bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study: Statistical Risk to a Drill Center From Shallow-Water Flow
Authors: Cundiff Les W. , Daugherty Bill , Mix Kurt 
Published: February 2015

Development projects in a number of deepwater provinces face the risk of shallow-water flow (SWF) from overpressured water-bearing sands. Typically found 1,000 to 3,000 ft below the mudline, these sands are often drilled before riser installation and can flow against a saltwater gradient. In extreme cases, vigorous flow will cause borehole rugosity or cavities from sand mining. After casing installation, poorly isolated SWF sands can flow, causing subsidence and casing buckling in both the afflicted well and its offsets. This article describes the evolution of SWF discovery, analysis, and mitigation on BP’s Atlantis project, located in 6,900 ft of water in southern Green Canyon.
The earliest seismic images of Atlantis had shown a possible SWF sand at 9,200 ft, some 2,300 ft below the mudline, that generally covered the entire prospect. Drilling revealed a pore pressure of 9.2 ppge for this zone, which was successfully cased by the first four wells on the prospect.
The fifth well, GC 743 #4, was spudded in July 2002. Drilling progressed below the 36-in. jet string at 7,100 ft toward the next planned casing point at 10,250 ft. At 8,400 ft, a 100-ft sand was drilled that had not been seen on seismic or in previous wells. The sand flowed against salt water during drilling, and at least some degree of sand mining occurred. After “pumping and dumping” to casing point at 10,250 ft, pad mud was spotted and the drillstring was retrieved to run 20-in. casing. The 20-in. shoe hit a ledge or bridge at the 8,400-ft sand, buckled above the wellhead, and parted. GC 743 #4 was cemented and abandoned after unsuccessful fishing attempts. A replacement well, GC 743 #6, was drilled 195 ft away with an additional string of 26-in. casing set above the newly identified 8,400-ft sand. Surprisingly, the sand was absent in this well, as shown in Fig. 1.
With the data from these two wells, recently acquired high-resolution seismic revealed vague images of a steeply banked sand-filled river channel meandering through DC-1, the primary Atlantis drill center. But seismic resolution was inadequate to map the exact boundaries of the sand. Bathymetry and proximity to the Sigsbee Escarpment prevented relocation of the drill center. With sanction approaching, an additional string of 26-in. casing, top set above the newly problematic 8,400-ft sand, was included for each of the 15 remaining wells.
Atlantis was sanctioned in November 2002 with the casing design shown in Fig. 2. A slimmer version, shown in Fig. 3, was under consideration at the time to reduce high “pump and dump” mud volumes experienced in GC 743 #4. The sanction work scope provided for a continuous batch-setting program for the remaining wells.
Guest Editorial: Oil and Efficient-Market Theory
Authors: Schulz Rodney 
Published: February 2015

In 2003, well-known economist Eugene Fama was nominated for the Nobel Prize in economics for work pertaining to his efficient-market hypothesis. Since the 1960s, that hypothesis has been researched, applied, and debated mostly in the context of stock markets. But the theory has measurable applicability to how we go about our daily business in the oil and gas industry.
In short, the efficient-market hypothesis states that a free and open market, such as the New York Stock Exchange, adjusts its prices almost instantaneously to all publicly available information. That suggests that one cannot predictably, consistently outperform market returns through fundamental or technical analysis of publicly available information. But what is considered "publicly available information"? Just about everything that happens outside a boardroom and much of what happens inside a boardroom. The market reacts, quickly and efficiently. It may not always be "right," but it will react and continually readjust almost instantaneously. Another part of the hypothesis states that price movements in the market follow a "random walk" pattern (i.e., price movements are random and the best predictor of tomorrow's price is today's price).
Taking the hypothesis to its next logical step implies that analysts and active stock investors cannot predictably, consistently outperform market returns by selectively placing bets on particular publicly traded investments. Although this flies against the beliefs and marketing strategies of most mutual funds and Wall Street firms, an extensive number of studies over the years indicate that passive, market-driven investments outperform active, arbitrary investments.

