bluuebunny/crossref_metadata_2025 huggingface dataset:
Comments: Fracturing Threat
Authors: Donnelly John
Published: February 2015

Editor's column

Legislation introduced in the US could place heavy restrictions on the widespread use of hydraulic fracturing, resulting in higher drilling costs and production delays.

With a new administration and Congress in place, the US oil and gas industry appears to be facing a new era of regulation. Three Democratic congressmen introduced a bill in June that would eliminate an exemption for hydraulic fracturing under the federal Safe Drinking Water Act. Currently, individual states in the US regulate fracturing but not the federal government. The legislators claim that fracturing may be releasing harmful chemicals and contaminating underground water reservoirs.

No federal or state studies have concluded that fracturing contaminates the water supply or has caused health problems. The exemption for hydraulic fracturing was part of the 2005 energy bill passed by Congress during the Bush administration and followed a US Environmental Protection Agency (EPA) report that found little or no threat to drinking water from fracturing. And in a report earlier this year, the US Department of Energy stated that "ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers."

The industry, including the American Petroleum Institute and the Independent Petroleum Producers Association, is gearing up for battle over regulating this common production practice. Fracturing is widely used in the US, and is critical in some of the country's biggest production areas, including the Haynesville, Barnett, and Marcellus shale plays as well as tight gas production in the Rocky Mountains region in the western US.

The proposed legislation could give the EPA power to limit the type of fluids used in hydraulic fracturing, control chemicals used in the practice, or prohibit hydraulic fracturing altogether. The proposed bill also would require companies to detail what chemicals or additives they use in fracturing, information that is usually considered proprietary. Fracturing fluids are generally water-based fluids mixed with additives to help the water carry sand proppant into fractures. Water and sand make up 98–99% of fracture fluid, with the rest chemical additives. The use of fracturing is one reason why shale gas production has become economically feasible in the past few years.

Eliminating the use of fracturing would cause a 45% drop in US natural gas production and a 17% decline in oil production within 5 years and continued declines after that, according to a study by IHS Herold. Restricting fracturing fluids would cut gas and oil production by 22% and 8%, respectively, while restricting chemical injection would lead to a 10% fall in gas output, according to the study. In addition, more regulation in this area would lead to higher costs, delays in drilling plans, and the possibility of litigation.
Lessons Learned from 2008
Authors: Al-Husseini Sadad I.
Published: February 2015

Guest editorial

The year 2008 may go down in history as the year of many lessons learned but soon forgotten. For the oil industry, it is important to reflect on what in fact those main lessons were and what their relevance is to the future.

One answer should not surprise most oil professionals. The industry discovered that it had been operating at a production capacity plateau for several years and no longer can provide the supply elasticity required by global oil demand given the cost and complexity of the oil-supply chain.

The oil price surge that started in 2003 and collapsed in 2008 had its roots in 1998. At that time, oil prices had sunk to USD 10/bbl, which resulted in the drying up of capacity investment across the world. In time, low oil prices resulted in runaway oil demand that could not be matched by increases in supplies. This shortfall resulted in the rapid increase in oil prices that eventually contributed to the global recession and the price collapse of 2008.

Even though the industry returned to making massive investments between 2003 and 2008, it could not match the tide of rising oil demand. Ultimately, it was unable to exceed a production plateau of 85 to 86 million BOPD in spite of the best efforts by OPEC and non-OPEC producers alike.

The attendant surge in oil prices to USD 147/bbl was, therefore, hardly surprising given these structural realities. These oil-supply limitations could not help but fuel the speculative fervor and hedging that occurred in the financial markets.

In hindsight, all of these events should have been predictable. While the global economy can shift its rate of growth within months, the energy industry is too complex and too mature to respond effectively, even under the most favorable economic circumstances. Politics, logistics, basin maturity, and technological limitations all converge to create an oil-supply plateau that cannot satisfy the growth of unconfined energy demand.

The existence of this ultimate supply ceiling will not recede under the current prospect for reduced upstream investments. In fact, there are good reasons to believe that this production plateau will become even more restrictive in the coming years.

Preventing the Boom and Bust Cycle

This vicious circle of rising energy demand, finite energy supplies, and volatile oil prices will repeat until the oil industry comes to terms with the need for better energy planning. Forward oil-supply planning is, in fact, the only option for setting constructive energy policies that can begin to facilitate the management of oil-price volatility.
Techbits: Efficiency Improvements for Facilities Focus of Workshop
Authors: JPT staff _
Published: February 2015

Techbits

Innovations aimed at improving efficiencies in surface facilities were the focus of an SPE Applied Technology Workshop (ATW) titled "Surface Facilities: Improving Efficiencies in Production, Energy Conservation, CO2 Reduction, and Waste Management" held in Dubai. More than 50 attendees from 25 companies and 16 countries reviewed the challenges of oil/water/gas separation, conservation, emission, and waste management in the backdrop of increasingly stringent regulatory requirements.

