bluuebunny/crossref_metadata_2025_split huggingface dataset:
How In-Situ Combustion Works in a Fractured System
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 117645, "How In-Situ Combustion Process Works in a Fractured System: Two-Dimensional, Core- and Block-Scale Simulation," by H. Fadaei, Institut Francais du Petrole; M. Quintard and G. Debenest, l'Institut de Mecanique des Fluides de Toulouse; G. Renard, SPE, Institut Francais du Petrole; and A.M. Kamp, SPE, Open and Experimental Center for Heavy Oil, prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed.
Simulation of an in-situ-combustion (ISC) process was performed for a fractured system at core and matrix-block scales. The aim of this work was to predict the ISC ignition/propagation conditions, understand the mechanism of oil recovery, and provide guidelines for ISC scaleup for a fractured system. The study was of a fine-grid single-porosity multiphase multicomponent system and used a thermal-reservoir simulator.

Introduction
Heavy-oil recovery from fractured carbonate reservoirs (one-third of global heavy-oil resources) has been low because of the complexity of such reservoirs. The recovery mechanism and the reservoir and operational conditions at which combustion can propagate in fractured systems are not understood clearly. This study investigated ISC-propagation conditions and oil-recovery mechanisms at the fractured-core scale, and investigated the process at the block scale to address the 2D behavior of ISC at large scale. The objective was to determine the dominant processes in combustion propagation at the block scale and the characteristics of different fronts that exist.

Model
Four phases exist in crude-oil combustion in porous media: oil, gas, water, and solid. The oil and gas phases are multicomponent (i.e., hydrocarbon components), the water is a vapor, and the solid phase contains inert solid and coke. Reactions take place in the oil, in the gas, and on the surface of the solid phase (when coke is present). Coke is formed by pyrolysis and deposited on the solid surface. Reactions in oil and gas phases are homogeneous, but the coke reaction is heterogeneous.

Simulation

Oil Combustion in a Fractured System.
Ignition/propagation conditions of the combustion front in a fractured system and the governing production mechanisms were studied. The simulation model is presented in Fig. 1, and the input data for the model are detailed in Table 1 of the full-length paper.
A vertical core was used to mimic a top-down process. The core had no temperature losses at its boundaries, and the top row of blocks was heated with a constant heating rate. Heat injection was maintained for 24 minutes, until ignition occurred. This time was considered to be approximately that used in a nonfractured core.
SEC Revises Reserves Rules on the Basis of SPE System
Authors: Parshall Joel 
Published: February 2015

The US Securities and Exchange Commission (SEC) late last year unanimously adopted revisions to its rules governing oil and natural gas reserves reporting, with those revisions aligned with and incorporating many of the definitions in the Society of Petroleum Engineers (SPE) Petroleum Resources Management System (PRMS). The revised rules will go into effect on January 1, 2010.
The SEC oversees US securities exchanges, securities brokers and dealers, investment advisers, and mutual funds. Companies publicly offering securities on US exchanges are required to file regular disclosures to the SEC, concerning their securities and the scope, practices, condition, and risks of their businesses with respect to investors.
The changes just adopted by the SEC, announced December 29, 2008, marked the first major revision of the commission's reserves-reporting rules since 1983.
"In the more than a quarter century since the SEC last reviewed its rules in this area, there have been significant changes in technology that have increasingly limited the usefulness of current disclosures to the market and investors," said Christopher Cox, then-Chairman of the SEC. "These updates to the SEC rules will help ensure more meaningful and comprehensive disclosure of information that, even though it does not appear on a company's balance sheet, is of significance to investors in making informed investment decisions."
Leo Roodhart, 2009 SPE President, praised the commission for modernizing the reporting rules. "The SEC is to be commended for updating the rules on oil and natural gas reserves reporting to reflect changes in technology, and for using the PRMS primarily as the basis for the technical changes," he said. "The updated rules recognize the importance of new technologies in making accurate and reliable estimates of oil and natural gas reserves as the industry develops resources in harsher environments, including ultradeepwater and the Arctic, as well as more unconventional resources."
The PRMS was developed by SPE in collaboration with the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers (SPEE).
"SPE's Oil and Gas Reserves Committee is gratified that our work has served as a foundation for improving the information provided to investors and the public about the reserves controlled by public companies," said Delores Hinkle, SPE Oil and Gas Reserves Committee Chairperson. "The updated rules allow companies the flexibility to provide additional reserve information to the investing public and should result in better reserve estimates, due to the inclusion of the advanced technologies and evaluation practices now in use around the world."
Shared Vision (April 2005)
Authors: Paccaloni Giovanni 
Published: February 2015

