bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting Flow Distribution for SAGD Producing Wells By Use of Permanently Installed Fiber Optics
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102159, "Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing Wells Using Permanently Installed Fiber-Optic Monitoring," by P. Krawchuk, SPE, and M.A. Beshry, Total E&P Canada, and G.A. Brown, SPE, and B. Brough, SPE, Schlumberger, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-27 September.
During the startup and early operation of horizontal steam-assisted gravity-drainage (SAGD) wells, it is important to understand the flow distribution of bitumen and water along the horizontal reservoir interval so steam distribution can be adjusted to optimize the startup and early operation of the SAGD pair. The injector/producer interval between SAGD wells was modeled with a thermal reservoir model. The results highlight the need for distributed temperature measurements in SAGD wells to understand the temperature response over time.

Introduction
The Joslyn field is west of the Athabasca River in Alberta, Canada. The McMurray formation is a 50-m-thick high-permeability sand at 60 to 100 m below the surface and contains high-viscosity bitumen. On the western part of the lease, the recovery method is SAGD, which requires injection of steam into an upper horizontal well, creating a steam chamber and reducing the viscosity of the bitumen. The bitumen and condensed steam flow by gravity down into the producer well 5 m below the injector, and from there they are pumped to the surface.
A pilot horizontal injector/producer pair was installed in the Joslyn field in 2004 as Phase I of reservoir development. During completion of the SAGD pair in Phase I, a fiber-optic distributed temperature system (DTS) was installed in the producer well, and data from this were monitored as the well was put on production. In January 2005, a workover was performed. Temperature monitoring along the wellbore with the DTS system continued through 2005.

Joslyn Completion
The upper and lower horizontal wells were completed with slotted liners along the reservoir interval. The upper steam-injection well had injection tubing to the toe of the well, allowing steam to be injected at the heel, toe, or a combination of both. The production well initially was completed with no tailpipe along the reservoir interval.
The downhole instrumentation string consisting of bubble tube and optic fiber in its 1/4-in. control line was deployed inside 1 1/2-in. coiled tubing (CT), which was inserted along the reservoir interval. In addition to the optic fiber, three vertical observation wells intersected the horizontal well trajectory between 1 and 2 m from the SAGD wells. These were at the heel, midway, and at the toe of the horizontal wells. Temperature measurements in these wells were provided by a string of 30 thermocouples that were monitored regularly.
Overview: Well Intervention and Control (January 2007)
Authors: Barnett David 
Published: February 2015

There are two big challenges that have been garnering considerable attention within the industry recently. Exploration and development in increasingly harsh and remote regions are challenging our ability to implement emergency interventions (i.e., blowout control), and advances in drilling technology are producing ever-more-complex wellbores that are challenging conventional well-intervention techniques (e.g., wireline and coiled tubing).
This is a time of unparalleled ventures into some of the most harsh and remote environments on Earth in search of the "big" reservoir. The most challenging operations, at least from a well-control/-intervention perspective, are situated in arctic regions. In some cases, the remote operations also are situated in geopolitical regions that create significant logistical and regulatory challenges.
The magnitude of these remote operations is such that only the largest E&P companies are in a position to finance and operate them. This is fortunate because these companies routinely include extensive emergency planning as a part of their operations. Just because emergency intervention is exceptionally challenging does not dissuade them from recognizing that it is an essential piece of the overall strategy.
Operators are redefining the limits of horizontal and complex well designs, including multilaterals and increasingly complex completion designs. The complexity of these wells continues to drive innovations that allow implementation of conventional well interventions. Moreover, the complexity of these wells is such that routine servicing, maintenance, and planned alterations are a much larger economic consideration than before. Some speculate that the cost of routine intervention on these more complex wellbores/completions will increasingly be one of the major deciding factors as to a given project's economic viability. Others fear that intervention technology simply will not be able to maintain an adequate pace relative to drilling and completion technology.
I am confident that the talented people within our dynamic industry will solve these problems. Issues like these are, after all, what makes our industry one that continues to draw talented people who savor a good challenge.
Well Intervention and Control additional reading available at the SPE eLibrary: www.spe.org
SPE 98077 "First Deepwater Application of Dynamic Annular-Pressure Control Succeeds" by V. Roes, SPE, Shell E&P Co., et al.
SPE 103853 "An Integrated Approach to Risk and Hydraulic Simulations in a Well-Control Planning Perspective" by Øystein Arild, SPE, IRIS, et al.
SPE 98739 "The Snorre-A Incident 28 November 2004: Lessons Learned" by G. Pettersen, SPE, Statoil ASA, et al.
Analysis of Alternative Well-Control Methods for Dual-Density Deepwater Drilling
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98957, "Analysis of Alternative Well-Control Methods for Dual-Density Deepwater Drilling," by M. Stanislawek, SPE, Ensco Offshore Co., and J.R. Smith, SPE, Louisiana State U., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21-23 February.
Dual-gradient drilling methods have been proposed to provide simpler, safer, and more economic well designs for deepwater gas resources. Riser gas lift was investigated as a means to implement a dual-gradient system. A primary concern was whether effective well control was possible in a system containing so many flow paths and fluids with different densities. A study with a transient, multiphase simulator found that well control was feasible by use of methods analogous to those for conventional operations.