Abbas Ahmed Yousef, field manager for Adco's Bab field, opened the ATW with a keynote address focusing on the means to improve surface-facility efficiency, emphasizing the need for operators to adopt more enhanced oil recovery (EOR) techniques to improve production efficiencies. He also touched on the importance of energy conservation and emissions and waste management, particularly as producing fields mature.

Oil/Water/Gas Separation and Handling

In the ATW's first session, Ahmed Abdulmajeed of Saudi Aramco discussed process enhancements in gas/oil separation plants within his company. He reviewed how a new mixing valve for wash water going to desalters was able to reduce wash water consumption from 50 to 30 gallons per minute, resulting in more than 10 million gallons of water savings over one year. He also discussed how the implementation of a smokeless, high-pressure air-assisted flare system, which employs a new flare-tip design and additional flare-tip shield, provides for better gas combustion. Saudi Aramco is also testing an in-line water separator that promises to remove approximately 70–80% of water without the need to treat in a gas/oil separation plant and with quality in the range of 22–35 ppm of oil in water.

Alexander de Kruijf of Petroleum Development Oman (PDO) discussed the pitfalls of improper oil and gas sampling and made predictions on future process-equipment design. Inaccurate measurement of H2S in one PDO application led to deteriorating sales gas quality, with H2S concentrations reaching 5 ppm. The result was 4 months of deferment equivalent to approximately 100,000 BOPD. To prevent acid corrosion in equipment, de Kruijf stressed the importance of routinely measuring for organic acid, using corrosion-resistant alloys with increased corrosion allowances, and implementing organic pH neutralizers. In general, he advised that production chemistry programs should be an integral part of a project's process.

Oliver Garnier of Total reviewed a strategy to maintain production from his company's mature Abu Al-Bukhoosh field. The field has been producing since 1974, and present production is 15,000 BOPD with an average basic sediment and water (BS&W) of 86%. By implementing improvements, including increasing the impeller size in the gas recovery compressor, closing wells with too high a BS&W, optimizing well productivity by using multiphase flowmeters, and implementing de-emulsifier injection with gas lift, Total has managed to level the oil production potential to above 16,000 BOPD since 2007.
Efficiency Improvements for Subsea Operations in Deepwater Angola
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119651, "Improvements in Efficiency for Subsea Operations in Deepwater Angola," by Jason Zook, SPE, ExxonMobil Development Company, and Arran Keith, Swift Technical Group, originally prepared for the 2009 SPE/ IADC Drilling Conference and Exhibition, Amsterdam, 17–19 March. The paper has not been peer reviewed.

Esso Exploration Angola Limited (EEAL) has realized substantial improvements in the efficiency of subsea operations in the deepwater environment of Angola Block 15 (AB15). EEAL has increased its efforts to improve efficiencies for subsea operations, specifically during simultaneous operations. Improvements in efficiency and schedule certainty were realized as a result of dedicating a work vessel primarily to subsea operations. The full-length paper presents case histories of various operations and discusses the effect on efficiency of a dedicated work vessel.

Introduction

EEAL along with coventurers is developing several fields in AB15, 145 km west of Soyo, Angola, and approximately 386 km northwest of Luanda. Water depths range from 700 to 1435 m. Exploration rights were awarded in 1994, and drilling began shortly thereafter. AB15 currently is producing from five floating production, storage, and offloading (FPSO) facilities. The Kizomba C development project, which supplies FPSOs Mondo and Saxi-Batuque, is under way, and a Kizomba Satellites development project is in the planning stages.

To bring these developments on line in the timeliest manner possible, as many as six rigs have operated simultaneously on the different fields within AB15. Two of these rigs are tension-leg platforms, and the remaining rigs were mobile offshore drilling units (MODUs) working on a drilling schedule of more than 100 subsea wells distributed amid 18 subsea drill centers. This high amount of activity within the block created the potential for large schedule conflicts as a result of installation-vessel and MODU simultaneous operations.

In response to these potential conflicts, EEAL evaluated operations to identify which nondrilling tasks could be separated from critical-path MODU operations. Removing these tasks from the MODU schedule increased schedule flexibility and decreased cost.

Suction-Embedded-Plate-Anchor (SEPA) Installation

Early in the project planning for the AB15 development, drill centers were planned in close proximity to one another to enable the most cost-effective subsea architecture. The decision was made that AB15 would use one or possibly more conventionally moored MODUs for its subsea development wells. To achieve such a subsea layout and its related cost savings, the anchor pat tern of a conventionally moored MODU must become more compact. This more-compact anchor pattern required the use of taut-leg-mooring (TLM) systems to allow a MODU to moor safely over drill centers set relatively close to each other.
Technology Focus: Health, Safety, and Environment (August 2009)
Authors: Veil John
Published: February 2015

Technology Focus

Health, safety, and environment (HSE) considerations continue to be integral parts of all sectors of the oil and gas industry. The health and safety of the industry work-force as well as of residents in producing regions are of paramount importance to the continued viability of the industry. In a recent example of an international health issue, the April 2009 emergence of a rapidly disseminated strain of swine flu created great concern around the world. Oil and gas industry personnel travel frequently between countries and can contribute to spreading of diseases.