Applications to the Oil and Gas Industry
Looking at the oil and gas industry, one immediately finds evidence of market efficiency with oil and gas prices. First, if the market were not efficient, firms that did nothing but trade oil and gas futures would be as ubiquitous as independent producers. Moreover, they would perform as well in down markets as in up markets. This would be an easy business to start, as there are almost no barriers to entry. However, firms that do nothing other than trade oil and gas futures are practically nonexistent. One sees few, if any, traders who do nothing other than trade futures paper or buy crude oil in a Cushing, Oklahoma, tank today and sell it in the same Cushing tank tomorrow, for a profit.
One may argue that the oil market is not efficient because a few large players, such as some of OPEC's largest producers, have the ability to move prices. And that is true, as well as the fact that insiders in those organizations can take advantage of certain information. But this is true in many industries, particularly those dominated by a few large concerns that everyone else follows. However, having dominant industry players does not mean that the market of buyers and sellers does not incorporate all publicly available information almost instantaneously. The world reacts to OPEC's moves as soon as they are discovered.
Management: How Do We Get There From Here? Global Energy Transitions Planning
Authors: Ebenhack Ben W. 
Published: February 2015

How shall we craft an energy future less dependent on petroleum? And what role will oil and gas play in that scenario? In spite of an impressive 150-year track record of increasing hydrocarbon production to meet growth in demand, constraints are emerging. There will be a pinch in production rates relative to growing demand, necessitating the development and deployment of alternative energy technologies from more sustainable resources. As of yet there is no consensus on how to transition to alternative fuels despite a great deal of talk about doing so.
Predictions of oil's demise have plagued the petroleum industry since its birth. Repeatedly, doomsayers have suggested that the world had no more than 20 or 30 years of oil left. The repeated failure of these dire predictions have led some to dismiss the finitude of petroleum resources completely—even claim that the world can never run out of oil.
These optimists are as correct in an absolute sense as they are ridiculously wrong in a practical sense. No matter how high the price of petroleum becomes no technology will ever extract every drop from the proven, producing reserves, let alone find every small reservoir that exists. The decline of petroleum is neither total nor sudden. But in a practical sense, a crisis will come when production can no longer keep pace with demand growth. At that time, we will be producing more oil than ever before! Petroleum production will reach a peak and ultimately decline. That peak will occur when surplus production capacity has diminished to zero and demand continues to grow (unless some alternative source succeeds in carving out a major market share very soon).
In his book The Long Emergency, James Howard Kunstler speaks of "delusional thinking" in regard to pinning hopes on emerging alternative energy technologies. But while the issue is muddied by ignorant, alarmist, and simplistic declarations of the end of petroleum, it is just as badly muddied by denial. Julian Simon, in his popular, highly misleading text The Ultimate Resource II, has a chapter titled "When Will We Run Out Of Oil? Never!" It is true that petroleum has been increasing in the marketplace. Demand has been growing steadily for more than 130 years, and thus far, the industry has kept pace. However, it is utter, antiscientific fallacy to draw any conclusions about the physical limits of the petroleum resource from economic data. The decline will come.
Overview: Production Operations (March 2007)
Authors: Poe Bob 
Published: February 2015

Welcome to the Production Operations feature once again. Some of the issues that production-operations engineers must address in their daily work include multiphase flow in production systems, well-productivity changes, and production-performance testing and analysis. These issues often are compounded when compositional changes occur in the produced reservoir fluids, as is commonly encountered in the production of gas-condensate reservoirs.
This year's Production Operations feature includes some very interesting research and some practical applications of the measurement and evaluation of well performance in multiphase-flow operations. There is significant need for a better understanding of the complex phenomena associated with multiphase flow in production systems, including the metering of fluid flow, the effects that multiphase flow and reservoir-fluid-compositional changes have on well productivity, and the overall production-system performance under multi-phase-and nonlinear-flow conditions.
With improved multiphase-flow metering and testing, improved wellbore multiphase-flow modeling, and more-realistic well-completion-efficiency evaluation, the production-operations engineer can make better-informed decisions about a well's performance and its potential for improvement. The articles presented in this issue highlight some of the advances being made to improve the measurement and evaluation of the production performance of wells in oil and gas-condensate reservoirs.
Production Operations additional reading available at the SPE eLibrary: www.spe.org
SPE 103255 "Optimizing the Productivity of Gas-Condensate Wells" by C. Shi, SPE, Stanford U., et al.
SPE 102231 "Modeling Nonisothermal Rapid Multiphase Flow in Wells Under Nonequilibrium Conditions" by G. Michel, U. of Oklahoma, et al.
SPE 103222 "Rate Allocation Using Permanent Downhole Pressures" by M. McCracken, SPE, ExxonMobil Upstream Research, et al.
Building Bridges: My Journey Continues… Carrying the Banner for Energy Education
Authors: Cobb Bill 
Published: February 2015