Introduction
Deepwater Gulf of Mexico (GOM) resources are especially important for reversing the decline in U.S. production. However, a narrow margin between formation pore and fracture pressure exists in many overpressured basins including the GOM. This limited margin between pore and fracture pressure often becomes narrower with increasing water depth as a result of the reduced overburden pressure and shallow onset of abnormal pressure. As a result, reaching the target depth while retaining a useable borehole size often is difficult, which can limit deepwater resource development. Dual-gradient drilling methods have been proposed as a means to overcome this. A dual-density drilling concept using riser gas lift was studied as a way to implement a dual-gradient system. The new system would provide a simpler, more economic design consisting of nitrogen and mud with an average density equivalent to seawater in the riser annulus and mud in the wellbore. In concept, more standard equipment would be used than in the industry projects focused on use of seafloor pumps. The expected advantages of such a system would be fewer casing strings, larger mud-weight margins, and a larger production-casing size.

Problem Description
The major question addressed in this study is if effective well control is possible for a system with so many different fluid densities and relatively complex flow paths. Three critical phases of a well-control operation were addressed: kick detection, stoppage of formation inflow, and circulation to remove kick fluids. Each of these phases was simulated in sequence by use of a transient, multiphase numerical simulator to determine the best well-control method.
Discussion/Reply of Rock/Fluid Characterization and Their Integration - Implications on Reservoir Management
Authors: Percival Iain , Honarpour M.M. , Nagarajan N.R. , Sampath K. 
Published: February 2015

Discussion
Iain Percival
I would like to offer my congratulations to the authors (M.M. Honarpour, N.R. Nagarajan, and K. Sampath) for their lucid and timely overview of an all-important topic in "Rock/Fluid Characterization and Their Integration—Implications on Reservoir Management" (Distinguished Author Series, September 2006 JPT, page 120). I say "timely" because of the rapidly increasing reliance on improved and enhanced recovery from the already discovered hydrocarbon resources to underpin production forecasts in the face of declining (size) of new discoveries. Without a genuine understanding of the fundamental properties of the fluids and the rocks that contain them, the estimates of proved, probable, and possible reserves and associated production are bound to be suspect to a greater or lesser degree. Yet in spite of this, many geoscientists and petroleum engineers have only a superficial knowledge of and limited interest in the fundamentals of the physics and chemistry dictating the properties that will ultimately determine the efficiency and effectiveness of a given (re)development plan. It is not seen as a "must have" on the curriculum vitae of many an ambitious petroleum engineer.
Earlier this year I retired from the position of Chief Petroleum Engineer at a major oil company publicly committed to technical excellence. Yet a major effort in the final 3 to 4 years was to continually nag the global operating units for minimal funding required to keep alive the laboratory equipment and technical capability necessary to conduct the serious special core analysis and geochemical studies to support reservoir simulations and development plans of an increasingly complicated nature. The response was generally, "Farm out the work to third-party laboratories; it is always cheaper than our lab." I grant that such laboratories fulfill a valuable service to the oil and gas business, but then one important element remains at arm's length from the operator.
This is the development of real knowledge of rocks and fluids gained from the process of designing analytical techniques/experiments, analyzing results, understanding errors, and working closely with applied mathematicians, physicists, and chemists. Any operator with aspirations to be considered a genuine "center of excellence in hydrocarbon recovery" must maintain in-house/company capability in order to truly understand the recovery processes. It is to the credit of ExxonMobil, for whom the authors work, that this remained a core capability (no pun intended) for the company even during the dark days of R&D cost cutting at the turn of the century, when in-house laboratories were regarded as expensive luxuries.
Building Bridges: My Journey Begins…(January 2008)
Authors: Cobb Bill 
Published: February 2015

