bluuebunny/crossref_metadata_2025_split huggingface dataset:
Through-Tubing-Conveyed ESP Replacement - Live Well Intervention
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116822, "Thru- Tubing Conveyed ESP Pump Replacement - Live-Well Intervention," by Walter Dinkins, SPE, and Steve Tetzlaff, Baker Hughes; John C. Patterson, SPE, Hai Hunt, SPE, Peter Nezaticky, SPE, and James Rogers, SPE, ConocoPhillips; and Bret Chambers, BP plc, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.
Through-tubing-conveyed (TTC) electrical-submersible-pump (ESP) technology was developed to address the high cost and long lead times associated with North Slope rig workovers to pull and replace worn or plugged pumps. TTC technology allows ESPs to be changed in live wells without the need to kill the well and work it over. When a TTC pump replacement is performed, the pump is pulled and replaced with slickline or coiled tubing while the tubing, seal section, motor, power cable, and downhole gauges remain in place.

Introduction
The first TTC systems were installed in West Sak development wells on the North Slope of Alaska in 1998. The first systems were TTC electrical submersible progressing-cavity pumps (TTCESPCPs). In 2001, TTC technology was expanded to include centrifugal pumps to achieve higher production rates. The centrifugal TTC pumps were given the designation TTCESP. TTCESP lift systems continue to be the preferred equipment for the West Sak field.
TTC technology is particularly applicable in wells with high solids production in which the pump is the primary failure mode. TTC technology also provides a means to upsize, downsize, or add pump components such as rotary gas separators without rig intervention on live wells.

TTCESPCP and TTCESP Components
From bottom to top, the rig-deployed (tubing-conveyed) components of a TTCESPCP consists of motor centralizer, motor, gear-reduction unit, tandem seal sections, and TTC crossover. A power cable is clamped to the outside of the tubing and is run from the motor to surface, and a separate instrument wire is run for a downhole gauge located in a side-pocket mandrel above the ESP assembly. The TTC crossover (Fig. 1) is what allows pumps to be pulled while the motor, gear-reduction unit, seal section, tubing, instrument wire, and power cable are left downhole. The slickline-deployed TTC components consist of a pump assembly, a packoff assembly, and a slipstop. The pump assembly consists of a pump "eye" (Fig. 2), which couples the pump to the TTC crossover, and pump and discharge assembly, which includes a centralizer and fishing neck.
Proper Evaluation of Shale-Gas Reservoirs Leads to More-Effective Hydraulic-Fracture Stimulation
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 123586, "Proper Evaluation of Shale-Gas Reservoirs Leads to a More Effective Hydraulic-Fracture Stimulation," by Donald Kundert, SPE, and Mike Mullen, SPE, Halliburton, originally prepared for the 2009 SPE Rocky Mountain Petroleum Technology Conference, Denver, 14–16 April. The paper has not been peer reviewed.
Shale-gas formations currently are being explored in the Rocky Mountain region. Whether the well is drilled vertically or horizontally, shale-gas wells need hydraulical fracture stimulation to produce commercial amounts of natural gas. Because each shale play has unique attributes, a systematic approach to well construction, data collection, and prefracture diagnostics is an essential component in the quest for the most effective hydraulic-fracture stimulation and the best chance to achieve commercial gas production.

Introduction
In recent years, natural-gas production from shale has become of increasing interest in the quest for future energy supplies. During the last 40 years, the petroleum industry has progressed from conventional gas reservoirs, to tight gas reservoirs, to ultralow matrix-permeability unconventional shale-gas reservoirs. Each type of reservoir has presented its own unique challenges. The matrix permeability of the reservoir of interest has gone from millidarcies (conventional), to microdarcies (tight gas), to nanodarcies (shale). It then becomes essential for the prospective shale-gas reservoir to have enhanced permeability beyond the matrix permeability, usually in the form of existing natural fractures. Even with enhanced permeability from natural fractures, a well-designed hydraulic-fracturing program is needed to provide successful production results.
A wide variety of mineralogy exists among formations that are classified as shales. Shale is not a rock type and is described by the formation-grain size and fissility of the rock. In the initial phases of a new shale play, considerable attention is required to describe the shale accurately. This can be achieved through laboratory testing of shale-formation samples, extensive openhole electric logging, physical pump-in testing, and other methods.

