slusarchuk was a drilling engineer with ExxonMobil on that project and eventually became a consultant with WearSox. Realizing there was an opportunity to redeploy the technology for shale producers, Slusarchuk founded WhiteHorse and was granted exclusive rights to the technology by WearSox, which opted to turn its focus to wear-banding centralizers used in offshore drilling operations. Because of her prior relationship with XTO’s parent company and its familiarity
with the technology, the shale producer was quick to adopt wear-banded pipe for its drilling operations in North Dakota. “They took a risk with us and are now squeezing every dollar out of it,” Slusarchuk said. She added that her clients will start saving on transportation costs as WhiteHorse completes the move of its fabrication operations from Houston to North Dakota. WhiteHorse also is researching how it can use its technology to build drilling motor stabilizers which would give drillers greater control in thin pay zones. If the company can produce a stabilizer that survives 50 hours of drilling, it expects to enter into a partnership with one of the major service companies. JPT
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Pores to Predictions Nanoscale Clues to Larger Mysteries Stephen Rassenfoss, JPT Emerging Technology Senior Editor
T
he story of unconventional oil and gas technology development has been focused on fractures. The formula has been more stages, more sand, and more water, targeting the most productive spots. The trend continues, with rising production and larger completions at a time when the oil price bust has slashed the cost of services and supplies. Even so, production from unconventional wells leaves 90% of the oil in the ground, raising the question, what is next? Some have taken on the daunting task of trying to understand how oil and gas flows out of the tiny pores in ultratight rock that feed the fractures flowing to the well. Compared to what it takes to effectively fracture rock and target sweet spots, the science behind fluid and gas flows through pore networks is a difficult slog deep into the unknown. It is a frustrating search, but that is where the oil is. “The first part of the problem is that people started to say that oil and gas is stored in the fractures and that by fracturing a well you are simply exploiting that storage event,” said Richard MacDonald, the innovation, strategy and execution manager for EP Energy, which
is among the companies looking deeper (Fig. 1). “We calculated what fractures will hold and that volume will last only a week or week-and-a-half of production. After 2 weeks, where is the oil from? The matrix.” The matrix is a frontier, like the unexplored lands shown in maps made centuries ago during the era of exploration when those vast uncharted spaces spawned fantastic tales. These explorers are looking at explanations for production patterns that diverge from what they know. “It is not something they taught us in school,” said Steve Jones, reservoir engineering advisor for Cimarex. “We are learning, figuring out what are the facts of life and the ground rules, the theory.” Based on his experience at Newfield Exploration, he delivered a technical paper at the recent Unconventional Resources Technology Conference (URTEC 2460396) explaining why changes in the gas/oil ratio (GOR) produced from certain unconventional wells, which would be alarming in a conventional field, are the norm in the unconventional plays he saw in Oklahoma (Fig. 2). Jones is among those working on field-scale problems. Others are doing pore-scale studies on this ultratight rock
where standard terms such as reservoir and transient seem an odd fit based on the established definitions. While an online dictionary defines a reservoir as a place where fluid collects, especially in rock strata, it offers a poor mental image of unconventional rock. There the oil in the rocks is scattered throughout pore networks with openings ranging in size from a large virus down to just a bit bigger than a DNA molecule. Spaces at the low end of the range are so confined they can alter the physical properties that control production, particularly the bubblepoint—the pressure at which the gas in oil escapes from the liquid. The definition of transient is a good fit for the rapid pressure changes that can occur in a conventional reservoir. But in the ultratight rock of an unconventional reservoir, this transient state is the opposite of fleeting. It can last decades and span the productive life of the well. “The difference is that in a higherpermeability (conventional) reservoir, the pressure is the same throughout the reservoir at any given time. It will take a few days for the pressure to stabilize a quarter-mile from the well,” Jones said. “In real tight reservoirs, it takes months
Fig. 1—The left image shows a network of oil (orange) containing dissolved gas. Production begins when gas begins coming out of solution, squeezing out oil molecules, and ends when all the gas (yellow) has left the remaining liquid (red). Source: EP Energy.
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Looking Deeper While academic researchers grapple with questions that could easily span a career, exploration and production teams in companies such as EP Energy need to identify ideas that can pay off in the near term. After years of slashing costs, the best option for producing more is to apply brainpower to find ways to get more oil out of the ground. When drilling was booming, it made economic sense to vary how wells were drilled and completed to see which changes correlated to better results.
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or even years for the pressure wave to get out even 100 feet.” Understanding how things work at pore scale is also a slow-moving process. Jones’ paper drew on the work of Chris Clarkson, a professor at the University of Calgary, who has written a series of papers in recent years about practical applications in developing unconventional wells. “What are the fundamental controls on flow and fluid storage in these rocks? We have a lot to learn,” Clarkson said, adding: “Our research group is trying to do this, and importantly, to marry field observations with experimental observations and theoretical studies.” The task is doubly difficult because these plays are so inconsistent. Production decline rates have been described as “decays in random disordered, chaotic, heterogeneous systems,” in the work of two petroleum engineering professors at Texas A&M University, Peter Valkó and Tom Blasingame. The phrase is an apt definition for widely varying formations. For example, a presentation by Blasingame offered three models of flow with equations mixing a traditional one for permeable spaces (Darcy) with ones used to describe diffusion (Knudsen and Klinkenberg). The formulas are evolving as more is learned. “They need models supported by lab experiments,” said Deepak Devegowda, an associate professor of petroleum engineering at the University of Oklahoma, who has studied flow equations as part of his work on modeling. “I think there is value. That value will be realized a few years down the line.”
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Fig. 2—The gas/oil ratio (GOR) in the conventional well (top) rises steadily over time, while in the unconventional well (bottom), it surges early, plateaus, and finally begins rising when production reaches the boundary of the productive rock. Source: URTEC paper 2460396.
But the drilling boom has passed and is not expected to return soon. Companies such as EP are turning to digital tools to test designs and ideas on a limited budget, whether it is for a completion or a research project. Initially, EP used statistics-based analysis from its drilling and deductive reasoning to understand how incremental improvements in well placement or fracturing designs correlated to well productivity. Now, with less drilling data to feed into analytics programs, it is looking for bigger gains through a better understanding of the physics that govern the flow of oil at the nanoscale pore to identify the cause of things. “At USD 100/bbl, price correlation works; at USD 40/bbl, causality is needed,” said Steve Geetan, geoscience advisor for EP Energy.
Proving that requires a digital simulator for experiments that show the dynamic behavior of fluids in nanopores. Digital testing offers a way to learn quicker, fail cheaper, and identify which working hypotheses are worth a field test. Since no simulator was readily available, the company developed its own in a process described in a recent technical paper (URTEC 2461115). It already had 3D microscale models of rock samples from one of the company’s unconventional wells on hand, showing a maze of pores that looked like capillaries circulating blood. But a way to simulate how gas and fluids behave when interacting within those constricted passages was lacking. There are many variables to consider. ◗ There are different pore types— organic pores holding kerogen that can produce oil and gas, and
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inorganic ones holding gas, oil, or water. ◗ The chemistry of the pore walls differs. Organic pore walls are thought to attract oil (oil-wet) while inorganic ones attract water (water-wet). ◗ The passages include a range of shapes and sizes with many spots so tight that quantum mechanics applies. “Geometry matters. The shape and walls of the pores are dominating how the system behaves,” Geetan said. “The nature and shape of organic and inorganic pores determine what they can hold or what they will release.” MacDonald and Geetan found a way forward when they met Denis Klemin, a senior digital rock engineer from Schlumberger’s Moscow Research Center, who coauthored the URTEC paper. After they discussed the problem, Klemin told them he had a way to describe the flow in those confined spaces. He had an algorithm that could simulate the interactions of liquids and gas in a 3D nanoscale pore network based on density functional theory. To reduce the still considerable computing time required, he wrote code for graphics processing units—processing chips created for demanding computer games and used to speed seismic processing. The program made it possible for a computer to create animations of how oil is pushed out of a pore when the pressure in a pore drops below the bubblepoint. At that level, gas begins to bubble out of the solution, expands, and replaces an oil molecule that had been securely adsorbed on the pore wall, expelling it from its secure spot and out of the pore. “As we lower the pressure in the rock model, the pores ooze a bit of oil. It is minor at best until we hit bubblepoint,” MacDonald said. At that point, gas bubbles out, driving the expulsion process that continues as long as there is gas left in the solution. A higher gas content means greater liquids production. Modeling showed that the volume of gas grows only as much as necessary to displace the volume of oil expelled. The limited growth in the gas volume main-
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tains the pressure near the bubblepoint as more gas breaks out of the solution. The simulation work led EP to a hypothesis that the primary source of production from the pore network changes over time, MacDonald said. Early on, when the reservoir pressure is above the bubblepoint, production is primarily draining the inorganic pores. As pressure falls in areas nearest the most conductive fractures, pressure around the organic pores drops below the bubblepoint, gas breaks out of solution, and the expulsion process begins. The area where expulsion is occurring gradually spreads as the pressure change slowly moves into the ultratight rock. “When one matrix element depletes, it will go to the next one and next one. It is chaining to the next active element,” he said. As it moves farther, the contribution of oil from the organic pores grows. Production by gas expulsion from an organic pore will have a different GOR than production from inorganic pores, he said. EP’s technical team has been using the model to study a long list of questions, such as how a rapid pressure change caused by a fracture hit from a nearby well affects production. “In digital space we can do whatever we want,” Geetan said. For example, they found it was possible to move water into the pore, if they made certain assumptions. That led to research into the assumptions. Gathering physical evidence from pores to test widely held assumptions is difficult because these features are so small that the focused ion beam used to slice a clean rock face for imaging by a scanning electron microscope can destroy evidence. During transport, hydrocarbons in the rock can evaporate and microfractures can occur. The quality of data gathering is critical because “we cannot work that out by waving our hands,” Geetan said.
Curious Relationship Production analysis is a critical part of this quest because what comes out of the ground is the sum total of multiple effects in these complex, unpredictable formations where different flow factors may cancel each other out.
“Lots of people focus on the really small pore scale,” said Devegowda, who puts himself in that group. “Other people focus on wells and reservoir-scale things. And we have that huge gap in between.” The work continues because there are unconventional puzzles at the field scale that are a product of what goes on at the pore scale. One such puzzle is what MacDonald describes as the tale of two wells. It can be seen in long-term production charts. Early on, there is a steep dive in the daily rate. Later on, the output steadies, declining slowly for years at a low level. In between is a noisy transition zone. “As reservoir engineers, we spend a lot of time on decline curve analysis to predict future performance,” MacDonald said. Projections based on later data required changing the inputs in the equation defining the decline rate and curve. “We can model the front end and the back end pretty good, but we cannot fit both ends into one model.” Another unconventional puzzle is the changing gas/oil ratio over time compared with conventional reservoirs. Jones’ paper was motivated by questions he was asked about changes in the GOR over the life of wells in places such as the Meramec play within the STACK formation in Oklahoma. “Management was asking why the gas/oil ratio was acting like it was. They thought it could be a bad thing,” Jones said. They were troubled because the ratio shot up early in the life of the well. “The gas/oil ratio can be higher in early stages of life than you would expect in a conventional reservoir” where the ratio stays low early on, then later rises at a steady angle, Jones wrote. The spike in the GOR in unconventional reservoirs is linked to the rapid pressure decline in and around the fractures during early production. “The steepest change in pressure occurs near the fracture face and this is where the pressure will first drop below the bubblepoint,” Blasingame said. In that area, the lower pressure allows gas to bubble out of solution, rapidly increasing the amount of gas per barrel of oil produced. This rapid rise ends when production moves into the tight
JPT • DECEMBER 2016
Grounded Models As the North Dakota research center continues to study how to enhance oil recovery in the Bakken formation, makers of
JPT • DECEMBER 2016
100
80 C2H6 CO2
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confines of the matrix rock where the rate of pressure change slows to a crawl, and the GOR stabilizes. Multiple factors contribute to this steady state. One is the fact that the bubblepoint is thought to be lower inside the smallest pores and openings than it would be in a lab test, and that affects production. This phase shift helps explain how rock thought too tight to produce oil actually does so, according to a 2013 paper by researchers from Colorado School of Mines (SPE 166306). Its simulation showed that in systems with mixed pore sizes, the low bubblepoint in the midsized and smaller pores “promotes more oil production while keeping total gas production nearly the same.” Painstaking laboratory testing has shown that in unconventional rock samples there is a relatively small percentage of spaces small enough to alter the bubblepoint. “Though it [extremely small pores and pore throats] represents only 20% of the storage volume, it is controlling the flow. It is a chokepoint,” Devegowda said. But not always. Jones’ paper also included GOR charts from other wells, demonstrating that in unconventional plays “generalizations are hard to come by.” For example, the Bakken and some areas of Eagle Ford do not see this GOR rise until later, he points out. At the University of North Dakota Energy & Environmental Research Center (EERC), researchers are doing extensive rock testing and laboratory work to create models that bring together all these data to try to explain how pore-scale phase changes affect field performance. “Phase differences in hydrocarbons can help predict changes in the gas/oil ratio over time,” said James Sorensen, a principal geologist for EERC. “It ripples through operations and how fields are managed on the surface. We are starting to connect those dots between microscale analytic work and what is happening at the reservoir scale.”
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Fig. 3—Over a 24-hour period, methane, ethane, and carbon dioxide all removed most of the oil in a core from the middle Bakken, while nitrogen did not, according to a test by the University of North Dakota Energy & Environmental Research Center (EERC). Source: EERC.
reservoir modeling software are paying close attention. The ambitious research program is gathering hard-to-find physical evidence as part of its program to extend the output of wells where production can fall 70% in the first 2 years. In another technical paper (URTEC 2433692), the center reported on a lab test where more than 90% of the hydrocarbons were extracted from pencilsized samples from the middle Bakken by bathing them in ethane and methane— singly and together—as well as carbon dioxide. Nitrogen was also tried, but was far less effective. Ethane was the most effective, which was a positive, because Bakken wells produce a lot of it and the market for it is limited, said Sorensen (Fig. 3). That observation was interesting, he said, because “we expected ethane to do better (than other options) but were surprised at how much better and, in some rocks, it was even better than CO2.” The center is gathering data and doing simulations to see if it can inject enough gas into the middle Bakken to extract the heavier oil molecules now left behind. Based on lab testing of core samples provided by companies there, “the pore throats are small but we are seeing a lot of connectivity,” Sorensen said. But in the ground, injected gas is likely to
follow the path of least resistance. In past field trials, it appeared that the gas bypassed the tight matrix rock by traveling through more open fractures. While North Dakota is studying what happens when gas is injected into a formation, the data are also useful for those trying to create more realistic models of production flowing out of unconventional rock. Sorenson said the big makers of commercial reservoir simulation software have provided valuable support for EERC’s work to create models to try out its ideas. “We are developing a lot of CO2 permeation rate data and hydrocarbon rate data and are just starting to show that to modelers and having higher-level discussions” on how they can build that into their programs, he said, adding, “It is in the early stages. They say there is value there.” The North Dakota researchers are also working on developing a way to trace the source of production. While most of the oil and gas is from the middle Bakken, it is thought that the shale in the upper and lower Bakken also contribute where penetrated by fractures (Fig. 4). “If we can demonstrate we can get more from shales, that will change everyone’s reserve estimates and technically recoverable estimates,” Sorensen said.
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production diagnostics that better reflect the nature of these reservoirs. “We have people sponsoring our research screaming for these tools that are relatively simple but still rigorous to apply to the hundreds or thousands of wells,” Clarkson said. “In my view, you are never going to get to the point of forecasting every single well with detailed numerical simulation,” he said. “The data quality does not usually support this level of analysis on many wells, and the models take too long to set up and run.” What is needed is an array of tools and a data-based method to choose the right one so the prediction is “tied to physical properties of the reservoir or fluids, Clarkson wrote in SPE 172928. He offered a workflow designed to adapt rate transient analysis to the complexities of an unconventional reservoir where many of the assumptions underlying normal rate transient analysis do not apply. The degree of differences among unconventional wells means that engineers should consider analyzing clusters of wells with similar properties, he said. The differences are based on the rock and fluid properties within the reservoirs, as well as how it was drilled and completed.
Keeping Quiet Fig. 4—It is hard to find the organic pores (green) in this 3D image of a sample of middle Bakken rock amid the inorganic pores (red, blue). Most of the organic material is light crude, which is lost during imaging. Source: EERC/Ingrain.
Flexible Tools Experience has shown that unconventional plays are unconventional in different ways. “How different is our Eagle Ford reservoir from our Wolfcamp? It is a lot different. Both are shales and that is kind of where the similarities end,” MacDonald said. As a result, he said, “The more you cannot explain, the more you have to start getting into more specifics.” While there is no such thing as a uniform reservoir, conventional ones are marvels of consistency compared with unconventional ones. Those common features make it possible to predict future production from far-flung conventional fields using a standard method, such as
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the Arps equations, whose history dates back to the 1920s. Arps is often held up as an example of a conventional method that does not work in unconventional plays. Numerical simulation methods could offer a well-by-well analysis, but they are not a practical option for petroleum engineers mass producing production projections. “People are really, really looking for an easy tool to get forecasts,” Devegowda said. “We do not have it. The only thing we can do is fit historical data to some models, which in itself is an assumption.” The demand is driving a search for new empirical methods, such as the power law exponential and stretched exponential
Work by academics stand out in this emerging field because companies are generally not talking about research that could give them a big production edge. One example of turning pore-level observations into a prediction is a reservoir simulator developed at Texas A&M. “The incorporation of pore confinement is not available in commercial simulators but may be a significant factor,” Brian Stimpson, a graduate researcher from Texas A&M, wrote in paper SPE 181686. “The relationship between pore size and permeability can also be obtained through correlations to better predict reservoir properties.” To simplify the problem, the model assumed all the pores were 15 nm. Stimpson is working to build a model with a more realistic range of pore sizes. Ultimately this line of work will raise another question: What is a reasonable
JPT • DECEMBER 2016
representation of the pore sizes in an unconventional reservoir? Those working to answer such questions do not have a lot of people to talk to. “One of the reasons we showed our work to a bigger group is that we wanted a little bit of a peer review, to see if someone wants to beat us up,” MacDonald said after the presentation at URTEC, adding, “We didn’t get much of that.” They see signs that others are quietly working in this area. Geetan said that questions raised at SPE workshops as well as company-sponsored research at universities suggest that companies are thinking about similar things. Those working on these problems are drawing knowledge from such fields as material sciences, chemical engineering, and medical research. “My petroleum engineering reading is down because it does not have much to do with what I am studying,” Devegowda said. This has not increased his popularity as a public speaker. “When I bring up this
topic, there are only two reactions. Probably five persons in the room have read some papers related to chemical engineering and respond to what I am saying,” he said. As for the others in the audience, “I begin to see their eyes glaze over.” JPT
For Further Reading SPE 166306 Multiphase Compositional Modeling in Small-Scale Pores of Unconventional Shale Reservoirs by N. Alharthy, Colorado School of Mines; T. Nguyen, Computer Modeling Group; and T. Teklu, Colorado School of Mines et al. SPE 172928 Analysis of Transient Linear Flow Associated with HydraulicallyFractured Tight Oil Wells Exhibiting Multi-Phase Flow by H. Behmanesh, H. Hamdi, and C. Clarkson, University of Calgary. SPE 181686 Effects of Confined Space on Production from Tight Reservoirs by B. Stimpson and M. Barrufet, Texas A&M University. URTEC 2433692 A Systematic Investigation of Gas-Based Improved Oil Recovery
Technologies for the Bakken Tight Oil Formation by L. Jin, S. Hawthorne, and J. Sorensen, University of North Dakota et al. URTEC 2460396 Producing Gas-Oil Ratio Behavior of Tight Oil Reservoirs by R.S. Jones Jr., Newfield Exploration. URTEC 2461115 Insights into Recovery Mechanisms in Shales through Digital Rock Technology by S. Geetan and R. MacDonald, EP Energy; and D. Klemin, Schlumberger Reservoir Laboratories. Devegowda, D. Project to develop simulators for shale gas reservoirs. http://www.rpsea. org/projects/09122-11/ SPE 181585 Experimental and Theoretical Study of Water-Solute Transport in Organic-Rich Carbonate Mudrocks by A. Padin, Colorado School of Mines, and M. Torcuk, EOG Resources. Clarkson, C. et al. 2016. Nanopores to Megafractures: Current Challenges and Methods for Shale Gas Reservoir and Hydraulic Fracture Characterization. Journal of Natural Gas Science and Engineering 31: 612–657.
