bluuebunny/crossref_metadata_2025 huggingface dataset:
George P. Mitchell and the Barnett Shale
Authors: Steward Dan B.
Published: February 2015

Mitchell and the Barnett Shale

George P. Mitchell died on 26 July 2013 at the age of 94. He left behind a multifaceted legacy that testified to his entrepreneurship, philanthropy, and love of country. Within the oil and gas community, this legacy focused on his work to prove up the Barnett shale unconventional gas resource, which established him as the “Father of the Shale Gas Revolution.” Through his vision, perseverance, and commitment, the knowledge base and application of existing and new technologies not only revolutionized the search for shale gas, but also carried over into tight oil and gas reservoirs, changing the global outlook for both.

Beginnings: Getting Into the Gas Business

George Mitchell entered the oil and gas industry through the encouragement and tutelage of his older brother Johnny. After graduating from Texas A&M University in 1940, earning a degree in petroleum engineering with an emphasis in geology, Mitchell served in the Army Corps of Engineers during World War II. He began working with his brother on oil prospects while still a member of the Army Corps. He and Johnny established their first company, Oil Drilling Inc., in the late 1940s, with George generating drilling prospects and his brother finding investors.

Ellison Miles, an acquaintance of George’s from his time at A&M, started a drilling company in north Texas after leaving the Army. He and business associate, John A. Jackson, became aware of the potential for a large stratigraphic gas accumulation in Pennsylvanian-age Atoka conglomerates in the Fort Worth basin of Texas and communicated their thoughts to George. Oil Drilling put together the necessary money and took their first lease in the Fort Worth basin, a 3,000-acre tract in southwest Wise County.

In 1952, George Mitchell’s journey to the Barnett began with the drilling of the first well on this lease, the D.J. Hughes No. 1. The well encountered multiple members of productive conglomerates and was completed as a shut-in gas well. According to Kutchin (2001), within 90 days of this discovery, Oil Drilling acquired 300,000 acres in the north Texas area. Subsequent test and re-entry of previously plugged wells confirmed the significance of the find.
SPE Liquids-Rich Basins Conference: New Technology for Old Plays
Authors: Beckwith Robin
Published: February 2015

Conference review

SPE’s recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme “New Technology for Old Plays,” SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories.

This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions—each with three speakers—each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday’s luncheon; and investigate the offerings of more than 20 exhibitors.

Two training courses were also given—a 2-day course Monday and Tuesday, 9 and 10 September, titled “Modern Production Data Analysis for Unconventional Reservoirs”; and a 1-day course Friday, 13 September, titled “An Overview of Microseismic Imaging of Hydraulic Fracturing.”

Thinking Strategically

The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development.

Crude and Liquids Growth in the US. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, “US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!” “‘Liquids-rich’ is my least favorite term,” he said. “It’s as accurate as calling a dog a non-cat.”

Basically, he said further, what people are talking about is natural-gas liquids (NGLs): “If it’s crude, they’re going to say it.”

When considering the question of why Brent crude is at USD 110/bbl, he said, “Risk premium is the last possible answer before the shoulder shrug.” He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms.

The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries’ (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries’ demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012.
Novel, Thermally Stable Fluid-Loss Pill Performs Better Than Guar-Based Gels
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165096, ’Performance and Formation-Damage Assessment of a Novel, Thermally Stable Solids-Free Fluid-Loss Gel,’ by Pubudu Gamage, Jay P. Deville, SPE, and Bill Shumway, SPE, Halliburton, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed.

A novel solids-free fluid-loss pill for higher-temperature reservoirs has been formulated. This pill can be used effectively in reservoirs with temperatures up to 350°F. Static thermal aging at 320°F demonstrated no noticeable loss of gel strength for at least 20 days. With regard to thermal stability and fluid loss, the synthetic-polymer-based gel outperforms guar-/borate-based gels tested under similar conditions.

Introduction

High downhole temperatures put a strain not only on equipment but also on the complex chemistry of drilling muds, drill-in fluids, and viscous pills. Some conventional materials, such as polysaccharide gums and sodium tetraborate crosslinking agents, are demonstrably unstable or simply rendered useless under high thermal loads for extended periods. This paper describes the development of a material for one such challenge—replacement of biopolymer-based gels for high-temperature applications. Research produced a novel, workable aqueous monovalent brine-based gel derived from a synthetic water-soluble polymer. The gel, which can be used for a variety of downhole applications including well kills, perforations, and other fluid-loss applications, is thermally stable and can be applied at temperatures up to 350°F, conditions where both polysaccharides and borate crosslinking begin to fail.

