bluuebunny/crossref_metadata_2025 huggingface dataset:
Fiber-Optic Sensing Technology Providing Well, Reservoir Information - Anyplace, Anytime
Authors: Koelman J. Vianney
Published: February 2015

Technology Update

Fiber-optic sensing is known in the oil and gas industry as a technology that allows continuous temperature profiling along entire well paths. However, surveillance applications focusing solely on temperature measurements are limited to recovery processes with a clear, unambiguous thermal signature. This has prevented fiber-optic sensing from becoming a widely deployed technology in oil and gas production. However, we are now witnessing a confluence of novel fiber-optic technologies that promise a much wider range of subsurface measurements. This opens new avenues in well and reservoir management and highlights the opportunity for fiber optics to become a pervasive oilfield technology. For this to achieve reality, the multiple sensing technologies being introduced by various providers need to be combined and deployment costs contained. The key enabler to achieving these goals is to bundle a selection of fibers into a single cable suitable for downhole deployment and optimized for monitoring a variety of in-situ data.

Distributed Sensing—A Growing Toolbox of Fiber-Optic Techniques

The individual sensing technologies are at various stages of development and derisking. Distributed temperature sensing (DTS) is the most mature technology, followed by distributed strain sensing (DSS). The latter technology, developed by Shell and Baker Hughes under the product name RTCM (Real Time Compaction Monitoring), allows operators to monitor tiny well deformations during the lifetime of a well (Earles et al. 2010). Both technologies can be combined, and fiber-optic pressure sensing capabilities (often labeled DPS) provide complementary data to this mix of sensing technologies (Available DPS systems tend to provide single- or multipoint pressure readings as opposed to true distributed pressure measurements, it should be noted.)

Other fiber-optic sensing technologies, such as distributed acoustic sensing (DAS) and distributed chemical sensing (DCS), are less mature but are expected to hit the market in the next few years. DAS turns a standard telecom fiber deployed over an entire well path into a permanent array of microphones. DCS, the latest addition to the growing toolbox of fiber-optic techniques, will allow the detection of specific molecules along the full inflow area of producing wells. Last year, Shell embarked on a collaboration with QinetiQ, based in the UK, to evaluate the potential of DAS for oil and gas applications, and this year Shell entered into a similar arrangement with TNO, based in the Netherlands, with the aim of derisking DCS technology. Currently, the DAS technology is undergoing field trials, while DCS is in an early derisking phase.
The Trend Toward Shale Oil
Authors: Beckwith Robin
Published: February 2015

The “shale gale” is not all about natural gas. While US shale gas drilling continues, it now is primarily to hold acreage and build gas reserves. As illustrated in Fig. 1, there is a definite trend in the US away from natural gas to crude oil. Many companies have pulled rigs from development drilling in gas shales to explore wet gas and oil-bearing shale plays. Lured by the prospect of high-value oil, whose margins promise a much higher return than those for natural gas, shale oil in US plays like the Bakken, Eagle Ford, Niobrara, Leonard (or Avalon), and Monterey is being extracted from low-permeability rock in increasing quantities.

For example, while 33 permits were issued in 2008 for drilling in the Eagle Ford Shale, for the first 11 months of 2010, 1,018 permits were issued. Oil and condensate production has also sharply increased in the Eagle Ford, from a combined 0.8 million bbl in 2009 to roughly 3.9 million bbl in the first 10 months of 2010. A recent study—“The Economic Impact of the Eagle Ford Shale,” prepared by the Center for Community and Business Research, University of Texas at San Antonio—forecasts annual Eagle Ford oil production at 15 million bbl for this year, rising consistently until 2020, when it is projected to reach 111.5 million bbl.

In 2008, the US Geological Survey estimated that the US portion of the Bakken formation contains between 3 billion and 4.3 billion bbl (a mean of 3.63 billion bbl) of undiscovered, recoverable oil, ranking it among the largest US oil plays ever. Production in 2009 reached nearly 8 million bbl per month from roughly 4,500 producing wells. Oil production in North Dakota—in the heart of the Bakken—increased from 35 million bbl in 2005 to nearly 80 million bbl in 2009.

Technology Is the Enabler

“The technology drivers that lifted gas recovery from 1% to 50% in the Barnett,” stated Apache global technology consultant George E. King, “will ultimately be the springboard that drives oil recovery from the initial 1% to 1.5% in the Bakken and Eagle Ford oil-producing shales to much higher values.”

Continental Resources, the number one driller and lease holder in the Bakken as of November 2010, with 864,559 net acres, has been driving its production upward with advances in technology. For example, in 2009, it per-formed the first 24-hour continuous hydraulic fracture in the North Dakota portion of the play. In 2010, Continental developed a drilling concept it calls the Eco-Pad, whereby the company drills multiple horizontal wells from a single pad with zero boundary-line setbacks. This concept is expected to reduce drilling and completion costs per well by approximately 10%, with about 70% less surface footprint area than four conventional drilling pads and only one access road.
Recent Developments and Remaining Challenges of Enhanced Oil Recovery
Authors: Pope Gary A.
Published: February 2015

R&D Grand Challenges - This is the second in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE R&D Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series are examining each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).