President's column
Our industry needs more young people to consider careers in energy. If forecasts are correct that the world consumption could reach 120 million BOPD in the next 25 years, up from the current level of about 85 million BOPD, it will be our young professionals, university students, and those in the next generation who will be called upon to meet these demands.
But beyond our industry's human resources needs, we recognize that ALL students need to become informed consumers of energy. Today's students are the future leaders of companies, universities, and public agencies—they will ultimately make critical decisions that impact our planet's energy supply. We need to let them know that our industry is both a growth and a very high-tech industry, and give them the knowledge to be energy-responsible leaders.
SPE has made some big steps in promoting educational programs about energy and careers to young people in elementary school through high school. I hope you've read the Energy Information Committee's reports on these programs over the past year in JPT's SPE News section. I'd like to thank former SPE President DeAnn Craig for her leadership as the first chairperson of the committee, and welcome Bill Pike as the new chairperson.
SPE's new energy education program, called Energy4me, has its own website combining all our resources in one place. When you visit www.energy4me.org, you'll notice that we discuss all energy sources, while we provide information about the importance of oil and gas in our everyday lives—an important part of improving our industry's image. The site also provides career information, including a new database showing all SPE section scholarships.
Take a special look at the new speaker resources that have been created. The Energy4me Kit updates the Magic Suitcase. You can find presentations that are ready to go. Students today respond positively to hands-on activities, and the new Energy4me kit has some activities that you can do in the classroom or copy and leave behind for the students to do later. You can see the elements of the new kit on the Energy4me.org website, along with an order form.
The Rise of New Bodacious Independents
Authors: Lovie Peter 
Published: February 2015

Guest editorial
As almost everyone knows, there has been a dramatic consolidation in the oil industry over the past 2 decades. However, many may not realize the extensive impact this shift has had on independent producers and how these companies have reinvented themselves in the face of change. Of 36 publicly traded independent producers in 1997, only 12 remained in 2007. Fig. 1 charts the growth of the remaining independents, mostly by acquisition, measured in enterprise value. A few have emerged as so-called "super independents," such as Anadarko and Devon, followed by Apache, Chesapeake, and XTO. To put these companies into perspective, Anadarko and Devon have grown individually to become the same size ChevronTexaco was 5 years ago and more than three times the size of Unocal when ChevronTexaco bought it 3 years ago. The chart also illustrates how the corporate landscape has changed since 1997. A decade ago, Unocal was the largest US-based independent. Today, Unocal and many other familiar names are gone.
Some of these surviving independents have achieved stature on an international scale. If you were to combine Anadarko and Devon, you would create a company larger than the national oil companies of Spain (Repsol) or of Norway (StatoilHydro). The growth of these super independents is also evident in the size and complexity of the field developments they are willing to tackle. Consider the Chuck prospect in the U.S. Gulf of Mexico (GOM), a USD 100 million wildcat being drilled in 6,500 ft of water. Devon is operator of Chuck, with a 40% interest. The company and its partners, ExxonMobil, ConocoPhillips, and Maersk, are drilling through a substantial salt canopy, targeting a Lower Tertiary reservoir more than 33,000 ft deep, and the Chuck exploratory well is expected to reach total depth this quarter.
The GOM's deep water is a frontier even for the super majors. Yet Devon runs second behind only Chevron in acreage within the trend. Despite the technological challenges that stretch the industry to the brink of its capability, Devon has flourished in the deepwater environment. So far, the company has been involved with seven wildcat wells in the Lower Tertiary. Four have been discoveries, two were unsuccessful, and completion of the Chuck well is expected later this year. Looking ahead, Devon has 18 additional Lower Tertiary prospects waiting to be explored.
In July 2007, the enormous Independence Hub began producing natural gas from 10 separate deepwater fields in the eastern GOM. The hub's designers stretched the limits of conventional construction to build a platform capable of producing 1 Bcf/D of natural gas. The Independence Hub is more than a technological feat. As its name implies, the hub represents a new day, a new stature, and a new role for the nation's independent energy producers. It represents the collaboration of Anadarko, Hydro, Devon, and Dominion. The companies combined innovation and cooperation to achieve an objective they could not have accomplished individually.
Technology Update: Aggressive Drilling Parameters, PDC-Bit Innovations Cut Run Times in Abrasive Oklahoma Granite Wash
Authors: Langille Peter , Hildebrand Jason , Massie Kyle 
Published: February 2015