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More Oil, More Water
How Produced Water Will Create Big Cost Problems for Shale Operators Trent Jacobs, JPT Senior Technology Writer
I
f crude prices, rig counts, and tight oil production demonstrate a stronger upward trend in the months to come, US shale operators may find themselves with more produced water than they bargained for. The concern is that a surge of produced water could eat into profit margins even as oil prices improve by driving up costs for hauling and disposal. Many shale producers can ill afford a significant spending hike on such services when, according to IHS Markit, produced water management can represent half of a shale well’s operating expenses.
The severity of this issue will depend on how aggressively shale producers seek to rebound from the downturn by drilling new wells. It also will depend on how quickly they activate the estimated 4,000 oil-rich, drilled-but-uncompleted wells (DUCs) that have amassed over the past 2 years as both a cost-cutting and a production management maneuver. “If you get a lot of new completions in a short amount of time, that means you are going to get a whole bunch of water too, and this is something that the industry needs to be thinking about and planning for,” said Piers Wells, co-founder and chief executive offi-
cer of Digital H2O, a company that uses analytics-based models to forecast oilfield water resources. Because it is the most active and prolific shale play, the Permian Basin of Texas is already under pressure. As shown by Digital H2O’s model, the recent uptick in drilling there and in the adjacent Delaware Basin is yielding produced water volumes that are approaching what many of the disposal wells can take away. “While they may not be at full pressure utilization today, many are getting close and, in a higher-price environment, you will see many more areas shifting into
Source: Getty Images.
high utilization,” Wells said. “The thing that people need to be aware of is that this could all happen really, really fast.” With far less drilling activity happening, North Dakota’s Bakken and Texas’ Eagle Ford shales are not facing quite the same situation as the Permian currently is. However, higher prices would start to change that, and there are also more than 2,000 DUCs in those two plays that if brought on line in quick succession have the potential to drive waterhandling costs higher. Produced water management is complex and expensive for shale producers partly because they have fewer
options than their conventional counterparts on what to do with it. One major disadvantage is their inability to reinject into unconventional reservoirs, underscoring that disposal wells will always play an outsized role in shale developments. And proving that even virtuous solutions have their limits, if every shale well in the US was hydraulically fractured with recycled produced water, it would account for only a single-digit fraction of the total volume of water generated each day. Those studying water management practices say that if operators start adopt-
ing longer-term strategies, they can gain leverage over rising wastewater costs. Their recommendations include lessening reliance on inefficient water trucks by building more water pipelines along with permanent processing and treatment facilities. Michael Dunkel, a vice president for the engineering consultancy CH2M, has been involved with water infrastructure projects in Texas and Oklahoma and said a number of operators are on the cusp of investing more capital on this front. However, he noted that a meaningful expansion of water facilities in the shale sector will be years in the making.
Forecasted Permian Basin Produced Water at Different WTI Prices 390 380
Millions of Barrels
370 363
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360 350
342
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346 334
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USD 30 WTI Price
USD 50 WTI Price
USD 70 WTI Price
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290
Oil prices are directly correlated to both oil and water production in US shale plays, which is why they may be the best predictor of how intense the issue of excess produced water becomes. Because it is the largest onshore producing region, the Permian Basin of Texas is likely to feel the squeeze before other areas. Source: Digital H20.
“It will be slow to evolve,” he emphasized. “But 5 years from now, I am confident that there will be a lot more water infrastructure in place, both to move around source water and to interconnect disposal water, which will give greater flexibility in transporting it to different disposal wells.”
Price Matters The place to watch will be the Permian where, according to the Baker Hughes rig count, there are more rigs turning to the right than in any other place on Earth. Having maintained solid growth throughout the downturn, the Permian is producing about 2 million B/D of oil— and about 11 million B/D of water. Assuming that even modest gains in crude prices will encourage more drilling in the Permian, as has been the case since June, Wells said one of his firm’s clients there is expecting the prolific region to see a “wall of water” next year. It is an assertion that the firm’s model for produced water largely agrees with—
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depending on prices. Wells said that if prices maintain a holding pattern of around USD 50/bbl, the model expects many disposal wells in the Permian to soon begin flirting with their upper injection limits. The screws tighten at around USD 70/bbl. It is a price point many in the business are longing for, but Digital H2O’s model shows that it will overstrain many disposal networks in the Permian and other high-producing basins. Wells noted that lead times to plan, permit, and drill new disposal wells could be at least a year. If demand outpaces supply, then bottlenecks could form and operators may be forced to expand their batteries of water storage tanks in order to keep producing unconstrained.
Uniquely Unconventional There are several reasons why this particular produced water problem is unique to unconventional developments. In the conventional world, operators have the luxury of reinjecting much of their produced water back into pro-
ducing formations for waterflooding or enhanced oil recovery. Unfortunately for shale producers, neither of those practices are applicable to nanoscale permeability reservoirs, yet. Shale wells are also drilled in much tighter clusters from pad sites than what one would see in conventional developments. This concentrates the volumes of produced water and places high demand on nearby disposal wells. As to why operators did not plan for this earlier, during the beginning of the shale revolution they had to be somewhat nomadic, in search of the best fairways and sweet spots. This left them uncertain about exactly where future production would come from, making it hard to invest in multimilliondollar water facilities that could not be moved. And lastly, while some data show that shale wells produce less water than conventional wells on average, they generate significantly more in the early life of the well. Industry-reported numbers show that a typical shale well unloads 30-40% of the water that it will churn out over an entire decade in the first year of production. About 20% of that water, termed flowback, includes the fluids used for hydraulic fracturing, which are also growing in volume. To get more proppant into fractures, many operators are using two or three times the volume of water for fracturing that they were just 3 years ago. Laura Capper, president of Houstonbased technology consultancy CAP Resources, explained that though water cuts from shale wells begin leveling off after year 1, their front-loaded production creates especially high demand for disposal services in areas where operators are ramping up. “What you have is a hot play, where all of a sudden you’re doing considerably more business there than you used to and you’re trying to inject the water close to the wellsite,” she said, adding that, “those neighboring injection wells are getting substantially higher injection volumes than the ones that are maybe 50 miles away and only running at say 10% of their volume capacity.”
JPT • DECEMBER 2016
More Pipes, More Infrastructure When it comes to whether companies should be using trucks or pipes to transport water, Capper said investing in the latter should be a “no brainer” decision. Operators can be charged more than USD 100 per truck per hour to move their water. Shale producers use thousands of these trucks each day to carry only 130 bbl of water a time. The trucks are hard on public roads, and represent a sizable proportion of the oilfield traffic that is attributed to an increased number of collisions around active shale plays. Pipelines, on the other hand, can move water continuously, and quietly, while avoiding many of the safety and environmental risks that come with trucking. Aware of these issues, a handful of larger shale producers have committed to building long networks of water pipelines. There is also a burgeoning industry of third-party companies that act as midstream operators for produced water. A recent example of this is a 30-mile pro-
duced water pipeline that was completed in July by a company called Oilfield Water Logistics. Located in the Delaware Basin of New Mexico, several operators including Chevron will have access to the pipeline that will transport 150,000 bbl of produced water each day—which otherwise would require more than 1,000 water trucks. In addition to a need for more pipes, more processing infrastructure will be required to handle and treat the produced water before it heads back to the subsurface. Just like a garbage disposal in a home, disposal wells run smoother and last longer when solids and other harmful elements are removed prior to injection. And while there are a number of new well-side treatment technologies available, in this case bigger is better. Dunkel said that based on his research, small and mobile treatment systems will not be a viable answer for mid- to largesized operators who have intensive water needs.
“The issue is actually very simple; it’s not that their capital cost is too high or that the technology itself doesn’t work— in many cases they do work well,” he said. “But if you have to have two people on site to run the system, the per barrel costs are just too high and the labor cost alone is almost a non-starter.” Elaborating on this point, Dunkel estimated that a two-person staff for a 5,000 B/D water treatment system costs an operator about USD 5,000 a day. But if those two workers, or even a third, operated a 50,000 B/D water treatment facility, economies-of-scale kick in and make small well-side options far less attractive. Dunkel said more operators are thinking about infrastructure today than before the downturn, but with cash flows still suffering, many have placed their plans on hold. One exception is the water treatment and handling facility that Pioneer Natural Resources is building for its unconventional development in the Permian. Pub-
A snapshot of Grady County, Oklahoma, in 2014 highlights that even during periods of high drilling activity there is far more produced water generated in a shale play than can be used by oil and gas companies. The costs and logistics of recycling that water to drinking quality are also extreme. Source: Laura Capper.
JPT • DECEMBER 2016
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lished company materials show that the facility will handle source water for fracturing operations and also recycle produced water for fracturing operations. Speaking to the vast nature of shale developments, the permanent infrastructure is supported by 100 miles of mainline, 10 pumping stations, and an additional 500 miles of subsystem piping. Pioneer says that upon completion, the project will move the equivalent of 2,000 truckloads of water a day. In addition to recycling, more produced water can be removed from the disposal equation if the multipurpose water facilities of the future come equipped with evaporation units. Another idea being discussed is for shale producers to join forces and create water management co-ops. This would help smaller companies deal with the high costs of infrastructure but it will come with competitive and regulatory challenges. Outside of Texas, liability laws make it difficult or impossible for oil companies to transfer ownership of produced water unless it is heading down a disposal well.
There are also operational considerations regarding who gets “first rights” to the services if a shared facility temporarily lost some of its capacity to take or supply water.
Big Limits on Recycling If you thought stepped-up recycling efforts would be the ultimate answer to the question of what to do with produced water, you would be wrong. Though recycling is seen as important for lessening the sector’s reliance on fresh water, shale producers will never drill and complete enough wells to reuse all their produced water for hydraulic fracturing. Capper said her analysis shows that while the majority of slickwater fracture jobs in the US now use recycled water, prior to the downturn when there was considerably more drilling taking place, the amount of water needed for fracturing vs. the total volume of produced water was fractional. Using one of Oklahoma’s most active areas as an example, Capper’s data show that from 2012–2014 overall injection volumes in Grady County quadrupled,
and daily injection volumes per disposal well tripled. She estimated that at the peak only 3% of that briny wastewater, which in 2014 totaled 80 million barrels, was needed to support the county’s entire oil and gas operations. It could require an annual spend of USD 400 million to treat the other 97%. “On top of that, we would have to dispose of some 16,500 railcars of associated salt,” said Capper. “No matter how you slice it, it is difficult to make the numbers work in a 100% recycling scenario— thus industry’s extreme dependence on relatively low-cost disposal wells.” All of this highlights two things: that disposal wells will always be critical to shale developments, and that though there is a need, it will not be easy to make large volumes of recycled produced water available to outside industries. The latter idea is termed beneficial reuse and may not always involve treating produced water to drinking quality if it is used for agriculture. In California, treated produced water has been used for many years for the irrigation
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Seismicity To Drive Costs Higher High-rate injection activity in disposal wells connected to fault-prone formations has been cited by both industry and government experts as the primary contributing factor to induced seismicity in the US. In areas where regulatory actions over induced seismicity have limited the supply of disposal wells, operators who want to increase production will have to spend more money hauling loads of excess water out of a quake zone. The epicenter of this scenario is in northern Oklahoma’s Mississippi Lime play where injection-linked earthquakes have led regulators to force shut-ins or curtail injections at hundreds of disposal sites spread across more than 10,000 sq. miles. In 2016, the state experienced three 5.0-magnitude quakes while the rest of the country saw two. “While the regulatory restrictions will undoubtedly impact operators, the problem is in fact manageable, albeit with more planning and analysis, which costs money,” said Capper, who recently contributed to a state-by-state risk analysis on disposal wells. She said for those companies working in potential seismic risk zones—which also include parts of Texas,
of tangerines and almond groves. Texas A&M University also recently concluded a study that used treated produced water to grow cotton.
Arkansas, and Ohio—the short-term solution to avoiding induced seismicity will involve a more “granular” approach to monitoring injection volumes and downhole pressures. It will also be key to understand local geological factors that may facilitate seismicity. By taking these steps, Capper explained that observant operators should be able to stay under the thresholds thought to trigger seismicity, something she added has been proven to work in certain areas where disposal activity was restricted. Though she emphasized that it can take 18 months or more for injection reductions to result in fewer observable, or felt, earthquakes. The idea taking shape around disposal wells in seismic risk zones is that geomechanics must trump logistics. If the industry can demonstrate an ability to self-regulate injection activity, and where necessary use a more dispersed network of disposal wells, additional government-enforced restrictions may be avoided. “We know where these events have happened, so they should be able to manage their businesses there,” Capper said. “But it’s still going to be an additional cost burden to the industry in that you will probably have to drive your water trucks farther out, or pipe it farther away.”
But aside from these isolated examples, this concept has not been warmly embraced or benefited from the type of extensive, and expensive, research
that is needed to prove to the wider public and relevant government agencies that it can be done safely on a larger scale. JPT
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Tapping the Value From Big Data Analytics Amit Mehta, Moblize
In a recent GE/Accenture report, surveys show that 81% of senior executives believe that big data analytics is one of the top three corporate priorities for the oil and gas industry through 2018. A striking finding was the sense of urgency felt by respondents about implementing data analytics solutions. This trend is driven primarily by current market conditions that are pushing companies to find new ways to become more efficient in exploration and production. In the quest by operators to become more efficient, many new initiatives are currently under way within organizations. Driven primarily by central excellence teams, objectives are to leverage both low- and high-resolution data (highresolution data defined as data collected in seconds/minutes) to make better decisions quickly vs. a traditional approach of evaluating trends over a 12- or 24-hour period or after the fact using old reporting methods. Decision makers are convinced that if other industries such as airlines and consumer Internet players such as Amazon and Expedia can leverage big data to drive efficiency and growth, the same should and can apply to the oil and gas industry.
Actionable Insights and Lower Costs If their assumptions are correct, leveraging hidden insights from mining data can help enterprise users make better, smarter decisions and reduce operational costs. However, as the industry pays closer attention to these initiatives, it is getting exposed to some harsh realities, including big data being uncharted ter-
ritory for information technology (IT) and a company’s business side. Efforts to improve may actually lead to worse instead of better decision making if conducted using the wrong approaches. Further complicating the data analytics issue, most IT organizations are traditionally more familiar with process automation projects where business needs are known and stable. In contrast, data needs are context-dependent, dynamic, and may be unarticulated or even unknown sometimes. Solving this challenge requires anthropological skills that are in short supply in today’s IT world. Unfortunately, traditional requirements gathering fails when assessing data needs since the needs are fast-changing and diverse. Additionally, today’s machine data quality (especially on historical data) lacks accuracy, precision, completeness, and consistency for real-time analytics. As a practical matter, less than 50% of today’s enterprise users find information from corporate sources to be in a usable format. This problem will only get worse as the number of information sources, uses, and users continues to increase. Also, IT does not have a sufficiently deep understanding of how, when, and why information will be used by specific user segments. At the same time, enterprise users do not fully trust data from others or their functions and current tools in the organization today. On the other end, with cost dominating every decision in today’s market, excellence centers are using traditional approaches of trials with multiple platforms without realizing the scalability and repeatability of the piloted solutions. Can manage-
Amit Mehta is CEO of Houston-based Moblize (www.moblize.com). He holds a master’s degree in manufacturing and business management and a BS in mechanical engineering from Cambridge University.
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ment afford to wait years for these initiatives to showcase value when in today’s market capital efficiency, faster adoption and implementation, lower total cost of ownership for many workloads, and shorter development cycles are key to surviving? Quite the opposite. Today it is imperative to view technology platforms as a combination of technology, delivery, and price model that supports an enterprise user adoption quickly vs. the traditional one-dimension “technology only” initiative. Realistically, the time is now for data analytics champions within oil and gas companies to consider adopting radical thinking while practicing “lessons learned” and avoiding faulty actions from the past. The following approaches can help management ensure that data initiatives will more quickly move their company toward generating intended results fast.
Workflow-Based Analytics These analytics are targeted toward answering the question: “How do we make an enterprise user’s work life better as consumer products do in people’s personal lives?” It involves developing an understanding of their daily pain points, segmenting their information usage patterns, and their stance toward technology adoption (e.g., visualization, delivery of business insight expectations). This differs from the traditional approach toward deep customer intimacy, i.e., gathering user requirements in RFP and ensuring that platform providers can satisfy them. Instead, the focus must be on mapping “data to decision” loops for enterprise users and reducing latency in them significantly to provide accurate actionable insights to the enterprise users. For successful adoption of this approach, consider the following:
JPT • DECEMBER 2016
1. Decision-based questions—Identify the universe of decisions that enterprise users are required to make daily. 2. Data architecture—Enable flexible, on-the-fly analysis capabilities through state-of-the-art architecture organized around key daily decision questions. 3. Contextualized information access— Provide enterprise users with access to information organized to address their top daily business questions. 4. Data quality transparency—Provide transparency into cleaning, filtering, and assembling all data sources to help the enterprise user gain trust in the data that will be used for decision making.
Optimization-Based Analytics In contrast with workflow-based analytics, optimization-based analytics are targeted toward answering the question whether reservoirs and downhole tools can be optimized to preempt failures and ensure that timely actions can be taken beforehand. Note the greater emphasis on downhole tools/reservoir optimization vs. creating customer intimacy. Though a promising dimension, this takes longer for organizations to realize value and advance to enterprise user adoption. That is primarily because only a few optimization experts from the central team drive it with a very heavy engineering focus vs. actual enterprise user involvement. This garners attention from IT/central teams and traditional data platform providers as it justifies the huge upfront cost of buying these platforms, eventually ending up as an IT project focused on the technology-only dimension. Timelines to realize value from this approach are relatively longer than the previous approach for some interesting reasons: 1) It requires a lot of heavy lifting to map/configure/assemble the data from disparate sources, and additionally the disengagement of actual operational enterprise users, primarily the central group team, is involved. 2) Since it is focused on solving very complex problems, the volumes and types of disparate data requirements to create optimization algorithms are cumbersome because legacy data lakes are fraught with bad quality data.
JPT • DECEMBER 2016
3) The designed solution may solve problems in a region/geography but is usually not scalable and repeatable easily to others (due to complexity of reservoirs, formations, and inconsistency of standardization of downhole tools). 4) The complexity of models requires a team of experts to vet the results 24/7, which is a huge upfront investment, not to mention change management and new processes introduction that are never easy to get implemented and adopted in the enterprises. Underscoring what management faces, an enterprise user survey revealed high dissatisfaction within the enterprise user community today around current IT. They voice the opinion that solutions being piloted are barely meeting their needs, complex to use, and require extensive heavy lifting, i.e., requiring business experts from vendor teams to extract value from them. One senior executive at an oil and gas enterprise said: “If you give a Lamborghini to a 12-year-old, will he have a clue how to get high performance?” He expected a negative response.