Last year I commented on the safety challenges of keeping up with the strong drilling demands resulting from high oil prices. This year offers a new set of challenges. With lower oil prices, companies may have cut back on some activities and programs. Hopefully, safety and environmental programs will remain as important and central elements of everyday work.

Industry performance in traditional air- and water-quality and waste-management programs remains very important. Overlain on these are highly visible global issues such as climate change and carbon capture and sequestration. Projects for injecting carbon dioxide into underground formations will need to draw on the decades of expertise in the oil and gas industry.

Previously, I have written about the challenges of selecting a small number of top papers to represent three separate disciplines (health, safety, and environment). My own work focuses only on environmental issues. This year, I enlisted the assistance of Tom Knode of Halliburton to help identify the top papers in health, safety, and social responsibility, which are areas within his scope of responsibility.

Health, Safety, and Environment additional reading available at OnePetro: www.onepetro.org

SPE 121065 • "The Use of Risk Analysis in Design: Safety Aspects Related to the Design and Operation of an FPSO" by Lars Tronstad, SPE, StatoilHydro.

SPE 118176 • "Health-Reporting System in the Oil and Gas Business" by Claudio Zappador, Eni, et al.

SPE 120973 • "Integrating Social Responsibility Into the Health, Environment, and Safety Management System" by Carolina Ortega Barrales, SPE, Occidental Oil and Gas, et al.

SPE 121104 • "Breakthrough Mobile-Water Treatment Converts 75% of Fracturing Flowback Fluid to Fresh Water and Lowers CO2 Emissions" by Aaron D. Horn, SPE, Newfield Exploration.

SPE 121050 • "Time To Protect: Layout Methodology for Safe SimOps in High-Pressure, High-Percent-H2S Facilities" by A. Blyth, Shell International.
A Risk-Based Approach to Offshore Classification
Authors: Sember William J.
Published: February 2015

Guest editorial - No abstract available.
Techbits: Unlocking Power of Technology in Mature Reservoirs
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Spotlight on R&D: R&D Needs for Offshore Facilities and Construction
Authors: Higgs William H.
Published: February 2015

Spotlight on R&D series - This is the fifth of a series of articles on the state of research and development (R&D) in the major upstream technological disciplines. The Spotlight on R&D Series, comprising articles published in JPT during 2004 and 2005, is available as a collection on OnePetro (SPE-101432-JPT).
West Africa Deepwater Developments: Subsurface Learnings
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16571, "West Africa Deepwater Developments: Subsurface Learnings," by Chuck W. Calavan and Timothy R. Garfield, ExxonMobil, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Drilling Maximum-Reservoir-Contact Wells in the Shaybah Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 85307, "Challenges and Achievements of Drilling Maximum- Reservoir-Contact Wells in the Shaybah Field," by A.S. Dossary, Saudi Aramco, and A.A. Mahgoub, Schlumberger, prepared for the 2003 SPE/IADC Middle East Drilling Technology Conference & Exhibition, Abu Dhabi, UAE, 20-22 October.
Re-enterable Through-Tubing Gravel-Pack System
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89524, "Re-enterable Through-Tubing Gravel- Pack System," by L.J. Leising, SPE, A.M. Ali, SPE, J.R. Young, and O.E. Arciniegas, SPE, Schlumberger, prepared for the 2004 SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, 23-24 March.
Optimizing Fracture-Fluid Crosslink, Stability, and Break Times on Bottomhole-Temperature-Gauge Data
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84215, "Case Study: Analyzing Bottomhole-Temperature- Gauge Data in Gulf of Mexico Frac Packs to Optimize Fracture-Fluid Crosslink, Stability, and Break Times," by S. Malochee, SPE, and B. Comeaux, SPE, BJ Services, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Slug-Suppression System
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84947, "The Slug-Suppression System in Operation," by K. Kovalev, Shell Global Solutions Intl. B.V.; A. Cruickshank, Dril-Quip Ltd.; and J. Purvis, Shell U.K. E&P, prepared for the 2003 Offshore Europe, Aberdeen, 2-5 September.
Gel Placement Key to Success for Water Shutoff in Gas Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89403, "Water Shutoff in Gas Wells: Proper Gel Placement Is the Key to Success," by F. Wassmuth, SPE, K. Green, and L. Hodgins, Alberta Research Council, prepared for the 2004 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17-21 April.
A Private Equity View of the North Sea
Authors: Sword Graeme
Published: February 2015

In the past year, significant developments have occurred regarding the prospects for North Sea oil and gas from a private equity viewpoint. Sustained high oil prices have led to a dramatic tightening of the North Sea assets market, making it tough for new, small oil companies to secure starter stakes. This has led to a large fall in the number of such companies seeking a North Sea position, and their focus has switched to areas of significant geopolitical risk backed by investors willing to accept greater uncertainty. However, considerable opportunities remain for novel hybrid oil and gas service/investor solutions that enable financially stranded North Sea assets to be developed. There has been a sharp improvement in prospects for the U.K.-based oil and gas supply chain, although strategic consolidations are important for capitalizing on emerging opportunities. Meanwhile, Norway is emerging as a place for private equity to invest in supply-chain opportunities.