The gel was specifically developed to be used in a 320°F gas reservoir. Gas regained permeability was used to assess any formation-damage issues of the gel in downhole applications. However, leakage of brine into the core during the hold-off period alters the water saturation of the core, adding complication in the regained permeability experiments because of water blockage.

Experimental Section

Gel Formulation. Gel was formulated with a high-density brine solution of a synthetic water-soluble polymer and a metal-based crosslinker. Further additives include pH buffers to lower the pH to an appropriate range for crosslinking to occur (pH of 4 to 5) and thermal stabilizers to mitigate gel decomposition by radical reactions and other processes. Concentration of polymer, the polymer/crosslinker ratio, and the pH of the formulation were tuned carefully to provide optimized gelling and fluid-loss properties. The formulations presented in this paper were based on 10.0-lbm/gal brine prepared by diluting stock 12.5-lbm/gal NaBr brine with water.
Impact of Liquid Loading in Hydraulic Fractures on Well Productivity
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163837, ’Impact of Liquid Loading in Hydraulic Fractures on Well Productivity,’ by Samarth Agrawal and Mukul M. Sharma, SPE, The University of Texas at Austin, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed.

One of the major challenges in fracturing low-permeability gas formations is the loss of well productivity caused by fluid entrapment in the matrix or fracture. Studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped because of the high capillary pressure in the matrix. This study shows that, in regard to hydraulic fractures in horizontal wells, the fluid may also be trapped within the fracture itself and may affect the cleanup as well as productivity. 

Introduction

The loss of fracturing fluid and its impact on the productivity of hydraulically fractured wells have been studied for many years. Conventional wisdom suggests that the liquid is trapped at the fracture face because of capillary effects. This reduces the relative permeability of the hydrocarbon phase during flowback. Most studies published thus far on the subject ignored the accumulation of liquid in the fracture itself and the effect of gravity and fluid segregation in the fracture. In this study, we show that liquid accumulation in the fracture itself can be significant and that this fluid saturation is coupled with the fluid saturation in the matrix, leading to a very different cleanup profile and time scale for cleanup. A 3D reservoir simulator was used to investigate liquid loading in hydraulic fractures in a horizontal well. Generally, hydraulic fractures in horizontal wells range from tens to hundreds of feet in height. If liquid loading takes place in a certain section of the fracture, it will impair the flow of gas there. This will lead to a reduction in the effective producing fracture area, even if the drawdown is greater than the capillary pressure. 

Liquid Loading Inside the Fracture. The desired lift velocity for unloading liquid and the available gas velocity in a fracture differ by almost two orders of magnitude. It is, therefore, very like-ly that the lower portions of fractures will be filled with liquid when production is initiated. This suggests that concerning load recovery from hydraulically fractured horizontal wells, even if the drawdown is able to overcome the capillary pressures, the inflow gas velocity may not be high enough to lift the liquid against gravity into the wellbore (Fig. 1). Liquid loaded inside the fracture in this way will affect the productivity of the well and the cleanup of the matrix. Understanding the conditions for liquid loading within the fracture will help identify remedial measures, which may be significantly different from remedial measures for reducing liquid blocking at the fracture face.
Reducing Intervention in Subsea Wells With Fiber-Optic Technology
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23929, ’Reducing Intervention in Subsea Wells With Fiber-Optic Technology,’ by John Lovell, Schlumberger, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

Fiber-optic-system installations have reduced the need for intervention by logging tools and have given crucial insights into wellbore integrity and reservoir production. Consequently, a prime application of fiber technology should be in deepwater fields, where intervention can be prohibitively expensive. The reluctance to incorporate downhole fiber appears to be caused by limitations of technology relating to cables, deployment, acquisition, and interfacing. These barriers are slowly being eliminated, and a small number of subsea wells have now been implemented with in-well fiber. 

Introduction

Permanently installed fiber-optic systems have been commercially available in the oil field since the early 1990s, with the bulk of the deployments providing fiber-optic distributed temperature based upon Raman backscattering. This Raman distributed-temperature-sensing (DTS) measurement system provides continuous data along the length of the completion without the need for intervention and without introducing restrictions in the inner diameter of the completion tubulars, restrictions that could impede subsequent wellbore access. Typical DTS spatial resolution is better than one data point per meter, with a temperature resolution of 0.01°C. Applications of the distributed-temperature data have included calculating flow contributions across the sandface, evaluating water-injection profiles, diagnosing the effectiveness of fracture jobs, finding cement tops behind casing, and identifying crossflow between producing zones.

