bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
Enhanced Heavy-Oil Recovery by Alkali/Surfactant Flooding
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110738, "Enhanced Heavy-Oil Recovery by Alkali/Surfactant Flooding," by J. Bryan, SPE, and A. Kantzas, SPE, University of Calgary and TIPM Laboratory, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed.

This study presents the results of laboratory core studies investigating the recovery mechanisms of alkali/surfactant (A/S) flooding in heavy-oil reservoirs. Specifically, mixtures of water and A/S systems have been injected into cores containing heavy oil. Salinity is varied to generate oil-in-water (O/W) vs. water-in-oil (W/O) emulsion systems, and the effects of generating different emulsions were compared. It was demonstrated that in heavy-oil systems, emulsion formation was necessary to produce the heavy oil.

Introduction

Several countries, including Canada and Venezuela, contain massive resources of unconventional heavy oil and bitumen. These oil sands are characterized as unconsolidated, high-porosity, and high-permeability reservoirs. The single biggest obstacle to successful recovery from the oil sands is the high oil viscosity. Heavy-oil reservoirs are a special subset of the oil sands, whereby the oil viscosity at reservoir temperature and pressure varies on the order of 50 to 50 000 mPa·s. While this oil is very viscous, it does have limited mobility at reservoir conditions. As much as 20% of the oil may be recovered by solution-gas drive, but in many cases, the recovery is much lower.

To recover additional heavy oil, a fluid usually must be injected to displace oil to the production wells. However, mobility-ratio concerns dominate displacement of viscous oil, and most enhanced-oil-recovery processes focus on reducing oil viscosity or improving the mobility ratio. Unfortunately, many of the heavy-oil reservoirs in Canada are relatively small and thin, making them poor candidates for expensive thermal processes. This work investigates the potential of A/S flooding for enhanced heavy-oil recovery.

Surfactants are a special class of molecule that is both hydrophobic and hydrophilic; thus, the most stable configuration for these molecules is at the oil/water interface. In surfactant flooding, these molecules generally are injected along with water to reduce the oil/water interfacial tension (IFT), which reduces capillary forces that may trap oil in rock pores. Alkali flooding is a special subset of chemical flooding whereby the surfactant is generated in situ through the reaction between the injected alkali and the acidic crude oil. It is likely that in actual reservoir applications, several processes are working together to improve oil recovery. This work considers the possible mechanisms that could be responsible for enhanced recovery of high-viscosity heavy oil.
Applying Science and Best Practices To Increase Production and Optimize Economics in a West Texas Gas Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117538, "Applying Science and Best Practices To increase Production and Optimize Economics in a West Texas Gas Field - A Canyon-Sand Case Study," by Kelly Blackwood, SPE, (now with Encana Oil and Gas), and Kaylene Williamson, SPE, Highmount Energy; Terry Palisch, SPE, and Mark Chapman, SPE, Carbo Ceramics; and Mike Vincent, SPE, Insight Consulting, originally prepared for the 2008 SPE Eastern Regional/AAPG Eastern Section Joint Meeting, Pittsburgh, Pennsylvania, 11-15 Octo ber. The paper has not been peer reviewed.

Hydraulic fracturing is the most popular and successful stimulation treatment in the petroleum industry. Fracturing technology has opened numerous unconventional hydrocarbon frontiers that, were it not for this process, would be uneconomic to develop. However, designing the optimal hydraulic fracture is anything but an exact science. The industry relies on many simplifying assumptions that assist in making expedient decisions but can prevent reaching a truly optimized treatment. The full-length paper outlines the approach taken by one Canyon sand operator to apply sound science and best practices to meet their financial.

Introduction

A field trial comparing the performance of 20/40 economy-lightweight-ceramic (ELWC) proppant to 20/40 Brady sand was completed in 2006 and 2007 in the Canyon sand, Sutton County, Texas. The trial was initiated after modeling suggested that the current hydraulic fractures were conductivity limited. Twenty-one wells in close proximity to each other were included in the study. Production analyses were performed after all wells had at least 1 year of post-fracture production. Both raw production and production normalized to reservoir quality were analyzed, and both indicate that the wells stimulated with ELWC proppant significantly outperformed the offset wells that used Brady sand. Several economic yardsticks then were evaluated in the full-length paper.