Uncharted Waters

The global upstream oil and gas industry has entered uncharted waters with an unprecedented run of nearly 6 years of high crude prices. While crude oil prices have been higher than U.S. $50/bbl in the past—equating to U.S. $70 in today’s money—those were brief spikes. This time high prices are persisting, with agencies and analysts revising projections upward time and again. There is growing talk of oil shortages, if not raw resources then certainly supplies to the market, and energy conservation has re-emerged as a big issue. But it is only since late 2004 that broad-based confidence has returned to the Northwest Europe Continental Shelf and the U.K. sector especially. An indicator of this is the way in which drilling activity has picked up significantly, with no fewer than 70 exploration and appraisal wells predicted for the U.K. North Sea sector this year and 40 for Norway.

In the longer term, the operating expenditure and capital expenditure outlook to 2010 reflects returning confidence to a province regarded as mature and in sharp decline. The drop in U.K. oil production from January 2004 through January 2005 is 15.6%. Encouragingly, the U.K. Offshore Operators Assn. says in its 2005 survey that the North Sea remains a world-class basin that will pro-duce about 3.6 million BOE/D this year. Indeed, the now exceptionally positive outlook has driven demand for mobile drilling units to the point where the North Sea now faces an acute shortage of working rigs. Because of its close linkage with drilling activity, the offshore support-vessel market also has taken off, though construction remains relatively subdued.

Overlaying the North Sea is the global marketplace. Business is booming just about everywhere, especially in west Africa, the Caspian, the Indian subcontinent, East/Southeast Asia, and the Americas. Opportunities were excellent in 2004 and are now unprecedented for the industry, though possibly not for the investment community. Therein lies an irony.
Deployment of Swelling-Elastomer Packers
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92346, "Deployment of Swelling Elastomer Packers in Shell E&P," by Martijn Kleverlaan, SPE, Roger H. van Noort, and Ian Jones, SPE, Shell Intl. E&P, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

Shell E&P has deployed swelling elastomers in a variety of applications: as a means to establish zonal isolation in liner completions, as a production separation packer, and as an integral part of expandable openhole clad tubulars. In these applications, the elastomers were run in various openhole, casing, and tubing sizes. Approximately 60 deployments have been recorded, all of which were successful.

Introduction

In most areas where Shell operates, especially in the more mature oilfield environments, there is a high focus on well-cost reduction. Various technology applications have been identified to meet this business need and allow the operator to drill wells cheaper and smarter, making the most of existing infrastructure. One technology that is experiencing a rapid uptake is the application of swelling-elastomer packers. These packers, which swell naturally when exposed to the appropriate swelling agent, have been used successfully as a replacement for traditional mechanical packers and cement. The business case for using swelling-elastomer packers is different for each application and can include time savings as well as direct tool-cost savings. Shell used swelling elastomers in combination with a solid-expandable-tubular (SET) system called openhole clad (OHC) in July 2002. First application of swelling packers for zonal isolation was in the South Furious field in Malaysia in June 2003. Since then, more than 60 deploy-ments have taken place in Malaysia, Brunei, Nigeria, Gabon, Oman, and the U.K.
Advanced Completions Maximize Reservoir Potential in the Snorre Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92255, "Use of Advanced Completion Solutions to Maximize Reservoir Potential - Experiences in the Snorre Field," by L.T. Skarsholt, SPE, A.F. Mitchell, and A.H. Bjornsgaard, SPE, Statoil ASA, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

Snorre Blocks 34/4 and 34/7 were the first in the Norwegian North Sea to have sur-face-operated zonal control installed to allow selective production from different sections of the reservoir. The concept of downhole instrumentation and control systems (DIACSs) has been further developed and refined and today is used by many operators. The Snorre field remains at the forefront of this development, and the technology has been used in an additional 17 wells across the field. The full-length paper focuses on the use and advantages of advanced completions.

Introduction

The Snorre field, operated by Statoil ASA, is in Blocks 34/4 and 34/7 of the Norwegian North Sea, approximately 150 km northwest of Bergen. Snorre A, which started production in 1992, consists of a tension-leg platform and a subsea production system in a water depth of approximately 350 m. Produced oil is exported to Statfjord A, while part of the gas is reinjected and part is exported to Statfjord A. As of November 2004, Snorre A consisted of 30 oil producers and 23 injectors, including subsea wells. Snorre B, which came on stream in June 2001, is a semisubmersible drilling, process, and accommodation platform. Oil is exported to Statfjord B, and the produced water and gas are reinjected. Currently, six production wells and three injectors are connected to Snorre B.