Conclusion For entirely too many years, oil and gas companies have possessed a virtual gold mine, acquired simply by conducting their daily operations but typically underutilized and undervalued or not leveraged at all. That vital commodity is data and its value is now being viewed in a new “bankable” perspective through the power of big data analytics. No matter which approach oil and gas management takes, the crux boils down to: “How do we apply the big data platform quickly to generate value and enable the ability to find and analyze information to make better decisions and insights at a reasonable investment?” Management throughout the oil and gas industry has a unique opportunity to realize quick wins and value from data platforms by focusing initially on workflow-based analytics to address the applicable facts and issues. The workflow approach results in generating business value and deeper customer intimacy as the key to adoption of any enterprise platform vs. the other approach where only business value will be realized over time. JPT
NOTRE DAME UNIVERSITY — LOUAIZE — Assistant Professor of Petroleum Engineering The Faculty Engineering at Notre Dame University-Louaize (NDU, Lebanon, invites applicants for full-time positions in Petroleum Engineering at the Assistant Professor level starting September 2017. NDU is a private, Lebanese non-profit, Catholic, higher education institution, which adopts the American education system. Candidates should have a Ph.D. in Petroleum Engineering or its equivalent (with preference given to those who have American experience). Good candidates will be considered in all relevant area of petroleum engineering. Previous teaching and/or post-doctoral experience is a plus. The successful applicants are expected to teach undergraduate and graduate courses, engage in research, and participate in the academic/social life of the university. Interested applicants should send a detailed CV (including teaching and research statements and a list of publications), copy of degrees, plus three letters of recommendation to feng@ndu.edu.lb The deadline for application is March 01, 2017.
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TECHNOLOGY FOCUS
Reserves/Asset Management Greg Horton, SPE, Retired, and Barbara Pribyl, SPE, Reserves and Resources Manager, Santos
The oil and gas industry is still adjusting to the significant change in oil and gas prices, and, unsurprisingly, many of the reserves- and asset-management papers published over the last 12 months focus on adding, optimizing, and protecting value. The papers have examined this task from many different perspectives, depending on the maturity of the asset, the circumstances of the company, and the local regulatory/political and economic environment. Governments, companies, service providers, and many other stakeholders in the industry have realized the oil-price outlook may remain low for longer than expected and the need to plan accordingly. Moreover, even if prices rise to higher levels than today, the focus on low-cost operations and value-generating projects must remain a priority. Further, there is a greater appreciation for project risk and uncertainty than ever before, and companies must recognize the worth of their assets and when projects should be continued or, indeed, when they should not. This is also in the context of changing commu-
nity and political attitudes to energy production and usage. As a result, it is clear that all stakeholders recognize the need to work together more than ever before to ensure a robust, sustainable industry. The suite of papers in this feature addresses various aspects of the theme of adding, optimizing, and protecting value. First, the importance of an integrated approach to addressing the reservoir, surface-network, and process issues associated with evaluating and understanding the interrelationship of all elements of an asset is presented in SPE 176322. The paper articulates the challenges and a very systematic approach to dealing with these interrelationships. As new projects get harder to justify commercially, brownfield projects that add value to existing projects are becoming more common. SPE 176810 provides an example where subsurface visualization concepts have been incorporated into planning, assessing, and implementing plant upgrades, from relatively minor operational enhancements to major changes, so that preplanning and imple-
Greg Horton, SPE, is retired from Santos after 33 years of reservoir-management responsibilities and maintains an active role in improving the SPE Petroleum Resources Management System (PRMS). He holds an honors degree in civil engineering from Adelaide University. Horton was a member of the SPE Oil and Gas Reserves Committee from 2011 to 2014, is a member of the SPE PRMS Improvements Subcommittee, and serves on the JPT Editorial Committee. Horton can be reached at ghortonpeteng@gmail.com. Barbara Pribyl, SPE, is reserves and resources manager at Santos. She has more than 20 years of experience as a geologist and in reserves and resources management, based in the Australian oil and gas, coal exploration, and coal-seam gas industry. Pribyl holds an honors degree in geology from the University of Wollongong. Her focus in recent years has been on Australian and international oil and gas reserves and resources assurance and reporting. Pribyl has been a member of the SPEÂ Oil and Gas Reserves Committee since 2014 and serves on the JPT Editorial Committee. She can be reached at barbara.pribyl@santos.com.
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mentation time and cost show very practical savings. Complex megaprojects also continue to have ongoing challenges during planning, design, and execution, especially where an organization or industry is handling several simultaneously. SPE 177860 provides the lessons learned from some recent experiences and offers some insights into how these learnings can be integrated, with a focus on the assurance process. Assessing unconventional-reservoir developments and deciding whether they should proceed represent project decision making in the face of technical uncertainty, data unreliability, and a challenging price environment. SPE 179996 provides a thorough discussion of the issues. The paper provides an excellent overview of the theoretical basis for assessing whether such a project may be economically leveraging off similar analysis for conventional reservoir developments. In particular, it points out common misunderstandings between the range of uncertainty of individual-well estimates and the range of uncertainty of the mean, and it provides insight into the situation where an operator achieves a poor result from a pilot and will need to distinguish between it being a reservoir issue or a stimulation design/ execution issue. JPT
Recommended additional reading at OnePetro: www.onepetro.org. SPE 176405 Risk Analysis Significantly Reduces Drilling-Project Costs: Vital in the New Oil-Price Era by Roberto F. Aguilera, Curtin University, et al. SPE 177215 Effect of Oil and Gas Prices in Unconventional-Resource Plays by M. Gibson, IDEAS, et al. SPE 177244 Regrading Proven Reserves With PRMS by Bob Harrison, LR Senergy, et al.
JPT â&#x20AC;˘ DECEMBER 2016
Integrated Asset Modeling: An Approach to Long-Term Production Planning
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ith declining trends in production and dwindling reserves for a 35-year-old offshore field, the Samarang Redevelopment Project was initiated with a vision toward implementing integrated operations as an asset-management decision-support tool. To realize expected reserves and optimize the production, an integratedasset-model (IAM) concept is introduced with state-of-the-art modeling techniques to treat the asset as a whole unit rather than as isolated silos, which had been the traditional approach.
Introduction The Samarang field is located in Subblock 6S-18 northwest of Labuan in eastern Baram Delta province. The production history of the field, first discovered and developed in the 1970s, is discussed in detail in the complete paper. A full-field review was carried out from 2004 to 2007 with the objective of identifying redevelopment opportunities. A field-development plan (FDP) was then established before an alliance was signed in 2010 to redevelop the field. The redevelopment team has drilled more than 17 infill wells, obtained new 3D-seismic data, carried out several studies including fine tuning of the enhanced-oilrecovery (EOR) development plan, and executed an extensive program of production enhancement and surveillance activities to boost the field production. This has given the team further insight
into the Samarang field potential as well as the untapped near-field potential. The proposed EOR process is gasassisted simultaneous water-and-gas (GASWAG) injection. This process consists of simultaneously injecting water updip in the gas cap and gas downdip in water-swept zones. The numerical reservoir-simulation model is the primary tool used for the EOR evaluations, optimizations, and forecasts. Implementation of the EOR scheme requires strategically positioning infill and injection wells. The recovery mechanisms targeted by this EOR scheme include ◗ Displacing attic oil back to existing well completions ◗ Sweeping the remaining oil toward new wells ◗ Repressuring the compartments ◗ Improving vertical sweep by using assistance gravity segregation ◗ Reducing residual oil in water by injecting gas in water-swept layers Traditionally, planning, forecasting, and optimization have been performed by the conventional approach of considering the reservoir, surface-network, and process-system models as being relatively isolated from one another. In this regard, many simplifications were taking place to translate the shared production limits, and account for surface backpressures, for each of the isolated models. These simplifications have negatively influenced production forecast for long-term predictions. The objective is to use an IAM ap-
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176322, “Samarang Integrated Operations: Integrated Asset Modeling— An Innovative Approach for Long-Term Production Planning Focused on Enhanced Oil Recovery,” by W. Sifuentes and J. Moreno, Schlumberger; P. Kumaran and R. Hamdan, Petronas; M. Muhamed Salim, M. Mohd. Som, H.W. Lee, A. Ahmad, N. Pangereyeva, S.S. Biniwale, N.J. Rodriguez, J.T. Nitura, R. Alia, O.A. Talabi, and V. Halabe, Schlumberger; and S. Pedraza, SPE, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed.
proach to analyze and improve the production process for long-term planning.
Solution Overview IAM Methodology. Creation of the IAM involved the following steps. Validate Model Component. The Samarang field is produced through three production platforms, or hubs. The total number of existing strings is 165; however, more than 70 strings are producing, with the remaining strings being shut in for various reasons. The producers have been predominantly gas lifted, with dualcompletion wells across multiple stacked reservoirs. Eight reservoir models are required to describe the complexity of the Samarang field. The recovery to date in the field is through primary depletion by combined drive mechanisms of moderate to strong aquifer support and gas-cap expansion. All wells produce below the original bubblepoint pressures, and artificial lift is required to sustain production because of higher water production and lower pressure in some reservoirs. Build Reservoir Coupling. Once all eight reservoir models are well-prepared, the individual reservoir models are coupled. The reservoir-model checks for the reservoir coupling focus on constraints management to ensure that there will be no clashing constraints that might cause potential problems or errors on the simulation runs. The reservoir coupling aids in handling global constraints, treating the asset as a whole. This is not possible with conventional reservoir simulation. This option is used within the IAM to set up the structure of the master/slave sets. Incorporate Production/Injection Network. Once the reservoir models are ready, the next step is to incorporate the surface-network model. Incorporate Process-Facilities Model. The process model has been built with a proprietary internal process simulator and is described in detail in the
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • DECEMBER 2016
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Phase 1: Standalone Phase 2: Reservoir Coupling Phase 3: IAM
Date
Fig. 1—Production forecasts from the different simulation phases.
complete paper. Once the baseline is established, several checks are necessary to perform the mapping of the wells between the reservoir model and surfacenetwork model. Execute What-If and Optimization Cases. The final step for the IAM work flow is to set up and execute various scenarios once the prediction baseline case has been run. A number of FDP scenarios can be simulated with the IAM once the baseline is established. In the case of Samarang, two FDP scenarios are prepared and compared against one another: the baseline simulation run and the manifold pressure optimization.
Results The Simulation Phases—Model Configurations. The simulation cases performed for this study were carried out in phases, to capture the effect of the IAM approach to the production forecasts. The different simulation-configuration stages/phases that were executed include the following: ◗ Phase 1 involved running the simulation of the eight reservoir models individually and summing up the results of the production forecasts through time. This accumulated forecast is then used as the baseline case against which the subsequent IAM case was compared. ◗ Phase 2 is an intermediate step toward full IAM simulation, involving the coupling of the eight reservoir models to test the deliverability of the individual reservoirs against one another. ◗ Phase 3 is the full IAM. Production-Simulation Profiles. The simulation cases were run for a 21-year period and included the application of
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a waterflood program and a GASWAG injection scheme on a number of reservoirs. Fig. 1 shows the production profiles that were generated from the different simulation phases. The Phase 1 production forecast (green trend) shows significantly higher initial rates. Investigation of the individual-well performance indicated that all of the designed wells in the reservoir models were initially flowing. This was not the case for the succeeding phases, particularly in Phase 3 (red trend), where a number of wells failed to flow as a result of backpressure and constraints imposed by the network model. Nodal analysis performed on such wells showed that the numerous simulation iterations performed for each timestep in the simulation failed to solve an operating point for the well to flow. Further results analysis revealed that the differences between the limits and constraints imposed on the Phase 1 and Phase 3 simulation cases have influenced the production profiles significantly. Some of the wells that were designed to flow for a longer period of time in the stand-alone case (Phase 1) were prematurely shut off or were flowed at a significantly lower rate, contributing to the overall lower rates recorded for the Phase 3 case. The differences in the constraints and limits are caused by the nature of the simulation configuration for Phase 1 and Phase 3. The former simulates production up to the tubinghead of the individual wells, while the latter covers the full production system up to the export point of the topside. As such, the Phase 3 simulation configuration allows a more-realistic simulation of the production performance. The effect of tubinghead-pressure (THP) limits imposed in the standalone
case becomes significant for the performance of the well because these determine both delivery capacity and flow sustainability. As with the usual practice for traditional production forecasting using reservoir simulation, the THPs in Phase 1 were explicitly placed as boundaries for the wells in the reservoir models. In practice, however, these THPs are influenced by the operating conditions of the topside equipment. This means that the calculated THPs, and by extension the calculated oil rates, from the IAM case (Phase 3) represent more-realistic values. On the other hand, some of the wells were determined to have the capacity to produce at lower THPs in the IAM case because the limits that were imposed on the standalone case were significantly higher than those that could be expected from operating the field. Checks on the simulations’ respective well counts reveal that the standalone case allowed more wells to produce, which was attributed to the lower fixed boundary pressure that was imposed. In the case of the IAM simulation, where the THPs were calculated on the basis of the constraints and limits imposed by the network and process models, a number of wells failed to either initiate or sustain production at economic levels. A comparison of the cumulative oil volumes for the 21-year period shows a difference of approximately 8.25 million STB, or 2%, between the two cases. This represents a significant figure and is expected to affect the asset’s economics because the original FDP was based on the standalone simulation case. Sensitivity Case: Manifold-Pressure Adjustments. A sensitivity case on the topside-landing pressures at the manifolds (upstream of the first-stage separator unit) of the three platform clusters was carried out. The results of this sensitivity case showed a 0.6% improvement on the cumulative volumes at the end of field life, allowing recovery of approximately one-third of the potential shortfall shown on the comparison between the previous two cases. This improvement was attributed to the increased contribution from a number of wells as a consequence of producing against a lowered boundary pressure at the manifold. JPT
JPT • DECEMBER 2016
How Visualization Technology Is Maximizing Uptime
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his paper will show that visualization technology, particularly spherical photographic visual-asset management (VAM), has positively affected the offshore industry by creating a wide array of efficiencies. Visualization technology has played a key role in reducing operational expenditure (OPEX) and improving collaboration, thus maximizing uptime across the industry throughout the asset life cycle.
Introduction Historically, “visualization” for those responsible for topside campaigns has meant relying upon computer-aideddesign models created from “as-built” drawings. Unfortunately, the significant drawback of these drawings is that they are rarely kept up to date. As assets now exceed their original life expectancy, thanks to new technologies and engineering practices available to the industry, they often end up being very different than when they were first built.
VAM The rise of VAM technology has helped operating companies create efficiencies through better planning and improved operational practices. The technology provides a cost-effective alternative by providing up-to-date and high-quality representations of assets that can be used to plan major campaigns as well as routine tasks. The technology simplifies the complex data held within as-built drawings by providing a visual context that is similar to that which users would see if they were standing on the asset itself.
This helps the information held within the drawings, and the information within other systems in use for that asset, to be more easily understood. Spherical photographic VAM technology uses high-quality photographic images to create the ultimate visual representation of the asset, providing a view of the location that is as close to physically being present as possible. The superior quality of the photographs enables users to view at extremely close range the condition, structure, fabric, and content of an asset in a high level of detail. One of the spherical photographic VAM systems currently available uses spherical photographs of 12,880×6,440 pixels that are made up of 35 individual photographs taken at varying exposure levels through a fish-eye lens. This means that users can zoom very closely into the image and can view it in varying exposures to ensure that every area of the image is visible in as much detail as possible. The images are also processed to reduce file size while maintaining the exposure range. The images are imported into the system and split into small tiles to enable quick loading over low-bandwidth connections, as is the case for many oiland-gas asset locations, some having to rely upon intermittent satellite connections. Once the spherical photographs are imported into the system, they are linked together across floor plans to show the location from which the images were taken. A key benefit of photographic VAM technology is its intuitive and simple usability. Users can see the asset in pictures, therefore allowing for visual orientation on the asset similar to physically walking
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176810, “How Visualization Technology Is Maximizing Uptime,” by Ruth Christie, Claire Fleming, and Bob Donnelly, SeaEnergy, and Sean Huff, SE Innovation, prepared for the 2015 SPE Middle East Intelligent Oil and Gas Conference and Exhibition, Abu Dhabi, 15–16 September. The paper has not been peer reviewed.
through the asset. Some systems enable annotations or text to be added to the images for communication between disparate users. These capabilities allow the technology to be used by a variety of different users and for a range of different purposes. Some systems can be used in standalone or networked modes that allow for wide collaboration. Security settings can enable visibility restrictions so that different teams can see different things on the same system and therefore work at the same time on different projects.
Times of Plenty The successful use of spherical photographic VAM with specific reference to a major renewal campaign demonstrates its application to the industry during a period of stable, high oil prices, and therefore its intrinsic value during leaner times. In 2011, focus fell on production efficiency in the North Sea. Production efficiency had declined from 80% in 2004 to 60% in 2012. Aging assets, integrity and reliability problems, large work scopes, and limited offshore bed space necessitated a more-sustainable operating model to address these issues. The renewal program embarked upon by the operator required a multibillion-dollar investment to maintain production while increasing the amount of work performed offshore—in short, optimizing scarce bed space. Use of spherical photographic VAM proved so successful that it was rolled out across all of the operators’ North Sea assets, which significantly maximized uptime to an estimate of several hundred man-days, equating to millions of dollars in OPEX.
Preparing for the Unplanned Reducing offshore transit requirements at any time reduces costs and mitigates against the risks posed by helicopter travel. Following the 2013 North Sea helicopter crash, anticipating the natural and po-
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • DECEMBER 2016
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benefit realized in relation to the saved number of offshore transit flights alone to be in excess of USD 500,000/yr.
VAM Improves Collaboration Across Businesses
Fig. 1—An example of VAM tagging capabilities.
tentially prolonged negative effect on the physical logistics of offshore helicopter transit and staff morale, one North Sea operator proactively prioritized the photographic VAM capture of a floating production, storage, and offloading vessel to mitigate against future downtime. By prioritizing bed space for the photographic capture team (comprising six photographers for 6 days), the operator helped itself to minimize future downtime and facilitated its ability to plan essential maintenance work onshore. This, in turn, provided the opportunity to conduct in-depth and collaborative work planning, increasing the efficiency of the asset engineers’ project execution and therefore maximizing uptime through more-effective planning and efficient use of bed space. On this occasion, uptime was also maximized through the additional efficiencies created by the ability of the operator to choose project priority areas to be built from the spherical photography into the VAM system. The capture of the asset was high priority; within the asset, there were areas that were higher priority than others. The operator dictated the order of each area’s priority, and the system was captured photographically and built in that order so that planning on the VAM technology could commence as quickly as possible. During a time of unplanned industrywide downtime, this provided competitive advantage to the operator, allowing work to be planned and conducted efficiently.