The world is changing. Some look back and some look forward. Some look at the challenges of ramping up enhanced oil recovery (EOR) in the past and some look at the opportunities for doing so now. This article will provide a broad view of recent developments and the remaining challenges for readers who are not EOR specialists.

There has been a renaissance in chemical EOR during the past few years because of major advances in the technology and high oil prices. Thermal and miscible gas methods are much more mature with the exception of processes such as co-injection of gases and surfactants for mobility control. The synergy between the EOR processes and improved reservoir characterization and formation evaluation, reservoir modeling and simulation, reservoir management, well technology, production methods, and facilities is significant and not as widely recognized as it should be.

Polymer flooding is the simplest and most widely used chemical EOR process. Polymer flooding has been used commercially since the 1960s; more oil is produced by polymer flooding than all of the other chemical EOR processes combined. Adding polymer to the water increases its viscosity. The benefit of polymer flooding increases as the oil viscosity and/or the reservoir heterogeneity increases. Polyacrylamide copolymers or hydrolyzed polyacrylamide (HPAM) polymers are by far the most widely used polymer for EOR. Much higher molecular weight HPAM is now available than when it was first used in the 1960s and 1970s. The quality of commercial HPAM polymer has also improved dramatically and the price relative to crude oil has decreased. In the early 1970s, oil sold for about USD 3/bbl and HPAM polymer for about USD 1.50/lb. Now oil is about USD 100/bbl and HPAM stays about the same price.

About 1 to 2 lbs of polymer are needed to produce an incremental barrel of oil, which means the polymer cost is about USD 1.50/bbl to USD 3/bbl. This helps explain why the number of polymer floods is increasing exponentially and about 1 billion lbs of polymer will be used for EOR this year. Most early polymer floods were done using very small amounts of polymer (i.e., low polymer concentrations and small pore volumes of polymer solution), but now we know polymer floods perform much better at large polymer concentration.
R&D on Campus: Developing Upstream Technology
Authors: Braswell Gentry
Published: February 2015

Editor’s note: JPT surveyed major universities around the world regarding their key upstream research and development projects and activities. This is the second installment of the two-part series.

Harold Vance Department of Petroleum Engineering, Texas A&M University, US

The Crisman Institute for Petroleum Research at Texas A&M University houses the Halliburton Center for Unconventional Resources, the Chevron Center for Well Construction and Production, the Schlumberger Center for Reservoir Description and Dynamics, and the Center for Energy, Environment, and Transportation Innovation. The focus of each center is to develop technology and processes to reduce the finding and development costs in petroleum reservoirs. The institute facilitates funding for graduate programs and research that includes work toward better mathematical models, better rheological reservoir control chemistry, and better predrilling geological interpretation and well modeling.

Texas A&M’s Global Petroleum Research Institute (GPRI) is the managing partner of a cooperative effort among 12 major oil producing companies conducting critical research in developing technologies to address the increasing demand for cost-effective production and enhanced recovery. The GPRI is primarily focused on unconventional resources, said David Burnett, research coordinator. There has been a “sea change” in focus since the US gas shale plays have emerged and offered opportunity to make gas a fuel supply for the power grid, he said. It is important to teach students, industry sponsors, and the public about appropriate water use and handling in drilling, as one’s license to operate is ultimately determined by environmental performance, Burnett said. If an operator is inattentive or environmentally negligent, it ends up out of business. “And one of the biggest parts of that is water,” Burnett said.

It takes lots of water to drill, and for 50 or 60 years the industry has reinjected produced water into the reservoirs. But shales are not reservoirs, so there is no way to appropriately reinject them, Burnett explained. Besides water treatment in gas shales, GPRI is currently collaborating with major operators on developing an environmentally friendly seismic signaling device and is also researching ways to keep deep sea pipelines from getting clogged, which is a challenge because low deep sea temperatures cause produced hydrocarbons to congeal.
Integration of 3D Seismics and Reservoir Simulation for Remaining-Oil Exploitation in a Heavy-Oil Field: SAGD Case Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134092, ’Integration of 3D Seismics and Reservoir Simulation for Remaining-Oil Exploitation in a Heavy- Oil Field: A Case Study,’ by Yun Ling, BGP CNPC; Xuri Huang, SPE, SunRise PetroSolutions Tech; and Xiangyu Guo and Yintao Cai, BGP CNPC, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

Integrated research on steam-assisted gravity-drainage (SAGD) production was carried out for an oil field in north-eastern China by use of full-azimuth 3D seismics (cell size 6.25×6.25 m with a coverage area of 14 km2) and reservoir simulation on a well group [40 vertical wells and five horizontal wells in an area of 600×375 m (Fig. 1)]. The research indicated that the configuration of steam chambers caused by steam injection could be delineated from the high-resolution 3D-seismics results, and that this is more accurate than the reservoir-simulation model alone in the local-variation description of the chambers.   