The growth of fiber installations for dry-tree (land and platform) applications is increasing exponentially. More than 1,200 installations have been deployed by one service company alone. Most of those installations were single-stage completions, often for thermal or steam-assisted-gravity-drainage (SAGD) application, and relied upon the ability to pump fiber along a control line to convey the sensing fiber. Approximately 20 of those wells have fiber pumped along the sandface of dual-stage openhole-gravel-pack (OHGP) completions.

A significant advantage of the pumped fiber was that, if the fiber degraded over time, it could be pumped out and replaced. This was particularly important before the discovery of how to construct fibers with some immunity to darkening from H+ and OH− ions. With hydrogen resistance came the possibility of increased longevity for fixed-fiber cables, and, since 2006, an alternative to pumped fiber has been available that combines multiple hydrogen-resistant fibers with an electronic line to create a hybrid cable (Fig. 1). This cable can power high-accuracy quartz gauges and can also give the benefits of fully distributed Raman DTS. More than 60 such systems have been deployed to date.
Securing a Productive Future for E&P: It's All About New Technologies
Authors: Gamman Einar
Published: February 2015

Guest editorial

The easy oil is gone. Schlumberger described it this way in its 2009 annual report: “As the exploration and production industry strives to meet the energy needs of tomorrow, it is challenged by deeper waters, increasingly complex geo-logical settings, more diverse hydrocarbons, and greater extremes of temperature and pressure.”

US President Barack Obama said it like this in a June speech on the tragic Deepwater Horizon accident in the Gulf of Mexico: “…oil companies are drilling a mile beneath the surface of the ocean because we are running out of places to drill on land and in shallow water.”

The reality behind these remarks, coupled with current economics, can paint a grim picture. In 2009, technology expenditures in the oil and gas industry were curtailed as world economic conditions worsened, dropping oil prices to under USD 40/bbl. The price has now recovered, remaining between USD 70 and USD 80/bbl, but regulatory uncertainty and other factors have kept the company purse strings closed on all but the most essential expenses.

In these times it is important that the oil and gas industry learns a few important lessons. The Deepwater Horizon incident has shed light on how dependent the industry is on technology that will perform in some of the Earth’s most difficult conditions, as well as how critical it is to protect employees, the public, and the environment—regardless of the cost.

As we look to the future, our industry faces rising energy demand—specifically an increasing need for transportation energy—and new, more stringent regulations on operations in many parts of the world. This means our industry will continue to move toward reserves that are harder to produce, and that increasing recovery from currently producing fields will have to be a priority to meet future demand.

How will we be able to produce more hydrocarbons in remote and complex environments and increase operational safety? The answer is, and has to be, technology.

Technology is the only bridge between where we stand now and a future in which we can produce hydrocarbons in ways that are safer, cleaner, and more efficient. But this begs another question. Investments in reserves and production are firmly at the top of most E&P companies’ agendas, with R&D coming in as a much lower priority, if it makes the list at all.

Historically, there are numerous examples of how our industry has made incredible advances in technology to meet increasingly difficult E&P challenges—advances that have moved the entire industry forward and resulted in billons of barrels of additional oil produced.

Across just about any industry, innovation is more fertile outside the largest companies and organizations. Oil companies themselves are doing less in-house technology development than in the past and, where service companies used to spend a sizable portion of their budgets on targeted R&D many have realized that acquiring intellectual property, technology, and services is an equally interesting and profitable way to increase their footprint.
Gas-Reserves Estimation in Resource Plays
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130102, ’Gas-Reserves Estimation in Resource Plays,’ by W.J. Lee, SPE, Texas A&M University, and R.E. Sidle, SPE, Consultant, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. See SPE Econ & Mgmt, October 2010, page 86.

The petroleum industry’s lack of understanding of physical properties and the physics that control production from many important resource plays limits the ability to model and forecast production and reserves from these resources with confidence. While measurement technology and modeling accuracy are improving, the industry often is forced to resort to empirical methods that lack the validation usually required for high-confidence results. Some of the procedures in common use for forecasting are reviewed, and key strengths and limitations of the techniques are identified.   

Introduction

Preferably, proper characterization of a resource play begins with production. When attempting to characterize a resource and to forecast production, it is important to know what can and cannot be determined. Thus, pilot tests, resource characterization, and analogs are favored over curve fitting or highly complex reservoir simulation. Analytical models not based on analogs are useful, but only to investigate the generalized incremental effects of different production conditions, such as horizontal vs. vertical wells or completion and well-operation methods. Analogs (usually based on older in-field wells) for decline analysis or type-curve techniques generally would be the preferred methods for high-confidence forecasts and reserves estimates. This approach has proved valuable in examples as diverse as the Antrim shale, Pinedale tight gas, and California diatomite.