My definition of a professional is a competent, educated, ethical, continuously developing person with communication and interpersonal skills, and a holistic perspective. A professional uses innovative approaches, participates in professional associations, and is committed to the pursuit of excellence. It is interesting to note that this definition encapsulates all of SPE’s core values.
SPE has always been dedicated to helping members to maintain and upgrade their technical knowledge through our publications, conferences, workshops, and other technical programs. Now we are exploring the opportunity to verify professionalism through a certification program being overseen by the SPE Engineering Professionalism Committee for members in countries where there is no governmental or organizational licensing. Our first step is a pilot program for Petroleum Professional Certification to be conducted in the Middle East. This pilot project stems from requests by members in the Middle East and elsewhere for SPE to offer an internationally recognized certification program for petroleum professionals. A task force was formed in 2003 to study and make recommendations on what SPE’s involvement in certification ought to be. We sought member feedback through focus groups in a number of locations, and a survey was sent to more than 6,200 members to gauge the interest in certification. An astounding 65% of the respondents said they were interested in obtaining SPE certification.
With those results in hand, the task force recommended that the SPE Board of Directors establish a certification program under the responsibility of the SPE Engineering Professionalism Committee and establish an SPE Petroleum Professional Certification Subcommittee to compose and maintain the certification examination. The Board approved conduct of a pilot to test the certification process thoroughly. Because of the strong interest demonstrated by members in the Middle East, the pilot examination is planned for February 2006 in Abu Dhabi.
SPE certification would mean that a petroleum professional has passed an examination and has met certain minimum requirements that demonstrate both technical knowledge as well as a commitment to ethics. Certification would not be conferred automatically through membership in the Society.
Value of In-Situ Seismic Waves - Regain Lost Reserves, Increase Oil Cut
Authors: JPT staff _ 
Published: February 2015

When Occidental of Elk Hills (Oxy) opted to explore a new enhanced-oil-recovery (EOR) method—in-situ seismic stimulation—to increase oil recovery in declining reservoirs, liberating residual oil was but one outcome. Oxy’s seismic-stimulation project offered improved oil recovery and increased flow, positive impact on relative phase permeability, and an understanding of the magnitude and extent of the stimulated area. This technology and project results are based on and can be correlated to oil response resulting from natural earthquakes. It is the first departure from variants on conventional stimulation methods (thermal, polymer, chemical, microbial) to be introduced commercially since the 1970s. While efforts were made in the 1980s to duplicate earthquake effects by use of vibrators above a targeted zone, these attempts had disadvantages that limited commercial viability.
Hydro-Impact stimulation services developed by Applied Seismic Research Corp., currently in use in the U.S. in California and Texas, involve the placement of tools to generate subsurface shockwaves that mimic primary waves generated by earthquakes. These shockwaves, generated every 10 seconds, produce power ranging from ≈1 to 10 million watts with pressure at the wave front that can be in excess of 4,000 psi. The waves, traveling at approximately 1½ miles/sec, generally are noticeably felt on the surface only in close proximity to the wellbore, but they have a significant measured seismic signal at distances of ¾ mile from the source (Fig. 1). Historically, effects from sonic stimulation could reach only 20 ft. The waves affect oil-bearing strata and increase the potential for oil flow by inducing coalescence of residual oil. The effect of the seismic shock: oil droplets are dislodged from the pore wall and coalesce into larger droplets that become mobile and move into flow streams that then begin to move into any existing flow system such as fractures.
In some cases, reservoirs exhibit a permanent increase in oil cut as a result of a permanent fieldwide improvement in injectivity when deployed on injectors, but this is unpredictable. Other fields return to the original decline soon after seismic stimulation is stopped and require stimulation on a continuous basis.
Because the seismic wave passes through the wellbore casing and cement within microseconds, it does not damage the wellbore or formation. The wave, propagating in all directions to eventually become an elastic wave, also can be used simultaneously with ongoing injection processes and considerably increases injectivity both in the injection well in which the tool is installed and other injection wells within the affected area.
Overview: Offshore Drilling and Completions (April 2005)
Authors: Gazaniol Didier 
Published: February 2015