President's column
The October JPT, which was a marvelous look at SPE's first 50 years, caused me to reflect on how the society has grown since I joined in 1963. Then, we had 14,270 members, two periodicals (JPT and SPE Journal), and six meetings. Today, we have more than 70,000 members, eight periodicals, and in 2007 held more than 100 meetings.
The story of our growth has been particularly impressive over 2001–06—a 38% increase in membership, a 75% growth in revenue, and a 100% increase in meetings. As I write this column, projections for 2007 membership and revenue continue the growth pattern, and by year end we will have held 62 workshops, 32 technical conferences, and 9 Forums around the world.
That is an impressive achievement for any professional association. But what is really important about these numbers?
First, growth in membership means that we are relevant. Yes, our business is booming, but that doesn't automatically translate to joining SPE—people don't join groups unless they get something gratifying in return. We are clearly doing things that oil and gas professionals want and need.
Second, growth in revenue means that our business model is right. We continue to generate revenue-producing initiatives that help us support non-revenue programs (like Distinguished Lecturers) and keep dues, meeting fees, and subscription rates low. And we control costs through the partnership of members’ volunteer efforts and the expertise of our professional staff.
Third, the growth in meetings shows that we meet our mission of technology dissemination in evolving ways. We are developing new conferences on vital subjects and revitalizing old conferences, and in the process generating 1,700 to 2,000 technical papers each year—all archived in the eLibrary. But the biggest growth in the 5-year increase has been from workshops, which evolved to meet members’ needs for short, quick-to-market events focused on providing practical information for immediate use.
But we are more than these statistics. Other noteworthy symbols of SPE's growth over the past 5 years are the eMentoring, young professionals, certification, and Ambassador Lecturer programs; the multisociety LookUpstream and OnePetro, spearheaded by SPE; and a major energy-education outreach that includes our website energy4me. org. During this period we also opened offices in Dubai and Moscow.
In closing, I want to report that the Annual Technical Conference and Exhibition in Anaheim was a great success. All expectations were met or exceeded. I take this opportunity to thank Technical Program Committee Chairperson Ashok K. Belani, Chief Technology Officer at Schlumberger, and Vice Chairperson Stuart Ferguson, Senior Vice President and Chief Technology Officer at Weatherford International; numerous volunteers who worked on the technical and arrangements committees; hundreds of authors; and the SPE staff for a job well done. I would be remiss if I did not also express SPE's deep gratitude to our exhibitors and sponsors.
On the road, building bridges, and encouraging SPE members…
Overview: Mature Field Revitalization (January 2008)
Authors: Ali Syed A. 
Published: February 2015

Overview
Mature fields, often referred to as brownfields, are defined as fields in a state of declining production or reaching the end of their productive lives. Recent studies estimate that hydrocarbon production from mature fields will account for more than one-half of the global energy mix for the next 20 years, and probably much longer. It is imperative that industry address important issues related to development of mature fields and continue to develop new technologies that will facilitate those developments.
Key issues in revitalization of mature fields include integrated reservoir management, identifying bypassed oil, well-intervention management, production stabilization and enhancement (i.e., stimulation), artificial lift, enhanced oil recovery (EOR), water control, gas-well-liquid removal, infill drilling, accessibility of unconventional reserves from existing facilities and wellbores, sustained casing pressure and its mitigation, and facilities upgrades and life extensions.
Revitalization of mature fields embraces multiple objectives, especially maximizing production while minimizing capital expense and reducing the inevitable decline rate while minimizing operating expense. The collective approach to meet these objectives is application of practical and focused engineering and geology tied with the introduction of new technology.
Although application of new technologies may play a key role in the successful revitalization of mature fields, there is general reluctance to apply new technologies because of cost concerns. In fact, many mature fields are being operated with technology put in place when the field was developed originally, and these fields may be performing below their real capacity.
Papers selected for this month's feature are aligned with some of the aforementioned key issues, such as integrated reservoir management, production enhancement, and EOR. In addition, papers dealing with project management, surface facilities, and application of workflow in mature fields are included under "additional reading." I hope that in the coming year there will be papers addressing other key issues in revitalization of mature fluids.
Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org
SPE 102123 "Russian Mature-Fields Redevelopment" by Miljenko Cimic, SPE, TNK-BP Management
SPE 106278 "Application of a Multidisciplinary Workflow in a Mature Oil Field, Mann Field, Myanmar" by J.L. Miskimins, Colorado School of Mines, et al.
SPE 107740 "Surface-Facilities Development for Mature Fields" by Rafael Morales, Petrobras, et al.
Hydraulic Blowout-Control Requirements
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105612, "Hydraulic Blowout- Control Requirements for Big-Bore and HP/HT Developments: Validation With Field Experience," by P. Oudeman, SPE, Shell Intl. E&P, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.
The full-length paper presents equations and guidelines for determining requirements for pump rates, number of wells, and kill fluids required to kill a blowout. A comparison with selected field cases demonstrates that the formulated guidelines match the requirements to actually kill these blowouts. This comparison gives confidence that the guidelines presented are a good starting point for contingency planning. Several blowout scenarios for a giant North Sea gas field are examined to demonstrate application of the guidelines.