As a result, high-confidence reserves estimates begin with older wells—wells that have experienced any early-life transient-production effects and have reached a stage in which only stable, long-term trends are the dominant influence on production rate. The considerable complexities of production from resource plays make it important to isolate early effects from those that are fundamental to ultimate recovery.

An incomplete understanding of the basic physics of fluid flow and stimulation results in complex-resource plays currently of interest has limited the ability to develop models that provide high confidence, particularly in shales. Because of this lack of understanding, empirical methods take on an unusually important role, but production histories from the most-modern completion and stimulation techniques are limited in duration, causing problems with validation of a forecasting methodology of any kind. The full-length paper provides a detailed critique of the methods used to forecast production and estimate reserves in poorly understood resource plays.
Spectrum: SPE's Efforts on Young Technology and Innovative Ideas
Authors: Thakur Ganesh
Published: February 2015

President's column

The need for oil and gas has not diminished and, contrary to popular belief, supply is abundant. Getting to that supply is the challenge. Many reservoirs are very complex in nature and reside in extreme environments. Producing these assets will require the most advanced technology, the brightest minds, more capital, and attention to safety and the environment.

To keep up, the industry must continue to invest in R&D and become better at being early adopters of technology. The industry has historically been slow in the uptake of new technology, but conditions will mandate a step-change in our behavior. Instead of adopting technology 10 to 15 years after its inception, the oil and gas industry needs to create ways to accelerate that time line. We cannot afford to spend 10 years vetting technology as we did with horizontal wells. It took 10 years to see a spike in SPE papers about horizontal well technology from its inception.

I believe SPE should take a leadership role in this initiative. SPE collects, disseminates, and exchanges technology and technical information that is vital in the uptake of new technology. The industry looks to SPE conference papers, books, periodicals, and events as guidance in what is successful in the industry. It is this exchange of ideas and knowledge sharing that is the vehicle to adopting technology. But this vehicle should have the speed of a Porsche, not a jalopy. Information about new and young technology should play a larger role in our communication. The earlier the communication, the faster the uptake.

The life cycle and uptake of technology can be represented by a curve (Fig. 1). Time is represented on the x axis and technology usage on the y axis. The curve is initiated by the innovator. In the first part of the curve, the usage is low, with only a few early adopters—the adventurers. As the technology proves successful, more users engage and the slope increases. When the technology becomes more established, the curve levels off, indicating that most operators have adopted the technology. Finally, the curve levels off as the technology becomes best practice.
Imagination, Purpose, and Vision
Authors: Fattahi Behrooz
Published: February 2015

Guest editorial

With the changing landscape of reservoir management, SPE has made dissemination of emerging technology a high priority. SPE meetings are excellent venues where you listen, debate, and discuss with some of the best brains in the industry on what will become the “next big thing,” possibly the game changer. We also look at what challenges the industry must face, and what technology can provide to help meet those challenges. This is a priceless experience. Whether it is a futuristic look at evolving reservoir surveillance and management technology (including data acquisition, high performance computing, processing, integration, visualization, and modeling), or what automated and intelligent applications of technology can do, SPE plays a key role in examining the path of progress toward the future of using game-changing technologies.

Daunting Challenges

The balance between the global supply and demand for crude oil is becoming tighter, increasingly requiring our industry to face new and unique challenges. The significant challenges are in the areas of operation in the inhospitable deepwater Arctic and economic recovery of unconventional oils.

More than two-thirds of the remaining known world oil reserves are in the unconventional form that mostly comprises heavy, extra-heavy and oil sands, and bitumen. With the estimated proven oil reserves at approximately 1.2 trillion bbl, the current unconventional oil reserves add up to roughly 800 billion bbl. This is a large figure, but we must remember that the world’s remaining oil in place probably amounts to 6 trillion to 7 trillion bbl. The technical and environmental challenges of recovering this oil are immense.

While we will not run out of oil anytime soon, the significant challenge will be to produce oil at a pace to meet the energy demand from the growing global economies led by China and India. The US Energy Information Administration predicts that the demand for energy will rise to 700 quadrillion BTUs or by more than 50% by 2030. The same outlook also projects that more than 80% of this future energy consumption will be from fossil fuels.