The Snorre field is a complex reservoir consisting of fluvial sandstones representing various fluvial styles and subfacies. The lateral extent of the channel belts varies from 300 m to several kilometers and the permeability from a few hundred millidarcies to several darcies. The channel belts are stacked and interbedded with mudstone, and under dynamic flowing conditions, several pressure regimes have been developed because of the limited vertical and lateral communication. It was originally planned that the undersaturated oil would be recovered with downdip water injection as the drive mechanism, but this was changed at an early stage to water-alternating-gas (WAG) injection to improve oil recovery as well as provide a method to use excess gas.

As of November 2004, the Snorre field had an expected stock-tank oil originally in place of 532×106 m3, with expected oil reserves of 242×106 m3.
Overview: Reservoir Performance and Monitoring (September 2005)
Authors: Potsch Klaus
Published: February 2015

We Still Don’t Know Enough

This year, the selection process was a major effort. A sizable pile landed on my desk. Going through the topics, I encountered very familiar subjects, subjects that I thought had already been dealt with and solutions made available. I cannot, of course, check all the papers for their innovative content, so there are several factors that could have influenced the process.

- The authors did not perform a literature search and reinvented the wheel.

- The process of approaching the solution is cumbersome and the incremental gain of knowledge is small.

- The authors need publications to survive; therefore, they release only a portion of what they already know to keep a reserve for future publications.

- I am not aware of how complicated the problem is.

With the easy and quick wins in the applications and the theory being already gone, the focus turns more and more to the hard parts and pieces. In comparison with the clastic reservoirs, the carbonates demand more care, diligence, and thinking. The pore system is no longer a single one. Matrix properties are easily accessible in laboratory measurements. But what everybody wants to know is how much is in the fractures and how easily the fluid will flow. However, especially these parameters hide behind other data. Put a condensate-fluid system into such a porous medium and the challenge is complete.

The engineers need to plan future production carefully. Therefore, attempts are increasing to improve the flow assurance and the surveillance of the wells. Permanent downhole devices produce more data than we can handle, which leads to another need: namely, data reduction. Further, there also are cases in which the well data and the production figures are scarce. The engineers will have to deal with both.

Available from the SPE eLibrary: www.spe.org

SPE 92060 - “Finding Natural Fractures and Improving Reservoir Performance in Western Venezuela: An Integrated Approach,” by Franco, A., Repsol YPF, et al.

SPE 93297 - “A Mechanistic Model To Evaluate Reservoir Souring in the Ekofisk Field,” by Burger, E.D., SPE, EB Technologies, et al.

SPE 94995 - “A Case History of Value Generation With Intelligent-Well Technology in a High-Productivity Thin-Oil-Rim Reservoir ,” by Elmsallati, S.M., SPE, Heriot-Watt U., et al.
Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2005)
Authors: Goodman Harvey E.
Published: February 2015

My October 2004 Overview “Wellbore Stability and Sand Control” began with a narrowly focused comment on near-well-bore-failure modeling and the difficulty of predicting the consequences of this failure to operations. I then introduced my opinion that the key value of geomechanics technology is to provide a consistent reference frame against which well failure-to-production trends can be measured.

This year’s Overview “Wellbore Integrity, Sand Management, and Frac Pack” continues to broaden the science of well failure, reaching out beyond the failure event to understand the effect on the entire production system. The operational goal is to ensure that the well system designs provide production reliability, availability, and maintainability throughout the economic life of the asset.

To achieve this goal, one must be able to characterize wellbore integrity reliably and understand completion dynamics, from sand failure and sand production to sand management in the production system. It is of particular interest to characterize completion-performance behavior reliably over time, including near-completion reservoir flow mechanics. The papers selected for this month’s review begin to satisfy these rigorous goals.

Available from the SPE eLibrary: www.spe.org

SPE 90164 - “Novel Perforating System Used in North Sea Results in Improved Perforation for Sand-Management Strategy,” by Hillestad, E., Statoil A/S, et al.

SPE 90530 - “The Significance of Non-Darcy- and Multiphase-Flow Effects in High-Rate Frac-Pack Gas Completions,” by Lolon, E.P., SPE, Texas A&M U., et al.

SPE 94758 - “3D Analysis for Wellbore Stability: Reducing Drilling Risks in the Oriente Basin, Ecuador,” by Torres, M.E., SPE, Schlumberger, et al.
Management: Building the High-Performance E&P Company
Authors: Close Deborah
Published: February 2015

In the E&P industry, the product is the same for all companies: oil and gas, or some form of them. So unlike, for example, the automotive or pharmaceutical industry, E&P companies cannot differentiate themselves by producing a new and exciting product. Rather, E&P companies differentiate themselves based on their ability to find and produce oil and gas more efficiently than their competitors. Even though the E&P industry is in many ways unique, there are lessons to be learned from studying other industries and the characteristics of their high-performing companies.