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Regaining Control A fire on the Erskine platform in the North Sea in early 2010 resulted in operational shutdown. The fire on the normally unmanned installation led to an 8-month restoration effort. Having been made aware of the benefits of VAM technology by a tier-one service provider, the offshore-installation manager for the asset was quick to consider the applications benefits for his organization. The technology adopted by the operator was created originally for the police to aid crime-scene investigations. It provides users with the ability to seamlessly link corresponding maps, diagrams, photos, notes, audio, video, and documents, thereby creating a single, easily accessed and updated asset database that was a natural fit for the reinstatement project. The technology was used for post-incident investigation, root-cause analysis, stakeholder engagement, planning, and collaboration throughout the supply chain. This VAM system proved so valuable for the operator during the reinstatement process that the effect on the business was realized beyond the scope of the original project. The operator has since completed the rollout of the spherical photographic VAM system across its North Sea assets, identifying it as a step change in providing benefits relating to maintenance, reliability, and integrity management. A value assessment completed by the operator in 2012 estimated the financial
VAM technology can be used as a central hub for a variety of systems also used in relation to a particular asset. Maintenance-management systems (MMSs), equipment-management systems, and conditioning-monitoring systems, for example, can all be linked within some VAM technologies. This benefits users because it creates a central point for data that are held within disparate systems that relate to the same asset. VAM also provides visual context to the data held within these systems, making the information clearer to understand. In 2011, an operator in the North Sea used photographic VAM technology to plan a large-scale maintenance campaign and create the work packs for the associated tasks. Each task was tagged within the system with a corresponding symbol to identify the kind of job, and then each work pack, which featured photographic images from the VAM system, was attached to the tag. Visually, this made it very easy to see the spread of tasks that were required within the campaign on the particular asset. The operator went a stage further to include the MMS data for each task within the corresponding tag on the VAM system. They then set up the tags to change color depending on the criticality of the job as dictated by the MMS. All of this planning and work-pack creation was completed from the office by use of the VAM technology. What this provided was a highly visual representation of the maintenance campaign that assisted the operator in ensuring that urgent tasks were handled first and ensured consistency across asset systems (Fig. 1). Furthermore, equipment vendors have been given access to the visualizations of some operators’ assets to discuss and identify issues with the plant. Images, sound recordings, and video can be added as tags in some VAM technology, enabling users to communicate faults with vendors as an initial step before a visit to the asset. In some cases, this may mean that visits to the asset to fix faulty equipment are reduced. JPT
JPT • DECEMBER 2016
Overcoming Technical-Assurance Challenges in Executing Parallel Megaprojects
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n order to meet short- and mediumterm expansion goals as well as ensure a sustainable long-term future, an operator has recently embarked on several greenfield and brownfield developments. These developments include several megaprojects currently under execution, running in parallel at different phases, in split packages, and under different project teams. The objective of this paper is to share the operator’s experience and success factors in driving technical assurance during project execution.
Overall Program Responsibility
Technical Support
Management Overall Project Responsibility
Functional Technical Assurance
PMT PMC Engineering Contractors
Technical Review and Consultation
DED
Direct Responsibility Interface
Project Technical Responsibility
Organizational Setup The operator’s Discipline Engineering Division (DED) is the company’s technical authority. This division acts as the center of technical-assurance expertise in support of all of the operator’s business activities, in particular the delivery of ongoing complex-project programs. During a project’s life cycle, the division is actively involved with the projectmanagement team (PMT) in the following roles: ◗ Providing a designated technical support team that works full time with the PMT as part of the project team supporting the project’s dayto-day activities ◗ Providing additional part-time support to the PMT through a pool of shared subject-matter experts (SMEs) as required ◗ Providing additional support to the project-management consultant (PMC) as required
DED Management/ Technical Authority
Fig. 1—DED technical-assurance model in a typical megaproject setup.
Providing the overall project program with management-level support in the role of the company’s overall technical authority Fig. 1 outlines the roles in a typical project setup. ◗
Functions DED roles are fulfilled by adopting a framework of proactive involvement and support throughout the full project life cycle at five different project phases: Assess, Select, Define, Execute, and Operate. This involvement and support are provided by fulfilling the following functions: ◗ Providing SME insight to projects through dedicated engineering project-support teams while
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 177860, “Overcoming Technical-Assurance Challenges in Executing Parallel Megaprojects,” by Hisham Awda, Anthony Kotey, Khaled Mohamed Al-Shehhi, Malik Mohamed Shahin, and Wael Al-Madhoun, ADMA OPCO, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
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keeping an overall centralized technical authority in one team. In this function, the support team is assigned to provide all required technical support to the project team, including participating in project reviews and witnessing selected key tests, reviewing technical deliverables to ensure compliance with the project requirements and company standards, reacting to technical issues that arise during the course of the project, and providing technical support to various stakeholders to facilitate swift decision making. Developing and updating relevant engineering technical codes and standards and assuring their compliance in all operator projects. In this function, a pool of SMEs is made available from the DED to work with other relevant divisions within the company to identify standards that must be created or updated, provide the technical
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • DECEMBER 2016
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input for these standards, and assure compliance across all projects. Being actively involved in the technical evaluation and selection of contractors, PMCs, and vendors as well as carrying out the required technical audits. In this function, the DED carries out technical evaluations of all bidders, technically evaluates proposals submitted, and helps review and select relevant personnel before their assignment to operator projects. Reviewing and evaluating project changes through an integrated management-of-change process. In this function, all changes proposed during the execution of a project undergo technical evaluation. All planned modifications, waivers, and concessions are reviewed and approved by the DED, which serves as a technical authority. Ensuring consistency across projects in terms of technical compliance to company standards,
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quality in design, and safety in design. In this function, the DED maintains a constant approach toward quality and safety across all projects, along with providing an extra layer of assurance to senior management. Being actively involved in all project phases from idea development to execution through the adopted gated value-assurance process (VAP). The VAP is a key business-investment process with an integrated approach to project selection and capital efficiency on the basis of estimated budget and return on investment. Decision-support packages are a sanction-level authorization for each project. The DED facilitates decision making by providing technical support and expertise throughout the different project phases and decision gates. In this function, the DED uses its involvement with all projects and its access to information from different stakeholders to identify
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Outcome The adopted model of seamless integration between projects and the DED has brought the operator increased project-delivery success with a reduced exposure to risks caused by project constraints. With technical assurance being applied as part of this model, parallel multibillion-dollar megaprojects are ongoing, with plentiful evidence that project objectives are being met while minimizing cost and schedule overruns, in line with operator business strategies.
Room for Improvement
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and help optimize and comprehend opportunities for cost efficiency and value. Acting as an authority for noveltechnology selection and adoption. In this function, the DED promotes innovation from within, looks for industry technology breakthroughs, and continues to be an active adopter of best practices and novel ideas. Assuring the continuous improvement of the technical skill set within the company through training, coaching, rotations, and professional networking. As a pool for technical knowledge, the DED fosters development programs and ensures that technical training and coaching are always current.
The following areas are identified for potential improvement: â&#x2014;&#x2014; Information technology (IT): Advances in IT are made at a fast pace. The DED has initiated developments in these areas, with innovations in the fields of communication, databases, and 3D modeling, to name but a few, in order to ensure efficiency and information access. For example, the use of video conferences and 3D models can help reduce time and cost associated with travel. â&#x2014;&#x2014; Cultivating more-active partnerships with contractors, PMCs, vendors, and third-party agencies. More effort and initiatives are to be put in place to promote a team spirit among all project stakeholders. JPT
JPT â&#x20AC;˘ DECEMBER 2016
Unconventional Risk and Uncertainty: What Does Success Look Like?
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his paper presents approaches for proper risking of uncertain recoverable volumes for an unconventional resource, taking into account the chance of false positives from appraisal-well information. A subjective risk tolerance can be included to respect how aggressive or conservative a company may be in pursuit of a project. A method of recasting production profiles is demonstrated as an improvement over the common method of scaling, or factoring, the initial production rate.
Introduction Onshore unconventional liquids-shale and gas-shale plays are often referred to as “continuous accumulations” or “resource plays.” The characterization of perceived geologic continuity frames perception of these plays as having little to no risk, to the point that “well manufacturing” is a noncontroversial term used to refer to development of these assets. Exploration-and-production companies often tout a “type well” as an indication of the viability of their assets. However, a type well, by definition, represents the mean of a population of wells. Not all individual wells must be commercial in order for the mean well to be commercial. The well population is something that cannot be predicted, but only estimated. This implies uncertainty. However, the argument that there is risk remains to be made. Regardless of the cause of this norisk assumption, the tools exist to address uncertainty. Empirical modeling must follow from first principles. This applies not only to the evaluation of individual wells
to determine their ultimate recovery but also to the statistical models built to judge the economic value of drilled wells. In the analysis of small sample sizes (and assuming independent and identically distributed samples), the variance is always overestimated. The cause of this phenomenon lies within the roots of regression analysis—or, more accurately, in the assumptions made during the application of regression analysis.
Distributions of Distributions Out of the infinite possible well distributions that may fit sample wells, some are more likely and others are less likely. If one wishes to generalize a description of these distributions, the first and second moments can be used—mean and variance. For a log-normal distribution, it is simpler to compute these moments for the logarithms of the samples. In this case, one wishes to assess the commercial risk of drilling wells. Drilling will commence only if assessment shows that the type well (mean) is commercial. The variance is unimportant. Data “points” are collapsed into continua. A series of data points remains that represents the means of many different well populations. A distribution of these well distributions may now be created. This will be referred to as the distribution of the mean well, also referred to as the type well.
Reliability of Information The variance of the well population is the inverse of the reliability of information gained from sampling that population. The variance corresponds to the “imperfectness” of well observations; the great-
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179996, “Unconventional Risk and Uncertainty: Show Me What Success Looks Like,” by David S. Fulford, Apache, prepared for the 2016 SPE/IAEE Hydrocarbon Economics and Evaluation Symposium, Houston, 17–18 May. The paper has not been peer reviewed.
er the variance, the greater the number of wells that must be drilled to achieve a reliable estimate of the type well. Imagine the case of no variance: Every well drilled would have the same result, and the well distribution would be known exactly after one well. For the case of only a little variance, one could treat it as a negligible uncertainty and simply use the mean of the wells without further consideration. For the case of a large amount of variance more closely resembling the real world, the variance is the cause of sampling error for a small sample size. However, abundant data are available on the variance of well populations. Although the exact value for any given play that is being explored may not be known, the good news about the variance of well populations is that, more or less, the value does not so much matter as long as one acknowledges that it is a non-negligible amount. Therefore, a lognormal distribution may be used to represent the well population. The P10/P90 ratio of a distribution is a useful metric because it instantly communicates how much better the best values are than the worst values. Appealingly, the log variance of a log-normal distribution is exactly related to the P10/P90 ratio. Skewness can be inferred in each well population by noting whether the P10/ P50 ratio or the P50/P90 ratio is larger. The variance of the well population quantifies the reliability of the information gained from each well drilled. By using a statistical basis for the expectation of the true variance rather than determination from data sets of small sample size, the inducing of bias into the estimate of the distribution of the well population can be avoided. This will result in less skew of the fitted distribution.
Quantifying Risk Because the commerciality of a play requires only that the type well is econom-
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • DECEMBER 2016
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Truncation of Type-Well Distribution
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Fig. 1—Intersection of the type-well distribution and the EUR threshold reveals the chance of a project’s commercial success.
ic, the chance of commercial success can be easily calculated. First, analysis to determine the estimated-ultimate-recovery (EUR) threshold above which the type well is commercial must be performed. This is analogous to the minimum economic (or commercial) field size for a conventional prospect. The chance of commercial success for a type well is calculated in exactly the same way as in the conventional case. The percentile at which the EUR threshold lies represents the project’s chance of commercial success (Pc). Fig. 1 shows an example with Pc=50%. It is generally accepted that the purpose of piloting is to gain enough information to determine whether the actual value of the type-well EUR is above or below the threshold. The general thinking continues something like this: If it is determined that the type well lies above, the play is developed; if the type well lies below, then the play is not developed. This leads to a decision that bifurcates the type-well distribution. On the “develop play” side, the threshold is exceeded, so any outcome below it is no longer a possibility. The remaining, truncated, “success-case” distribution represents all remaining possibilities of the type-well EUR. On the “do not develop play” side, no more wells would be drilled. However, for an unconventional reservoir, is it fair to assume that the type well’s position above or below the threshold can be determined absolutely? This is a bold assumption regarding the reliability of the information gained from a pilot program. It seems to suppose that, while individual-well results cannot be predict-
50
ed, they can absolutely be explained after the fact. This is creeping determinism that must be done away with. Ignoring the possibility of developing a play when the type well has a negative value creates an optimistic view of the economics of the play. The expected value of the development project would not include the negative value resulting from a failure outcome, and would be calculated as more positive than it should be. Worse still, the evaluators performing the truncation might view themselves as being statistically prudent.
The values of the type well and the EUR threshold for the example shown in the complete paper were chosen specifically to demonstrate a case in which the proper characterization of uncertainty in the project might be thought unnecessary. Deterministic estimation completely breaks down if the threshold is greater than the estimate of the type well. The project would simply be assigned a negative value and would never be pursued. The deterministic success case not only underestimates the risk involved in exploration but also underestimates the expected value of the project. Without optionality, it is implicit that failure outcomes would still be developed, and these outcomes are included in the estimated type well. Without recognition of the risk and uncertainty involved, failure outcomes might actually be developed before an operator realizes that an estimate was optimistic. The increase in the modeled expected value of the project can be realized only if the decisions made in the real world mirror those in the model.
Conclusions ◗
Project Economics Two sample cases—one in which the pilot provides perfect information, and another in which the pilot provides imperfect information—are discussed in detail in the complete paper. Estimate revision, risk-tolerance determination, productionforecast recasting, and embedded-optionmodel construction are also discussed.
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Discussion While the embedment of options into the project model exposes the upside (P10) outcome, the decisions themselves cannot improve the value of the project. Instead, the decisions act to mitigate risk by exiting a play, or not developing a project, when its success seems unlikely. Decision quality is improved by the inclusion of all available data into the creation of a revised estimate, because decisions are the result of uncertainties and thresholds. If the uncertainty can be reduced, then the true positive and true negative realizations can be improved.
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Evaluation of uncertainty and calculation of risk have been translated from the well-established work flow in conventional exploration for application to unconventional resources. Formalized statistical definitions for pilot effectiveness have been provided in both frequentist and Bayesian terms, both of which include the inclusion and inference of previously gathered information. Risk tolerance is defined as a threshold for the estimated chance of success from the revised typewell estimate. Neutral risk tolerance can be calculated as the chance that the type well exceeds the revised estimate given that the pilot mean is exactly equal to the EUR threshold. The imbedded-option model quantifies project risk, chance of commercial success, upside potential, and false-positive outcomes. Recognizing and modeling the decision not to develop a project if the information gained by a pilot program indicates that it will not work will mitigate project risk and increase expected value. JPT
JPT • DECEMBER 2016
TECHNOLOGY FOCUS
Production and Facilities Ted Frankiewicz, SPE, Engineering Adviser, SPEC Services
I keep a sign on my desk, purported to be a Chinese proverb, that says, “Those who say it cannot be done should not interrupt those who are doing it.” This bit of wisdom certainly applies as we recap the impressive progress made in a wide range of technologies related to production and facilities. Significant advances were reported in materials, field optimization, safe operations, corrosion, and wellborerelated technologies. In each area, progress was reported toward more-efficient field development, extended equipment and pipeline service life, and reduced environmental-release risks. In materials, papers described new liquid coatings (SPE 176048, SPE 179933) as well as new alloy coatings (SPE 176930) that provide improved corrosion- and erosion-resistance properties. The strength and fit-for-service range is being extended for pipelines by the development of new polymeric and composite materials (OTC 26506, OTC 27179). On the flip side, a material for fully degradable fracturing plugs was also reported (SPE 176917). Who knew that sometimes we want things to fall apart in a timely manner? In field optimization, the development of an artificial-neural-network (ANN) model significantly reduced the amount
Several of these technical advancements may now allow operators to do routinely what many may have previously said cannot be done. of computational time required to generate an optimal well-placement strategy (SPE 177442). An ANN-modeling approach also improved the reliability and accuracy of a model for detecting gas-pipeline leaks from basic flow-rate, velocity, pressure, and temperature signatures of the pipeline (SPE 177459). Another paper reported on the development of an Excel-based tool that allows nonchemists, field personnel, and engineers to make rapid determinations of the threat to asset integrity by sour (hydrogen-sulfide-containing) production streams (SPE 179921). For safe operations, a model was developed to improve the reliability of blowout-preventer control systems that included the interaction of multidomain dynamically coupled systems rather than just taking a steady-state approach (OTC 27292). Another paper described
Ted Frankiewicz, SPE, has more than 30 years of experience with oilfield process systems and produced-water treatment. He holds a PhD degree in physical chemistry from the University of Chicago. Frankiewicz holds 15 patents. His experience includes hands-on operations, equipment design and manufacturing, and process engineering. Frankiewicz has worked for Occidental Petroleum, Unocal, Natco Group, and SPEC Services. At Unocal, he was responsible for developing water-treatment systems for the Gulf of Thailand to remove mercury and arsenic as well as residual oil from produced water. At SPEC Services, Frankiewicz has designed equipment and process systems for, and diagnosed performance issues with, facilities and water-treatment systems for major and independent operators. He was an SPE Distinguished Lecturer in 2009–2010 and is a member of the JPT Editorial Committee. Frankiewicz can be reached at tfrankiewicz@specservices.com.
JPT • DECEMBER 2016
advances in the use of robotic technology for internal pressure-vessel inspections, significantly reducing the required time and personnel hazards associated with conventional human-entry inspections (SPE 177913). A combination of drill-rig automation and improved inspection technologies reduces well-workover times (and costs) while also reducing personnel exposure to operational hazards. One paper described an online method for inspecting tubing as it was being pulled from a well by use of electromagnetic inspection (SPE 177741), while another described an automated pipe-racking system that removes personnel from this hazardous procedure (SPE 176336). These papers are only a limited sampling of the progress made this past year in the development of new technology for production and facilities. Several of these technical advancements may now allow operators to do routinely what many may have previously said cannot be done. JPT
Recommended additional reading at OnePetro: www.onepetro.org. SPE 176930 Boosting Performance of Component Assets Used in UnconventionalResource Plays With Nanolaminated Alloy Coatings by Christina Lomasney, Modumetal, et al. SPE 177741 Application of Flux Leakage Technique and Hydrostatic Pressure Testing To Evaluate Imperfections in Used Tubing by Fajarul Majeed M, AlMansoori Inspection Services OTC 27292 Holistic Systems Analysis: A Case Study Demonstrating Simple Models Improving the Reliability of the BOP Control Equipment Ecosystem by Daniel C. Barker, Cameron SPE 176048 Next-Generation DamageResistant Liquid Coatings by Melvin Devadass, 3M, et al.
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Determination of H2S Partial Pressures and Fugacities in Flowing Streams
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100 90 80 Oil-, Water-, and Gas-Phase Species
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n Excel-based tool was developed that uses cubic-equation-of-state (EOS) and thermodynamic electrolytechemistry modeling to assess sourproduction streams from a reservoir, through production tubing, pipelines, and facilities to an export pipeline within a range of temperature and pressure conditions. The approach is need to assess the integrity risk posed to system components in the Alba field in the North Sea.
Water-Phase Species
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Theory and Methodology To accurately determine multiphase sulfide concentrations, and therefore hydrogen sulfide (H2S) partial pressures and the resulting integrity threat in sourproduction streams, it is first important to understand the pH-dependent distribution of the three species of sulfide that may be present in an aqueous solution. Many commercially available EOS software packages do not take into account aqueous pH- and speciation-driven aqueous sulfide solubility. They merely assume that the gas-phase and oil-phase H2S remains as H2S in all three phases and, as such, that the aqueous solubility is limited by the solubility of the H2S species in water. The three species of sulfide that may be present in an aqueous solution are H2S, HS−, and S2−. How much of each species is present (as a fraction) is dependent largely upon the aqueous pH. H2S is the only species of sulfide that exists in all three phases; some aqueous sulfide must speciate to H2S before H2S is
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pH Fig. 1—Sulfide speciation as percentage of total sulfide in aqueous solution (adapted from commercial-thermodynamic-model outputs).
found in the oil and gas phases. Therefore, in an oil-production system in thermodynamic equilibrium, with an aqueous pH of 9.5 or higher, all sulfide must be in the water phase and oil and gas phases must be completely free of H2S. However, this would be very unusual in an oil-production system or reservoir where typical aqueous pH values are much lower. At very low pH values, three-phase H2S distribution is driven by temperature and pressure alone: Increasing pressure reduces gas-phase H2S and increases oil- and water-phase H2S, whereas increasing temperature increases gasphase H2S and reduces oil- and waterphase H2S (Fig. 1). Speciation is driven by the availability of hydrogen (H+) and hydroxide (OH−) ions. At high pH, with a deficiency in dissolved H+ ions and an overabundance of
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179921, “Determination of H2S Partial Pressures and Fugacities in Flowing Streams for a More-Accurate Assessment of Integrity Threat in Sour Systems,” by Christopher Harper, Kanan Taghiyev, and Peter Wilkie, Baker Hughes, and Douglas Hall, Chevron, prepared for the 2016 SPE International Oilfield Corrosion Conference and Exhibition, Aberdeen, 9–10 May. The paper has not been peer reviewed.