A recent study by Energy Files shows that the gap between the oil supply and demand will grow dramatically to as much as 20 million B/D even with painful conservation measures in place. The alarming report requires our immediate attention.

The immense challenges ahead are global, multidimensional, complex, and interlaced. Failure in one area will have detrimental effects on others, posing a serious threat to our growth. These issues are many and some of the most critical ones we are clearly experiencing today, namely management of human assets, technology from development to application, process optimization, collaborative efforts, and managing risk and uncertainties. These are not new issues, but ones that have become the most critical to the future of oil supply.
Brazil Using Offshore Oil Boom To Build International R&D Center
Authors: Rassenfoss Stephen
Published: February 2015

In Rio de Janeiro, they are building an island of energy technology.

Near the center of the Ihla do Fundao is Petrobras’ central research center (Cenpes), which recently doubled in size with an enormous structure topped by a roof that looks like a giant wave. From the open top floor is a view of the south end of the island where the Rio Technology Park is sprouting.

The park, nearly vacant a year ago, is now home to Schlumberger’s Brazilian research center. Its staffers will soon be joined by hundreds more from FMC Technologies and Baker Hughes. The construction wave is expected to grow from here. Within two years, the park is expected to be filled by international companies including Halliburton, BG, General Electric, Tenaris, and Siemens.

Between the technology park and Petrobras lies the campus of Federal University of Rio de Janeiro (UFRJ). The university, which created the park, is part of a network of research institutions in Brazil that have partnered with Petrobras on research and development (R&D) projects that have helped the company become an exploration and production (E&P) technology leader.

The island is on the leading edge of Brazil’s drive to become an international center for oil industry technology development. Fueling the transformation are the billions of barrels of oil found beneath a thick layer of salt in the deep waters far off the coast of Brazil.

Investor-owned oil companies are buying into government policies that will funnel billions of dollars into research in Brazil because the country offers a rare opportunity to lease off shore blocks that could hold billions of barrels of crude. Winning those blocks at auction requires buying Brazilian, hiring Brazilians, and now developing technology in Brazil.

“We are doing all of this with a purpose” to improve the Brazilian economy, said Magda Chambriard, director of the National Agency of Petroleum, Natural Gas and Biofuels (ANP), which regulates the country’s oil business. “We will have a lot of investment in research and development that will come from these agreements for oil exploration.”

Two parts of the country’s oil regulations are driving the changes: local content requirement and the 1% rule.

In lease auctions, a key measure for determining winners has been how much of the materials, labor, and services used will be from Brazil. Now there is an added criterion: Was the technology developed in Brazil?
A Look at the Ohmsett Oil Spill Research and Test Facility
Authors: Beckwith Robin
Published: February 2015

On 11 October 2011, the X Prize Foundation announced the winners of the USD 1.4 million Wendy Schmidt Oil Cleanup X CHALLENGE, launched during the summer of 2010 in the wake of the Deepwater Horizon oil spill disaster in the US Gulf of Mexico. According to a press release, “the competition inspired entrepreneurs, engineers, and scientists worldwide to develop innovative, rapidly deployable, and highly efﬁcient methods of capturing crude oil from the ocean surface.” Emerging from an original ﬁeld of more than 350 submissions from all over the world, Elastec/American Marine of Carmi, Illinois, captured the USD 1 million ﬁrst prize, with Norway’s NOFI Tromsø awarded the USD 300,000 second prize; no contestant’s cleanup system qualiﬁed to receive third prize.

Testing the 10 ﬁnalists’ technologies in order to determine the winner would have been impossible were it not for a facility called Ohmsett (Oil and Hazardous Materials Environmental Test Tank). What is Ohmsett, and why is it so critical to the development of oil spill prevention and mitigation technology?

Omsett’s Origins

The existence of Ohmsett arose from response to another oil spill disaster.

On 24 March 1989, the Exxon Valdez oil tanker struck Bligh Reef in Prince William Sound, Alaska, spilling an estimated 260,000 bbl to 750,000 bbl of crude oil. Considered one of the most devastating human-caused environmental disasters, a number of preventative or cautionary measures ensued. One of these was the US Oil Pollution Act (OPA 90) of 1990, which among its many provisions established a program providing for “research, development, and demonstration of new or improved technologies which are effective in preventing or mitigating oil discharges and which protect the environment.” The disaster also provided the push needed to get the Oil Spill Liability Trust Fund (OSLTF), created in 1986 by the US Congress, off the ground.