Lessons Learned From Dell and Wal-Mart

Michael Hammer is a well-known business author who has written a number of books and articles on high-performing companies. He has studied in depth companies such as Dell and Wal-Mart, two companies that are held up as shining examples of high performance and leadership in their respective industries. What might Dell and Wal-Mart have in common with the E&P industry?

First, like oil and gas companies, these companies are not differentiated by their products. Dell is the leader in the personal computer industry, an industry the product of which is considered to be a commodity. Wal-Mart is the premier retailer in the world, but Wal-Mart does not sell unique products. In both cases, the products they sell are not easily differentiated, so these companies have had to establish a competitive advantage in other ways. Certainly, they have developed unique features in their business models and customer interface. For example, Dell has focused on a mail-order or online customer interface and delivery mechanism. Wal-Mart, on the other hand, is known for its friendly service, employee training programs, and store greeters. But surely, these are characteristics or strategies that could be replicated by competitors. Moreover, in both the computer and retail industries, competition is fierce, and margins are paper thin. What is it that consistently sets these leaders apart from their competitors in such a tough environment?

Hammer refers to a characteristic he calls "operational innovation," which he defines as "the invention of new ways of doing work." When examining Dell and Wal-Mart, one finds that these companies did not grow through diversification of businesses, nor did they grow through merger and acquisition. On the contrary, both companies have "stuck to their knitting" and have grown by systematically and organically increasing market share. They have been able to do this because they have practiced operational innovation, which has produced superior profitability compared with their competitors. For example, both Dell and Wal-Mart are recognized leaders in supply-chain management. They have integrated and innovated the processes for engaging and communicating with their suppliers, and have done so in a way that their competitors have been unable to replicate. That is because the process changes are not incremental or evolutionary; they reflect a completely new way of interacting with suppliers. They are revolutionary.
Laboratory Perforating Tests in Coal Results in Lower-Than-Expected Penetration
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102309, "First Laboratory Perforating Tests in Coal Show Lower-Than-Expected Penetration," by P.M. Snider, SPE, Marathon Oil Co.; I.C. Walton, SPE, Schlumberger; T.K. Skinner, Marathon Oil Company; and D.C. Atwood, SPE, B.M. Grove, SPE, and C. Graham, SPE, Schlumberger, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

The full-length paper describes a laboratory-testing program to investigate shaped-charge penetration in coal targets. Mechanical properties of the coals tested and penetration results for different shaped charges shot at various stress conditions are described. Preliminary experiments indicate that shaped-charge penetration in coal is significantly less than expected, considering the density and strength of the target.

Introduction

Estimates of world coalbed-methane (CBM) reserves range from 4,416 to 8,556 Tcf, with 749 Tcf located within the US. Production of CBM has increased steadily in the last decade, particularly in the US, which would seem to justify additional perforating research.

The coal samples used in the present testing program came from a producing formation in Wyoming's Powder River basin, which covers approximately 4.3 million acres and contains an estimated 800 billion tons of subbituminous coal. This CBM resource consists of many shallow seams from 200 to 3,000 ft deep. An estimated 12,000 wells are in production in the Powder River basin, and an estimated 50,000 more wells will be drilled in the next 5 to 10 years. Average well production is 163 Mcf/D, with an average estimated life of 8 to 10 years. Gas produced from Powder River basin coal is almost 100% methane, with an estimated 25 to 50 ft3 of gas per ton of coal, although gas content varies appreciably among the various coal formations.

Completing CBM Wells

Unlike sandstones, which trap natural gas in the intergranular-pore spaces, coal adsorbs the gas onto its surface. Production of this gas is contingent on reducing the pressure in the reservoir to allow the gas to desorb off the coal face. Once the gas is liberated, it must be transported to the wellbore. Therein lies the second difficulty in completing coal reservoirs because the permeability of the coal matrix often is very small. Fortunately, coal has many natural fractures, or cleats, through which the produced gas can flow. One of the major objectives of a CBM completion design is to provide effective communication between the wellbore and the natural-fracture, or cleat, system.
Overview: Reservoir Performance and Monitoring (September 2007)
Authors: Clemens Torsten
Published: February 2015

Optimizing hydrocarbon production and recovery requires fluid-production allocation from the different layers encountered in the wells. In recent years, downhole-monitoring systems have been used increasingly to unravel bulk production data measured at the surface. In particular, multilateral and "smart-well" technologies require much more-detailed spatial information about inflow than conventional wells.

One technology that has been improved significantly is the use of fiber-optic sensors. The first oilfield application of this technology was in steam-injection projects. With advanced understanding, improved sensors, and simulation of the well/reservoir coupling, fiber-optic sensor data can now be used for flow profiling, monitoring minifrac treatments, or diagnosing pumped wells, as discussed in the first featured paper.

