bluuebunny/crossref_metadata_2025 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 The paper has not been peer reviewed.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."
Risky Business: The Continuing Problem of Vehicle Accidents in the E&P Industry
Authors: Cook Pat , Knode Tom
Published: February 2015

Guest editorial - No abstract available.
Overview: Offshore Drilling and Completions (April 2004)
Authors: Hilton Paul R.
Published: February 2015

Overview - No abstract available.
Offshore Drilling and Completions: Innovative Workover-Riser System for 3000-m Water Depth
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15183, "An Innovative Workover-Riser System for 3000-m Water Depth," by J.R.F. Moreira, Petrobras, and M.F.D. Oliveira, P.C.S. Paulo, M. Branca, and F.J. Mateus, Kvaerner Oilfield Products Brazil, originally presented at the 2003 Offshore Technology Conference, Houston, 5-8 May.
Natural Gas Technology/Monetization: Transportation of GTL Products From the Alaskan North Slope
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86931, "Technical and Economic Issues in Transportation of GTL Products From Alaskan North Slope to the Markets," by Santanu Khataniar, SPE, Godwin A. Chukwu, SPE, Shirish L. Patil, SPE, and Abhijit Y. Dandekar, SPE, U. of Alaska Fairbanks, prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
Natural Gas Technology/Monetization: Latest Developments in Rapid- Phase-Transition Modeling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 15228, "Last Developments in Rapid-Phase- Transition Knowledge and Modeling Techniques," by D. Nedelka and V. Sauter, Gaz de France; J. Goanvic, Total; and R. Ohba, Mitsubishi Heavy Industries, prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
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.
Overview: Natural Gas Technology/Monetization (April 2005)
Authors: Vitucci John
Published: February 2015

Developing the world’s natural-gas resources continues at the forefront of the industry as we continue to embrace clean-energy initiatives and gas discoveries continue to increase on a worldwide basis. Once considered a nuisance by the industry, natural gas has become the leading clean energy to lead us into the future. Our industry continues to develop innovative ideas and technologies for finding, producing, transporting, and distributing natural gas. The drilling, completions, reservoir-characterization, and production disciplines continue to generate new technology, improve existing technologies, and improve our understanding of subsurface information. Transport, processing, and distribution technologies [e.g., liquefied natural gas, gas to liquids (GTL), and gas to wire] continue to make natural gas a viable option to a greater number of markets. Unconventional gas sources, such as coalbed methane, continue to grow in importance as technology improves production and economics. New technologies for gas-hydrate production and stranded-gas use are in their conceptual phases.

As one looks across the natural-gas value chain from reservoir to end markets, there is a realization that technology is driving our ability to develop natural gas into a leading energy resource for the world. The broad diversity of technologies surrounding natural-gas production and use makes it difficult to capture in a few select articles. The feature papers included this month are only a sampling of our industry’s innovative technologies and our ability to apply these technologies for economical use of the world’s natural-gas resources. I encourage readers to review the list of additional technical papers to fully appreciate our collective ability to develop natural gas in meeting the world’s energy needs well into the future.

Additional Natural Gas Technology/Monetization Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 90530 - The Significance of Non-Darcy and Multiphase-Flow Effects in High-Rate Frac-Pack Gas Completions

SPE 92764 - The Planning and Drilling of Hot Ice No. 1—Gas-Hydrate Exploration Well in the Alaskan Arctic

SPE 90177 - Risk, Uncertainty, and Optimization for Offshore-Gas-Asset Planning in Litoral Tabasco
Software Tool Improves Fractured-Reservoir Characterization and Modeling
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88785, "New Software Tool Improves Fractured-Reservoir Characterization and Modeling Through Maximized Use of Constraints and Data Integration," by K. Rawnsley, Shell Intl.; P. Swaby, SPE, SSL; S. Bettembourg, S. Dhahab, H. Hillgartner, and M. de Keijzer, Shell Intl.; P. Richard, and P. Schoepfer, PDO; and B. Stephenson and L. Wei, Shell Intl., prepared for the 2004 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10-13 October.