In August 1990, US President George H.W. Bush signed OPA 90 into law, and authorized both the use of the OSLTF as well as collection of revenue to maintain it. One of the primary purposes of OSLTF’s Principal Fund (exclusive of its Emergency Fund) is to carry out oil spill-related research and development (R&D).
Technology Focus: Production Facilities (December 2011)
Authors: Saadawi Hisham
Published: February 2015

Technology Focus

Every year, SPE organizes more than 30 conferences worldwide. Critical issues of current interest to the oil industry are reflected in the SPE papers presented at these conferences. When selecting papers for this feature, I was not surprised that many papers deal with topics related to safety in facilities design and to asset integrity.

With recent publicized accidents and the industry’s continuing concern about its public image, operating companies are focusing on process safety and improving asset integrity, and are addressing these issues early in facilities design. Indeed, it can be argued that enhancing safety performance and dealing with the increased environmental risks remain the key challenges facing the industry today. Some concepts relevant to these topics are briefly outlined.

Asset integrity can be defined as the ability of the asset to perform its required function effectively and efficiently while managing health, safety, and the environment. In this context, asset integrity refers to hydrocarbon systems and includes support systems and infrastructure, such as platform structures.

Critical safety elements are those systems and equipment that prevent, control, or mitigate major accidents. They include elements such as pressure-relief valves, shutdown systems, fire- and gas-detection systems, and firefighting equipment.

Safety instrumented systems (SISs)—since its publication in 2003, the International Electrotechnical Commission (IEC) 61511 standard is becoming the basis for the specifications and implementation of SISs in the oil industry. Initially, the industry was relatively slow to adopt this standard. A dilemma facing operating companies is what to do about the existing shutdown safety systems that were installed before 2003 and that are not in compliance with IEC 61511.

Papers selected for this feature along with those recommended for additional reading highlight industry progress in these issues. I hope that they will be of interest to you.

Production Facilities additional reading available at OnePetro: www.onepetro.org

SPE 146240 • “The Practical Application of Process Safety Principles To Determine and Monitor Asset Integrity of Oil and Gas Facilities” by John Hopkins, WGPSN.

SPE 141174 • “Replacement of Existing ESD Valves With New SIL Rated ESD Valves: A Case Study of Production Optimization and Enhancement of Process Safety and Integrity in Kuwait Oil Company” by Sadoun Mutar Bezea Al-Khaledi, Kuwait Oil Company, et al.

SPE 137461 • “Corrosion Management of a Worldwide Existing Pipeline Network” by Michel Bonis, Total S.A., et al.
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2011)
Authors: Fear Martyn
Published: February 2015

Technology Focus

The last decade has seen significant change in many areas of the drilling business, particularly with bits and bottomhole assemblies. Rising drilling costs, more-complex and -demanding drilling environments, and the ever-present stimulus of provider competition are continuing to drive improved understanding and decision making in this area. The days when bits were seen as simple commodities, with their leverage on well time and cost unrecognized, are fading. And this is long overdue.

Particularly encouraging is the growing use of field-behavior modeling of the bit and drillstring under realistic conditions, and the development of knowledge-based tool-selection techniques, refined by an intensive study of field data. The migration toward deeper or more-tortuous well designs, often accompanied by simultaneous drilling and hole opening in regions in which vibration effects are prolific and are more punishing, is leading to more understanding and rigor. These are admirable trends that more-traditional operations can and should capitalize on, and sometimes are.

My learned colleague Graham Mensa-Wilmot wrote of these trends a year ago in this feature, correctly pointing out to us that “We have the key, let’s open the door.” Perhaps we can claim to have done so with some challenges and in some geographical areas (e.g., vibration diagnosis and mitigation in deepwater Gulf of Mexico operations). However, with other equally important challenges (quantitative optimizing of the rate of penetration comes to mind), fundamental understanding and rigorous methods are not so widespread; we are still operating with “pockets of excellence.” So, it is appropriate to lay another challenge to those managing drilling operations and providing drilling services—if your teams are relying on a fuzzy definition of downhole processes or on trial and error to deliver drilling performance, it is time to modernize—let’s have the current pockets of excellence show the rest of us the way.

Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org

SPE 142431 • “A Practical, Application-Based Guide to Borehole-Enlargement-Tool Selection” by J. McCarthy, SPE, National Oilwell Varco, et al.

SPE 146732 • “Geosteering With Sonic in Conventional and Unconventional Reservoirs” by Jason Pitcher, Halliburton, et al.