Shale-Gas-Evaluation and -Stimulation Process
The full-length paper proposes a step-by-step procedure for planning, evaluating, and stimulating potential shale-gas reservoirs in a systematic process. The intent is to gain a thorough understanding of the resource so that commercial production can be obtained economically.

Well Construction

Drilling Fluid.
The drilling fluid used for the well should provide good hole stability and induce minimal damage to the formation. Depending on the shale-formation mineralogy and stress conditions, the hole can be drilled with freshwater mud, potassium chloride (KCl)-based mud, oil-based mud, or even air.
Gorgon Project: Subsurface Evaluation of Carbon Dioxide Disposal Under Barrow Island
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116372, "Gorgon Project: Subsurface Evaluation of Carbon Dioxide Disposal Under Barrow Island," by Matthew Flett, SPE, Graeme Beacher, Jeroen Brantjes, SPE, Aaron Burt, Chris Dauth, SPE, Fiona Koelmeyer, SPE, Robert Lawrence, Seb Leigh, and Jason McKenna, Chevron Australia; Randal Gurton, and William F. Robinson IV, SPE, Chevron Energy Technology Company; and Terrell Tankersley, SPE, TengizChevroil, prepared for the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.
The Gorgon Project is a major liquefied-natural-gas (LNG) development in northwestern Australia. The reservoir fluids of several fields contain carbon dioxide (CO2), which will be extracted from the produced gas before liquefaction into LNG. The Gorgon joint-venture participants have proposed geological disposing of the produced reservoir CO2 at the Barrow Island LNG plant. Key drivers are maximizing per-well injection of CO2 and ensuring containment of CO2 within the reservoir. Effective subsurface and economic evaluation enabled building a phased and flexible development plan for CO2 disposal.

Introduction
The Gorgon and Io/Jansz gas fields will be developed initially as a subsea development with a tieback to Barrow Island, where the raw gas will undergo liquefaction for export. Production of gas also is considered for supply into the Australian domestic market.
The Gorgon gas field has 14% CO2 in the reservoir-fluid composition. Reservoir CO2 must be removed from the raw-gas stream before manufacture of LNG because the liquefaction process occurs at process conditions at which CO2 is solid. A large-volume of high-pressure CO2 will be a byproduct from the necessary gas processing. Rather than emit the CO2 to the atmosphere, it is proposed to dispose of the separated CO2 into an unused saline aquifer, the Dupuy formation, more than 2000 m beneath Barrow Island. Over the life of the project, it is expected that more than 120 million tonnes of CO2 will be injected into the Dupuy formation at rates of approximately 3.8 Mt/a.

Environmental Approvals
The CO2-injection project was documented extensively, reviewed, and subjected to public comment as part of the Gorgon Project environmental-impact-assessment process for a 10-Mt/a LNG development. Following this process, the Western Australia (WA) Environmental Protection Authority found that the environmental risks associated with the CO2-injection project were acceptable and recommended that CO2 injection must proceed as an integral component of the Gorgon Project.
IBP Promotes Brazil's Energy Industry
Authors: JPT staff _ 
Published: February 2015