To enhance oil recovery from several fractured-carbonate reservoirs in Oman, Shell’s carbonate-development team and Petroleum Development Oman (PDO) applied a workflow and a research-software package aimed at better characterizing the complex subsurface. The work-flow comprised several steps, each supported by a multidisciplinary research program and implemented in an integrated-software environment for application to field development and enhanced-oil-recovery projects. The software tool, which interacts with existing static- and dynamic-modeling packages, produces integrated reservoir models including fracture-specific information.

Introduction

The main objectives of these studies were to provide enhanced constraints on fracture modeling in the subsurface. The following are important aspects of fracture systems, which typically are poorly constrained by subsurface data alone.

- Accurate 2D and 3D characterization of structural objects, especially fracture corridors and the internal geometries of fault zones.

- Organization of multiscaled fracture systems within mechanically layered rocks (i.e., the vertical extents of fractures intersected by wells).

- Internal flow properties of the fractures.

Several reservoir studies were carried out in parallel, for example in the northern Oman region, operated by PDO, providing an excellent opportunity to link observations made at the surface with the complete reservoir data sets. The current research builds on the understanding of the regional structural framework and evolution of North Oman from previous studies. The objective was to show how a software tool developed in Shell facilitated bringing research and field studies together to pro-vide enhanced reservoir characterization. Fig. 1 shows a generic workflow.
3D Visualization: A Common Language for the Drilling and Subsurface Communities
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90659, "3D Visualization: A Common Language for the Drilling and Subsurface Communities," by C. Telford and M. Burns, BP plc, and N. Whiteley, Landmark Graphics Corp. Ltd., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

3D visualization has enabled the Andrew field team in the North Sea to develop a common understanding of geologically related drilling hazards to achieve best-in-class drilling performance on Well 16/28-A16. Improvement continued in Well 16/28-A17 with further reduction in geologically related nonproductive time (NPT). The common language pro-vided by the 3D-visualization tools enabled the different disciplines onshore and offshore to communicate effectively, integrating the team.

Introduction

This paper describes how the reservoir model, pressure cube, and structural model were used with the 4D seismic to identify the geological targets in the reservoir. These models, together with historical drilling NPT data and mapping of the overburden, were used to determine the optimal wellbore trajectory. The ability of the multidisciplinary team to view the subsurface field data along-side the drilling NPT information provided a greater understanding of potential risks and challenges and ensured agreement by all in the project from planning through to production. Visual images developed during the planning process then were used to brief the drilling and subsurface contractor services in technical-limit, prespud, and refresher sessions before each drilling phase.
Techbits: Digital Energy Conference Tackles Range of Issues
Authors: JPT staff _
Published: February 2015

Oilfield applications of digital technology, including best practices, cutting-edge applications, and future technologies, were the themes of "Digital Energy 2006: Bytes and Barrels," a 2-day conference held in Houston in February. SPE and the SPE Gulf Coast Section worked together on the event, the sixth annual conference on applications of digital technology in the oil and gas industry. The event featured the perspectives of operators, service companies, and firms directly involved in information technology (IT) on such issues as data management, how demographics will influence IT, production-operations monitoring, collaboration, systems integration, and drilling and operations.

In the conference keynote address, Steven B. Hinchman, Senior Vice President of Worldwide Production for Marathon Oil Corp., addressed "New Work Processes Required for Success." Supply and demand factors will influence how companies operate in the future, he said. "The global energy outlook really defines this changing work model," Hinchman said. Those factors include rising energy demand, especially in places such as China; growing transportation demand; the rise of natural gas as a global commodity; and a heavier and more sour barrel of oil that is becoming more difficult to produce.

"The most critical question international oil and gas companies face today is access to resources," Hinchman said. By 2020, the industry will need to provide 125 million BOE in additional production capacity because of the rise in global demand and the decline rate of current producing fields, he said.