Introduction

It has been observed in laboratories that a large seismic-velocity change can occur in rocks containing heavy oil when the oil is replaced by steam. The Duri heavy-oil field in Indonesia uses steam injection, and time-lapse seismics is used to monitor production. However, the effectiveness and reliability of the method depend on the quality and repeatability of the surveys. The technique of combining 3D-seismic exploration for the remaining oil with historical production data (called 3.5D seismics) avoids the nonrepeatability problem commonly associated with time-lapse seismic. This technique was applied to the Ng reservoir in northeastern China.

Geological and Seismic Background

The main producing reservoir, Ng, is on a monoclinal structure covering 1.95 km2. Its maximum thickness is 145 m and is found at a depth between 540 and 800 m. The reservoir porosity is 36%, permeability is 5.5 darcies, and the reservoir has edge, top, and bottom water. Production started in 1997, and 10 to 12 cycles of steam stimulation have been implemented in a well interval of 70 m. Enhanced oil recovery (EOR) reached 20 to 25%. Starting in 2005, five SAGD well pairs were used, and they are still in production. The SAGD process raised the EOR by 5 to 10%. A high-density 3D-seismic survey (with a wide azimuth and an aspect ratio of 0.874) was acquired in February 2009. The processing procedure that was used enhances the vertical resolution and preserves reservoir information.
Best Practices and Innovations for Improved ESP Performance
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 136407, ’Best Practices & Innovations for Improved ESP Performance; Mature Field Case History; TNK-BP Company, Russian Federation,’ by D.C. Borling, SPE, BP, and S.V. Sviderskiy, SPE, and, S.F. Gorlanov, SPE, TNK-BP, originally prepared for the 2010 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 26-28 October. The paper has not been peer reviewed.

Leadership, teamwork, and technical ingenuity were critical strategy elements that resulted in an 82% run-life improvement for electrical-submersible-pump (ESP) systems in the TNK-BP company. During the past 4 years, the 12-month rolling mean time between failure (MTBF) steadily improved from 295 days during January 2006 to the current 541 days in July 2010. This 246-day improvement was achieved across more than 14,250 ESPs and achieved USD 307 million value to date.

Introduction

TNK-BP is a privately owned oil and gas joint venture. The company was formed in 2003 and for the past 7 years its upstream producing operations were located primarily in West Siberia (Khanty-Mansiysk and Yamalo-Nenets Autonomous Districts, Tyumen Region), East Siberia (Irkutsk Region), and Volga-Urals (Orenburg Region).

As of July 2010, the company operated more than 200 hydrocarbon-bearing fields with approximately 15,700 active producing oil wells. More than 98% of these wells used artificial lift.

In TNK-BP, ESP systems refer to both surface and downhole equipment components. Surface components include transformer, switchboard (and/or variable-speed motor controller), and a relatively short surface power cable. Downhole components include pump intake (and/or gas separator), seal element, motor, and a long downhole cable (used to transfer power from the surface to the motor).

Operating Conditions

Each of the company’s 14 regional business locations has unique operating conditions. By mid-2010, more than 50 different types of ESP equipment were deployed across the company to lift a wide range of produced-fluid rates and gas and solid content.

Approximately 92% of all deployed ESP equipment was manufactured within the Russian Federation. The remaining 8% was imported for use in complicated well conditions and harsh downhole operating environments.

TNK-BP deployed ESP equipment in almost every type of downhole condition imaginable. Harshest conditions included a mixture of high temperature, abrasive solids, scaling, asphaltene, paraffin, high free-gas content, and corrosive fluids.

Teamwork

Without good teamwork on a massive scale across five business segments and 14 regional businesses, the TNK-BP ESP-MTBF-improvement initiative would not have achieved the intended results.

A best practice was the method used to align ESP MTBF key performance indicators and work plans at the start of each year. While this alignment was a big undertaking, it proved itself to be worth the effort each year.
Use of a Vertical Wind Turbine in an Offshore Floating Wind Farm
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21705, ’Use of a Vertical Wind Turbine in an Offshore Floating Wind Farm,’ by Marc Cahay and Eric Luquiau, Technip, and Charles Smadja and Frederic Silvert, Nenuphar, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.

With 2.0 GW already installed and more than 50.0 GW planned in Europe by 2020, as reported by the European Wind-Energy Association, the installation of bottom-mounted offshore wind turbines in very shallow water (less than 40 m) is now well established. The foundation and the offshore installation costs represent approximately 50% of the total development cost of an offshore wind farm, and this proportion increases with the water depth. Hence, floating wind turbines are the solution for deep offshore.   