Introduction
Because of advances in drilling and production technology, blowouts have become an increasingly rare phenomenon. A report published by the United Nations Environment Program that cites statistics from the US Gulf of Mexico (GOM) and the North Sea shows the probability of shallow-gas blowouts in exploration wells to be approximately one in every 200 wells; for workover operations, one in every 2,500 wells for oil wells and one in every 1,000 wells for gas wells; and for infill wells, less than one in every 10,000 wells drilled. Because of this, blowout prevention is a top priority in drilling and well intervention. A contingency plan must be formulated before spudding development wells to limit the consequences of a blowout by prescribing an adequate emergency response to a possible well-control incident. On the basis of the emergency-response plan, preparations can be made to take action rapidly after an incident is reported. Such preparations would include ensuring the availability of a nearby rig for drilling a relief well, sufficient tubular-goods stock to complete a relief well, and pump capacity to kill the blowing well. With these elements in place, relief efforts can be started quickly, thus reducing the time to regain control of the well. The plan should consider the possible modes of failure and the response to these failures to restore well integrity.
In the majority of cases, "capping" of the well (i.e., replacing the damaged wellhead) is the most efficient method to stop flow from the well. To illustrate, most of the more than 780 wells that were sabotaged and set on fire during the 1991 Gulf War in Kuwait were brought under control within 8 months by capping. With this success, well-control companies demonstrated that even under harsh post-war conditions, capping technology could deal with almost any form of wellhead damage.
Fueling the Future
Authors: Judzis Arnis 
Published: February 2015

Guest editorial
As a member of the SPE Research and Development (R&D) Advisory Committee, I see numerous colleagues and organizations in the oil and gas industry articulating research needs to meet the challenges of increasing reserves, drilling faster, optimizing production, and more. Some focus on longer-term R&D and consider using technologies normally thought to be outside the upstream exploration and production business. For the SPE R&D Advisory Committee, identifying these challenges is important, as one of the committee's objectives is to encourage R&D and to match providers with users. This is not an easy task to accomplish, and it is even more difficult to measure performance. One solution is to provide a forum where both R&D providers and practitioners can speak and join in the discussion on how to "fuel the future."
To this end, SPE will hold its second R&D Conference during 3–4 March 2009 in Lisbon, Portugal, with the theme of "Fueling the Future." The conference follows the first R&D Conference held in San Antonio, Texas in 2007. The first conference brought together attendees from operators, service companies, academia, and a broad spectrum of other organizations to identify and discuss the R&D challenges facing the industry as it seeks to find and produce the next trillion barrels. The second R&D Conference will focus on research areas thought to have significant potential to make material changes in recovery, productivity, and other metrics. One highlighted topic will be "Unlocking the Molecules," which may sound rather chemistry-oriented but is indeed a prominent topic in our industry. I invite you and your colleagues to join us for the second SPE R&D Conference. More details on the conference can be found at www.spe.org/events/rdc.
Another way the R&D Advisory Committee has raised awareness of R&D challenges in our industry is through articles in JPT. Several series addressing R&D have been featured over the past few years. I had the pleasure of coordinating a series related to R&D challenges in each of the SPE disciplines, including Production and Operations; Projects, Facilities, and Construction; and Management and Information. Industry leaders in each discipline compiled an exceptional set of issues and challenges to address to ensure that the next trillion barrels of oil will be produced. Some of those challenges included reserves estimation, one-trip well concepts, multiphase flow, stranded gas, and controlling discharges to minimize environmental impact. Research on some of these topics is well documented in SPE journals and conference proceedings.