bluuebunny/crossref_metadata_2025_split huggingface dataset:
Building Bridges: Work to Advance Use of Reserves Guidelines Continues
Authors: Cobb Bill 
Published: February 2015

President's column
Much has happened since the Petroleum Resources Management System (PRMS) was completed in March 2007, providing updated definitions and a related classification system for petroleum reserves and resources. This landmark document reflects advancements in technology, the international expansion of the industry, and the increasing role of unconventional resources, as well as incorporating recommended best practices identified in other international petroleum and mineral classification systems.
SPE is proud to have led the effort that produced a set of technical guidelines that can be adopted by oil and gas companies to better manage their business and that can be consistently used in estimating reserves by international financial, regulatory, and reporting bodies. The PRMS is the result of more than 2 years of collaboration by SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE), with considerable input from the industry at large and other external organizations.
Our work was not over with the completion of the technical definitions. Intense education and training are required to support consistent use by the industry and other financial and regulatory bodies. I want to give you a brief report on the progress that has been made to educate important stakeholders about the new system.
In December, the U.S. Securities and Exchange Commission (SEC) announced it would seek public comment on possible revisions to disclosure requirements for oil and gas reserves, citing the extent and nature of changes that have occurred in the oil and gas industry in the nearly three decades since the commission first adopted its oil and gas disclosure rules. SPE's Oil and Gas Reserves Committee, among many others, provided comments to the SEC that recommend the use of PRMS as the technical basis for a reporting process. It is notable that the overwhelming majority of comments made to the SEC that addressed the PRMS recommended using it in some form. All of the comments can be viewed on the SEC website at http://www.sec.gov/comments/s7-29-07/s72907.shtml.
To help energy professionals apply the definitions, the Oil and Gas Reserves Committee and SPE's Reserves Education Committee are collaborating on an applications manual for the PRMS that will include detailed discussion and examples of use. Companies have been asked to submit examples and case studies from petroleum provinces worldwide.
The applications manual will be a valuable, comprehensive, and long-lasting reference document. The manual will be consistent with the PRMS, update and incorporate the content of the 2001 "Guidelines for the Evaluation of Petroleum Reserves and Resources," and expand the content to address the full spectrum of hydrocarbon evaluation situations experienced by industry. It will be available in the reserves section of www.spe.org.
Deepwater Gulf of Mexico Development Challenges
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113011, "Deepwater Gulf of Mexico Development Challenges Overview," by Frank Close, Bob McCavitt, SPE, and Brian Smith, Chevron North America E&P Company, prepared for the 2008 SPE North Africa Technical Conference and Exhibition, Marrakech, Morocco, 12–14 March. The paper has not been peer reviewed.
A high-level review of recent development challenges for the deepwater and ultradeepwater fields in the Gulf of Mexico (GOM) is presented. How these challenges were addressed and how Chevron plans to address even-more-demanding challenges in the future are summarized.

Introduction
Operating in all areas of the world presents many challenges. The GOM, although a long-established and prolific hydrocarbon basin, has, over the past 15 or so years, evolved into an arena where operations challenges have been encountered in ever-increasing water depths further from the coast. These challenges include seismic acquisition, drilling operations, completion operations, subsea operations, production operations, logistics support, and many more. Fields are being developed in the GOM that pose the greatest engineering challenges that the company has addressed. It is anticipated that developing resources in water depths of 10,000 ft will be fundamental to the continued long-term success of the GOM as one of the world's major producing basins.