Technology Update
A combination of new drill-bit technology and new operational practices has enabled operator Marathon Oil to use polycrystalline-diamond-compact (PDC) drill bits, and reduce drilling time by 24%, on wells in a part of the Anadarko basin where abrasive conditions at shallow depths previously have required the use of roller-cone bits.
Much of the Anadarko basin is dominated by PDC-bit drilling. However, in the southwest Canute area of Washita County, Oklahoma, the highly abrasive Granite Wash formation is encountered at depths of 5,000−6,000 ft, compared with its more typical 11,000-ft point of emergence in most of the Anadarko basin.
In the deep Anadarko, of which the southwest Canute area is a part, exploratory wells are drilled either to approximately 13,500 ft to produce the Atoka Wash and Red Fork sands or to approximately 17,500 ft to pro-duce the Morrow sands. The surface string in either type of well is set in or below the Brown dolomite formation (≈3,500−4,500 ft). The lithology below the surface casing consists of a long sequence of sand/shale with interbedded granite wash. This gives way to more-consolidated sand intervals and granite-wash formations, a transition often marked by the showing of the Tonkawa and Prue sands at approximately 9,000 and 11,000 ft, respectively.
In drilling Atoka Wash/Red Fork wells in the southwest Canute area, the operator set a goal of reaching the Prue sands by use of two PDC bits, eliminating the use of three to eight roller-cone bits that previously would have been required. Aggressive drilling parameters typically reserved for roller-cone bits, employing high weight on bit (WOB) and low revolutions per minute (rev/min), were combined with innovative PDC-bit frames, designed to increase the load/cutter ratio, and with new cutter technology to enable the operator to achieve the goal. A depth of 10,700 ft was reached with two PDC bits, and cost savings of approximately USD 200,000 were realized.

Well Plan
For the operator, a typical Atoka Wash/Red Fork well involves a 12.25-in. section drilled into the Brown dolomite and a 7.875-in. section then drilled to total depth (TD). For the 12.25-in. section, casing points differ according to TD. Typically, 9.625-in. casing is set at ≈3,500 ft. The 12.25-in. interval is easily drilled with a single PDC bit.
A 7.875-in. hole is drilled below the 9.625-in. casing and extends to TD. Historically, this interval has been drilled with multiple IADC 5–2–7 or 5–3–7 roller-cone bits. More recently, the use of PDC bits at drillout has become common. However, the ability to make the interval to the Prue sands has proved very elusive.
Technology Focus: Production Operations (March 2008)
Authors: Poe Bob 
Published: February 2015