Society Spotlight
Editor's note: SPE seeks to develop strong relationships with other oil and gas societies worldwide. Many of these societies partner with SPE and other organizations on conferences, workshops, and other programs, at both the local and international levels. This series offers an overview of some of these societies. This first installment in the series spotlights the Instituto Brasileiro de Petróleo, Gás e Biocombustíveis, commonly known as IBP, which has been operating in Brazil for more than 50 years.
The Instituto Brasileiro de Petróleo, Gás e Biocombustíveis (the Brazilian Petroleum, Gas, and Biofuels Institute, often referred to as IBP) is a private, nonprofit organization whose objective is to promote the development of a competitive, sustainable, ethical, and socially responsible petroleum, gas, and biofuels industry. Founded in 1957, IBP has achieved acclaim in Brazilian industry and government for its promotion of technical know-how and also for its important contributions since 1996 in the discussion and implementation of regulatory and sustainability issues related to the development of an open petroleum market in Brazil. IBP lists among its goals representation of the industry, public awareness about the oil and gas industry, promotion of technical development, and protection of the country's environment and safety.
With 220 member companies among the oil and gas, goods and services, and other related industries, IBP has more than 42 committees, subcommittees, and ad-hoc committees. The organization's membership totals 950 and includes executives and other professionals from not only the oil and gas industry but also from scientific and academic institutions, governmental bodies, and related associations.
The committees provide support to IBP-member management and help put together events, courses, standards, and certification. IBP also produces and sells technical publications, and its library has a wide variety of archives for local and online consultation. One of the main activities organized by the institute is the largest oil and gas show in Latin America, the Rio Oil & Gas Expo and Conference, held every 2 years in Rio de Janeiro. IBP organizes about 15 events per year, and conducts an average of 120 courses a year in 85 different subjects along the petroleum production chain.
A Conceptual Change in Perforating Dynamics
Authors: JPT staff _ 
Published: February 2015

A new approach to underbalanced perforating to achieve clean, zero-skin perforations is replacing the prevailing underbalanced concept of perforating job design. One approach is through the use of methodology being employed in the Schlumberger perforating system for clean perforations, Perforating for Ultimate Reservoir Exploitation (PURE). Ongoing research and field application show that the control-manipulation of the pressure transients in wellbore immediately after perforating has a direct impact on perforation cleanup. This technique is being combined with a new deep-penetrating shaped charge, the Schlumberger PowerJet Omega, to create a dynamic underbalance transient, cleaning the perforations and improving well performance.
Methodology Application
Job design consists of an evaluation of available well data, reservoir data, perforating systems, and methods to convey these systems. Applicable in various environments, the design facilitates pressure transient development in the wellbore immediately after perforating (Fig. 1) and can be effective when initial static well conditions are underbalanced, overbalanced, or balanced. The underbalance effect happens quickly (within milliseconds of the guns firing) and lasts for 100 to 500 milliseconds. It is during this time that zero-skin perforations are created.
The job design considers different factors, including flow area into the gun string, charge selection, additional chambers when required, hydrostatic pressure, well fluids, reservoir properties, and completion characteristics. Used in new wells and old wells with existing perforations, the method has proved successful in oil and gas producers, water and gas injectors, depleted wells where pumps are employed, and naturally flowing wells.
In Combination
Combining PURE with PowerJet Omega (Fig. 2) is designed to enable clean perforations and deeper penetration, bypassing formation damage and cleaning the perforation tunnel, eliminating perforation skin and allowing optimal production. In a recent job, this shaped charge shot at 6 spf provided the same productivity as the former leading deep-penetrating charge at 12 spf in less rig time, with less casing damage, less debris, and ultimately, less chance of problems. The deep-penetrating charge can also be used alone to improve productivity in wells where the PURE technique is not an option, such as in very-low-pressure reservoirs or where there must be gas in the wellbore at the time of perforating.
It has been witnessed in the field results that by using a combination design, tight gas wells can be brought on stream without near-wellbore acid-wash treatments. Wells have been perforated successfully in reservoirs with pressures as low as 1,000 psi and permeabilities as low as 0.05 md gas. In addition to wells with significant potential for productivity improvement, candidates include wells requiring expensive operations to establish underbalance, wells that require near-wellbore acid washes after perforating, and those that require high underbalanced pressures for cleanup.
Applying HSE Lessons to Information Management
Authors: Srinivasan Sundaram 
Published: February 2015