OH− ions, sulfide speciates to HS− or S2− as the associated H+ reacts with OH− to form H2O. At low pH, with an abundance of H+ ions and a deficiency of OH− ions, the HS− and S2− will take up free H+. In both cases, the solution tends toward a system thermodynamic equilibrium. The three-phase distribution of sulfide in an oil production system is a complex interplay of temperature, pressure, and aqueous pH, as well as the relative volumes and compositions of each phase at each condition. Simply assuming constant gas-phase H2S concentrations or performing modeling that does not take into account the aqueous pH effects is unlikely to yield accurate results from which an accurate partial pressure can be derived. The model calculations rely upon the corrected Peng-Robinson cubic-EOS model and thermodynamic electrolytechemistry modeling. Pressure/volume/ temperature data relevant to the producing formation are used to calculate oil molecular weights, densities, and bubblepoint pressures across a range of temperatures, pressures, and water cuts. The first step of the modeling process is to calculate the equilibrium pH at the
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 52
JPT • DECEMBER 2016
point of sampling. This is calculated from alkalinity, dissolved ionic components, gas-phase carbon dioxide (CO2) and H2S concentrations, water cut, temperature, and pressure. When this is defined, the partition coefficients for sulfide can be calculated and the total loading of sulfide per unit volume of produced fluid can be defined using either the water-, oil-, or gas-phase sulfide concentration. The total mass is reconciled to reservoir conditions where near-wellboreregion loading of sulfide in oil can be calculated from the defined pH values and the corresponding partition coefficients. The alkalinity at the sampling point, if determined soon after sampling, is likely very close to the alkalinity of the fluids within the system at the point of sampling. Downhole alkalinity, however, may be significantly different from that measured in the sample because of CO2 loss and carbonate speciation reactions. The alkalinity is resolved by first equilibrating carbonate species (CO2, HCO3−, CO32−, and H2CO3−) with known concentrations in any of the three phases. The temperature and pressure profiles within the system must also be calculated, along with the resulting oil/gas/ water compositions, physical properties, and aqueous pH at each location of interest. From this partition, coefficients can be derived that describe the threephase distribution of H2S at each location of interest. At each point, using the total moles of hydrocarbons, sulfide, and water, the three-phase H2S concentrations can be calculated and checked in terms of mass balance. Where the gas-phase concentrations, partial pressures, and fugacities of H2S are calculated, the figure can be compared with metallurgy limits to determine how close system sulfide-induced stresses are to recognized material limits. Features such as artificial lift may mean that temperature and pressure profiles must be forced from calculated data points rather than calculated from hydrostatic head and frictional losses. Gaslift wells also must be modeled with the additional hydrocarbons in the stream from the point of the active lift gas injection mandrel upward within the EOS calculations. For well-shutdown conditions, the values of shutdown wellhead tempera-
JPT • DECEMBER 2016
ture and downhole temperature must be based on regional geothermal gradients. In topside process calculations, it is important to account for the molar flows of sulfide, hydrocarbons, and water to account for degassing, dewatering, and commingling of streams. Multiple reservoir-production flows produce intermediate compositions as a result of physical and compositional property changes. Therefore, new EOS and thermodynamic calculations must be performed where oil and water of significantly different compositions commingle. Each topside-process work flow must be specified for each operation, because each process is different in terms of the order of degassing, dewatering, and commingling of the streams. Also, there may be many various reservoir horizons producing to one process, each with significantly different compositions. Individual wells may also produce from multiple horizons.
Building the Model and Results Comparisons The model only requires the input of parameters that are readily available in operator databases or routinely determined by operations and laboratory personnel. The model is a combination of design elements developed with the operator and a database of standard production data for each well and system. Most of these input data are editable if required. However, typically, the operator of the tool needs to import only the data relevant to a specific well or production scenario and then update values such as gas phase H2S (or oilphase H2S or water-phase sulfide), CO2, water cut, and operating temperatures and pressures. Unless significantly different (i.e., because of sudden injectionwater breakthrough), compositional data do not need to be updated. However, in this circumstance, it is recommended to update the database rather than compositional values at every run, to maintain ease of use and to reduce the time required to perform a set of calculations. The model was developed from, and used exclusively for, the Alba field in the North Sea. The field’s production engineers use the model to ascertain the integrity threat to production tubing and wellheads. Calculated values of the threephase distribution of sulfide in the test
separator compare well with the measured values. Comparison of tool outputs with field data is difficult to achieve because most locations of interest are not accessible for sampling during production; however, it is possible to compare test-separator data with model outputs to demonstrate how field data compare with the calculated values. In several well tests in which the water-phase and the gas-phase sulfide concentrations were measured, the measured and calculated values compare well, indicating at the very least that the partition coefficients calculated for the test separator are representative of the real sulfide partitioning behaviors. Furthermore, the model compares well with commercial software, which does not take into account thermodynamics but merely relies upon composition and pH input values from the user.
Practical Application and Benefits Initially, the asset production engineers incorrectly calculated the H2S partial pressure. The production tubing for the operator’s Alba production wells is predominantly L80-13Cr, which has a National Association of Corrosion Engineers (NACE) H2S-partial-pressure limit of 1.45 psia, or L80 carbon steel (sourservice rated). However, the critical integrity point in the production system was previously identified as the tree that contained specific steel elements, for which the NACE guidelines specified an H2S partial pressure of 0.5 psia. Risk assessments were conducted, and three Alba wells were shut in and secured with base oil, resulting in an approximately 1,700-BOPD loss. Three additional wells were at imminent risk of being shut in, and four other wells were under increased surveillance for rising H2S levels. Following the development of the tool for the Alba field, two of the wells that were shut in and secured were returned to service, with the remainder no longer under imminent threat. The asset production engineers use the tool to recalculate the H2S partial pressure following changes in water-chemistry parameters. The tool is used primarily following increases in H2S levels measured during well tests, but also frequently amended are water cut and flowing pressures. JPT
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Production-Optimization Strategy Using a Hybrid Genetic Algorithm
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he optimization algorithm used in this work is a hybrid genetic algorithm (HGA), which is the combination of GAs with artificial neural networks (ANNs) and evolution strategies (ESs). This HGA attempts to simplify the complex and diverse parameters governing the production-optimization problem. The HGA is coupled with a commercial simulator and has been applied to real fields to quantify the benefits of this HGA over a base case with the conventional GA.
Background GAs. GAs are part of a larger group of methods in artificial intelligence (AI) called evolutionary computation. These methods are inspired by natural evolution in biology. The GA has been wellrecognized as an optimization method that has the ability to work in a solution space with nonsmooth and nonlinear topology, where traditional methods generally fail. Several entities that make up the building blocks of GAs have their direct counterpart in nature. Populations, individuals and their fitness, generations, and genomes are all present both in nature and in GAs. A detailed discussion of the GA method is provided in the complete paper. ANNs. ANNs are a method in AI inspired by brain structure and function. The method aims to interpret the functions, processes, simulators, or similar artifacts that produce input/output patterns by learning by use of given training points. The learning process for the ANN in this study uses a back-propagation (BP) algorithm. After learning from training data has been accomplished by an ANN, the system will
receive input, process it, and provide the output. Many variants and types of ANNs exist. In ANNs, there are some nodes that receive inputs, some nodes that provide output, and hidden nodes in between. Neural networks are composed of nodes or units connected by directed links. Learning in an ANN is typically accomplished through use of examples. This is also called “training” in ANN because the learning is achieved by adjusting the weights iteratively so that a trained ANN can perform well to interpret the function by use of testing points. The most common method in training the ANN is the BP method. ESs. ESs are a major class of evolutionary algorithms (EAs) (EAs includes evolutionary programming, GAs, and ESs). ESs are similar to GAs as optimizers; the main difference is that ESs focus only on mutations as the operator. This distinction makes ESs more powerful than GAs in dealing with large, complex problems that generate many local optima. ESs can also deal with problems where no explicit or exact objective function is available. ESs start with a population of candidates of trial solutions. At each iteration (generation), ESs update each individual in the population by use of control parameters called strategy parameters. This updating process is called the ES mutation operation.
Evolution in Artificial Neural Networks (EANNs) In this study, the authors attempted to generalize the HGA so that it could be used to optimize any kind of reservoir
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 177442, “Production-Optimization Strategy Using a Hybrid Genetic Algorithm,” by Damian Dion Salam, Irwan Gunardi, and Amega Yasutra, Bandung Institute of Technology, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
model automatically. An alternative possibility in reaching this goal is revealed by exploring possible benefits arising from the combination of two augmented algorithms, which are between ANN and EA. Evolution has been introduced into the ANN at roughly three different levels: connection weights, architectures, and learning rules. The evolution of connection weights introduces an adaptive and global approach to training, especially in the reinforcement-learning and recurrent-network-learning paradigms, where gradient-based training algorithms often experience difficulties. The evolution of architectures enables ANNs to adapt their topologies to different tasks without human intervention and thus provides an approach to automatic ANN design because both ANN connection weights and structures can be evolved.
Methodology The optimization process proposed in this study is based on a GA coupled with an ANN and ESs. The ANN and ESs are mainly used to reduce the number of simulations; thus, the process becomes time-efficient. It is known that the architecture of an ANN determines the information-processing capability of the ANN. This results in the algorithm becoming problem-dependent. This algorithm searches the near-optimal sets of production variables to optimize the objective function, which is net present value (NPV). The process work flow is shown in Fig. 1. HGA Structure/Work Flow. Initial Population Generation. In this first step, the input variables are encoded into binary strings to form a genotype. The initial population is then ready to be generated, either randomly or by use of algorithms that ensure appropriate distribution of the population. In this work, the initial population is generated using the latin-hypercube-design (LHD) algorithm.
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 54
JPT • DECEMBER 2016
Choosing initial population randomly often causes inefficiency of the algorithm. To ensure that the initial population is generated properly and has appropriate distribution, the LHD method is used. Evaluation. After the initial population has been generated, all of the individuals are evaluated. The evaluation of the individuals is performed with a commercial simulator. After simulation is completed, the result of the objective function is returned to the program for continuation of the algorithm process. Evaluation for each individual is called fitness value. Results of the evaluation are then ranked from best to worst. Database. During the optimization process, all of the evaluation results using the simulator will be stored in the database. This storage process aims to prevent multiple evaluations of the same inputs using the simulator. Training EANN. The input points from the database are then used as training points and validation points. In order to prevent overfitting (overtraining), the cross-validation algorithm is used. Reproduction. The reproduction module of the program uses two mechanisms, crossover and mutation. The crossover method selected is single-point crossover, for its simplicity and the lack of evidence that multiple-point crossover improves the algorithm. Mating crossovers are chosen randomly on the basis of the crossover rate between the individuals. The mutations are applied in conjunction with the crossover process. Elitism and Selection of New Population for the Next Generation. Elitism is mainly used to ensure that the best individuals of the previous generation will survive to the next generation. In this program, 20% of the best individuals from the previous generation will automatically become the individuals for the next generation. In this way, every new generation will be at least as good as the previous one.
Application The HGA is then applied to a realistic reservoir model with an area of 14 km2 to demonstrate the application of the methodology (field characteristics are provided in the complete paper). The optimization process was carried out for solving a production-strategy
JPT • DECEMBER 2016
START HELPER
GA LHD
Initial Population
Elitism and Selection of New Population
Simulation
GA Process Line HELPER Process Line HELPER Data Line Economic Calculation
Fitness Calculation Training Database No
Check Termination Criteria
Reproduction Evolving Neural Network
Crossover
Mutation
Yes
Offspring STOP Evaluation Using Neural Network
Fig. 1—HGA flow chart.
problem for vertical wells. The HGA will be used to optimize the NPV with production variables of well placement, production and injection rates, and scheduling of conversion of production wells to injection wells. The optimization process is divided into two main schemes: (1) optimizing the well placement for 10 production wells and (2) optimizing the scheduling of conversion of production wells to injection wells, considering the rates. The first scheme aims to locate the 10 production wells to optimize the cumulative oil production. After optimizing the first scheme, there exist 10 production wells with varied rates. The duration of the contract is 19 years. Production management decides to convert production wells to injection wells after 5 years of production in order to enhance the recovery of oil. The number of injection wells and the time at which they will be activated are defined by use of the optimizer. The rate of injection also would be optimized, together with two former variables. The constraints are as follows: The rate of injection is between 100 and 1,500 BWPD, the range of conversion is between the sixth and the 19th year, the time span between the conversion of one well to another is 1 year, and maximum water cut is 95% (producers were shut in if this constraint was violated). In this optimization process, the crossover function was set to 0.6 and the mutation rate was set to 0.3. The number of the population for each generation is N=10. For the first scheme, the evaluation was performed by reservoir simula-
tor to obtain the cumulative oil production; for the second scheme, the objective function was the NPV.
Data and Results Scheme 1: Well-Placement Optimization of 10 Production Wells. Applying the previously described realistic reservoir model, the optimization using HGA was conducted. The result shows that, after running 604 simulations at the 64th generation, the optimal fitness value was obtained. Total time needed for the whole optimization process using this HGA was 6.5 hours. The conventional GAs were then implemented to optimize the same problem; 640 simulations at the 64th generation were required to reach the optimal fitness value of 88 million STB. This confirms the superiority of the HGA in this study. Scheme 2: Optimizing the Scheduling of Conversion of Production Wells to Injection Wells. The position of 10 existing production wells is plotted at the fifth year of production. The NPV is determined to be USD 290 million by converting Production Wells 1, 2, and 10 at Years 12, 13, and 14, respectively. The rate of injection for Wells 1 and 2 is 900 BWPD, while for Well 10, the rate is 1,500 BWPD. If the field was not optimized (conversion of production wells to injection wells is not taken into account), the economic calculation determines the NPV to be USD 275 million. Therefore, use of the HGA optimization enhances the recovery significantly, by approximately USD 15 million. JPT
55
Qualification of Composite Pipe
T
his paper describes the qualification process for a thermoplastic composite pipe manufactured for use in high-performance riser, jumper-spool, and intervention-line applications. The pipe is manufactured from polymer, carbon-fiber, and glass-fiber materials with an automated laser-based welding process.
Product Architecture The body of the pipe contains no metallic components, only polymer and fibers. These pipes consist of a smooth-bore inner-pipe precursor, extruded from Victrex PEEK polymer, with a thin wall thickness onto which layers of composite tape are welded by laser to form the pipe wall laminate (Fig. 1). This laminate can be any thickness and orientation of fibers, with the function of providing the strength and stiffness of the pipe. Once manufactured, the function of the inner-pipe precursor is to provide high-integrity sealing, resistance to hydrocarbon and other fluid and gas permeations and high temperatures, and a smooth bore for high fluid-flow rate. The internal bore is typically in the range of 2 to 6 in., and the lengths can range from a few meters to kilometers for spoolable applications. At either end are steel end fittings that provide the interface to the external subsea system. The composite end fitting uses a steel collar that interfaces with a taper in the laminate to transmit bending and axial loads from the pipe body to the external system.
Manufacturing Processes A thermoplastic composite pipe is typically manufactured from individual
composite tapes on the order of 10 mm in width, 0.2 mm in thickness, and several hundred meters in length. The composite tapes consist of many thousands of glass or carbon fibers impregnated with the thermoplastic matrix. Adjacent tapes are placed with the same orientation by robot, to form plies. The plies may be oriented in different directions through the wall thickness of the pipe to tailor the mechanical properties of the structure. A laser or other heat source is used to heat each incoming tape and the surface of the pipe to a temperature above the melting temperature of the thermoplastic polymer. The thermoplastic welding process enables high levels of control and design flexibility to vary the layup and wall thickness along the length (for instance, to build in bend stiffeners). Long lengths of pipe require spooling during manufacture because the pipe requires multiple passes through the welding equipment to build up the wall thickness. After manufacture, spooling may also be necessary for transportation and installation. The automated laser-welding process has some applications in the automotive and aerospace industries but has not previously been used for subsea-pipe applications. As with any composite product, the manufacturing process has an important influence on the structural quality of the finished laminate. Hence, the mechanical properties of the pipe are a function not only of the precursor fiber and polymer but also of the manufacturing processes during pipe construction.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27179, “Qualification of Composite Pipe,” by Jonathan Wilkins, Magma Global, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.
A detailed discussion of current technology-qualification standards as well as product-qualification standards is provided in the complete paper.
Approach to Testing and Analysis The manufacturer follows the pyramid principle shown in Fig. 2. It is considerably cheaper, safer, and quicker to test on small-scale coupons rather than on full pipe structures, particularly at extreme temperatures and when establishing chemical-resistance limits of the material in the presence of oilfield fluids or hydrogen sulfide gas. Long-term material behavior such as fatigue testing to cycles on the order of 106 can be evaluated an order of magnitude more quickly on material coupons than on pipes. Such effects on the material do need to be verified at a pipe level higher up the pyramid. However, where possible, such testing can be minimized by use of the structural model to predict behavior of the full-scale pipe. Small Scale. Historically, the majority of composite-material-testing methods and laboratory-test equipment has been designed for use with flat coupons. This creates a significant challenge for manufacturers of pipes, whose manufacturing equipment is specifically designed to make specimens that are tubular. For fiber-dominated properties such as tensile or compressive strength along the axis of a ply, the values are dominated by the fibers themselves and the bond strength to the matrix. For these tests, the manufacturer has elected to use standard test methods and to adapt the laser-welding manufacturing process to produce flat coupons. However, for shear properties, or those properties transverse to the axis of a ply, the strengths are dominated by the thermoplastic matrix and the qual-
The complete paper is available for purchase at OnePetro: www.onepetro.org. 56
JPT • DECEMBER 2016
ity of the welding process. To obtain realistic data, the coupon-manufacturing process needs to accurately represent physics similar to that which occurs in the production of the pipe. Therefore, unidirectional tubular coupons are selected for these tests. Having decided the basic merits of flat vs. tubular coupons, the choice of test method for each property still requires some careful thought. This choice of test method and tabbing material affected the value of compressive strength along the axis of the carbon fibers in early experiments on the manufacturer’s material. Compressive testing of composites is notoriously difficult because of the inherent high strength of the material and influence of the test equipment. All the test methods are legitimate, but depending on the details of the implementation, the range of mean strengths that were measured is between 400 and 1000 MPa. Thus, before the specifics of the small-scale testing are decided, it is useful to have some knowledge of how the actual laminate behaves in order to judge which coupon results are reasonable. It is important to avoid introducing artificial scatter into the coupon-test data, either from the coupon manufacture from the base laminate or from the test methods. Most composite-design methodologies require the use of characteristic strengths rather than mean values for design purposes. A characteristic strength is a certain number of standard deviations, typically two, away from the mean value measured in the test. Hence, artificial scatter can affect the useful capacity of the material significantly; this is a key challenge in testing composite materials. Therefore, it is important that every coupon be inspected after testing to ensure that it failed from a legitimate mechanism, rather than from a laboratory artifact, because invalid failure mechanisms typically lead to high variation in results.
mance. A validated analysis model is needed to avoid “qualification by testing,” which implies full-scale testing of each load case of concern. A validated analysis model allows these load cases to be simulated at low cost and high speed with a computer. The wall of a typical thermoplastic composite pipe consists of plies of composite material arranged at different orientations selected by the designer
to give the required structural response for the application. The manufacturer’s analysis model generates a layer-bylayer model for each laminate tape layer, with its defined properties and orientation with respect to the pipe axis. The modeling approach is developed on the assumption that the composite tapes are transversely isotropic in their structural response, allowing the number of elastic constants to be reduced from 21
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Local Pipe-Body Analysis A reliable structural-analysis model of the pipe body is as important as the test data. According to the pyramid principle, the model is needed to connect the small-scale coupon data to the prediction of the full-scale product perfor-
JPT • DECEMBER 2016
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57
Smooth inner-bore polymer extrusion
Decreasing number of tests
Full-Scale Testing Survival tests on critical load cases Confirm structural-model predictions Complete pipe system
Medium-Scale Testing Confirm structural-model predictions Modeling based on small-scale data Replicate manufacturing process
Small-Scale Testing Fundamental material properties Effects of environment and time Statistical evaluation of properties
Fig. 1—Views of typical thermoplastic composite pipe.
to five. This greatly simplifies the volume of material properties that must be measured and fed into the model, as well as the complexity of modeling and post-processing.