Changing Relationship

Another issue affecting how companies operate is the changing relationship between private international oil companies (IOCs) and national oil companies (NOCs), Hinchman said. NOCs control most of the world's reserves and are becoming increasingly active in the international arena. And today, NOCs have access to the industry's conventional technology, have more financial resources than they did in the past, and are becoming more active outside their borders. "IOCs will have to be able to differentiate themselves," he added.

Oil and gas is becoming increasingly harder to produce because of rising E&P complexity and access to resources. Much of the industry's focus in the future will be on producing unconventional oil and gas, new gas technologies such as liquefied natural gas and gas to liquids, Arctic seas drilling, and ultradeepwater drilling. "All this means is that technology will play an even more important role in the next 20 years than it has in the past 20," he said. The industry's well-noted demographic challenges also will add pressure to how companies operate.

Hinchman sees the need for a "new generation work model" that would involve:Integration of resource holders, suppliers, and vendors.Increased productivity.Disciplined processes and work flow.Leveraging of technology.Globalized work teams.Accelerated learning and knowledge transfer.
Technology Tomorrow: The Next Trillion: Anticipating and Enabling Game-Changing Recoveries
Authors: Saleri Nansen G.
Published: February 2015

Editor's note: This is the second installment of a yearlong series designed to stimulate discussion in research and development. The Technology Tomorrow articles will be published every other month and vary in emphasis, covering topics as broad as R&D industry trends and as focused as improving reservoir recovery factors. This series is one of several actions being taken by the SPE R&D Advisory Committee to encourage R&D development and discussion. The target audience is the entire readership of JPT. We hope to create a forum that sparks discourse and ideas, including ideas that may not be in the current mainstream of thought. Comments on the articles are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.

By any measure of efficiency, globally reported expected ultimate recoveries (EURs) have been less than impressive. The often-quoted industry average of 35% recovery (for conventional crude oil) sets a useful benchmark for the future, and raises the question, "Can we double it for the next trillion?" As we look ahead to April 2007, the date of the first SPE R&D Conference, one might ponder several related questions: How high can the industry stretch EURs? What are the major impediments to achieving them? Do R&D programs have a role to play, or does the spontaneous technology boom in the industry coupled with free-market dynamics signal the end of organized R&D?

A quick look at global oil resources, their acknowledged uncertainties not withstanding, calls for some perspective on this issue (Fig. 1). In 2005, global consumption had depleted only one out of seven barrels of conventional oil initially in place (and a fraction of nonconventional), a point perhaps overlooked by peak-oil advocates (Deffeyes, 2005; Tertzakian, 2006). A 10% incremental recovery translates to about 1.4 trillion bbl of recoverable resources, roughly an additional 50-year supply of global crude consumption at current rates. The gains in gas reserves could be equally rewarding.

The point is not so much to argue for the veracity or the feasibility of these figures. Instead, the intent is to highlight vast possibilities in the context of twin questions: How can R&D shape the energy future, and how should the desired future outlook govern present-day R&D? Intent matters! The industry has no choice but to articulate its own anticipations for the future regarding trillions of barrels of recoverable resources. The recovery standards of the past century certainly cannot be the basis going forward.
Marco Polo Deepwater TLP
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95331, "Marco Polo Deepwater TLP: Completion Implementation and Performance," by J. Burman, SPE, Exploitation Technologies LLC, and K. Renfro, SPE, and M. Conrad, SPE, Anadarko Petroleum, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

Novel well-completion techniques and exceptional field execution allowed the six well completions in the Marco Polo deep-water tension-leg-platform (TLP) project to be accomplished in world-class fashion. All six wells (17 frac packs) were placed on pro-duction in only 168 days, including 14 days lost because of storms. The full-length paper focuses on how the implementation challenges of completing 17 zones in six deepwater dry-tree wells with a 1,000-hp rig were met and highlights a number of concepts and technical firsts that can be used in other deepwater development projects.