Canyon Sand

The Canyon sandstone is productive in several fields, including the Sonora, Sawyers, Shurley, and Aldwell fields, with first production occurring in 1952. The Canyon-sandstone trend occurs basinward of the western margin of the Eastern shelf in west Texas. The sandstones were deposited from the Eastern shelf into the Val Verde basin. The reservoir is oil prone adjacent to the Midland basin and gas prone adjacent to the Val Verde basin. The vast majority of the sandstone members are fine- to medium-grained quartz lithic arenites.
Resolving Created, Propped, and Effective Hydraulic-Fracture Length
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12147, "Re solving Created, Propped, and Effective Hydraulic-Fracture Length," by C.L. Cipolla, SPE, E.P. Lolon, SPE, and M.J. Mayerhofer, SPE, Pinnacle Technologies, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

The full-length paper compares the strengths, weaknesses, and limitations of fracture modeling, production-data analysis (PDA), pressure-transient analysis (PTA), and numerical reservoir modeling in estimating effective fracture length and conductivity. The paper also evaluates how the complexities (in the hydraulic fracture) associated with non-Darcy flow, multiphase flow, and complex fracture geometries affect the results from the various techniques. The paper documents the significant differences in "effective" fracture length that, in many cases, can result from each technique.

Introduction

Reliable estimates of fracture length (i.e., created, propped, and producing or effective) are necessary to consider design changes in subsequent fracture treatments to optimize the performance of hydraulically fractured wells, particularly in low-permeability reservoirs. The created fracture length is the fracture length propagated during the fracture treatment, while the propped fracture length is the length supported by proppant after the fracture closes. The effective, or producing, length is the length that is open or contributing to hydrocarbon production after a fracture treatment. Increasing the effective fracture length usually means increased production.

Incorrect estimates of the effective fracture length can lead to less-than-optimal gas recovery and often contribute to modifications of fracturing designs that may not result in improved well productivity. It has been known that the fracture lengths determined from fracture modeling, PDA, PTA, and numerical reservoir modeling are not in agreement with the created fracture lengths obtained from fracture mapping.

Techniques for Determining Fracture Properties

Fracture Modeling.

Fracture modeling (i.e., net-pressure analysis) can provide information about fracture length, height, width, and conductivity. Fracture dimensions and conductivity can be estimated from fracture modeling by matching the observed fracturing net pressures (fracturing pressure minus minimum rock stress, or closure pressure). The limitations of this technique are that it typically provides nonunique solutions, can be unreliable if not calibrated, and requires baseline rock and stress data.

Net-pressure history matching can be implemented by adding new physics to fracture models. With the right assumptions and physics, inferred fracture geometry can be more reliable; however, inferred geometry from net-pressure matching does not always agree with directly measured geometry.
Case Study: Restoring Sand-Prone Subsea Wells to Production
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115058, "Case Study: Restoring Sand-Prone Subsea Wells to Production," by M. Vazir, SPE, and L.G. Acosta, SPE, BP, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.

This case study describes intervention efforts that returned one dry-tree and two subsea wells to production after an extended shut-in in a mature BP-operated Gulf of Mexico deepwater field. The three wells had been shut in because of sand production. The production facility was not designed with any sand-management capability. Several operational challenges were faced during the planning and execution of this operation. They were carefully assessed, and the risks were managed effectively to return all three wells to production.

Introduction

Pompano is the oldest BP-operated facility in the Gulf of Mexico; first production was in 1994. The facility was developed with 33 dry-tree wells and a 10-well subsea-template tieback to the fixed-jacket platform. The template is tied to the platform through two subsea flow loops, one 8-in. insulated loop for normal production and one 3-in. uninsulated loop for well testing and well servicing (Fig. 1). Pompano-field production peaked at 65,000 BOPD in 1999. By July 2007, total field production was approximately 11,500 BOPD.

Low-cost high-return well-intervention work was key to maximize field value. The challenge for the Pompano team was to identify and implement unique and creative production-enhancement activities. At the forefront of this search was a rigorous effort to revisit and recover production from shut-in wells.