Vertiwind Project

Coming from a strong and complementary partnership of utilities, industrials, and academics, the Vertiwind project plans to build, install, and operate, in real offshore conditions, a full-scale floating vertical-axis wind turbine (VAWT) of 2 MW. This is a real step change in the technology compared with most offshore wind turbines with horizontal axes.

The floater concept retained is of a semisubmersible design and is called “multifloater.” It skillfully combines an out-of-the-wave excitation response, a shallow draft to facilitate fabrication, and a very simple installation procedure requiring only one or two tugs. The VAWT is located in the center of the floater, ensuring that the center of gravity, the buoyancy, and the convergence point of the mooring lines are all on the same axis. This geometrical property highly reduces the sway and yaw response of the floater subject to noncolinearity or heading variation of wave and wind. Because of the architecture and underlying principles of this Darrieus turbine, the power production is not affected by the inclination of the turbine axis relative to the wind direction as a result of the floater motions.

The turbine design is carried out in parallel with the floater. It integrates, at an early stage, all requirements of the offshore environment in terms of loads, accessibility, and ease of maintenance. The complete unit will be anchored to the seabed and linked to the network by a compliant subsea cable.
Techbits: Workshop Focuses on Critical Issues of Social Responsibility
Authors: JPT staff _
Published: February 2015

Techbits

Social responsibility (SR) is the newest element within the health, safety, security, environment, and social responsibility (HSSE SR) field of the oil and gas industry. SR is a nontechnical risk, and its professionalization requires multidisciplinary teams with specialists in capacity building, resolution of conflicts, and human rights. Appropriate SR management aims to increase cost effectiveness, minimize legal and financial liabilities, build reputational capital, drive innovation, and capture business opportunities.

A connection between HSSE and SR is essential, but few organizations have clearly defined what constitutes excellence in SR performance or programs, especially in project development. As one of the many “business risks” that the industry faces, it is likely that social pressures will force additional action and attention on SR. Organizations must understand and communicate SR risks to internal stakeholders to effectively address them during project development.

SPE recently held its first Social Responsibility Workshop in Paris. The workshop explored the key SR challenges facing the oil and gas industry, sought to establish a common understanding about terms and practices, and provided an opportunity for participants to learn from the operational experiences of major industry players.

The workshop was divided into seven sessions.

Social issues compliance and the value of social risk management

Stakeholder engagement in the life cycle of an exploration and production (E&P) project

Opportunity and risk analysis

Operating in conflict-affected or high-risk areas

Working together: the range of players and their roles

Challenges during the project development’s life cycle

Success stories: overcoming challenges in implementing SR in operations

Best practices for corporate management of social issues and regulatory compliance have evolved greatly over the past 10 years. The first session explored current thinking on best practices in the industry. In a changing world with no more “easy oil,” there is a shift in the size of projects, from a typical USD 3 billion to 5 billion price tag in the early 2000s to an impressive USD 35 billion this year for a project in Australia. There is also a change in project time frame, which has nearly doubled in the past decade. The average project delay is 1 year, and 73% of delays are caused by nontechnical risks. With this growth and change come new demands from leadership that requires new, proactive positions on such risks. Part of the challenge is to recognize that new sources of risk exist and that new approaches to risk management are required.
Apps and the Digital Oil Field
Authors: Beckwith Robin
Published: February 2015

App technology

The oil and gas industry tends to be resistant to marketing fads. If a software phenomenon such as the app cannot help get oil and gas out of the Earth safer, faster, and more economically, then the industry will not use it. This may be why, of the hundreds of thousands of apps now publicly available, only a few dozen are devoted to the industry.

Apps Developed for the Oil and Gas Industry

None of the online app stores has a separate category for the petroleum industry. Oil and gas apps are primarily housed under app stores’ business, education, productivity, or reference headings. While an app must meet certain software standards to be included in an app store, the actual content receives no vetting. So, beyond the name and reputation of the company or person providing the app, no assurance is provided on the accuracy of the app’s information, mathematical formulas, or simulation parameters.

Oil and gas industry apps comprise the following five categories:

Those devoted to marketing materials—These marketing collateral materials take the place of printed catalogs, annual reports, brochures, and data sheets. While companies have made such materials available on their websites ever since the Web began rising in prominence in the early 1990s, the primary advantage of accessing them via a smartphone or tablet lies in the greater portability of the devices themselves, as well as the ability for updated material to be added at any time.

For example, Aker Solutions recently implemented a smartphone app for its wireline tractor catalog. On a tablet, this is downloaded as a portable document format (PDF) file that is accessible through a book library app.