Technology Focus
Welcome to the Production Operations feature. Practicing production-operations engineers may employ a wide variety of technologies in their work, and several of these technologies are highlighted in this feature. Some of the commonly used technologies are the analysis of the production performance of oil or gas wells, methods for identification and remediation of water-production issues, fluid-inflow-control design, and actions in a horizontal or complex multibranched wellbore. In each case, reliable and accurate characterization of the productive formation and the well-completion properties is fundamentally required.
This issue includes summaries of some excellent research efforts and field-application results in the evaluation of well performance in low-permeability and complex reservoirs. Reservoir complexities addressed in the selected technical articles include the practical reservoir- and production-engineering aspects of stress-sensitive formations, composite and multilayer formations, single- and dual-porosity reservoirs, fracture cleanup and/or damage with respect to production time, and the very common effect of wellbore liquid loading. Specific issues that pertain to the evaluation of fractured and horizontal wells are addressed in the selected technical papers, including the design and application of inflow-control devices to enhance the production of horizontal-well completions.
In addition to the cited articles, some extremely valuable developments and insight are available in the additional reading references. The research presented in these articles includes the tomographic evaluation of skin-damage evolution in unconsolidated sandstones and the control and remediation of water production in stratified and low-permeability gas reservoirs. Each of these issues is also extremely important in production operations.
Production Operations additional reading available at the SPE eLibrary: www.spe.org
SPE 107832 • "Study of Skin Damage in Unconsolidated Sandstone by Computed Tomography" by E.S. Sales, COPPE/UFRJ, et al.
SPE 106640 • "Optimum Control of Unwanted Water Production in Stratified Gas Reservoirs" by Nampetch Yamali, SPE, University of Texas at Austin, et al.
SPE 105262 • "Successful Innovative Water-Shutoff Operations in Low-Permeability Gas Wells" by Hassan Chaabouni, SPE, Schlumberger, et al.
Technology Focus: Heavy Oil (March 2008)
Authors: Kovscek Tony 
Published: February 2015

Technology Focus
Recently, I served as cochairperson of the SPE Forum on "Enhanced Oil Recovery—What's Next?" The consensus of attendees was that while there is some promising technology, no game-changing enhanced-oil-recovery (EOR) technologies appeared to be on the immediate horizon. In the area of heavy hydrocarbons, on the other hand, it was expressed that in-situ upgrading of resources such as heavy oil, tar, and oil shale could be a game changer if more-vigorous work was conducted in the area of upgrading. The dawn for surface upgrading of bitumen appears to have occurred.
Various possibilities for in-situ upgrading were discussed in some detail including electrical heating to create an upgrader and refinery-in-the-ground for oil shale; solvents tailored to precipitate the asphaltene fractions of crude oil; and in-situ combustion, in which the heaviest fractions of the crude are consumed selectively as fuel for combustion, thereby increasing the API gravity of the oil. A common theme is that in-situ upgrading is a complex process needing much more R&D.
The conversion of trillions of barrels of oil equivalent to a lighter, sweeter synthetic crude oil is an exhilarating thought, especially given the possibility that such upgrading can be accomplished in a fashion that is close to being environmentally benign if it is carried out in situ with geological sequestration of any carbon dioxide created during upgrading. Considering the analogous time frame for implementation of the markedly simpler process of steamdrive for EOR, however, provides a sobering perspective. From the initial engineering report to commencement of a commercial project at Mt. Poso, a total of 20 years elapsed.
Papers for this feature span many aspects related to heavy hydrocarbons including in-situ combustion, steam injection, optimization of thermal-recovery processes, chemical-based EOR for heavy oil, as well as artificial lift. Many questions linger for me regarding in-situ upgrading. Is an extended R&D time frame realistic today? If a significant portion of the technical workforce is poised to retire within a decade, where/when will the future workforce be trained for such an enormous challenge and who will be their mentors? Ultimately, could we extract the energy in the form of clean-burning hydrogen, or preferably methane, because of the significant natural-gas infrastructure already in place?
Heavy Oil additional reading available at the SPE eLibrary: www.spe.org
SPE 110479 • "World's First Metal PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case" by Jean-Louis Beauquin, Total, et al.
SPE 107949 • "Optimization of Cyclic Steam Stimulation Under Uncertainty" by K. Revana, Halliburton, et al.
SPE 106908 • "Applicability of Water-Shutoff Treatment for Horizontal Wells in Heavy-Oil Reservoirs" by Francesco Verre, Imperial College, London, et al.