Global Analysis For a new product, the load cases to consider are not always obvious because the pipe may behave quite differently from traditional products. A global structural
}
Structural model linking different testing scales
Laser-welded composite laminate
Fig. 2—Pyramid principle for testing and structural analysis.
model of the pipe within the proposed subsea system must be used to accurately define the load cases of greatest concern for subsequent assessment in the local pipe model. Having established the properties of the unidirectional laminate plies at the small scale, it becomes important to test at the intermediate scale with multidirectional laminate, with ply angles that are representative of those in the
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commercial product. This intermediatescale testing allows the local analysis model to be validated, and adjusted if necessary. In general, the manufacturer uses the simpler maximum-failure-strain model for an initial assessment of new designs. This is reasonable, because the design allowable strains are typically one-half to one-third of the failure strains, and, in this region, the structural response is quite linear. The computationally intensive progressive-damage model is used for subsequent checks of specific load cases deemed to be of highest risk.
Full Scale
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58
The top of the qualification pyramid requires testing on full-scale pipe. This is to provide the final evidence and empirical data to verify the modeling approach and the use of materials testing from smaller scales. Strain gauging and digital-image correlation techniques were used to assess the mechanical behavior against analysismodel predictions. It is also important to validate trends in long-term properties such as fatigue performance seen on small-scale coupons or intermediate-scale laminates with checks at full scale. While this approach is applicable to loading such as pressure, bending, and tension, certain effects (such as rapid gas depressurization and impact damage) cannot be computationally simulated so easily and, therefore, are best assessed by testing. JPT
JPT • DECEMBER 2016
TECHNOLOGY FOCUS
Bit Technology and Bottomhole Assemblies Graham Mensa-Wilmot, SPE, Drilling Engineering Senior Adviser, Chevron
Rotary-steerable tools (RSTs) are now deemed mainstays in the drilling community. Their introduction, considering the directional-drilling challenges they sought to address and their overall effect on wellbore-construction efficiencies, injected lots of excitement into the industry. Initial successes facilitated expanded use of RSTs into other project types, notably vertical drilling and much-higherdogleg-severity (DLS) applications. To sustain the initial improvements achieved with the tools, several questions had to be raised. First, can simpler, efficient, and cost-effective RSTs be developed for vertical drilling? Second, do the higher-DLS conditions (greater than 8°/100 ft) present different challenges, and can the requirements be achieved with the existing tools? These questions initiated development of new and improved RSTs. Additionally, there was a clear realization that solutions for the challenges had to involve other disciplines. Yes, improved RSTs have been developed for higher-DLS applications. However, achievement of
[A]nalysis of RST vibration issues, as they relate to reliability and efficiency, must be executed holistically. this performance objective depends on several other factors and not just the RST. In addition to achieving the higherDLS requirement and ensuring delivery of useable wellbores, it is also important to have long runs at rates of penetration (ROPs) that reduce project costs and cycle times. Drilling vibrations, regardless of the specific modes, are seen as critical barriers to the achievement of these goals. In most instances, strategies used to improve DLS capabilities during drilling end up compromising other critical performance objectives. In this respect, the biggest losers are usually ROP and footage. If left unattended, these eventualities and the resulting strategies and consequences could end up having negative effects on cycle
Graham Mensa-Wilmot, SPE, is a senior adviser for drilling engineering at Chevron’s Energy Technology Company. He is the MAXDRILL (performance drilling) project leader and has more than 28 years of experience in drilling-applications research, downhole-tool development, drilling mechanics, drillingvibrations identification and remediation, and performancedrilling improvement. Mensa-Wilmot serves on the SPE/IADC Drilling Conference Program and SPE Drilling and Completions technical review committees. He is an SPE Distinguished Lecturer for 2016–2017 and previously served as a drilling-dynamics and performance-drilling instructor for the Petroleum Network Educational Courses series. Mensa-Wilmot serves on the technical board of the SPE Gulf Coast Section. He holds an MS degree in drilling engineering from Romania’s Petroleum-Gas University of Ploieşti. Mensa-Wilmot can be reached at gmensawilmot@chevron.com.
JPT • DECEMBER 2016
time, the very factor they were intended to improve. Researchers, in studying the unique effects of vibrations on drilling performance and specifically on higher-DLS requirements, have identified most of the driving factors. The elements include bits, reamers, bottomhole assemblies, drill designs, formation drillability, drilling parameters, stabilizer types, hole sizes, and drilling-fluid types. It is also worth noting that an RST, on the basis of its functioning principles, can also initiate vibrations. Consequently, analysis of RST vibration issues, as they relate to reliability and efficiency, must be executed holistically. Finding effective and lasting solutions that address RST vibration issues (on the basis of driving factors) requires a multidisciplinary effort where all hands have to be invited on deck. JPT
Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 178147 True Point-the-Bit RSS Upgrades Meet Well-Placement Challenges in High-Build-Rate Application: A Case Study From Kuwait by Mohamed Boushahri, Kuwait Oil Company, et al. SPE/IADC 178788 Fully Mechanical Vertical-Drilling System Delivers RSS Performance in Vertical-Drilling Applications While Providing an Economical Alternative to Conventional Rotary-Steerable-Systems Setup for Vertical-Hold Mode by Steve Jones, Scout Downhole, et al. SPE 175834 Insights of Wellbore Imaging and Lithology and Minerology Wireline Logs To Minimize the Uncertainty Regarding Bit Selection and Design, an Engineering Approach by Wael El Sherbeny, Baker Hughes, et al.
59
New Rotary-Steerable System Delivers High Dogleg Severity, Improves Penetration Rate
A
new rotary-steerable system (RSS) was designed to give geometrically greater dogleg-severity (DLS) capability while still being able to withstand the increased bending stresses. This high-build-rate RSS was able to eliminate controlled rate of penetration (ROP) as a limiter, which resulted in 39% ROP improvement. In addition, the development of a high-build-rate RSS provided multiple benefits, including elimination of ROP and logging-while-drilling limitations, increased curvature capabilities, and higher reliability of the system with respect to high-bending-related issues.
Introduction Directional-Drilling Methods. In the early days of directional drilling, the process involved jetting and the use of bent subs as the main methods for deviating a wellbore. These methods largely have been superseded by the use of engineered bottomhole assemblies (BHAs) for inclination-only control and motor or rotary-steerable BHAs for complete 3D control. Simple BHAs (Inclination Control). In simple BHAs, placement of stabilizer elements determines the net force on the bit and results in either a building or a dropping tendency of the BHA. A stabilizer placed close to the bit acts as a fulcrum, with one side being forced down by the weight of drill collars. Because of this, the bit will drill along a path
Fig. 1—Three-point geometry.
of increasing inclination and the BHA will have a tendency to build angle. On the other hand, a stabilizer placed significantly away from the bit will cause the collars below to sink to the low side of the borehole, pushing the bit to drill a path of decreasing inclination. This BHA will have a tendency to drop angle. A BHA designed to maintain direction will have stabilizers placed so as to create a rigid BHA, which will not bend in any direction with the force of gravity, causing the bit to drill along a straight path. Motor BHAs (Full Directional Control). Mud motors are used routinely to drill directional wells. They consist of a power section that converts mud flow into rotational movement of the rotor. The directional control is derived from an integral bent housing that can be adjusted to provide various bend angles. The higher the bend, the greater the capability to drill in a given direction, providing greater DLS. In this mode, the drillstring is kept stationary and the bit is rotated through the action of the motor only. To drill in a straight line, the complete assembly is rotated, which results in a tendency to drill along a relatively
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177836, “New Rotary-Steerable Drilling System Introduction in the UAE for ADCO Delivers High DLS Capabilities While Improving ROP and Providing Extensive Formation-Evaluation Data,” by Imran Tipu, Shurooq Abdulla Mohamed Al Jasmi, Juma Sulaiman Al Shamsi, Ali M. Danche, and Muhammad Javid, Abu Dhabi Company for Onshore Petroleum Operations, and Jehanzeb Nurzai, SPE, Enrico Biscaro, SPE, and Nour Shat, Baker Hughes, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
straight path. To drill in a particular direction, the motor bend is pointed in the given direction and weight is applied on the bit. This will result in the bit being tilted from the hole axis in the direction of the bend and in the formation being cut in that direction, thus achieving the required trajectory. Because the bend needs to be pointed in the direction of the turn, the motor BHA is not rotated when drilling. RSSs (Full Directional Control). RSSs achieve directional capability by creating a bend near the bit while the BHA is rotating. The most common type of RSS works on a point-the-bit or push-the-bit principle or a hybrid of both. Point-the-bit systems create the required bend through an internal mechanical or hydraulic arrangement that tilts the bit in the required direction. Pushthe-bit and hybrid systems, on the other hand, create the bend by pushing against the formation and bending the BHA in the required direction. Both systems are required to achieve this while the BHA is rotating. Geometrical DLS Capability. Any directional-drilling BHA will need to have the bit tilted relative to the main BHA axis to be able to drill in the given direction. The tilt angle and distance between the first three contact points (Fig. 1) determine the maximum DLS achievable by the BHA. These values will determine the geometrical limit that the BHA can achieve by design. By reducing the distance between the contact points while maintaining the same tilt, the DLS capability of the BHA will be increased.
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 60
JPT • DECEMBER 2016
In addition to geometrical constraints, the formation hardness will play a key role in determining whether the maximum geometrical DLS is achievable. A formation that is washed away by mud flow will have different geometry and will achieve lower DLS. Very hard formations will not allow easy penetration and will cause the actual DLS to be lower than the geometrical prediction. When the required DLS is not being achieved, the standard procedure is to slow down the ROP to allow the bit to cut in the required direction at its maximum. This reduces the forward movement, and, with maximum side cutting, a DLS can be achieved up to the geometrical limit.
Drilling 8½-in. Section With the Required DLS Drilling 8½-in. hole required building from vertical to horizontal in approximately 2,000 ft of section length. The build section consisted of a large shale sequence of varying properties. In some zones, it is easier to build angle; in other zones, properties limit the achievable DLS. The well-plan requirements called for an average DLS of 5°/100 ft or greater for this section. Using previous drilling experience, the planned well path in these wells was adjusted to achieve greater DLS in the beginning and later parts of the section and the required DLS was reduced in the middle. This resulted in maximum planned DLS of 7°/100 ft in some sections and 2–3° in other parts of the 8½-in. section. All these factors resulted in a planned and drilled well path that had high variation in DLS along its 8½-in. section. Almost every well had some 8½-in. section where the required DLS challenged the available tool limits and where failure to deliver the DLS meant that a plugback might become necessary.
Standard 8½-in.-Section RSS BHA Performance This section was traditionally drilled with an RSS with a logging BHA consisting of gamma, resistivity, neutron, and density tools. The standard BHA was optimized with a flexible stabilizer sub that would stabilize the RSS while maintaining enough flexibility to deliver the required DLS.
JPT • DECEMBER 2016
Because of the formation characteristics, it was sometimes necessary to control ROP to allow the RSS to achieve the required DLS. This was also the case if the formation tops were detected to be shallower during drilling and an early landing of the well had to be performed. Drilling with a controlled ROP to achieve the require DLS was identified as a performance limiter. Given that there was no other reason to control ROP, if DLS could be achieved without controlling ROP, an improvement of greater than 50% could be achieved.
the advantage of a greater geometrical DLS capability. A review of this application was performed, and the BHA was analyzed on finite-element software to determine ◗ That the required DLS could be achieved consistently without controlling the ROP ◗ That the BHA components would not be stressed beyond their rated stress limits It was concluded that the application had a good chance of success. There was little risk because all of the components had been proved through previous use.
Improved Steering-Unit Design Considering the ROP limitation imposed by the DLS requirements, it was determined that a different design with higher DLS capability was required. With the higher DLS capability, the tool could achieve the required DLS without controlling the ROP. Two possible scenarios existed for increasing the DLS capability: ◗ Make the current BHA more flexible so that small forces at the bit could create greater BHA deflection and thus greater DLS. ◗ Increase the geometric DLS capability by changing the BHA components and placement to create a high-DLS-capable configuration; this could be achieved by reducing the distance between the bit and the contact points behind it (i.e., stabilizers). The flexibility option was discarded because it was determined that the current BHA was already quite flexible and any more reduction in rigidity would increase the extent of damaging vibrations. The focus was then placed on increasing the geometric DLS capability. A high-DLS-capable RSS already had been released for the US land market capable of delivering a DLS of up to 15°/100 ft because of its geometrical design. The design placed the three contact points closer to each other, thus allowing a significantly greater DLS capability. The design and components were engineered to deliver the required DLS and were rated to withstand stresses at these high DLSs. The steering unit of this new RSS could be integrated into a standard BHA and could be used to deliver
Results Consistently higher on-bottom ROPs were observed when the new RSS was used to drill the 8½-in. sections. The incidence of controlled ROP fell to a minimum, and forces required to achieve required DLS dropped significantly. Another benefit was that wells could be planned with a consistent DLS because high DLS was now achievable throughout the section. JPT
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61
Bending Rules With High-Build-Rate Rotary-Steerable Systems
T
his paper explores the applications, benefits, and value of a high-buildrate rotary-steerable system (HRSS) capable of delivering dogleg severity (DLS) greater than 18°/100 ft. The application of this technology has led to an estimated savings of 40 days. Other benefits include better hole cleaning and smoother wellbores, leading to less wellbore tortuosity and improved postdrilling trips with drilling, logging, and casing assemblies.
Internal pads push against the ID of steering sleeve
Tool axis offset from the hole axis
Fig. 1—HRSS. ID=internal diameter.
Strike ring limits offset
Introduction Traditionally, steerable motors were used to drill an 8½-in. long-radius curve section requiring DLS of 6–7°/100 ft to land the well in the reservoir. Drilling longradius curves required drilling through problematic and unstable formations and would require approximately 1,000– 1,200 ft of vertical-section length to reach the target entry (TE). In another drilling scenario, sidetracking from a cement plug, the first run was always with a steerable motor with a measurement-whiledrilling (MWD) tool to the sidetrack and then 100–150 ft followed by a second run of a rotary-steerable system (RSS) and logging-while-drilling (LWD) tools. When sidetracking from a whipstock, though, the first run was with a motor and MWD tool, a gyro shot to the sidetrack, and then 150 ft, followed by a second run of the RSS LWD bottomhole assembly (BHA). The long-radius wells were kicked off in the Shilaif formation, and the well profiles require DLS of 6–7°/100 ft through the Shilaif and Maudud formations,
4.5°/100 ft through approximately 700-ft measured depth of Nahr Umr, and finally 6–7°/100 ft through Bab to reach TE. The initial approach to drill these wells using steerable mud motors resulted in only 62% shoe-to-shoe runs [i.e., 38% of the runs required more than one run to drill the 8½-in. section, and the average rate of penetration (ROP) to drill the section was only 24.6 ft/hr]. In addition, other risks are associated with drilling high-DLS wells with a conventional mud motor. For example, achieving the required DLS, the inability to rotate the drillstring runs the risk of poor wellbore quality, hole-cleaning issues, and potential sticking while sliding in overbalance conditions of 2,000– 3,500 psi. These risks resulted in extra trips, extra wiper trips, and multiple reaming trips before running the 7-in. liner. The solution allowed for drilling 85% faster than with conventional motors, and shoe-to-shoe runs increased to 86.2% compared with 62% with motors.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177898, “Bending Rules With High-Build-Rate RSS,” by Imran Tipu, Eman Alawadhi, R. Kumar, Batyr Amanov, Mohamed A. El Gebaly, A.M. Al-Hammadi, A.M. Bin Shamlan, and Ali M. Danche, Abu Dhabi Company for Onshore Petroleum Operations, and Sukesh Ganda, Rajan Dua, and Nour Hariri, Schlumberger, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
Universal joint acts as pivot point
The success of the RSS deployment paved the way for improving future drilling efficiency, yet two limitations remained with the conventional RSS system: ◗ Whipstock exits—For the whipstock exits, two runs were required, a conventional-motor run to exit the magnetic interference followed by an RSS run to drill to total depth of the section. ◗ Dogleg assurance—The conventional RSS is capable of delivering 7–8°/100 ft in Shilaif, Maudud, and Thamama formations and 4.5°/100 ft in the Nahr Umr formation.
Solution The HRSS, which is capable of providing DLS of up to 18°/100 ft, was introduced as a solution. With the use of HRSS, the intent was to drill vertically, curve, and land the well in a single run, eliminating at least one bit run (the motor and gyro run). Although the success of the project was based on existing technology, innovation was required. Innovation included the HRSS being run with an engineered sixbladed bit with 16-mm cutters, designed specifically for this application using an integrated drillbit-design software. To be able to achieve the required high DLS, engineering analysis was conducted for the bit. A bit analysis was conducted with the software to analyze and compare a
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 62
JPT • DECEMBER 2016
SOCIETY OF PETROLEUM ENGINEERS
six-bladed bit with 16-mm cutters and a six-bladed bit with 19-mm cutters. The analysis program generated up to 50 iterations of weight on bit and revolution/minute combinations, and outputs generated were BHA dynamics and DLS predictions. The most stable bit was selected. As per the drilling simulations, the bit with the 16-mm cutters produced less lateral acceleration, less stick/slip, and less bit bouncing than the bit with the 19-mm cutters. To ensure consistent DLS and steerability and to manage fatigue, various BHA designs were put through an in-house drilling simulator. For the planned BHAs, critical resonance frequency analysis was conducted. The analysis gave the revolutions/minute that, once induced, can initiate BHA dynamics that can result in detrimental shocks and vibrations and steerability-control issues and that need to be avoided while drilling. Using the simulator analysis for axial, lateral, and torsional displacement on the HRSS BHA and comparing the results with various BHA options helped finalize stabilization points along the BHA. Further, the BHA was designed to reduce connections as far as possible, and this was accomplished by integrating the float, filter, and flow-sleeve subs into existing BHA components.
HRSS Principle of Operation The HRSS (Fig. 1) is a true hybrid system that combines the principles of push-thebit and point-the-bit systems to deliver the maximum DLS. The touch points for the system are the bit and two stabilizers on the collar of the tool. In steering mode, the electronics stabilize a geostationary valve that diverts mud to the steering unit. At any given time, two pistons are energized simultaneously. This is the push part of the system. When energized, the piston strikes against the inner diameter of the steering sleeve. The resultant force vector deflects the steering sleeve, and the amount of deflection is limited mechanically and electronically. The entire assembly is pivoted on a universal joint close to the bit, which deflects the bit in the desired direction. This is the point action of the system. Because the pivot is internal to the tool and is very close to the bit, the system delivers high, consistent, repeatable DLS independent of the type of formation. In neutral mode, the electronics rotate the control valve continuously and
JPT • DECEMBER 2016
the bit force is distributed uniformly along the borehole wall and with the borehole axis, thus drilling ahead without generating any DLS.