Business has entered the age of information management, and the oil and gas industry is no different. Remember the days of cable-tool drilling and even the good old Kelly? Well, the top-drive days are here—or should I say the “hard drive” days?—and the oil and gas industry should capitalize on the benefits of this evolution through judicious and efficient practices. Probably no other industry is as dependent on data and its manipulation in such variety as ours. Some industries have greater information flow per unit of time (e.g., banking), and there are those in which the quality of data is absolutely crucial (e.g., health care), but where else would you find an industry that has such large volumes of data, shifts between aggregated data at very macro levels (e.g., seismic), and correlation with very-high-resolution data (e.g., logging)? And where else would you find such a capital-intensive industry in which the information itself is such a vital asset?
But the industry is still leaving a lot of value on the table by not capitalizing on optimum information management opportunities. I have had the good fortune to have led many lives in this industry over the last 20 years, and that experience has led me to conclude that perhaps the answer lies within the industry itself. There are many lessons to be learned from other areas, which might be initially counterintuitive, and in particular health, safety, and environment (HSE) management.

The HSE Parallel
The 1970s and even the early 1980s saw an industry that did not see a terrible need to invest heavily in safety and the environment. Oh, yes, the talk was there, but not the walk. It was not until the realization came that HSE was, indeed, good business that the momentum for change in this area began to occur. Even then, progress was slow, and the concept of a job in HSE only gradually shifted from being viewed with a negative connotation (a “pasture” job) to that of a job that really made a difference to the business. The industry was still largely in a reactive mode when the effects of poor HSE management started to become evident after some industry accidents.
Then came the most important change in thinking that really caused the step change in HSE performance: HSE became a line-management responsibility. I can still remember the first questions in almost every HSE audit that I have ever done or received: “Who is in charge of HSE around here?” was a question typically asked to the base or facility or enterprise manager. The answer slowly moved over the decade from “My safety manager” to “I am.” And that is precisely what the missing link is today in information management. Information management is not a line-management responsibility today; it is either the responsibility of the chief information officer (CIO) or someone in the information technology department.
Q&A with Linda Cook
Authors: Cook Linda , Donnelly John 
Published: February 2015

Linda Cook, SPE, is Executive Director, Gas and Power, of the Royal Dutch/Shell Group. She is also responsible for Renewables and Hydrogen, Shell Global Solutions, Group Research, East Asia and Australasia. She has been a managing director of Royal Dutch Petroleum Co. since August 2004. She joined Shell after receiving a BS degree in petroleum engineering from the U. of Kansas and has worked for Shell companies in the U.S., The Netherlands, and Canada. Before becoming a group managing director, Cook was President and Chief Executive Officer of Shell Canada Ltd. She also is a Director of the Boeing Co.

Demand for natural gas is surging, and gas may soon replace oil as the hydrocarbon of choice. Will the energy industry be able to keep up with the global demand? What are the challenges?
Indeed, natural gas demand is surging. In fact, gas demand will grow more rapidly than oil, and the latest Shell scenarios suggest that by 2025, natural gas will meet more than 25% of the world’s energy needs.
The industry is doing what it can to enable supply to keep pace with the rising demand. In general, capital budgets are increasing, as is the hiring of new graduates. For natural gas in particular, major new projects are being fast-tracked to production, especially in the area of liquefied natural gas (LNG) in a number of countries including Qatar, Russia, Nigeria, and Australia.
But the challenges are significant. The engineering and construction sectors are stretched to the limit of their capabilities. Delivery times for long-lead-time equipment are lengthening. Logistics are strained in some areas. And there is a shortage of the human resources required in certain disciplines to meet the surge in natural gas demand.
Stepping Up the Fitness Program in Producing Fields
Authors: Langley Diane 
Published: February 2015