The basics of offshore drilling are the same as those of onshore drilling. Actually, the pioneers of offshore drilling just transported their equipment to an offshore platform. Very quickly, however, specific offshore drilling units were built (many being mobile units). There were two main consequences.
First, with high drilling-unit costs, more emphasis has been put on reducing well-construction time, either by minimizing nonproductive time or by developing new technologies. Drilling units specifically built to remove as many operations as possible from the critical path exist, but a lot of effort has also been put into procedure optimization.
Second, beyond the issues related to safety or logistics, several new challenges have appeared that are specific to offshore operations. These new challenges were particularly evident when drilling with a floating unit, for which new areas of expertise were developed, such as rig positioning or riser and subsea-blowout-preventer management.
In recent years, the latest technical developments were, to a large extent, dedicated to deep offshore, where the issues have become even more challenging. New pressure issues appeared, related to different pressure gradients in the water and in the sediments, as well as temperature issues with mud, cement, well architecture, and the completion string.
Eventually, some of the offshore-drilling solutions appear in land drilling, such as in remote harsh-environment arctic conditions. The evolution appears to be closing the loop; however, this is another story.
Additional Offshore Drilling and Completions Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 91239 - Challenges in Implementing UBO Technology
Available at the OTC Library: www.otcnet.org
OTC 16624 - Managed-Pressure Drilling Fills a Key Void in the Evolution of Offshore-Drilling Technology
OTC 16228 - Na Kika Completions Overview: Challenges and Accomplishments
OTC 16621 - Managed-Pressure-Drilling Applications Index
Thunder Horse Drilling-Riser Break - The Road to Recovery
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90628, "Thunder Horse Drilling-Riser Break - The Road to Recovery," by Bill Kirton and Gary Wulf, SPE, BP plc, and Bill Henderson, SPE, Resultants, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
The full-length paper presents key learnings by BP’s wells team on the Thunder Horse project after responding to a major incident—the break of the drilling riser on the Discoverer Enterprise drillship in May 2003 in the Gulf of Mexico. Even though BP has established policies for the immediate incident-response phase and conducts training exercises, there is less focus on the later recovery phase. The full-length paper increases the awareness of critical project-management issues that may arise during transition from response to recovery phase after a major incident.

The Event
At 3:59 a.m. on 21 May 2003, the drilling riser on the Discoverer Enterprise parted during operations at the BP-operated Thunder Horse field. With the riser under 2.1 million lbf of top tension, the parting produced a loud bang, and all on board the vessel felt the subsequent sudden jarring. At the time, the crew had tripped about 200 ft out of hole after reaching a total depth of 24,901 ft (8,000 ft of departure) on the Mississippi Canyon (MC) 822 Well 6. A remotely operated vehicle (ROV) was deployed and found the riser parted at 3,200 ft subsea, with drillpipe still intact.
Following the drillpipe deeper, the ROV located the top of the riser at 5,100 ft subsea, supported vertically by the internal drillpipe that was still connected to the surface (Fig. 1). Diving to the ocean floor at 6,100 ft, the ROV spotted the lower marine-riser package (LMRP) on top of the blowout preventer (BOP), where the riser and drillpipe had snapped off. Riser-joint number 1 was resting against the BOP close to the control lines that operate the stack (Fig. 2). Fig. 3 shows the top of the LMRP after the riser break.
The BOP’s deadman sequence functioned as designed and secured the well with the blind shears. No one was injured, and the well was secure. Approximately 1,900 ft of riser, still joined together, lay scattered around the drill center, either buried in the mud or resting on the seafloor and on the wellhead of the abandoned discovery well, MC 778 Well 1. Another 3,200 ft of riser remained suspended from the drillship, while yet another 900 ft of riser stood vertically above the seabed around the parted drillpipe.
Benchmarking Drilling Performance of MODU Operating Practices for Deepwater Drilling
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92235, "Benchmarking Drilling Performance: Achieving Excellence in MODU's Operating Practices for Deepwater Drilling," by Hugo Valdez, SPE, and Jurgen Sager, Transocean, prepared or the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
Practical and straightforward application of continuous-improvement and bench-marking techniques to monitor, document, analyze, and detect best practices during the drilling process can improve operational efficiency and reduce well costs significantly. The full-length paper describes how a rigorous approach to performance benchmarking, with documented objectives, user-friendly and meaningful reports, and critical process and task analysis, can help identify nonvalue-added activities and performance gaps in the well-construction process.