On the reservoir scale, time-lapse (4D) seismic is used to monitor fluid movements directly. This method determines changes in seismic signals to infer fluid-saturation changes in the subsurface. However, techniques other than seismic can detect changes at the reservoir level. The second featured paper gives an example of such a technology: Surface-gravity measurements were used to monitor water injection into the gas cap of a large field.

The methods described above, for which gathering detailed downhole data or reservoir-scale time-lapse data is required, can be expensive and time consuming. However, a wealth of production data is continuously recorded at surface. These data are the key source for reserves evaluation by decline-curve analysis and for simple forecasting of hydrocarbon production. Paper SPE 107967, which is recommended for further reading, shows that much more information about the well and reservoir can be derived from these data by use of a new derivative function.

Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org

SPE 107967 "Application of the β-Integral Derivative Function to Production Analysis" by D. Ilk, SPE, Texas A&M University, et al.

SPE 107268 "Placement of Permanent Downhole Pressure Sensors in Reservoir Surveillance" by B. Izgec, SPE, Chevron, et al.

SPE 102801 "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity" by S.C. Maxwell, Pinnacle Technologies, et al.
4D Microgravity Surveillance of a Waterflood - Prudhoe Bay, Alaska
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101762, "Results of the World's First 4D Microgravity Surveillance of a Waterflood - Prudhoe Bay, Alaska," by J.L. Brady, SPE, BP Exploration Alaska; J.L. Hare, Zonge Engineering; J.F. Ferguson, U. of Texas at Dallas; J.E. Seibert, Seibert & Assocs.; and F.J. Klopping, T. Chen, and T. Niebauer, Micro-g Lacoste, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

A 4D surface-gravity surveillance of a waterflood was implemented at Prudhoe Bay, Alaska. This monitoring technique is essential for surveillance of the gas-cap water-injection (GCWI) project. Drilling numerous surveillance wells to monitor water movement adequately would have been cost-prohibitive. Field surveys showed conclusively that density changes associated with water replacing gas are readily detected by use of high-resolution surface-gravity measurements.

Introduction

The fundamental problem in monitoring the GCWI project is sparcity of monitoring wells and lack of producing wells in the gas-cap area of Prudhoe Bay. Distances between some monitoring wells are greater than 10,000 ft, and years would be required for the injected water to propagate these distances. Too few wells exist to monitor the water movement adequately with conventional downhole-logging techniques. Therefore, the Prudhoe Bay surveillance program uses a combination of conventional downhole logging in existing wells and 4D surface-gravity monitoring. The major monitoring concern with the waterflood is to ensure that water added in the gas cap does not prematurely flow downdip into the oil-producing portions of the field, where it could interfere with a highly efficient gravity-drainage mechanism.

Surface-gravity instruments measure the Earth's gravitational field at a specific point, or station. With an array of these measurements, local structural traps, stratigraphic traps, or fluid movement can be identified if sufficient density contrast exists between the feature of interest and the surrounding rock. The surface-gravity technique can be applied to any field, depending on reservoir thickness, size, depth of burial, porosity, and density contrast between the fluids. The surface-gravity technique requires that several time-lapse gravity surveys be made over the life of the field. The first survey should be performed before any change occurs in the fluid volumes to obtain baseline data. The baseline survey can be subtracted from future gravity surveys to obtain the gravity anomaly associated with the change in fluid volumes. The technique assumes that any other time-dependent gravity changes can be accounted for by measurement or modeling, and that noise caused by the measurement process and unmodeled (near-surface) density changes has tolerable characteristics.
Overview: Field Development Projects (September 2007)
Authors: Cunha J.C.
Published: February 2015

Recently, during the Second International Oil Congress and Exhibition in Mexico, I had the opportunity to attend a roundtable discussion on "Global Trends in Deepwater Development." The event, held in Veracruz, had representatives from some of the major players in deepwater field development, and most talks and discussions focused on the challenges, concerns, problems, and rewards expected in coming years in the deepwater and ultradeepwater environments.

In the Gulf of Mexico alone, it is expected that new oil reserves in excess of 45 billion bbl will be found in the near future. However, improved economic development of those reserves will be achieved only with state-of-the-art technologies in all phases of the project. Efficient field development must take into account simultaneously the constraints in well drilling, production scheme, subsea equipment, and reservoir management. Because only limited information is available in the earlier stages of the development plan, a structured way to handle the risks involved also must be implemented.

Establishing a field-development strategy under very-high-uncertainty conditions appears to be the rule in most recent deepwater projects. In the round-table discussion in Veracruz, the panelists seemed to be conscious of the huge challenges ahead and, at the same time, excited and optimistic about the future development of fields that just a few years back were deemed impossible ventures. What do you think? I invite you to read the featured articles presented this month and reach your own conclusions. Enjoy.