Challenges
Many of the prospects in the ultradeep-water GOM have a unique combination of challenges. The combination of deep water (to 10,000 ft water depth), high pressure (&gt;10,000 psi shut-in pressures), high temperatures (&gt;350°F bottomhole temperature), problematic formations (e.g., salt or tar zones), deep reservoirs (more than 30,000 ft true vertical depth), tight-sandstone reservoirs (&lt;10 md), and fluids with extreme flow-assurance issues separates many GOM deepwater and ultradeepwater wells from deepwater and ultradeepwater wells in other parts of the world.
As Fig. 1 shows, much of the prospective GOM deepwater exploration area is in 4,000 to 10,000 ft of water. Most of this area is in a subsalt environment, with salt canopies ranging from 7,000 to 20,000 ft thick and target depths ranging from 25,000 to 35,000 ft true vertical depth.
The vast salt zones inhibit deep-seismic resolution, presenting great challenges in exploration, appraisal, and development operations. Understanding the geology associated with the massive salt and, more importantly, the quality of imaging below the salt is paramount.
A key technology being developed to address this challenge is wide-azimuth-towed-streamer technology. This technique allows better subsurface imaging for effective reservoir management and will dictate well placement and number of wells required to drain the reservoir optimally. The true vertical depths of some deepwater wells are in excess of 34,000 ft. Fig. 2 shows some of the drilling challenges.
Dual Activities Without the Second Derrick
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112869, "Dual Activities Without the Second Derrick - A Success Story," by Tamara Webb and Kasim Selamat, SPE, Murphy Sabah Oil; and Bill Fletcher, SPE, Seadrill, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4–6 March. The paper has not been peer reviewed.
Kikeh field is 120 km from Labuan, offshore Sabah, Malaysia. The field, in 1330-m water depth, is the first deepwater development in Malaysia and consists of subsea and surface-piercing-articulated-riser (SPAR) development wells. Considering the wide scope of completion work outlined in the program, a detailed work assessment was conducted focusing on processes for which offline activities could be conducted safely and efficiently. As a result, at least seven completion-related activities were identified. During the first batch of SPAR completions, which involved five wells, several activities were completed offline successfully, allowing the rig to be used for critical-path operations.

Introduction
Completion operations played a major role in the overall Kikeh deepwater development, with 25% of the total field development and 58% of the capital expenditures attributed to well completions. Early focus was on timesaving opportunities that could be performed off of the rig's critical-path operations. Many factors were assessed including rig capabilities, SPAR capabilities, and personnel. The need for extensive planning and proper communication was investigated, as were completion activities and equipment design.
The scope of SPAR-completion activities was divided into nine phases: production tensioner and riser installation, wellbore cleanout, tubing-conveyed perforation, lower-completion installation, upper-completion installation, tree installation, riser-annulus dewatering, well cleanup, and testing. In addition, several completion-phase activities were identified: cement- and riser-evaluation logging and installation/commissioning of the umbilicals and flowline jumpers.
During the first completion campaign, the following eight activities were consistently performed off the rig's critical-path operations. The work description and how the work objectives were achieved are detailed in the full-length paper.

Offline Activities
Tubular Makeup and Racking Back. Rig design contributed to the success of offline activities. The offline-activities cantilever (OAC), shown in Fig. 1, consists of two dedicated mouse holes capable of handling various ranges of pipe and an overhead crane mounted in the derrick, which accommodated racking tubulars on both the driller side and the off-driller side of the derrick. The OAC provides adequate space to set up a power tong inclusive of a torque turn system.
Technology Focus: Well Stimulation (June 2008)
Authors: Hager Charles 
Published: February 2015

Technology Focus
This feature highlights three papers that are examples of working smarter, better, or cheaper to help us be more competitive in an ever-growing world energy market. In 2004, oil and gas production was the leading supplier of energy generation with approximately 55% of the world market. Four key competitors made up more than 44%: coal, nuclear, hydroelectric, and bio-mass/waste. It would seem that new competitors continue to appear.
One major E&P company is touting its lead as the largest producer of magma-heated steam to drive power generators—enough to support millions of homes. The water captured after power generation is reinjected and reheated to temperatures as high as 570°F, completing a renewable-energy cycle. Then there is the latest liquid-sodium-cooled nuclear power plants, such as the "Toshiba 4S." Additionally, others are pushing solar, wind, bitumen, and now power plants that can switch between coal and natural gas. As the price of oil climbs, our competitors will catch up all the quicker to meet the world's growing energy needs.
Now is the time to raise the bar for defining well-stimulation success, not after our competitors have caught up. Is it possible that we spend too much time looking at future wells and not enough quantifying past results? Let us take the example of stimulating a four-fold increase in production, which generates a high economic return. If we determine that we could have achieved a six-fold increase with a greater return, or perhaps even a 20-fold increase by combining with a multistage-treated horizontal well, does this alter our idea of success?
It is time to take stimulation effectiveness to the next level, being measured and understood more reliably through integrated and detailed approaches. Success should be demonstrated through consistent engineered improvements. It is defining a greater understanding from previous stimulations that will allow us to realize more rapidly what is possible, thereby increasing our level of competition in a world market, one well at a time.
Well Stimulation additional reading available at the SPE eLibrary: www.spe.org
SPE 110707 • "Real-Time Diversion Quantification and Optimization Using DTS" by Gerard Glasbergen, SPE, Halliburton, et al.
SPE 111512 • "Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone Reservoir" by Goran Andersson, PetroBoscan, et al.
New HF-Acid System for a Heavy-Crude Brownfield With Fines Problems
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112558, "Increasing Production in a Brownfield With Heavy Crude and Fines Problems by Application of New HF-Acid System: Case Histories," by Folorunso Afolabi, SPE, Austa Opusunju, SPE, and Jaspers Henri, SPE, Shell, and Cletus Onyekwere, SPE, Chris Onyekwere, SPE, and Davalos Juan, SPE, Weafri, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13–15 February. The paper has not been peer reviewed.
Minimizing fines migration and improving high-water-cut-well productivities with improved treatment-fluid designs, detailed candidate selection, and enhanced pumping methods yielded positive results in aged-field production enhancement. A slow-release-hydrogen retarded-hydrofluoric-acid (SRH-RHF) system was used on the basis of a detailed candidate selection, case-specific fluid design for high-water-cut wells, and mechanism of fines and clay migration and control methodology to acidize heavy- or medium-crude reservoirs.