In another example, Tenaris has created its own TenarisLibrary, featuring a complete and integrated package of its available marketing literature and videos. These appear in a variety of languages, and access can be tailored to individual interests. Calling it a “dynamic library,” Tenaris writes, “Each user is invited to create their own customized library to navigate the material once disconnected from the Internet.”

Those that supply computations—Designing a drilling program and constructing, drilling, and completing a well demand input of a huge number of variables that can be manipulated using mathematical formulas and computations. Each variable rests upon a solid foundation of physical reality, including measured depth, pipe inner and outer diameter, downhole pressure and temperature, azimuth, mud weight, rate of penetration, and weight on bit. Some computationally based apps—including Halliburton’s eRedBook and eChartBook and Schlumberger’s Smith Bits Quick Calc Hydraulics—are of use in the field. Others—such as Wellcontrol.com.br’s Well Control, Leak-Off Test, and Drilling simulators—are useful as educational tools.
Deepwater Spill Control Devices Go Global
Authors: Rassenfoss Stephen
Published: February 2015

The first thing a visitor sees at Trendsetter Engineering is a massive device standing ready if the worst happens on a well in the Gulf of Mexico. This amalgam of connectors, pipes, valves, and blowout preventers (BOPs) is a capping stack—a name that entered the language in 2010 when the first one was quickly assembled to shut off the flow of oil from the Macondo field.

The Helix Well Containment Group (HWCG), which has 25 member companies, stores this early example of what has become a global trend. Industry organizations and operators now have more than 15 capping stacks in service and on order.

Many of them have been built, or will be, at Trendsetter. On a day in early April, the engineering consulting and equipment maker was building a capping stack for Shell, which will be part of its Arctic drilling program.

And they were planning to build another designed by Shell to fit into the narrow space beneath a tension-leg platform. When complete, that one will become the property of the Marine Well Containment Corp. (MWCC), serving 10 large operators in the Gulf of Mexico. By year’s end, MWCC will have three capping stacks and a growing inventory of related equipment, including two vessels to capture, process, and offload crude to tankers and flare natural gas.

Another four capping stacks to be built by Trendsetter will be deployed to offshore oil basins around the globe by the Subsea Well Response Project (SWRP), a nine-member Norway-based industry group.

BP recently added another capping stack in the Houston area that also has a global mission. The device, weighing more than 100 tons, can be broken down into two pieces and flown anywhere that BP is working offshore, said Geir Karlsen, BP Containment Response Team leader.

A variety of factors are pushing a trend that started in the Gulf of Mexico after the Macondo disaster led regulators to require that operators seeking drilling permits demonstrate they can control a deep sea blowout. Two ventures, MWCC and HWCG, were created to cooperatively provide those services in the Gulf of Mexico.

When Shell sought permits to drill offshore in Alaska, it faced a similar requirement and needed a capping stack there.

In the North Sea, operators formed the Oil Spill Prevention and Response Advisory Group (OSPRAG) with a stack built by Cameron designed for conditions there.

International oil companies, such as Shell and BP, have internal standards for offshore operations requiring capping stacks be available around the world, which many countries are coming to expect. They responded with caps of their own and by being part of SWRP.
Fayetteville-Shale Production: Seismic-to- Simulation Reservoir Characterization
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147226, ’Understanding and Predicting Fayetteville-Shale Gas Production Through Integrated Seismic-to-Simulation Reservoir-Characterization Workflow,’ by Hariharan Ramakrishnan, SPE, Eva Peza, Shekhar Sinha, SPE, and Miriam Woods, Schlumberger, and Christopher Ikeocha, Flemming Mengel, Yves Simon, Paul Pearce, Jeff Kiester, Steven McKetta, SPE, and John Jeffers, SPE, Southwestern Energy, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

A comprehensive workflow was developed that incorporates geologic, seismic, and production data in an effort to understand and predict the performance of gas wells in the Fayetteville shale play. A reservoir model was developed by integrating all available well, log, petrophysical, sonic, image, core, stimulation, production, microseismic, and processed surface-seismic data. This static reservoir model was used to history match the short- and long-term production performance and its variations across the exploration area. The reservoir characterization and the dual-porosity simulation model were used to predict production performance of future wells in the Fayetteville shale formation.

Introduction

Significant technological advances have been made toward identifying shale-gas resources and developing those resources economically. Acquiring (and use of the correct combination) of information and measurements to understand production capabilities early in the life of a large play remains a critical challenge. An integrated seismic-to-simulation workflow was developed to understand and predict the production performance of Fayetteville shale-gas wells.

The Fayetteville shale-gas play extends across northern Arkansas, USA, from the state’s western edge through-out north-central Arkansas. Ranging in thickness from 50 to 550 ft and varying in depth from 1,500 to 6,500 ft, this Mississippian shale is the geologic equivalent of the Barnett shale in north Texas and the Caney shale in Oklahoma. Currently, this operator controls approximately 916,000 acres, which produced 350 Bcf of gas in 2010. Between the start of the project in 2004 and 31 December 2010, the company had spudded 2,445 wells.