SPE 140069 • “Exploration of the Interaction Between Drill-Bit-Gauge Profile and Point-The-Bit Rotary-Steerable Systems” by L.A. Lines, SPE, Weatherford, et al.
Depending On Guar For Shale Oil And Gas Development
Authors: Beckwith Robin
Published: February 2015

Matador, a guar variety jointly owned by Texas Tech University and Halliburton, is grown as a breeders' seed increase (i.e., to increase the amount of seed available) at the Texas Tech campus farm at Lubbock, Texas.

Guar is a modest-looking shrubby plant. Primarily grown in India and Pakistan, it is known there as a “poor-man’s crop,” according to Calvin Trostle, associate professor and extension agronomist, Texas A&M AgriLife Research & Extension Center in Lubbock, Texas.

This stepchild crop has risen in importance during the last few years as the source of an important ingredient that makes high-viscosity (as opposed to slickwater) hydraulic fracturing as effective and cost-effective a process as it is. This ingredient is known as guar gum.

Made from the endosperm of the guar seed, which is ground into a fine powder, a tiny concentration of guar gum interacts quickly with hydraulic fracturing water to thicken it. In simple terms, guar gum renders the water viscous and thus capable of evenly suspending and carrying proppant deep into the fractures that are created with the enormous pressures of the pumped water. Its biopolymeric viscosity properties also help reduce friction and augment water pressure.

No guar substitute has yet been developed that is as effective for high-viscosity hydraulic fracturing, although Halliburton, Baker Hughes, Schlumberger, FTS International, or their affiliates, as well as the chemical company Dupont, are working on developing synthetic polymers whose properties might rival those of guar gum.

According to Mickey Callanan, president of PfP Technology, “Guar is a perfect material for hydraulic fracturing.” He cites the following elements that guar gum brings to bear:

Available in large amounts

Availability currently not limited

Affordable, low cost

Superior thickening agent

Excellent friction reducer

Crosslinkable

Breakable

Biodegradable

Trostle says reported oilfield services industry numbers suggest that an average amount of guar gum required to hydraulically fracture one well could be as much as 20,000 lb. That is the equivalent of about 100 acres of average-yielding west Texas dry-land guar production (at 750 lb/acre).

Guar gum is also used as an ingredient in drilling fluids and enhanced-oil-recovery methods, though not as consistently or in such vast quantities as for hydraulic fracturing. Arguably, without guar, shale gas and oil development would not be burgeoning nearly to the extent it is.

Humble Beginnings to Today’s Prominence

Although guar pods (with the seeds inside them), which grow in clusters on the plant, are used for human consumption, the traditional use of guar has been for cattle feed. In fact, according to Sudhir Merchant, chairman and chief executive officer of Encore Natural Polymers of Ahmedabad, India, in India “gaw – har” means “cattle – food.”
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2012)
Authors: Fear Martyn
Published: February 2015

Technology Focus

The oil and gas business continues to migrate toward deeper plays, less drillable geology, and more tortuous directional objectives, all within a cost framework that sustained high oil prices are driving upward. Our part of the oil and gas industry—well construction—is having to expand drilling capability and continuously improve efficiency so that operators can keep marginal projects economic and avoid dramatic departures from planned schedule and cost.

Against this background, it is vital that our knowledge of the downhole drilling environment improves. The historical habit of “try it and see,” driven by an absence of downhole measurements or the applied use of them, all too frequently failed to deliver predictable performance, especially in technically demanding scenarios. Our industry deserves better than that, so it is appropriate to ask, “Are we optimized yet?”

As in previous features, there is progress to celebrate. The articles here will demonstrate that the quest to improve understanding of drillstring and tool behavior, to optimize well placement, and to execute with failure avoidance and ever-improving performance continues. It is much rarer now to see operations plagued by poor bit selection, baffled drilling teams, and repeated tool failures—a tribute to the drilling industry’s hunger to improve.

There is, however, more to do—rate of penetration to be raised, bit life to be lengthened, tool life to be improved, geosteering to be refined. So, if your team is not actively working on improvement in these areas or is not equipped with the knowledge or data to do so, ask why; there are people and tools out there ready to help. Let’s remember that, when we integrate the measurements, the gurus, and the operational practitioners, improvement usually results. The key to an optimized operation is knowledge; and performance will tell you whether your operation has enough of it. So, if predictable, improving performance is not what you see from your operation or your service, keep pushing. Our industry needs it.

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

SPE/IADC 151175 A Systematic Approach To Improving Directional Drilling Tool Reliability in HP/HT Horizontals in the Haynesville Shale by Errol Pinto, Shell Upstream Americas, et al.