Introduction
Improving productivity in these Niger delta brownfields that produce heavy crude and experience fines migration had been approached with little or no consideration to such challenges as water production. Many wells were treated with a conventional mud-acid system, either with or without a solvent-soak treatment. Clay-control agents are no longer used to stop fines problems because the additive had little effect. Wells with high water cut were treated only with solvent material, realizing minimal effect. Foam diversion often had inconsistent results. Other diverting techniques also proved unpredictable in this environment. A coating of heavy crude on the formation wall inhibited the reaction of the mud-acid system with the formation. An acid system or formulation that would maintain matrix acidizing was needed for well-productivity problems in the Niger delta.
In December 1996, an SRH-RHF sys-tem was used. Data indicated a consistent production increase with evidence of deep penetration into the damaged zone. Failures experienced with this sys-tem were traced to a shortage of well information for proper diagnosis and the need for a core-flow test in one field with three treatments resulting in no increase or a reduction in production.
In the past, acid stimulation was limited to wells with water cut less than 30%. In late 2001, an improvement was made in candidate selection, treatment design, foam diversion, and pumping method for high-water-cut wells and heavy-crude wells. The high-water-cut limit was increased to 60%. In 2005, a new SRH-RHF system was developed. Its application in nine wells with heavy or medium crude was successful.
Coiled-Tubing Underbalanced Drilling in the Lisburne Field, Alaska
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108337, "Coiled-Tubing Underbalanced-Drilling Applications in the Lisburne Field, Alaska," by Mark Johnson, SPE, BP; Patrick Brand, SPE, Blade; Sam French, SPE and Greg Sarber, SPE, BP; Dave Hildreth, SPE, Orbis; Bob Harris, SPE, Baker Oil Tool; Pedro Rangel, SPE, Schlumberger; Udo Cassee, SPE, Nordic; and Jimmy Clark, ASRC, prepared for the 2007 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Galveston, Texas, 28–29 March. The paper has not been peer reviewed.
In 2005, BP Alaska began evaluating the application of underbalanced-drilling (UBD) technology as a method for drilling multilateral wells in the Lisburne field. The evaluation process was enacted as a response to slow rate of penetration (ROP) through the hard carbonate Wahoo formation; frequent total losses of drilling fluid when drilling conventionally; and poor understanding of the orientation, frequency, and effect of fractures on production.

Introduction
The Lisburne carbonate reservoir has approximately 2 billion bbl of original oil in place. The Wahoo formation, at a depth of approximately 8,900 ft true vertical depth (TVD), is tight, fairly thick (400 ft), and highly consolidated, with thin interbedded mudstone layers. Reservoir fluid is mainly oil with a gas cap covering a portion of the field. The gas contains approximately 60 ppm H2S and 12% CO2.
Previous drilling in the reservoir was overbalanced. Lisburne is a hard-rock carbonate with unconfined compressive strengths from 15,000 to 25,000 psi. Drilling problems include low ROP when drilling overbalanced and instability of the mudstone layers when exposed to water-based muds (WBMs). Production performance of the reservoir in general has been disappointing, with an oil recovery to date of only 8% because of low matrix permeability and excessive gas production. It is apparent that the formation is fractured and that intersection of effective fractures is critical to well performance. Wells that have intersected significant fractures have been among the better performers.
In a bid to intersect more of the fractures, BP Alaska had attempted through-tubing coiled-tubing (CT) sidetracking, placing single horizontal laterals in the carbonate sections. Production-performance delivery of these wells has been 50% successful, prompting consideration of other alternatives. One of the main alternatives considered was through-tubing CT-UBD sidetracks. The idea was to place multiple laterals from a single main wellbore within the carbonate sections, thus increasing exposure and avoiding the potentially unstable mudstones. The main motivation for UBD was to improve ROP and eliminate drilling problems associated with overbalanced operations.
CT-Failure Causes: A Decade of Experience
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113676, "CT-Failure Monitoring: A Decade of Experience," by A.R. Crabtree, SPE, BJ Services, prepared for the 2008 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 1–2 April. The paper has not been peer reviewed.
The full-length paper reviews a decade of tracking coiled-tubing (CT) failures and their causes and sets the results against the perspective of the changing nature of the business over the same time period. Critical factors for reliable CT service-life performance are identified, and whether reliability is higher today than a decade ago is examined.