Geological Setting

The structures in this area are the result of Precambrian-to-Cambrian rifting that generated the Reelfoot rift, also called the Mississippi Valley graben, and subsequent compressional tectonics of the Ouachita orogeny. The rifting event generated large normal northeast-striking faults, whereas the tectonics related to the development of the Ouachita orogeny is characterized by generally north-directed thrusting as a result of continent-to-continent collision along the southern margin of North America. The current orientation of maximum horizontal stress is northeast/southwest. In the study area, the Fayetteville shale is 250 to 300 ft thick and at a depth of 2,500 to 3,000 ft.
Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146765, ’Economics and Technology Drive Development of Unconventional Oil and Gas Reservoirs: Lessons Learned in the United States,’ by C.P. Flores, SPE, PB Energy Storage Services, and S.A. Holditch, SPE, and W.B. Ayers, SPE, Texas A&M University, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

Advances in technology and better economics have supported the exploitation of unconventional reservoirs in the United States. The concept of the energy-resource triangle put forth by J.A. Masters in 1979 explains that unconventional oil and gas are abundant but the exploitation of these resources is particularly sensitive to both technology and commodity prices. Here, the effects of technology and various geopolitical and economic events on US unconventional production are assessed in the context of Master’s resource-triangle theory (RTT).

History of Commodity Prices—Oil- and Gas-Price Fluctuations

Traditionally, commodity prices have been the result of the supply and demand in the markets; however, on occasion, organizations have restricted production to try to affect prices. The fluctuations in oil prices are also related to various political events.

Major critical petroleum-related events from 1861 through 2006 explain fluctuations in oil prices. The Pennsylvania oil boom in the 1860s saw prices reaching a peak of USD 104.35/bbl (in 2006 dollars) until the oil boom began in Texas with the discovery of the Spindletop (1901) and East Texas (1930) fields. The boom in Texas originated a period of stable, low prices sustained by product availability. In 1931, oil prices fell to a low of USD 8.66/bbl (in 2006 dollars) and continued to be relatively stable until the oil crisis in the Middle East during the 1970s. The Yom Kippur war in 1973, the Iranian Revolution in 1978–79, and the Iraq invasion of Kuwait in 1991–92 caused spikes of USD 14.99/bbl (in 2006 dollars), USD 88.13/bbl (in 2006 dollars), and USD 29.71/bbl (in 2006 dollars), respectively. In 1998, the Asian financial crisis saw prices fall to USD 16.22/bbl (in 2006 dollars), but, in 2006, oil prices quadrupled, reaching USD   65.14/bbl. The increase in oil prices continued until recently with prices of approximately USD 70/bbl.

Political, economic, or social events are, among other parameters, responsible for oil-price fluctuations. Historically, periods of high prices have benefited the exploitation of unconventional reservoirs because these reservoirs require costly stimulation methods to produce at economic rates. The link between periods of high price and development of unconventional reservoirs supports the RTT.
Technology Focus: CO2 Applications (July 2012)
Authors: Rogers John D.
Published: February 2015

Technology Focus

Last year in this focus on CO2 applications, I (as others have) connected enhanced oil recovery (EOR) as an enabling business foundation and a possible way forward to accomplish carbon capture and storage (CCS) as a business investment. This year, in an address to the CCS conference in Pittsburgh, Pennsylvania, US Department of Energy (DOE) Assistant Secretary of Fossil Energy Charles McConnell encouraged the CCS industry to help operators establish a salient business case between CO2 EOR and usage and sequestration. Creating a technical lead in CO2 EOR and other usage technologies establishes an opportunity to commercialize the technologies that could be in high demand in the years to come, particularly in coal-reliant developing countries such as China and India.

The technologies needed to accomplish carbon capture, utilization, and storage (CCUS) require expertise in science and engineering that, in some cases, are not completely matured or, at least, require a different focus and commitment in science and business to affect CCUS. An acceptable return on investment will depend on economic CO2 capture and largely on regulatory stability.

Administratively, the US Environmental Protection Agency proposed a carbon pollutions standard for new power plants, which will have to meet 1,000 lbm of CO2 per electrical megawatt-hour produced. Older coal plants average approximately 1,768 lbm of CO2 per megawatt-hour but are exempt from the standard, as are plants permitted to begin construction within a year. A typical natural-gas electricity-generation plant emits 800 to 860 lbm of CO2 per megawatt-hour.    

Recommended additional reading at OnePetro: www.onepetro.org.

IPTC 15029 An Integrated Reservoir-Simulation/Geomechanical Study on Feasability of CO2 Storage in M4 Carbonate Reservoir, Malaysia by Rahim Masoudi, Petronas, et al.