Introduction
Since the early days of offshore drilling when operators first mounted land rigs on piers, mechanization and automation gradually have changed the way oil wells are drilled. As the industry moved into deeper waters, while targeting even deeper pay zones and requiring large wellbores to achieve the production rates to support costly projects, drillpipe, casing, and riser sizes and weights continued to increase. Safety considerations drove the need to mechanize pipe handling and minimize manual intervention. Drilling-rig technology evolved from the traditional rig-floor configuration of slips and tongs to the highly sophisticated mechanized multi-activity designs found on the latest generation of semisubmersibles and drillships.
While significant improvements in safety have been achieved by use of more mechanized and automated equipment, some critical-path operations—particularly those involving moving drillpipe, casing, and tubing into and out of the wellbore—were slower than expected. After noting that rigs with exactly the same capabilities performed differently when operating under similar conditions, an internal benchmarking program was launched to identify, understand, compare, measure, and adapt best practices from top-performing mobile offshore drilling units (MODUs) to help improve performance of a particular drilling rig.
Development of an Ultraharsh- Environment Jackup Drilling Rig
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92760, "Development of the Ultimate Ultra Harsh Environment Jack-up Drilling Rigs," by Frederik Smidth, SPE, and Per Wullf, M ærsk Contractors, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
Drilling with jackups in harsh environments has moved into deeper water during the last 10 years. Before, 300 ft was the maximum operating water depth, but now operations are possible in water depths as great as 500 ft. Several new features are available on harsh-environment jackups that increase drilling efficiency by as much as 25%. The full-length paper describes the process of creating the next-generation deepwater jackup drilling rig and operational experience with the Mærsk I-Class rigs.

Design Phase
Mærsk Contractors operate several ultra-harsh-environment rigs in the North Sea. On the basis of experience with these rigs, functional requirements were developed for the next generation of ultraharsh-environment jackup rigs. The main focus was to improve the safety level on board and provide more value for money to the clients. A large number of North Sea operators were consulted to obtain their view of the ideal rig of the future. More than 650 suggestions were received from the rig crews in the existing fleet, more than 450 of which were incorporated in the final design.
A 1:1 mockup of the drill floor with simulated work situations was used to gather input about drill-floor layout. Use of the rigs in subsea and production mode also was considered. The MSC-CJ70 was chosen as the basic design. This included an XY cantilever system that provides opportunities to increase efficiency and introduce improvements on the drill floor.
Surface BOP, Slim Riser, or Conventional 21-in. Riser - Which Is Best To Use?
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92762, "Surface BOP, Slim Rise or Conventional 21-Inch Riser - What Is the Best Concept To Use," by Mark Childers, SPE, Atwood Oceanics, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
One of the major cost components of ultradeepwater wells is the cost to build and operate the new fifth-generation mobile offshore drilling units (MODUs) required to drill in these water depths. Until recently, the only option for operators and contract drillers was to use a conventional 21-in. riser with an 18¾-in. subsea-blowout-preventer (BOP) system. In the early 2000s, a new, somewhat radical concept of placing a surface-BOP stack (SBOP) directly under the rotary and running a high-pressure-casing riser below the SBOP to the seafloor was used. The full-length paper discusses a recent modification to the SBOP concept and a third proposed concept as alternatives to the 21-in. riser.

Introduction
The SBOP concept assumes that the drilled wells are expendable, simple, and have normal pressures and that slimhole technology is applicable and a second-generation semisubmersible is adequate. It was anticipated that if the MODU had a mooring failure or the high-pressure riser failed, the well would be killed by the seawater head. Some 150 wells were drilled successfully in the benign waters of the Far East using the SBOP concept, with up to 70% savings. Recently, the SBOP concept has been modified by use of a seafloor subsea disconnect system (SDS).
A third proposed concept uses a 16-in.-outside-diameter (OD) standard riser in combination with a conventional 18¾-in. BOP stack. The concept uses slimhole drilling technology, like the SBOP concept does, but maintains the BOP stack on the seafloor. The slim-riser concept (SRC) is attractive because a third- or fourth-generation semisubmersible MODU can be adapted easily for its use, thus eliminating the requirement for a much more expensive fifth-generation MODU.