Well Histories

This project focused on three shut-in wells, one dry-tree well (A-03) and two subsea wells (TB-03 and TB-07). Well A-03 was producing 290 BOPD, 52 BWPD, and 1.04 MMscf/D of gas before shut-in. The well was shut in August 2000 because of solids observed in the shake-outs during the monthly testing of the well.

Well TB-03 was shut in initially because of Hurricane Katrina in September 2005. The well remained shut-in for almost 5 months as a result of this event. Before this shut-in, the well was producing 930 BOPD, 480 BWPD, and 1.09 MMscf/D of gas. A startup was attempted in January 2006, and the well produced approximately one-half cup of solids in 8 hours. Shake-outs during this period showed between a trace amount and 10% solids in the flow stream. The well was shut in pending analysis of the produced solids.

Laboratory analysis of the produced solids showed them to be fine grained and that they could have been produced through the type of frac-pack completion in Well TB-03. This information indicated that the integrity of the completion might still remain and that the well could be restored to production.
Q&A with Guilherme de Oliveira Estrella
Authors: de Oliveira Estrella Guilherme , Donnelly John
Published: February 2015

Q&A - No abstract available.
Complex Flows in Nonvertical Wells Pose Logging-Tool Challenges
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
Offshore Drilling and Completions: Kick Detection in Subsea Mudlift Drilling
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87114, "Analyses and Procedures for Kick Detection in Subsea Mudlift Drilling," by Jonggeun Choe, SPE, Seoul Natl. U., and Jerome J. Schubert, SPE, and Hans C. Juvkam- Wold, SPE, Texas A&M U., prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Offshore Drilling and Completions: Completion and Well-Performance Results: Genesis Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84415, "Completion and Well-Performance Results, Genesis Field, Deepwater Gulf of Mexico," by R.D. Pourciau, SPE, J.H. Fisk, SPE, and F.J. Descant, SPE, ChevronTexaco E&P Co., and R.B. Waltman, SPE, Halliburton, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Overview: Natural Gas Technology/Monetization (April 2004)
Authors: Jones Jack R.
Published: February 2015

Overview - No abstract available.
Natural Gas Technology/Monetization: Overview of the Mallik Gas-Hydrate Production Research Well
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 15124, "Operation Overview of the 2002 Mallik Gas-Hydrate Production Research Well Program at the Mackenzie Delta in the Canadian Arctic," by Hideaki Takahashi, Japan Petroleum Exploration Co. Ltd.; Tetsuo Yonezawa, SPE, Japan Natl. Oil Corp.; and Ed Fercho, Canadian Petroleum Engineering Inc., prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Overview: Reservoir Simulation and Visualization (April 2004)
Authors: May Ed
Published: February 2015

Overview - No abstract available.
Reservoir Simulation and Visualization: Fracture-Flow Modeling and Visualization
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86554, "Fracture-Flow Modeling and Visualization," by Jody R. Augustine, SPE, Baker Oil Tools, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Q&A with James Farnsworth
Authors: Farnsworth James , Donnelly John
Published: February 2015

What do you think of oil prices near U.S. $50/bbl? Is that price here to stay?

If past history is any guide, it seems unlikely. There does appear to have been at least a medium-term shift in prices, largely driven by increased demand, particularly in China. Despite this, we still test our projects at U.S. $20/BOE to ensure they are robust throughout the duration of field life.

How have major operators, and in particular BP, reacted to the recent surge in oil prices? Are operators putting more money into exploration, technology R&D, or both?

Many of the projects that result from BP’s exploration success require several years to develop, and, because of their size, they frequently will be produced for decades. Because of this, we work very hard to maintain discipline in our exploration investment, not substantially increasing or decreasing on the basis of price but, rather, opportunities. It is becoming clear, however, that some of our competitors are significantly increasing their investments in exploration as cash flow has increased and reserves replacement has proved difficult.

On technology investment, BP has chosen to invest significant amounts in R&D in some focused areas, which we refer to as Technology Leadership Areas, where we see a real need, a competitive advantage, or perceive a gap in what the service industry is providing.