CMTC 151027 NETL CO2-Injection and -Storage Cost Model by T.C. Grant, US Department of Energy, et al.

SPE 154539 Evaluation of the CO2-Storage Capacity of the Captain Sandstone Formation by Min Jin, Heriot-Watt University, et al.

SPE 145440 Monitoring on CO2 EOR and Storage in a CCS Demonstration Project of Jilin Oil Field China by Shaoran Ren, China University of Petroleum, et al.

CMTC 151716 The Longannet to Goldeneye Project: Challenges in Developing an End-to-End CCS Scheme by P.J. Garnham, Shell, et al.
Shale 2.0: From Efficient to Effective Shale Development
Authors: Meisenhelder Jeff
Published: February 2015

Guest editorial

Hydrocarbons from shale were first produced commercially as long ago as 1821, and from the 1860s through the 1920s gas was produced from shallow, low-pressure, naturally fractured shales in the eastern US. However, today’s shale “revolution” did not really begin until 1985. That was when George Mitchell started developing a model for economically viable exploitation of the Barnett Shale. It took almost 20 years and literally hundreds of wells to find the right formula, based on two transformative technologies: horizontal drilling and multistage hydraulic fracturing.

Shale 1.0: The Quest for Operational Efficiency

Since roughly 2005—the beginning of what I call Shale 1.0—we have successfully revived old shale plays and developed new ones. Every year, North American companies complete thousands of wells in shale reservoirs. However, even in mature plays like the Barnett, where productivity per well has doubled or tripled over the past decade, as many as 30% of all perforation clusters contribute absolutely nothing to production. That is the same as drilling 30 totally nonproductive wells out of every 100. To improve shale economics, operators and oilfield service companies have focused considerable brainpower and technical resources on reducing the unit cost of production through greater operational efficiency.

In many cases, we have brought drilling and completion costs down 50%, largely through application of new technologies, efficient project management, and supply chain negotiations. In some cases, advanced drilling technologies, automation, and real-time data have slashed average time to total depth from 48 days to just 8. Not all new technologies are exotic. For example, installation of rupture disk valves—which replace coiled tubing or drillpipe-conveyed perforations for the first stage in horizontal wells—reduced completion costs in 15 Eagle Ford wells by more than USD 100,000 per well. 

The shale revolution has yielded many economic and social benefits, including growth in jobs and local businesses across the US, lower domestic energy costs, reduced CO2 emissions, and—perhaps most important—access to a new national resource that holds enormous potential for long-term energy security.

According to the Institute for Energy Research, the US has more than 200 years’ capacity of technically recoverable oil reserves and 110 years’ worth of natural gas at current rates of consumption, much of those from unconventional plays. In fact, shale oil is leading the current growth in US crude production. The US Energy Information Administration conservatively predicts global shale oil production will reach more than 4 million BOPD by 2030. Other analysts double that estimate.
Mobile Mixer Adds Dry Friction Reducer to Fracturing Fluid at the Wellsite
Authors: Nakra Geeta , Wright Steven , Wright David
Published: February 2015

Technology Update

A mobile system has been developed that mixes consistent solutions of powder-based friction reducers (FRs) at the wellsite and adds them to hydraulic fracturing fluid. The use of the system has achieved reductions in fracture stage cycle times of as much as 10% and significant cost savings, compared with the convention-al use of oil-based liquid emulsion FRs in slickwater fracturing fluids.

In addition, the use of powder-based FRs reduces the potential of the FR solution freezing, settling, or gelling and eliminates the hazard of liquid FR spillage in work areas. 

Water-soluble dry polyacrylamide can be used as an FR, with the selection of a polymer dependent on water quality. Dry FRs can perform in waters ranging from fresh water to high-brine produced water.

The challenge to developing the use of dry FRs in fracturing fluid was the ability to hydrate them on a treatment site. The PowderFrac mobile mixing and feeding system developed by SNF has performed successfully in the field since its initial deployment in the Barnett Shale of Texas during 2011. The system provides onsite storage, hydration, and dose control of the powder FRs.

The mobile unit enables well operators to reduce logistics and labor costs, and the chemistry of the dry FR solutions is also less costly. Deployment of the mobile unit does not require the modification of equipment or infrastructure at the fracturing site. The unit was designed and built with field replaceable parts to ensure prompt, cost-effective vehicle maintenance while deployed.

The equipment includes a patented Polymer Slicing Unit (PSU) for rapid hydration of the dry FR. The PSU can operate at treatment rates up to 120 bbl/min. Additional equipment consists of two solution tanks, a 12,000-lbm dry storage container, a horizontal screw conveyor, water filter pots, water pumps, FR solution pumps, and a self-contained generator system that can be fueled by an onboard tank or the saddle tank of the tractor.