Field Development Projects additional reading available at the SPE eLibrary: www.spe.org

SPE 101286 "Exploration Potential of Sinuous (Channel-Like) Events in Late Cretaceous of Al-Khafji Field, Middle East" by Kalyan Chakraborty, SPE, Kuwait Gulf Oil Company, et al.

SPE 107387 "The Challenges of Developing a Deep Offshore Heavy-Oil Field in Campos Basin" by F.P. Figueiredo Júnior, Petrobras, et al.

Available at the OTC Library: www.otcnet.org

OTC 18538 "The Dalia Development Challenges and Achievements" by D. Picard, Total E&P Angola, et al.
Interview with 2009 SPE President Leo Roodhart
Authors: Roodhart Leo , Donnelly John
Published: February 2015

President's interview

Leo Roodhart is Head of Strategic Innovation at Shell International. With Shell since 1980, he has worked in R&D, production engineering, business development, and innovation.

Roodhart has been active in SPE for more than 25 years, most recently Director for SPE's North Sea Region, Chairperson of the Board Committee on Technical Programs and Meetings, and a member of the Board Committee on Finance and Administration. His contributions to the Society, at the local and international levels, have emphasized encouraging technology innovation. Roodhart has actively contributed to the SPE Forum Series, serving on Forum steering committees and as a member and as Chairperson of its Implementation Committee for the Eastern Hemisphere. He also has chaired the Forum Series Coordinating Committee. Roodhart has served as both Program and Section Chairperson for SPE's Netherlands Section. He has served on the program committee for Europec and on the 2001, 2003, and 2005 Offshore Europe executive committees. Roodhart chaired the first two Netherlands Applied Technology Workshops (ATWs) on Mature Reservoirs and has served on or chaired many Forum and ATW committees. He has been a member of the Distinguished Lecturer Committee and was an SPE Distinguished Lecturer during 2007–08.

Roodhart is an Associate Fellow at Templeton College, Oxford University, on Strategic Innovation. He earned an MS degree in chemistry and a PhD degree in mathematics and physics from the University of Amsterdam.

What would you like to accomplish during your term as SPE President?

Each SPE President is just one of the links in a long chain of Presidents, each with his or her own aspirations; together they built SPE into what it is now. Even if it would be possible, and it is not, for a President to make big changes in the one year he/she has, it is probably not a good idea.

That said, the SPE Board of Directors developed some time ago a Long-Range Plan to guide our Society, which is updated regularly. The current Long-Range Plan identifies key strategic issues, such as turning SPE into a truly global society; engaging young people, particularly inducing students to come select careers in our industry; and tackling such global issues as reserves definitions, capture and sequestration of CO2, and improving the industry's image.
Barnett Shale Showcases Tight-Gas Development
Authors: Parshall Joel
Published: February 2015

Horizontal drilling and continuing advances in hydraulic fracturing have made the Barnett Shale formation of north Texas one of the great recent success stories in gas production and a showcase for tight-reservoir development technologies. Yearly production from the north-Texas Barnett Shale, officially called the Newark East field by the Texas Railroad Commission, grew to 1.1 Tcf of gas equivalent in 2007, making it second in size only to the Panhandle-Hugoton field among US producing gas fields. Cumulative Barnett production from 2000 onward now exceeds 4 Tcf.

The north-Texas Barnett Shale extends over 5,000 square miles and at least 17 counties, with the core areas lying within Denton, Tarrant, and Wise counties. While the formation can be found at depths as shallow as 3,000 ft in some areas, it primarily appears between 7,000- and 9,000-ft depths. Pay-zone thickness ranges from 100 to 1,000 ft and averages 300–500 ft.

Notably, shales like the Barnett once were seen mainly for their role as barriers that trapped hydrocarbons in other rock or were useful for containing secondary-recovery repressurization or fracturing operations. They were seldom considered producible formations because of shale's low permeability, making it difficult for fluids to move within the rock and, thus, for hydrocarbons to flow to the wellbore. Matrix permeability in the Barnett is extremely low, ranging generally between 10–7 and 10–9 darcies. Partially improving the permeability is the presence of interbedded silt- and sand-sized particles.

The Barnett Shale was believed to be hydrocarbon-rich even before a discovery well was drilled by Mitchell Energy in 1981. Nonetheless, development activity had to wait another decade or more and did not attain any momentum until the late 1990s.

With the extremely tight formation, the use of fracturing to break up as much reservoir rock as possible was a necessity. At first, Mitchell's development strategy consisted of drilling vertical wells completed with massive hydraulic fracturing treatments, using crosslinked gels to transport from 1 to 1.5 million lbm of sand proppant in the formation. In 1997, with the success that another operator had experienced with slickwater fracturing (water-frac) technology in the east-Texas Cotton Valley formation, Mitchell began to apply slickwater fracs in the Barnett, with impressive results.