How much does BP spend on upstream R&D now compared with a decade ago? What accounts for that change?

The spending for BP in this area is roughly similar, but it is much more focused based upon the nature of our evolving portfolio. Obviously, the continued growth of deep water is an example of this. Another is the continuing need for enhanced seismic imaging, moving from simply imaging complex structures to resolving reservoirs in complex structures.
GTL: An Attractive Route For Gas Monetization?
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88642, "GTL: Is It an Attractive Route for Gas Monetization?," by Osama Abdul Rahman and Mohamed Al-Maslamani, SPE, Qatar Petroleum, prepared for the 2004 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October.

The gas-to-liquid (GTL) conversion of natural gas into synthetic fuel is an active area of development. Many companies are involved in research, pilot plants, or demonstration units with the objective of reducing capital and operating costs of this technology. Major factors affecting the economics of the GTL process are gas price and capital cost. The GTL process could be an attractive way to monetize stranded gas reserves where the application of pipeline or liquefied-natural-gas (LNG) technology is not technically or economically feasible because the gas is either too far from a market or the gas reserves cannot support an LNG plant.

Introduction

The GTL process involves the conversion of natural gas into a clean source of energy, mainly diesel and naphtha. As the sulfur and aromatics specifications for diesel oil become tighter and complying with exhaust/emission requirements becomes more difficult, the GTL diesel market expands. Production of refinery diesel with ultralow sulfur content from crude oil will be expensive. The production cost of GTL diesel oil, which contains near-zero sulfur and less than 1% aromatics, will become competitive.
Simplified Wellbore Flow Modeling of Gas/Condensate Systems
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89754, "Simplified Wellbore Flow Modeling in Gas-Condensate Systems," by C.S. Kabir, SPE, ChevronTexaco, and A.R. Hasan, SPE, U. of Minnesota-Duluth, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Predicting long-term reservoir performance with realistic wellbore models is fraught with uncertainty because of the complexity of two-phase flow. Even a calibrated two-phase-flow model departs from its expected performance trend when changes in flow conditions occur. The full-length paper explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. Statistical results from BHP computations on three independent data sets comprising 167 gas/condensate-well tests show that the homogeneous model compares quite favorably with mechanistic two-phase-flow models.

Introduction

Two-phase-flow modeling of gas/condensate wells has not received as much attention as that of oil wells. The popular Gray correlation appears to do a good job in most gas/condensate wells. However, applicability of this correlation outside the bounds of its specified parameters remains unclear.

A user must specify one computational approach for flow in pipes when long-term integrated reservoir/wellbore/flowline performance is sought over a field’s producing life. Declining condensate/gas ratio (CGR) and increasing water production with time have the potential for complicating any modeling effort.

Besides the two-component gas/liquid Gray correlation, other approaches have emerged for modeling gas/condensate flow. The semimechanistic model of Govier and Fogarasi represents the multi-component approach with flash calculations. In contrast, the wet-gas concept offered by Peffer et al. suggests extreme pseudoization with single-component gas.

Computational Approach and Results Data from the literature and those from a few west African fields with medium- to high-CGR production were used. In all, 167 tests were examined. The methods used were the homogeneous model; the steady-state OLGA; those of Gray, Aziz et al., and Ansari et al.; and the wet-gas approach, advanced by Peffer, in which the gas gravity is weighted to include the density of the produced liquid.
Overview: Reservoir Simulation and Visualization (April 2005)
Authors: Smart Tom
Published: February 2015

The success of reservoir development and reservoir management can be summed up in one statement: The explosion of data available to today’s reservoir engineer mandates the use of advanced simulation and visualization technology.

With ongoing technological advances, our capability to measure and acquire more and more data will continue to increase. This increase in data will stretch the limits of our capacity to gather, manage, and use this information effectively. Our appetite for data will increase further, because as we learn to analyze this data efficiently, we realize additional data are needed. That is, the more we know, the more we realize what we do not know.