Background

Field Development. The Marco Polo field in Green Canyon Block 608 in the Gulf of Mexico (GOM) was discovered in 2000. Six development wells were drilled in 2002 and 2003 and were temporarily abandoned to await completion of the TLP. The TLP hull and deck were installed in January 2004 and were designed to accommodate a 1,000-hp completion rig to run riser tiebacks and perform completions. Only 88 persons are allowed on the platform at a time because of U.S. Coast Guard rules, a significant issue for rig operations.

Reservoir. Initial reservoir pressures and temperatures range from 6,700 to 7,600 psi and from 115 to 122°F, respectively. Reservoir fluids are undersaturated black oils, with gravity ranging from 30 to 34°API and gas/oil ratio ranging from 700 to 1,000 scf/STB.

Completion-Design Overview. Multiple pay sands, low reservoir temperatures, the requirement to gas lift the wells, and the deepwater environment drove the design of the Marco Polo completions. After significant flow-assurance modeling and evaluation, dual-barrier risers with insulating gel and a separate gas lift string were chosen as the upper-completion design.

The sandface-completion design focused on risk management during completion operations, with the hardware designed to minimize future intervention risk. The 17 pay intervals in the six wells were developed with multizone, selective single, stacked frac-pack completions, using sliding sleeves with a concentric isolation string for zonal isolation.

Multiple chemical-injection points are installed for hydrate, paraffin, asphaltene, and scale prevention. The installation of fiber-optic technology for downhole-pressure and -temperature sensing assisted in well surveillance and hydrate prevention. Fig. 4 in the full-length paper shows a generalized Marco Polo wellbore schematic.
Economic and Operational Benefits of Drill-Through Completion Technologies
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17405, "Economic and Operational Benefits of Drill-Through Completion Technologies," by M. Matusek, S. Stjernstrom, and D. Theiss, Cooper Cameron Corp., prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May.

The drill-through completion concept revolves around the principle that substantial cost savings can be realized by installing the subsea horizontal tree before running the blowout preventer (BOP) stack, thus eliminating one BOP stack round trip. Drilling operations are performed through the subsea horizontal tree. Additional cost savings can be achieved in a batch-drilling and -completion program by reducing the number of required rig moves and BOP-stack trips.

Introduction

Interest in drill-through systems has increased in recent years as oil companies search for ways to reduce installation and workover costs associated with deepwater drilling and completions. As water depth increases, time required to deploy equipment to the seabed and the day rate of a rig capable of operating in deeper waters increase. As a result, the value of reducing deployment trips and improving operations reliability increases.

The horizontal subsea tree has had a large influence on the way completion and workover operations are conducted. Drill-through technology allows some or all of the drilling operations to be conducted through the tree—providing numerous opportunities to save time and money, particularly in deepwater operations.

Benefits

The conventional approach to drilling and completing wells involves two round trips of the BOP stack. The drill-through approach to drilling allows the horizontal tree to be installed on top of the wellhead high-pressure housing before running the BOP stack, so that all drilling operations are performed through the tree. The tree is capable of drifting all of the drill bits, casing hangers, seal assemblies, and associated running/test tools required during the drilling and wellhead-installation process. This drilling and completion method requires only a single BOP-stack trip. By eliminating one of the round-trip BOP-stack deployments, substantial cost savings can be achieved.

For a rig operating in 6,000 to 8,000 ft of water, deployment of the BOP-stack and drilling-riser system is estimated to require 4 to 5 rig days. Another 8 to 12 hours are required to test the BOP-stack connections, functions, and control system once it is landed. BOP-stack retrieval is estimated to require 3 days of rig time. With the cost for deepwater rigs estimated to be U.S. $180,000 to $240,000 per day, the estimated cost to make one BOP-stack and riser-system round trip is U.S. $1,300,000 to $2,000,000. This cost may be significantly higher if poor weather conditions delay operations.
Clair Field, West of Shetland
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97772, "Unlocking the Potential: A North Sea Heavy Oil Success Story," by J.J. Wylde, SPE, and G.D.M. Williams, SPE, Clariant Oil Services, and R.E. Cousins, BP plc, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November.