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Twenty-two shoe-to-shoe wells were delivered using the HRSS, wells that previously could be drilled only with a mud motor yet were drilled with wellbore quality of an RSS. Nine wells were sidetracked from vertical cement plugs. Time savings of 2.5 rig days per well was seen, translating to USD 250,000 per well. Four complicated wells were drilled, 3D profile wells with 72° inclination and 33° azimuthal turns and with continuous DLS of greater than 7°. Two wells were kicked off in the Nahr Umr formation with planned DLS of 6.4°/100 ft and 5.6°/100 ft. A consistent DLS of greater than 6°/100 ft was delivered across the Nahr Umr. Fourteen short-departure wells, all with departure less than 900 ft, were drilled in single runs (drilled shoe to shoe). Improved ROP. A total of 3,792 ft was drilled in 105.9 hours with the HRSS in a single run.
Conclusions An HRSS was deployed in a challenging drilling environment in the UAE. The system was run with a six-bladed bit with 16-mm cutters designed specifically for the application. Deployment of the technology allowed the kickoff point to be pushed deeper, reducing risk and cost. During execution, even though applications did not call for DLS greater than 8°/100 ft, the HRSS showed a DLS capability of greater than 18°/100 ft. The section that previously required two bit runs was drilled in a single run, resulting in average savings of 2 days per well. Technology and engineered solutions led to finishing the well with an outstanding performance of 85% ROP improvement over the average ROP of offset wells being drilled with conventional assemblies. So far, the introduction of a superior drilling system has led to savings greater than USD 4 million. JPT
ANNUAL TECHNICAL CONFERENCE AND EXHIBITION
San Antonio, Texas, USA 9-11 October 2017 www.spe.org/atce/2017
Call For Papers Paper Proposal Submission Deadline: 31 January 2017 Submit your proposal online at www.spe.org/atce/2017 Technical Categories: • Completions • Drilling • Health, Safety, Security, Environment and Social Responsibility • Management and Information • Production and Operations • Projects, Facilities and Construction • Reservoir Description and Dynamics
S P E C E L E B R AT E S 6 0 Y E A R S “Looking Back to Move Forward.”
Improvements in Root-Cause Analysis of Drillstring Vibration
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rillstring vibration is a leading cause of downhole-tool failure and premature wear of downhole equipment. The main challenges faced during drilling include performing rapid analyses to determine the root cause of the vibration, clear identification of the active mechanism, and implementation of the appropriate corrective action quickly enough to prevent failure. This paper describes a comprehensive methodology created to identify root causes, vibration mechanisms, and methods to reduce or eliminate drillstring vibration.
Introduction A bottomhole assembly (BHA) and drillstring have six degrees of freedom and three dominant modes of vibration: axial, lateral, and torsional. This movement is used to describe the different vibration mechanisms such as stick/slip; bit bounce; bit whirl; BHA whirl, both forward and backward; torsional resonance; bit chatter; modal coupling; and lateral shocks. Data are collected from downhole and surface sensors, as well as cuttings analyses, that measure modes and magnitudes of vibration, tension, compression, and bending within the BHA; drilling parameters; fluid properties; and lithology and rock properties. The methodology uses some or all of these factors to identify the root cause and is enhanced by the ability to summarize the distribution of vibration levels across a run, by histogram analysis, and by the ability to filter across time or depth ranges and filter further on the basis of rig-activity codes.
A combination of factors generates or influences drillstring vibration, including the energy inputs of weight on bit and torque; bit type; BHA design and stabilization; lithology type; geological structures; bit/lithology interaction; borehole and BHA size; hole trajectory; backreaming or rotating off-bottom; hole enlargement; the rig’s electrical system; and, on offshore floating vessels, rig heave. The methodology is able to identify and isolate which factors are the root cause of a specific mechanism by incorporating time-based analyses with depthbased logs and plotting a to-scale BHA to identify correlations of the bit position, stabilizer, and other BHA components to formation types and boundaries, holesize changes, and casing positions. This enables a significantly faster data analysis and a more rapid assessment of the root cause of the vibration, thereby delivering specific benefits through identifying and then reducing or eliminating drillstring vibration on a range of different operations.
Vibration Mechanisms The starting point in a root-cause analysis is to identify the presence of vibration and classify it into different mechanisms that describe the differing mechanical behaviors of the drillstring and BHA. This allows for further definition within the analysis by using the mechanisms to narrow the potential options for the root cause on the basis of the type of vibration that can generate the mechanism and the factors that affect the vibration. Mechanically, the BHA behaves as a pipe, a beam, a column, and a shaft and
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IADC/SPE 178819, “Improvements in the Root-Cause Analysis of Drillstring Vibration,” by Jeremy A. Greenwood, SPE, Halliburton, prepared for the 2016 IADC/ SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
has six degrees of freedom with three mutually orthogonal axes: x and y perpendicular to the drillstring and z parallel to the drillstring. The vibration mechanisms are classified by which motion dominates the dynamic behavior when vibration occurs and by the specific frequency range of the dominant vibration. Nine discrete mechanisms have been identified as part of the root-causeanalysis methodology: stick/slip; bit bounce; bit whirl; BHA whirl, either forward or backward; lateral shocks; torsional resonance; parametric resonance; bit chatter; and modal coupling.
Types of Vibration Once the mechanism has been identified, it is further categorized by type—free, forced, or self-excited—because this governs the source and type of energy inputs that generate the vibration. Free vibrations are excited by a force or impulse applied to a system. The vibration can occur at one or more of the system’s natural frequencies. If no damage occurs as a result of the original impulse, the vibration will decay as a result of the dissipation of energy through system damping. Forced vibrations are caused by a periodic external excitation source, such as mass imbalance during rotation. These forces are periodic in nature (e.g., the rotation of a drillstring with a mass imbalance, such as a bent housing on a motor); the period of the excitation force in such an imbalanced system is governed by the rotational speed. When such a force acts on an elastic solid (in this case, the drillstring, which has its own natural frequency), the interaction of the frequencies produces extremely large vibrations when the input frequency coincides with the natural frequencies. This interaction is referred to as forced resonance, because the elastic solid is forced to vibrate at its natural
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 64
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frequency by excitement from a periodic energy input. Self-excited vibrations are caused by a constant energy source, which may be either external or internal to the system and is defined as the conversion of nonoscillatory energy into vibration. There are similarities to forced resonance in that the system will vibrate at a natural frequency. However, the important difference is that the source of excitation is constant in this case, not periodic. Therefore, although the energy source has a bearing on the amplitude of the vibration, it has no bearing on the frequency at which the system vibrates.
Root-Cause-Analysis Methodology The first stage of the analysis is the identification of the presence of vibration and its location and duration within the wellbore. Because vibration is a time-based phenomenon, a time-based log must be created with all of the vibration information and surface drilling parameters, including torque; revolutions/minute; hookload; weight on bit; standpipe pressure; mud-flow rates; block height movement; bit depth and hole depth; and, if a positive-displacement motor or turbine is being used, downhole annular and drillpipe bore-pressure readings. This allows all on- and off-bottom activities to be analyzed and captures all incidences of vibration and the varying energy inputs into the system. Next, an analysis of a depth-based log containing downhole-vibration measurements, surface drilling data, and other information directly related to the depth of the well—including wellbore-trajectory information, the formation type and thickness, and a description of formation properties, a scale representation of the BHA and drillstring, and, if available, hole-caliper information—is required. These methods identify the vibration’s location in the wellbore, its duration, and the drilling activity during which the vibration occurs. The occurrence and duration of vibration are recorded, and each event can be investigated individually. For each event, the next stage in the root-cause-analysis methodology is to categorize the vibration mechanism from the different measurement sources, including triaxial accelerometers
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from which the peak and average vibration levels are processed and from which high-frequency data can be analyzed to determine the dominant frequencies and amplitudes. Once the mechanism has been established, it is then categorized by the potential vibration type. Because each vibration mechanism has differing methods of initiation, a different work flow is applied to each one to determine the root cause. The information required is drawn from different sources, and a quantitative assessment of the duration and severity of each event and the levels of the energy inputs is made, not just a qualitative assessment of the occurrence.
Factors Affecting Vibration In addition to identifying the types of vibration, all of the factors that affect the initiation of the different behaviors must be identified and quantified within the analysis system, and a determination as to whether they are the root cause or are a contributing factor should be made. These factors include drilling parameters such as revolutions/minute; torque; hookload; standpipe pressure and mudflow rate; hole angle and azimuth; dogleg severity; drilling-fluid type; borehole size; drillstring and BHA size and stabilization; bit type; lithology; bit/lithology interaction; on- or off-bottom rotation; back reaming; the rig’s power system; and, when offshore on floating vessels, rig heave.
drilling, circulating, tripping in, tripping out, and reaming. To identify forced resonance and distinguish between the different whirling mechanisms, a finite-element model was developed to predict the natural lateral frequency and harmonics for the specific BHA. The application containing the model has the ability to compare the calculated frequencies against the excitation sources, such as the bit, straightbladed stabilizers, and mud-motor nutation frequencies. Confirming the frequency responses of the vibration requires that high-samplerate downhole burst data be captured and high-sample-rate surface measurements be taken so that a quick Fourier transform can be performed on each measurement and the dominant frequencies and amplitudes can be determined. Predrill calculations of drillstring torque and drag values and the potential for and location of buckling need to be updated with measurements from the well being drilled to identify if they are a root cause or contributing factor. JPT
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Analysis Tools The duration of an event can be relatively brief—a few minutes—or sustained for many hours. Tools were developed to create summary histograms from the data from each downhole-vibration measurement, including a force-measurement tool containing the severity and duration at each severity level. The histogram analysis can be performed on time- or depth-based data for the entire bit run or can be limited to a specific range to investigate a specific event. A filter also can be applied to separate the data into different drilling activities so that the relative severity of the event under different conditions can be determined and any correlation to on- and off-bottom conditions can be established. The filter settings are
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TECHNOLOGY FOCUS
Water Management Syed A. Ali, SPE, Consultant
Considering the current downturn in crude prices, there is a renewed interest in recycling produced water for reuse in hydraulic fracturing in the development of unconventional resource plays. As the hydrocarbons are produced, large quantities of water containing high amounts of total dissolved solids (TDS) are also produced in the process. Most of the produced water usually is reinjected into disposal wells. This practice has become a topic of public concern after reports of earthquakes began approximately 5 years ago in the central United States, where disposal wells are heavily used. Reusing produced water as the base fluid for hydraulic fracturing not only alleviates the operators’ dependence on fresh water but also lowers the overall cost of fracturing treatments. Produced water usually is composed of natural formation water and flowback water. Flowback water is water that was a large component of fracturing fluids injected into a well at high pressure as a part of the hydraulic-fracturing treatment. Within a few hours to a few weeks
Reusing produced water as the base fluid for hydraulic fracturing not only alleviates the operators’ dependence on fresh water but also lowers the overall cost of fracturing treatments. after the fracturing job is completed, a portion of the injected water returns to the surface. It typically contains much higher levels of chemical constituents, including TDS, than the original fracturing fluid did. The amount of produced water, and the chemical constituents (i.e., anions and cations) and their concentrations present in the produced water, usually varies significantly over the lifetime of a field. Early in the process, the water-generation rate can be a small fraction of the oilproduction rate, but it can increase with time to tens of times the rate of oil produced. Compositionally, the changes are
Syed A. Ali, SPE, is a consultant. Previously, he was a technical adviser with Schlumberger, and, before that, he was a Chevron Fellow with Chevron Energy Technology Company. Ali became an SPE Honorary Member in 2015, and he received the 2014 SPE DeGolyer Distinguished Service Medal, the 2012 SPE Distinguished Service Award, and the 2006 SPE Production and Operations Award. He served as an SPE Distinguished Lecturer in 2004–2005. Ali holds BS, MS, and PhD degrees. He served as executive editor of SPE Production & Operations and currently serves on several SPE committees, including the JPT Editorial Committee, the Completion Optimization and Technology Award Committee, the Well Operations Subcommittee, and the Completions Advisory Committee. Ali can be reached at syed1940@gmail.com.
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complex and field-specific because they are a function of formation mineralogy, oil and water (both in-situ and injected) chemistry, rock/fluid interactions, type of production, and the required additives for oil-production-related activities. To reuse the high-TDS produced water as a base fluid for formulating crosslinked-gel-based fracturing fluids, the water must first be treated to remove ions that hinder the development of crosslinked fluid or that cause scale buildup in the wellbore. An ideal solution would be to reuse the high-TDS produced water in subsequent fracturing treatment with no treatment or fit-for-purpose treatment. The papers featured this month deal with a fit-for-purpose treatment of produced water, a new guar-based system that allows the use of 100% produced water without treatment as a base fluid, and produced-water reinjection. I hope you enjoy reading the selected papers and search for additional papers in the OnePetro online library. JPT
Recommended additional reading at OnePetro: www.onepetro.org. SPE 175206 Produced-Water Injection— The Challenges Faced by N. Bhola, Jorin, et al. SPE 177067 The Integrated Approach to Formation-Water Management Part 2: Field Applications and Best Practices by R. Correa, AGIP Oil Ecuador, et al. SPE 181588 Reuse of Produced Water by Membranes for Enhanced Oil Recovery by Remya Ravindran Nair, University of Stavanger, et al.
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Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing in the Permian Basin
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ourcing water for large multifracture stimulations in west Texas is a well-known constraint on oil and gas activities in the area. A 6-month pilot operation demonstrated that produced-water reuse is technically feasible and can be a cost-effective solution. A fit-forpurpose treatment scheme was created to remove free oil, suspended solids, hydrogen sulfide, and iron and to render microorganisms inactive. The technical approach developed allowed for the use of salty produced water for completion activities using a new type of friction reducer.
Introduction The oil and gas industry has identified water management as one of the top challenges for energy extraction from unconventional resources. In the Permian Basin, surface water and groundwater resources are scarce and large multifracture stimulations regularly require more than 100,000 bbl of water per well. The Texas Railroad Commission also employs a geologist to assess seismicity at water-disposal facilities. Because of these challenges, many operators in the Permian Basin have begun to investigate and implement producedwater reuse. Produced-water-reuse initiatives executed in early 2014 paved the way for full-field produced-water-reuse implementation. The water-management team identified that produced-water
reuse could significantly reduce effects to the limited water resources in the Permian Basin and help achieve sustainable-development objectives for the company. Several wells were identified as suitable candidates for the pilot because they were designed to be stimulated with a slickwater/crosslink base fluid. Additionally, these new wells were being developed in the proximity of existing producing wells, so the produced water from the existing wells can be treated easily and used to complete the new wells. The team selected multiple wells from conventional and unconventional assets to qualify water-treatment and stimulation chemistry technologies for produced-water reuse.
Pilot Setup and Operation Fig. 1 shows the site arrangement during the pilot test. The untreated water was stored in a set of 15 tanks, which were fed with produced water from 130-bbl delivery trucks hauling produced water from the production battery. After the treatment, produced water was stored in two sets of 10 holding tanks. Treated-water quality was measured before transferring the water into the storage tanks. The water-treatment-pilot studies for iron removal were conducted over a period of 6 months. This involved oxidation followed by clarification and filtration. A similar setup was used for hydrogen sulfide (H2S) removal, with the exception that no clarification step
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18340, “Fit-for-Purpose Treatment of Produced Water for Hydraulic Fracturing—A Permian Basin Experience,” by Ramesh Sharma, SPE, Kristie McLin, SPE, Kevin Bjornen, SPE, Austin Shields, SPE, Zakir Hirani, and Samer Adham, SPE, ConocoPhillips, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission.
was used. The entire treatment process ran in a semicontinuous mode. The untreated produced water was transferred safely from a bank of receiving storage tanks into the reaction tanks. Sodium hydroxide and hydrogen peroxide were gravity fed into the reaction tank containing produced water. The amount of sodium hydroxide added was controlled to obtain an optimum pH of between 7.4 and 7.6 for iron hydroxide precipitation. After 30–40 minutes of recirculation, residual-oxidant and dissolved-iron concentrations were measured. Oxidant residual of more than 50 ppm and dissolved-iron concentration of less than 5 mg/L were considered adequate for transferring produced water from the reaction tank to settling tanks. It was found that 3–4 hours of settling time was sufficient to settle the iron precipitates. Once the total iron concentration in the clarified produced water dropped below 10 mg/L, the produced water was transferred to weir tanks. A longer settling time is anticipated during winter operation because of an increase in the viscosity of the produced water. A two-step filtration process using a primary filter and a polishing filter was used to ensure that the treated produced water met turbidity specifications of less than 10 nephelometric turbidity units (NTU). Each bag filter was rated at 5-µm absolute pore size and contained 4.4 ft2 of media surface. Each filter pod contained eight bags, providing a total filtration area of 35.2 ft2. Filter replacement required approximately 30–45 minutes of operator time; therefore, a second filter train was provided to allow continuous operation. The used bag filters were sent to a certified oilfieldwaste-handling facility for disposal. The treated produced water leaving the filtration step consistently met the water-quality goals of less than 5 mg/L
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • DECEMBER 2016
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PRODUCED WATER: Six Evergreen Tanks; Mainfolded and Isolated
Trash Trailer, Two Portable Toilets Trailer, Water Tank, and Septic Tank (From North to South)
CLEAN BRINE: Eight Evergreen Holding Tanks; Manifolded and Isolated
Evergreen Evergreen Tank Tank for Oil for Peroxide Treatment
FRESH WATER: Six Nabors Tanks With an 8-in. T-Valve on the Third Tank; Manifolded With a Double Valve Splitter
CLEAN BRINE: 16 Evergreen Holding Tanks; Eight Tanks for Each Bank; Manifolded
Evergreen Tank for Sludge Four Empty Evergreen Tanks; Manifolded and Isolated
CLEAN BRINE: Six Evergreen Tanks With an 8-in. T-Valve on the Third Tank; Manifolded and Connected to Splitter
CLEAN BRINE: 13 Nabors Tanks Manifolded
6×3 Pump
Smart Chemical Treatment Equipment
Fracturing Tank
Texturized 40 m Containment
Chemical Trailer
CLEAN BRINE: 34 Evergreen Holding Tanks; 17 Tanks for Each Bank; Manifolded
Need Enough Space for 10×8 Pumps During Fracturing
4×4 Pump
Light Plant
Filtration Unit
Hydrocyclone
Shower Trailer
Dissolved Air Filtration Unit
Fig. 1—Schematic of tank arrangement for treatment and storage of produced water.
of total iron and turbidity less than 10 NTU. In addition, a peroxide residual of 10–20 mg/L was carried through the filtration step to achieve inactivation of any surviving bacteria. The residual oxidant disappeared after 2–3 hours of contact time in the storage tank. The finished produced water was retreated after 2 weeks with biocide to prevent any regrowth of microbial population. The biocide is compatible with cationic and anionic friction reducers and is soluble in solutions containing greater than 15% solids.
Results and Discussion Treated-Water Quality. The treatment for H2S removal included oxidation with H2O2 followed by filtration. The H2O2 dosing to the reaction tanks was adjusted on the basis of the inlet and outlet H2S concentrations measured in the reaction tanks, with a target concentration of outlet H2S at less than 0.2 mg/L.