Introduction
Since the beginning of 1996, all early CT-string failures experienced in company operations have been examined to identify cause of failure. The results of these examinations are recorded in a database to enable historical tracking, so trends can be observed and appropriate policy or procedural changes made. The full-length paper presents data captured from 1997 through 2007. Early failures are those that are experienced before the safe working life of a CT string has been fully consumed. Very few strings are used until they reach their maximum-allowable safe working life, and, therefore, this database basically captures all string-failure data.
The database contains information on more than 250 failure investigations. During the same period, more than 2,200 CT strings were in service, performing approximately 60,000 jobs, using an average of 138 CT units, with both land and offshore operating locations.
Research into the low-cycle fatigue performance of CT conducted since the early 1990s has resulted in predictive algorithms and fatigue-management software. This, combined with improved string-manufacturing techniques, has all but eliminated most pure cyclic-strain-induced fatigue failures (i.e., fatigue not associated with secondary mechanisms such as corrosion).

Data Overview
Examination of all the data (Fig. 1) shows that the leading reasons for early failure are dominated by five main classifications: corrosion, mechanical damage, manufacturing flaws (or defects), operator error, and hydrogen sulfide (H2S) cracking. These groups account for approximately 94% of all failures.
Reviewing the overall data and superimposing the number of jobs per year (Fig. 2), it can be seen that the number of failures appears to be proportional to jobs performed. This would seem to indicate that the failure rate (jobs performed/number of failures) has not improved. However, this is not the case because the chart belies the underlying numbers. In fact, the failure rate from 2000 through 2007 improved 47%. The year 2003 was anomalous and is a result, in part, of an increase in the CT fleet in the later portion of 2002, leading to the addition of several new CT strings being used in 2003.
How High-Speed Telemetry Affects the Drilling Process
Authors: Wassermann Ingolf , Kaniappan Aravindh 
Published: February 2015

Technology Update
Regardless of whether you look at consumer or industrial applications, whenever a technical breakthrough in available communication bandwidth is achieved, the affected environment and feasible applications change significantly. One recent example was the introduction of the digital subscriber line (DSL) to replace modems for Internet access.
With high-speed telemetry systems becoming economically viable in an increasing number of drilling applications, our industry is in a situation similar to that seen at the introduction of DSL. Following the parallel of Internet access via DSL vs. modem, the relevant questions are: How has high-speed telemetry changed the drilling process, and what further changes will we see in the near future?
This article first intends to explain why oilfield service companies continually strive for higher telemetry data rates. It then identifies and exemplifies fields of application for both available technologies—high-speed mud-pulse telemetry and wired drillstring telemetry—with two case histories. The conclusion provides an outlook on possible future opportunities and technological developments.

Rationale for Higher Telemetry Data Rates
Every breakthrough in drilling technology creates an increasing demand on telemetry speed, requiring new telemetry technologies to meet that demand. Consequently, the meaning of high-speed telemetry has changed and will continue to change over time.
The most recent major change in drilling technologies has been the rise of increasingly sophisticated measurement-while-drilling (MWD) and logging-while-drilling (LWD) services, e.g., drilling dynamics, formation-pressure testing, high-resolution resistivity and electrical images, and magnetic-resonance measurements.
MWD and LWD services reduce the necessity for wireline runs and increase the log quality at the same time because the formation is logged immediately after penetration. In contrast to wireline logging, MWD/LWD tools "see" the freshly cut formation rather than logging it after days of exposure to drilling mud, which results in formation deterioration. They also make downhole drilling-dynamics measurements available in real time, something that has previously been impossible.
In the past, one of the major challenges with MWD/LWD services was the ability to transmit all the data gathered downhole. The majority of measurements were written to memory onboard the downhole tool, and only a fraction of the collected data was transmitted in real time to surface. The data then was retrieved from memory after pulling the drillstring out of hole.