The full-length paper details one of the newest producing fields in the North Sea, the West of Shetland development. Prestartup design and implementation challenges are described, as well as commissioning philosophy for the plant and chemical-injection facilities. Most of the full-length paper focuses on the first 6 months of production history, production-technology management, and how actual operation differed from the planned and designed specifications.

Clair Field Background

The Clair field is 40 miles west of the Shetland Islands and currently is produced from a single fixed platform in 460 ft of water. The field produces both oil and gas. The field produces 20°API crude with a 550 scf/bbl gas/oil ratio. The Clair reservoir extends over a 25×12.5-mile area in complex Devonian and Carboniferous units covering five license blocks. Current estimates of likely oil exceed 4 billion STB original oil in place (OOIP), making Clair the largest undeveloped hydrocarbon accumulation on the U.K. continental shelf and a key component of future U.K. production stategy.

The Clair field was discovered in 1977. In the early 1990s, 3D-seismic data were acquired over the whole field, and two wells were drilled in 1991 and 1992. Although demonstrating commercial flow rates, the wells were not produced for sufficiently long to provide confidence in long-term reservoir performance. In 1996, an extended performance test was conducted on Well 206/8-10z in the core area. Flowing at an average rate of 10,000 B/D for 23 days, with a 18.5-B/D peak, the well performance changed the perception of the Clair reservoir by demonstrating sustainable crude-oil delivery.

Because of its extent, the Clair field is to be produced as a phased development. The first phase builds on the successful 1996 well test and targets development of the Core, Graben, and Horst areas. The reservoir is divided into nine fault-bounded segments having a common free-water level and 1,969-ft maximum oil column. A gas cap is present in the structurally elevated ridge segments. The reservoir depth is 6,070 ft true vertical depth subsurface, and initial reservoir pressure was 2,736 psi with a 151°F temperature. Work is continuing to define this first development. The challenge for Clair is understanding the issues of reservoir deliverability, well productivity, and managing the cost base while achieving a sustainable development. Clair will be the third West of Shetland development, following Foinaven and Schiehallion.
New Logging Tool Enhances Multiphase Production Analysis
Authors: JPT staff _
Published: February 2015

A new multifunction production logging (PL) platform is producing quantifiable results in complex triphasic flow regimes. At 25 ft long, the system takes the place of a conventional PL tool string five times as long. The Schlumberger Flow Scanner tool, unlike its predecessor, features close integration of its 17 sensors in an 11-ft-long sonde so that true dynamic flow characteristics can be obtained at any point in the well. The new system is designed to operate in wellbore diameters ranging from 2 7/8 to 9 in. and under environmental conditions up to 300°F and 15,000 psi. This technology is particularly valuable in deviated and horizontal multiphase wells, where phase behavior is extremely variable and complex. To obtain an accurate picture of the dynamic flow regime at any point in the well, it is necessary to scan the full diameter of the wellbore. The new logging tool does this mechanically, electrically, and optically. (Fig. 1).

Run eccentered in open or cased holes, the tool finds the low side of the hole thanks to gravity. Then an articulated sensor arm is deployed that spans the wellbore, providing five equally spaced measurements of flow velocity, direction, and phase fraction. Together, these measurements provide three-phase holdup, which is defined as the dynamic phase fraction at any point in the wellbore. Holdup differs from produced volume fraction, or cut, because the phases travel at different velocities. Other tool sensors measure pressure and temperature, hole diameter, and instantaneous tool orientation.

To analyze a production interval properly, one must understand exactly what is happening at each spot in the wellbore. Previous PL methods interfered with the flow regime they were trying to measure, and typical phenomena such as heavy-phase recirculation resulted in ambiguous data with gaps over critical intervals. In addition, interpretation could take months and involved dozens of specialists examining data from several log passes. In contrast, the new logging tool was designed using computational fluid-dynamics simulations to optimize its shape and minimize any flow perturbations. A real-time graphics display and processing workflow makes preliminary interpretation possible with a single logging pass. One or two additional passes at different logging speeds can enhance overall accuracy.