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The treatment process was operated in a semicontinuous mode to allow for H2O2dosing adjustments. With the inlet H2S concentrations varying between 400 and 600 mg/L, the treated-water H2S concentrations were consistently below the method detection limit of 0.2 mg/L. Similar to the H2S-treatment pilot, the treated-water samples were also collected during the iron-removal pilot and were analyzed on-site for turbidity, iron, pH, and residual H2O2. Comprehensive analysis on select treated samples was conducted at a certified laboratory. The treated-water iron concentrations were mostly below 2 mg/L throughout the test period; the median produced-water (inlet) iron concentration was 70 mg/L. The turbidity in the treated water stayed consistently below 10 NTU. Friction-Reduction Test. The frictionreduction testing conducted at laboratory scale with constant Reynolds num-
ber indicated that deionized water and the treated produced water had identical pressure drops. Field observation showed similar behavior, which helped qualify the treated water as a substitute for fresh water in slickwater fracture jobs. Gel-Stability Testing With Crosslinkers. Further laboratory testing was conducted in which the ratios of treated produced water and fresh water were varied to find the optimum blend suitable for crosslinked-gel systems. These tests indicated that a 75%-producedwater mixture would perform efficiently for a longer pump time and a 100% mixture for a shorter pump time. The 100% produced water recovered quickly after shear but degraded rapidly because of an increase in temperature. Qualification of H2S-Removal Process for a Vertical Well. The produced
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water collected from the production facilities was transferred to the on-site tank battery and to the storage tanks using a polymeric line. An oil-skim tank was placed between the battery and the storage tank to provide sufficient residence time to skim oil from the produced water. Initial H2S concentration in the produced water ranged between 400 and 600 ppm. A sufficient amount of H2O2 was added to the storage tank until the H2S concentration fell below the detection limit. The treated water was sent to a nearby well pad for fracturing, which eliminated trucking cost. After successful qualification of the H2S-removal process for the vertical wells, the process was evaluated to address iron removal for horizontal-well application. Qualification of Iron-Removal Process for Horizontal Wells. The treated produced water was used successfully in four horizontal wells, each of which used more than 100,000 bbl
of total fluid per well during the pilot study. The treated water was qualified for use as a slickwater fracturing fluid after undergoing satisfactory testing with a brine-compatible friction reducer. The fluid was pumped without any issue on the slickwater stages of four development wells in the area. Step-down tests were performed to confirm that there was no excess pipe friction over previous freshwater-treated wells. Lessons learned from the vertical-well pilots were incorporated into larger-scale horizontal wells.
Conclusions Any water-treatment program for hydraulic fracturing must be fit for purpose to meet fracturing-fluid-rheology and formation-compatibility requirements. The infrastructure and availability of water-supply and -disposal options can be key drivers in making the decision to reuse water. Producedwater reuse is a game changer for Permian Basin completions. Reducing freshwater use has positive health/safety/en-
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vironment and financial implications. Thousands of trucking trips can be eliminated, thereby avoiding major incidents or spills. The fit-for-purpose treatment selected to treat salty produced water (greater than 220 000 mg/L total dissolved solids and iron between 70 and 165 mg/L) for completion activities using a new type of friction reducer was oxidation followed by filtration. The iron in the produced water was oxidized by adding H2O2, followed by adjustment of pH using caustic to precipitate the colloidal iron. A two-stage 5-µm bag filter was used to ensure that the clarified water met the turbidity specification. The treated water was qualified for use as a slickwater fracturing fluid after undergoing testing with a brine-compatible friction reducer. The fluid was pumped without any issue on the slickwater stages of four development wells in the area. No significant hydrocarbon production variations from the previously established type curves were seen in these wells. JPT
Solving Produced-Water Challenges With a Novel Guar-Based System
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his paper summarizes the benefits of using a bipolymer crosslinking system in environments where water quality cannot be guaranteed. In addition to the cost advantages of using a crosslinking system that uses a conventional gelling agent, this paper also demonstrates the yielded cost savings per well that are achievable when reusing 100% produced or flowback water for hydraulic fracturing. The new fluid system consists of a specially formulated biopolymer crosslinking system that is not affected by the inconsistent quality of produced/ flowback water typically associated with fracturing applications.
Introduction Water management is an environmental and logistical challenge to many operators across the United States. With the typical unconventional horizontal well requiring, on average, more than 8 million gal of water in a standard stimulation design, the need for an alternative to fresh water is a growing concern. A common approach to help mitigate freshwater use is on-site or centralized filtration to return produced or flowback water to a usable base fluid and even to fresh water in some cases, depending on the chemistry used and application. Filtration methods are considered a standard approach that lowers completion costs in terms of disposal reduction and freshwater conservation. However, many fracturing chemistries require increased filtration methods that create not only increased solid waste but also an associated cost burden be-
cause the cost of recycled produced water is more than double that of fresh water. As industry operators seek to lower completion costs, one practical approach is use of a slickwater-fracturing-fluid additive that is robust enough to withstand high salinity divalent environments and boron content when crosslinked fluids are used. One unavoidable hurdle to the use of produced water is free-floating iron content and destructive bacteria that, if not controlled, can present compatibility concerns not only in fracturing fluid but more so in post-completion well performance. Increased acceptance of oxidizing bactericides, such as chlorine dioxide (ClO2), which quickly penetrate encapsulated bacteria, has further enabled the use of produced water with reduced filtration for optimal well completion. With the ability to oxidize the solution at a controlled rate, iron sulfide (FeS), solid soluble particles, suspended solids, and organic materials are flocculated out, which allows impurities to settle out of solution and enables more-effective removal of flocculants with on-the-fly canister filtration. Oxidization of FeS and iron transforms them from soluble ferrous iron to ferric iron and results in accelerated settling of flocculated particles by final composition of ferric hydroxide (Fig. 1).
Technology Advancements in fluid design, such as bipolymer linear and crosslinked fluids with the addition of robust frictionreducer additives, enable making optimal fracturing fluids from 100% produced water. However, even when bi-
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177678, “Solving Field Produced-Water Challenges With a Novel GuarBased System: A Comprehensive Review of Actual Field Examples and Cost-Savings Analysis,” by Branden Ruyle, SPE, and Francisco E. Fragachan, SPE, Weatherford, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
polymer crosslinked fluids are designed to remain compatible in fluids with high total dissolved solids (TDS) and are formulated to exhibit optimal regainedpermeability performance, source waters containing destructive bacteria and freefloating FeS present an unavoidable challenge to achieving satisfactory long-term well performance. ClO2 is a powerful oxidizer bacteria solution that has been used in the United States for more than 74 years with a focus on water-treatment facilities and municipal applications. ClO2 was accepted by the Environmental Protection Agency (EPA) as a safe yet powerful disinfectant in the 1974 Safe Drinking Water Act. The need for the economical use of produced water and the EPA’s approval are major factors leading to recent increased acceptance of ClO2. ClO2 is commonly a three-part aqueous system consisting of sodium chlorite (NaClO2), sodium hypochlorite (NaClO), and hydrochloric acid (HCl) not exceeding 25, 12.5, and 15%, respectively. When the three precursor chemicals are introduced at determined ratios, ClO2 is formed in concentrations between 2,000 and 3,000 ppm, which allows for increased oxidation effectiveness but is dilute enough to be handled safely and to perform effectively as a fracturing fluid. Common practice of on-site ClO2 generation is to use motive water driven by a Venturi eductor system. Motive water is generated by transferred water creating suction as water travels through the ClO2 generator. The Venturi effect creates continual suction as water flowing through the eductor pulls together all three precursor chemicals at continuous rates into the reaction chamber, ultimately being diluted into source water per the required demand for raw water. The first of two reactions is combining 15% HCl and a 12.5% solution of sodium hypochlorite (bleach) in the reaction
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 70
JPT • DECEMBER 2016
(a)
(b)
(c)
(d)
Fig. 1—(a) Raw source water with 3,232 ppm total suspended solids with FeS present. (b) Introduction of ClO2. (c) Solution allowed to mix for 2 minutes before static settling and flocculation of impurities occurred in 10-minute increments. (d) Solution after being poured through coarse filter paper to simulate media filtration.
chamber at the required flow ratio with respect to motive water through the generator and demand of raw water, which generates a small amount of hydrated chlorine (2HCl+NaClO→Cl2+H2O+NaCl). Then, in the second reaction, 25% sodium chlorite is introduced at a controlled rate with respect to motive water through the generator and demand of raw water to create Cl2+2NaClO2→2ClO2+2NaCl. Aqueous ClO2 generated in the second reaction is carried from the reaction chamber to be diluted into source water that enables the Venturi eductor. This method of mixing precursor chemicals increases well safety by mitigating the possibility of generating chlorine without motive water essentially to prime the generator. The greatest completion efficiencies are gained by reducing the filtration processes required to use produced water. Recent advantages in produced-watercompatible fluids have allowed the combination of slickwater crosslinked with ClO2 technology to form an efficient solution when using 100% produced water in fracturing applications. Advancements in bipolymer technology enable crosslinked fluids to remain optimal in high-TDS produced water. Rheological performance data also show shear stability with respect to baseline viscosity. Although filtration is not necessary for crosslinked fluid to remain optimal, it is recommended that suspended solids be mitigated to a size of less than 400 µm. Combining bipolymer technology using ClO2 to kill bacteria and real-time, inline, flow-through-canister filtration to reduce solids enables cost-effective produced-water use. When effectively dosed, ClO2 effectively oxidizes iron and organic impurities, enabling complete removal of impurities. Advanced fracturing fluid is optimal at neutral pH, which allows for traditionally
JPT • DECEMBER 2016
known interfering ions to remain in solution and reduce scaling tendencies. When divalent ions are present, scale tends to occur in two forms: carbonate and sulfate. Because bipolymer technology has more-neutral pH, scaling tendencies are reduced to sulfate scaling. The ability of ClO2 to oxidize iron, phenols, manganese, and sulfites greatly reduces formation of sulfates and their ability to bond to calcium and barium to form insoluble scaling as a well begins production. In relation to formation-damage control, bipolymer technology optimizes on neutral pH levels, allowing divalent ions such as calcium, magnesium, and iron to remain in solution, whereas more-traditional fluids require alkaline pH levels, which create an environment for calcium, magnesium, and iron to precipitate out of solution and cause near-wellbore damage.
SPE Hydraulic Fracturing Technology Conference 24–26 January 2017 The Woodlands, Texas, USA The Woodlands Waterway Marriott Hotel and Convention Center
Conclusion Water reuse for fracturing applications is not new. Water reclamation is a common practice not only in fracturing applications but also in agriculture. As more-economical completion methods are continually being considered, advancements in fluid technology allow for increased efficiencies in terms of perbarrel-cost reduction in filtration, in turn reducing pretreatment requirements by 87% (assuming the requirement to filter 200,000 bbl). Use of biopolymerfluid technology and greater acceptance of ClO2 have enabled increased use of produced water, with savings per well ranging from USD 55,000 to more than USD 600,000, depending on various ratios of produced-water use. Economic advantages and reduced environmental impact are gained by mitigating on-site or centralized filtration and the waste disposal that typically occurs as a result of TDS and mineral removal. JPT
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Produced-Water Reinjection— Case Study From Onshore Abu Dhabi
W
ater production normally increases as fields mature, and two main ways exist to deal with the produced water. One is to dispose of the produced water into dedicated disposal wells. The other is to reinject the produced water for pressure maintenance or sweep efficiency. In 2010, a produced-water-reinjection (PWRI) project began in a giant field that involved replacing the aquifer water being injected in one of the waterinjection clusters with produced water without water treatment.
Case History This project was conducted in a giant onshore field in Abu Dhabi. This field is approximately 85 km southwest of Abu Dhabi Island and consists of multistacked reservoirs. The main reservoir, where the project was conducted, will be referred to as Reservoir 1. Reservoir 1 has approximately 75% of the field’s proven reserves and contributed approximately 90% of the field’s oil production when the project began. Almost all the produced water in the field is injected water from Reservoir 1. Reservoir 1 has been a waterflooded reservoir since the 1970s. The waterflooding project was completed in different stages. First, peripheral waterinjection wells were developed. At the start of the PWRI project, the average reservoir water injection was approximately 500,000 BWPD. The injection water is delivered and injected through waterinjection clusters. Each cluster normally consists of a water-supply well completed
through aquifers and produced by electrical submersible pumps, a surface pump, and a network of pipes distributing the water to the injection wells connected to that cluster. The nominal capacity of a cluster is 20,000–30,000 BWPD, and, on the basis of a well’s injectivity and injection requirements, five to 10 wells may be connected to each cluster. Reservoir 1 started to show water production in 2000. This water production is entirely from water breakthrough. The natural reservoir aquifer is very weak, and its petrophysical properties are not supportive of aquifer-water production. During the past 15 years, the reservoir’s water cut increased to approximately 17%. Production forecasts show that the reservoir’s water production is expected to increase to more than 150,000 BWPD by 2020. Handling this increasing water production is an important part of the reservoir’s development. In 2010, the decision was made to pilot reinjecting the produced water with one of the existing water-injection clusters in Reservoir 1 (Cluster 16). This cluster was selected to be the pilot because it is near the processing area, minimizing the cost of laying pipes to transfer the produced water to the injectors. The water-injection performance was closely monitored with wellhead injection pressure (WHIP), injection rate, and tests to detect any injectivity effects. Pressure-falloff (PFO) tests were performed frequently to detect any formation damage associated with the PWRI. Moreover, production logging was performed in one of the wells before and
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177538, “Produced-Water Reinjection—Case Study From Onshore Abu Dhabi,” by K. Mahmoud, SPE, A. Al Tenaiji, M. Al Sharafi, SPE, S. El-Abd, M. Abdou, SPE, and H. Hafez, Abu Dhabi Company for Onshore Petroleum Operations, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
after switching from aquifer water to produced water. The two logs were compared and revealed no change in the injection profile across the horizontal section of that well. Corrosion logs were also used and showed no integrity issues related to PWRI. So far, approximately 24 million bbl of produced water has been injected with no effect on well injectivity or integrity. Four wells are connected to Cluster 16. Three have been injecting since the early 1990s, and one was drilled in 2008. Well 1. This well started injection in 1993 as a vertical, dual-completion well through the two main reservoir layers. In 2010, the well was made horizontal and completed as a single water injector into the lower reservoir layer. Because the well orientation was changed from vertical to horizontal, comparing the well’s performance before and after switching from aquifer water to produced water may not be relevant. However, when the project started in 2010, the water source changed from aquifer to produced water for mechanical reasons. Generally, however, produced water was the main injectant between 2010 and 2013, when aquifer water was used again. Now, produced water is being used again as the produced-water network is being expanded. Despite the transitions, the well’s performance did not show any kind of injectivity impairment or deterioration. Well 2. This well started injection in 1993 as a vertical, dual-completion well through the two main reservoir layers. In 2007, the well was made horizontal and completed as single water injection into the lower reservoir layer. The well’s injectivity was steady, although it worked only intermittently for operational reasons. The PWRI project started in July 2010. Comparing the well’s performance before and after then showed that the
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 72
JPT • DECEMBER 2016
JPT • DECEMBER 2016
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Well 3. Similar to the preceding two wells, Well 3 was drilled and completed as a vertical water-injection well into the upper and lower layers of Reservoir 1. In 2009, the well was made horizontal and was completed as single water injection into the lower reservoir layer. After being made horizontal, the well continued to inject aquifer water for almost 1 year before switching to produced water. Produced water became the continuous injection fluid in late 2010. The performance of the well was similar with the aquifer water and the produced water. This is good evidence that the produced water does not affect the well’s injectivity. The well shows steady performance in terms of water-injection rate. However, the WHIP tests showed a slight increase when comparing the two periods. This increase in WHIP may be interpreted as an injectivity impairment; however, the increase was slight and, more importantly, was not permanent. The PFO test is another tool to assess production and injection performance and was used here to check the effect of switching from aquifer water to produced water. The main parameter was skin factor. PFO tests before the PWRI project revealed the skin factor to be −0.3. After the project, the skin factor was +0.3, indicating slight damage. This change was noted after approximately 2.1 billion bbl of produced water had been injected. Water-injection distribution across the horizontal section is important to examine in order to ensure that switching from aquifer water to produced water does not affect reservoir sublayers. A production-logging survey was conducted for Well 3 in February 2010 while aquifer water was being injected. A similar logging survey was conducted in June 2012 after switching to produced water (the total volume of injected produced water was 3.6 million bbl). A comparison of the injection profiles of both surveys reveals that the profile stays nearly the
Cluster 16 Water-Injection Performance 35,000
Water Injection Rate (B/D)
well’s injectivity remained steady. After returning to aquifer water in December 2013, the well’s injectivity did not show any dramatic change. Injection-rate and WHIP tests indicate steady performance before, during, and after switching to produced water.
Fig. 1—Overall cluster water-injection performance (aquifer and produced water).
same after switching from aquifer water to produced water. Well integrity is another important parameter to monitor when switching from aquifer water to produced water. All the wells in this project were completed using normal steel. The integrity of Well 3 was checked in May 2010 before starting the project, and the tubing was found to be in excellent condition. In March 2012, 2 years after switching to produced water, the same survey was conducted. The new survey confirmed the good condition of the tubing; only small pitting was seen at a shallow depth where penetration was approximately 35%. Well 4. This well was drilled in 2008 as a horizontal water-injection well. The well began injection in 2010, a few months before the beginning of the PWRI project. The well’s injectivity did not change after switching from aquifer water to produced water late in 2010 or after switching back to aquifer water in late 2013. Overall Cluster. The performance of the overall cluster is shown in Fig. 1. The performance does not appear to be significantly sensitive to the source of the water, meaning that the cluster injection volume is reasonably similar regardless of the water source. Although the injection volume sometimes changed, it remained within limits allowed by the reservoirmanagement strategy. During the PWRI
project, the cluster’s injection rate ranges from 22,000 to 29,000 BWPD, with an average rate of approximately 24,000 BWPD. The total volume of produced water injected was approximately 24 million bbl. The cluster has been using aquifer water since late 2013. JPT
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SPE Foundation Finances SPE Programs, Announces New Fund Honoring Dan Adamson For more than 35 years, the SPE Foundation has played an important role in providing support for SPE programs and services for members. SPE Foundation trustees, who are all past presidents of SPE, are dedicated to the principles of OneSPE, and are particularly keen to fund activities that benefit SPE members worldwide. Foundation support to SPE in 2016 includes the following: ◗ Scholarships: the Archie, van Wingen, and Imomoh scholarships (USD 54,000 total) ◗ SPE webinars and physical Distinguished Lecturer Program support (USD 675,000) ◗ Adamson Fund: leadership gift to establish (USD 100,000) The Foundation’s intent is to provide a similar amount of money in the first two categories in 2017, and to make USD 5,000 available for distinctive leadership training from the Adamson Fund.
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The Adamson Fund is a new initiative, established to recognize the man who led SPE as executive director from 1979 to 2001. Proceeds from this fund will be used to provide leadership training for SPE staff to further develop their specialist job skills and/or prepare them for advanced management positions, thereby enhancing their ability to provide support for SPE programs. In addition to the USD 100,000 grant to establish the fund, the Foundation has created a matching fund pool to provide a 1:1 match for the first USD 50,000 of additional contributions received. Members wishing to honor Adamson with a gift may direct contributions of any size to this fund for the 2016 and 2017 calendar years. More than USD 16,000 has been raised to date from individual donors beyond the grant earmarked by the Foundation. In addition, through the Moving Forward Giving Back initiative, the Foundation provides a way for individual members to support vital programs that serve current and future generations of petroleum professionals. For more information on supporting the Foundation, contact Jane Boyce at 1.972.952.9312 or jboyce@spe.org. While the primary purpose of the SPE Foundation is to financially support the mission of SPE itself, other purposes served are 1) to be a source of information, counsel, and advice to the current leadership of SPE, and 2) to provide a structure to allow former SPE presidents to continue to serve the Society.
Industry Conditions Prompt SPE Staff Reduction The continuing industry downturn has led to an additional reduction of 13% in SPE staff. This reduction brings SPE’s headcount to about two-thirds of what it was in 2014 before oil prices began to decline. “We regret the necessity of this staff reduction, which takes our headcount back to 2009 levels. We remain focused on delivering essential programs and services consistent with our mission, despite our staff reduction,” said CEO and Executive Vice President Mark Rubin. Some programs may be scaled back until conditions improve. SPE serves its members from seven offices globally: Calgary, Dallas, Dubai, Houston, Kuala Lumpur, London, and Moscow. All seven offices will remain open to provide services to members in the region.
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