Advances in collaborative visualization, along with efficient asset-team organization, are having a profound effect on our ability to make proper use of this wealth of data. Software tools that facilitate true integrated work processes are emerging, providing asset teams the ability to characterize, model, and simulate reservoirs in a multidisciplinary manner. This ability for all asset-team members to communicate by use of visualization throughout the reservoir-management process provides more fit-for-purpose reservoir models, which in turn leads to better drilling choices; improved reservoir development and performance predictions; and, ultimately, better economic decisions under uncertainty.

Additionally, significant advances in reservoir-simulation technology continue. Many of these advances represent approaches to take advantage of the growing mountain of data. More data leads to larger and more-complex reservoir models. Despite ever-increasing computation power, improved methods for scaling up models are needed. Streamline simulation, integrated with dynamic data, has become an effective tool for use in screening, scaling up, and history matching these models. With increased model complexity comes the need to use reservoir-simulation models that maintain that complexity. A new generation of reservoir simulators is emerging that captures the complexity through unstructured gridding, advanced formulations, and integrating surface and reservoir modeling.

Going forward, visualization and reservoir-simulation technology will continue to advance in an attempt to keep pace with the ever-increasing volume of data. In the future, look for advances in real-time data acquisition leading to the need for ever-improving visualization and reservoir-simulation techniques to contribute to the optimization of daily reservoir-management operations.

Additional Reservoir Simulation and Visualization Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 93080 - Development and Field Application of a High-Performance Unstructured Simulator With Parallel Capability

SPE 90009 - Dynamic Flow-Based PEBI Grids for Reservoir Simulation

SPE 93339 - A New Upscaling Approach for Highly Heterogeneous Reservoirs
Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89914, "Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs," by Mishal Al-Harbi, SPE, Hao Cheng, SPE, Zhong He, and Akhil Datta-Gupta, SPE, Texas A&M U., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Streamline-based models have shown great potential in reconciling high-resolution geologic models with production data. Use of streamline-based production-data integration has been extended to naturally fractured reservoirs. A dual-porosity streamline model was used for fracture-flow simulation by treating the fracture and matrix as separate continua connected through a transfer function. The sensitivities that define the relationship between reservoir properties and the production response in fractured reservoirs were computed analytically. The production-data integration was carried out with a generalized travel-time inversion.

Introduction

Natural fractures play a significant role in subsurface flow and transport of fluids. Seismic imaging and horizontal drilling have revealed the extent of fractures in many reservoirs and enabled operators to use novel ways to use fracture connectivity to enhance recovery. The number of reservoirs that are considered naturally fractured has risen significantly, increasing the need for robust fracture-characterization methods that integrate both static and dynamic data.

Discrete-fracture-network (DFN) techniques map fracture planes in 3D space by use of statistical properties of fracture swarms, fracture-network geometry, and flow characteristics. DFN models can incorporate complex-fracture patterns by use of field-data sources such as cores, well logs, borehole images, seismics, and geomechanics. Although the DFN models can reproduce very realistic fracture geometry, these models must be conditiond to dynamic data (such as well-test, tracer, and production data) to reproduce the flow behavior in the reservoir. Such conditioning is particularly important for fractured reservoirs because only a few of the fractures in the DFN model might carry most of the fluid flow.

Streamline models have shown great potential in integrating dynamic data into high-resolution geologic models. Streamline models can determine the sensitivity of the production data to reservoir parameters such as porosity and permeability. These sensitivities are partial derivatives that quantify how the production response will be affected by changes in reservoir properties. Typically, integrating dynamic data into reservoir models involves solving an inverse problem in which sensitivities play a key role. Streamline-based sensitivities were used in conjunction with a generalized travel-time-inversion method to integrate production data into geologic models.
Management: Moving Project Management to the Next Level of Performance
Authors: Holland Dutch , Skarke Gary
Published: February 2015

What an extraordinary opportunity to see how conventional management thinking actually plays out in the real world. In 2005, a professional development event "packed the house" with 300 highly experienced senior project managers in the global oil and gas industry. No rookies with outlandish expectations or unrealistic goals while learning their craft occupied these seats. Just the opposite. These were skilled professionals at the hub of projects sometimes costing as much as the gross domestic product of a small developing nation.