SPE 151377 Anomalous Behaviors of a Propagating Borehole by Luc Perneder, University of Minnesota, et al.
New Model of Bit Whirl Takes Into Account Boundary Conditions at Bit/Rock Interface
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156240, ’A New Model of Bit Whirl,’ by Yevhen Kovalyshen, CSIRO Earth Science and Resource Engineering, prepared for the 2012 SPE/IADC Asia Pacific Drilling Technology Conference and Exhibition, Tianjin, China, 9-11 July. The paper has not been peer reviewed.

Previous analytical models of bit whirl considered bottomhole assembly (BHA) mass imbalance to model bit whirl. The model presented here takes into account the history-dependent boundary conditions at the bit/rock interface. Within this model, the geometry of the bit is characterized by three dimensionless parameters. The results show that, depending on the value of these parameters, the system can be stable or undergo forward or backward whirl. As a result, the model has potential application as a tool that assists bit design.

Introduction

Bit whirl is a lateral vibration of the drill bit during which the bit axis undergoes a circular motion. If the axis of the bit rotates in the same direction as the bit itself, the bit is said to undergo forward whirl. If the axis of the bit rotates in the direction opposite to that of the bit, the bit is said to undergo backward whirl. Bit whirl is the most damaging mode of vibration and is responsible for the premature damage principally of polycrystalline-diamond-compact (PDC) bits. Most whirl models are based on the assumption that the whirl instability is caused by an imbalance of the BHA. The imbalance is either from mass imbalance or from imbalance in the cutting structure. Although experiments show that BHA imbalance can increase the whirl tendencies, a perfectly balanced BHA also can generate bit vibrations. This suggests that bit whirl cannot be explained solely by BHA imbalance. According to field observations, the main factor influencing whirl is bit geometry. For example, a paper published in 1990 states, “... longer tapers, more aggressive structures, or aggressive gauge cutters all significantly increase a bit’s tendency to whirl. Conversely, higher back rake, flatter profiles, and smooth gauge all tend to reduce bit whirl. Also, features that would seem to possibly prevent whirl, such as irregular spacing blades, strongly inverted cones, or perfectly balanced bits, do not completely eliminate whirl … .” According to the same authors, shock subs do not alleviate the problem. Another factor that affects bit whirl tendency is rock strength; the harder the rock is, the higher the chance of bit whirl is. Proper bit/rock interaction has been incorporated into a numerical analysis of bit vibration, but no theories have been able to explain the field observations. In contrast to previous studies, this work takes into account bit geometry and the regenerative effect, while the BHA is modeled as a mass/spring/dashpot system. Furthermore, the investigation concentrates on stability analysis rather than on solution of an evolution problem.
The Control Room of the Future
Authors: Urso Jason
Published: February 2015

Guest editorial

Control rooms have come a long way over the years, and there remains ample room for improvement. Fortunately for operators, though, a significantly improved control room of the future might be closer to reality than they think.

Years ago, control rooms were dominated by large mimic panels covered with gauges and dials that provided a limited view and inflexible means of interacting with the process. Today, the modern control room includes sophisticated graphical user interfaces, and specialized furniture in purpose-designed spaces that make careful use of lighting and ventilation. The layout of the control room is arranged to accommodate the movement of people and to abate excessive noise. A control room may have a range of adjoining facilities, such as a kitchen and even gymnasium equipment, to help operators keep healthy and alert. Of course, not all control rooms are like this, but a state-of-the-art control room can provide operators with an environment that is, at least superficially, a pleasant and comfortable place to work.

Although these advances have certainly improved conditions, several important areas could be further improved. Today’s operator console, a key element of the control room, is effectively an isolated island from which operators can rarely escape. Operators have difficulty moving away from the console to take brief breaks or work with others in the control room without losing critical situation awareness. Display layouts tend to be inflexible, often hamstrung by having to display information across multiple small screens, making it difficult for operators to access necessary information. The operator is also confronted with a multitude of devices such as keyboards, mice, radios, and telephones, and it is difficult for operators to work efficiently when constantly switching between devices. Additionally, consoles are difficult to scale from single to multiple operators and are typically engineered to cope with the maximum number of operators required for startup, shutdown, and turnaround operations. On top of this, the console’s physical arrangement does not allow operators working 12-hour shifts to get and stay comfortable. The result is that life for operators might be compared to traveling in economy class on a long, overnight, intercontinental flight while being asked to make rapid and critical decisions throughout the flight. The odds are stacked against the operators when they are uncomfortable and tired in environments that do not fully accommodate their basic physical and task-related needs.