Safe deployment and operation is a crucial part of the unit’s design. All electronics capable of data recording can perform reporting and analysis. The mobile unit, 45 ft in length, requires no special transport permits and can be refilled with dry powder FR by a powder bulk truck.

The friction reduction from a polyacrylamide will be affected by water quality and salinity and any other additives in the fluid that interact with the polymer. Concentrations of FR are adjusted during the treatment to lower or raise the pumping pressure.
CLD Rigs, MPD Change Equation for Deepwater Well Control
Authors: Grayson Brian
Published: February 2015

Technology Update

Closed loop drilling (CLD) systems and managed pressure drilling (MPD) are challenging long-held industry ideas about well control. This realignment in philosophy is happening because of a unique ability to precisely monitor, analyze, and control wellbore pressure in real time.

These capabilities are the basis for a growing number of proactive and reactive methods and tools that are solving many conventional well control problems. This is particularly true in the extremes of deepwater drilling, in which managing wellbore pressure plays a principal role in safety, efficiency, and even the ability to drill the well. Fig. 1 presents many of the critical issues addressed by advances in MPD.

Although the number of deepwater MPD applications is relatively small, the advantages being achieved with closed loop systems are driving its increased use and the development of specialized deep-water MPD technology and drilling rigs.

Monitoring and Control

MPD reduces well control events and pressure-related wellbore problems by addressing two key challenges associated with conventional methods: the uncertainty of the predrill model and the inflexibility of the resulting well design and mud regimes. These challenges are overcome by a dynamic capability that is counter to static predrill models.

Uncertainty is reduced by very precise measurements of wellbore pressure profiles in real time. Just as important, MPD complements this information with equally precise real-time control. This dynamic solution is proving a key enabler for enhancing safety, efficiency, and operational capabilities in deepwater drilling.

To achieve these capabilities, MPD builds on the inherent characteristics of a closed loop system. Within this contained, pressurized wellbore environment, pressure is closely monitored. Pressure changes, such as those caused by an influx, loss, or ballooning, are rapidly detected and controlled in increments as small as a few barrels. Accurate fingerprinting of these minute pressure oscillations quickly identifies the event, which both informs an effective response and avoids a misdiagnosis that can exacerbate the condition.

The MPD control response is initiated at the surface by automatically or manually varying the annular backpressure by using a specialized MPD choke manifold. These changes within the closed fluid system are used to manipulate downhole pressure without the delay, cost, and imprecision of changing mud weight.

The ability to immediately dial in and hold the desired wellbore pressure changes the well control equation fundamentally with a new set of proactive and reactive pressure management options.

Micro influxes that are the precursor to well control events are quickly managed before they can escalate into a kick. When kicks occur, they are rapidly identified, controlled, and circulated out of the well. This mitigates a significant source of risk and nonproductive time (NPT).
Well Capping Becomes an Industry of Its Own
Authors: Rassenfoss Stephen
Published: February 2015

Well Control Improvements

The word to describe offshore well capping is more. There are more people being hired to manage more hardware in more places around the world, and there are more things under development.

A niche business within the offshore exploration and production sector has sprung up since the Macondo disaster destroyed the Deepwater Horizon in 2010, which killed 11 and flowed for months before it was finally capped. This growing industry is going to be a “lasting and ever-evolving” part of the business, said Kurt Kriter, Americas regional director for Oil Spill Response Ltd. (OSRL), which is one of the interlocking network of industry-owned organizations responsible for this growth.

Oil Spill Response is an industry-owned cooperative whose responsibilities include owning and managing equipment to quickly respond to out-of-control wells around the globe for another group created by nine big oil companies, called the Subsea Well Response Project (SWRP).

The four recently established hubs covering major oil regions around the globe feature four high-capacity capping stacks, which were built using design advice from the engineering departments of the SWRP members. The two highest-performance units can shut off a well flowing at 15,000 psi, and divert up to 100,000 B/D to surface vessels. When the last of the caps is delivered later this year to Brazil by Trendsetter Engineering, it will mark a transition for this business, which has been focused on building capping stacks, going from zero before Macondo to around 20 currently. The focus is shifting toward operations and developing improved response methods.

This year, OSRL is staffing hubs in Stavanger, Norway; Cape Town, South Africa; Angara dos Reis, Brazil; and Singapore, with six in each location, and 10 in its British well response center, said Jan Strom, director of subsea well intervention services for OSRL. The local teams are charged with maintenance and logistics, with support from outside advisors, such as Trendsetter, which has built nine caps, making it one of the largest companies active in this field.

Well capping companies began in the US, with Marine Well Containment Corporation (MWCC) and Helix Well Containment Group (HWCG). They were created to allow offshore exploration companies to share the cost of buying and maintaining the equipment needed to respond to well incidents. Macondo showed the need, and led to US regulations requiring operators to demonstrate they have access to the equipment and expertise needed to stop an offshore blowout. Now governments around the world have similar regulations.