If this sounds like a gathering of corporate happy campers engaged in rounds of back-patting, hold that thought. Lean back and digest what they said in a questionnaire about their profession's status within their energy company. Were they in tune with conventional management thinking or not?

Biggest Project-Management Challenges

On its face, the formal-sounding project management (PM) name would seem no more controversial than a business leader saying, "Business is a good thing." However, PM's history has been bumpier than a back country road, especially in the oil industry, which, ironically, thrives on policies, procedures, and protocol.

Consider questionnaire results about the greatest challenge faced by project managers in their oil industry organizations, in order of most frequent response:Getting PM recognized as a core work process. That includes differentiating PM from daily line management. That includes the reality that at most companies, supply chain, accounting, and procurement are typically viewed as formalized work processes that demand strict compliance. Why isn't project management viewed this way, too?Companywide adoption of standardized templates/approaches for conducting PM. More typically, different regions of the same company use different PM approaches, making global projects difficult to manage. These big projects are hard enough without having to squabble over whose template is best.Invest in PM. Commit to PM, then put teeth into the commitment. Hire experienced project managers, hire enough of them, provide comprehensive training and development, provide cross-training for managers outside PM, and encourage certification/support of the PM organization. Significantly, PM tools (such as software) were not an expressed concern.Acute time pressure to make PM work. And these were only the top complaints, with many other noteworthy ones including too many projects but too little time; little or no upper management acceptance; lack of consistency or templates; focus on company earnings forcing shortsightedness in project planning; being expected to perform magic with few or no resources, poor executive understanding, or undercommitment; and the overwhelming need to get the word out that PM is important.
Offshore E&P - Still More To Learn
Authors: Langley Diane
Published: February 2015

Offshore, shallow or deep, is a realm unto itself in which technology and economics are entwined and constantly evolving. The technical agenda for the 2006 Offshore Technology Conference (OTC) May 1–4 in Houston promises to deliver the next chapter in offshore E&P. Approximately 40 technical sessions and more than 300 technical presentations are planned.

Seven papers chosen by OTC 2006 program organizers emphasize that the one sure thing is that the pressure is on the industry to maintain a healthy balance between high risk, steep cost, and reasonable reward. The technical papers discussed in this article are listed below.

Recent Findings in Anisotropy Estimation

The authors of paper OTC 17866 estimate parameters of depth-variant vertical transverse isotropy (VTI) from the first-arrival times recorded in a 3D vertical seismic profile (VSP) survey over a deepwater Gulf of Mexico (GOM) project. They use both conventional slowness inversion and a recently developed travel-time extrapolation technique. The authors are not aware of any depth-dependent estimates of anisotropy from VSP data done before their study. Their work confirms that 3D VSP acquisition geometry is ideally suited for estimating in-situ seismic anisotropy; however, the locality of anisotropy measurements is achieved only when local quantities are used. This is not the case when the horizontal slowness components are involved in the inversion process because they are influenced by lateral velocity variations in the entire overburden. "Correcting the horizontal slownesses for lateral velocity heterogeneity requires knowing the seismic velocity model with accuracy hardly attainable in practice," the paper states.

A VSP survey was shot in a spiral pattern, with waveforms recorded by 28 geophones placed in 100-ft increments at depths ranging from 17,528 to 20,228 ft. The first-break times were picked from the data. The authors apply both the conventional slowness and novel travel-time extrapolation techniques and obtain comparable estimates of anisotropy. The travel-time extrapolation method, however, better illustrates the accuracy of knowing the lateral velocity variations needed to achieve the locality of anisotropy estimates. "One subsurface feature—a salt body—profoundly influences our ability to estimate anisotropy from the VSP data," say the authors. "Its presence causes a decrease of the first-break times clearly seen in the northern portion of the survey. The salt outline is easily identified in the travel-time data (Fig. 1)." This case study reveals the problem with deriving anisotropy from the slowness surfaces; the presence of salt produces slowness distortions that are impossible to fit with any anisotropic model, forcing the authors to rely only on the data recorded outside the salt. Realistic constraints of parameters are discussed. "Our most interesting finding was the negative sign of the an ellipticity coefficient η," the authors say. "It remains to be understood whether the negative sign of η bears lithologic or any other significance."