The prescription for improving production fitness in mature fields is not always about turning back the clock, as participants in the 2005 OE Oil and Gas Exhibition/Conference will discover. More accurately, remedies involve updating field practices and modernizing both the approach taken to increase production and the systems to effect such a renaissance. Environmental cleanliness receives top billing.
Ten technical presentations and five panel sessions will revolve around the technological advances that have materialized and demonstrated applicability in reviving mature fields. Headliner presentations in the areas of Reservoir Management, Formation Re-Evaluation, Drilling, Smart Production, and Tertiary Recovery were selected by the Conference Program Committee, because they typify new mature-field developments. The technical papers discussed in this article are:
SPE 96742 - Tracing the Path of Carbon Dioxide From a Gas/Condensate Reservoir, Through an Amine Plant, and Back Into a Subsurface Aquifer by Helga Hansen, Reservoir Engineer; Ola Eiken, Geophysicist; and Thor Aasum, Process Engineer, all of Statoil
SPE 96383 - The Hod Geohazard: A Unique Overpressured Interval—Cooperation in Its Recognition, Evaluation, and Risk Mitigation by Gordon Holm, Operations Geologist, Total E&P U.K.; John Owens, Petrophysics Technical Support Team Leader–Aberdeen, Shell U.K.; Geoff Page, Region Petrophysicist–Aberdeen, Baker Atlas/INTEQ, and Angus Ritchie, Petrophysicist, Baker Hughes/INTEQ
SPE 96329 - TTRD Rotary-Steerable System (RSS) Extends the Production Plateau of Brownfields by Kamel El-Kholy, Schlumberger Rotary Steerable Product Champion; Chris Kuyken, Technology Team Leader, and Martijn Kleverlaan, Well Engineer–Technology, Shell U.K.; Dave Saul, Project Leader–Upstream Technology, BP U.K.; Stein Andersen, Network Manager, and Erik Kirkemo, Well Engineer, both of Statoil Norway
SPE 94400 - An Innovative Way of Integrating Reliability of Intelligent-Well Completion Systems With Reservoir Modeling by Arashi Ajayi, Senior Reservoir Engineer, and Mike Konopczynski, both of WellDynamics
SPE 93378 - Performance Analysis of Compositional and Modified Black-Oil Models for a Rich Gas/Condensate Reservoir by Bulent Izgec, Research Assistant, and Maria Barrufet, Dept. of Petroleum Engineering Professor, both of Texas A&M U.
Overview: Offshore Completions (August 2005)
Authors: Cunha J.C. 
Published: February 2015

Last year, in this space, I commented on innovations being implemented on recent offshore completion projects and how offshore completion practices have undergone major changes. Our industry, regarding offshore developments, apparently has an unlimited ability to amaze the world with new advances. Projects that were considered not feasible 5 years ago now are being implemented. Driven by various reasons, including depletion of conventional reserves and increasing oil prices, oil and gas production in deep water became customary in many regions around the world, and it was not a surprise that, during the 2005 Offshore Technology Conference, oil companies started to reveal plans aiming at production of fields under 3000 m of water.
Use of intelligent-well completions is spreading globally, not only for large deepwater projects, but also for small offshore discoveries where its use in subsea satellite wells may bring profitability to an otherwise uneconomical project. Smart systems, with remotely operated valves, allow operators to control various producing zones, shutting down those not responding as expected without expensive well interventions. All of that can be achieved while data for each independent zone are simultaneously acquired and recorded.
Developing fields that present complex geology and deep reservoirs that have high pressures and temperatures still present challenges for the industry, mainly when unconventional-trajectory wells are used. Some of the issues being investigated involve completion of long horizontal sections in unconsolidated reservoirs; flow assurance, mainly for deepwater conditions; and subsea processing, including gas compression and gas/liquid and oil/water separation. Some of these challenges are addressed well in the papers featured in this issue.
Available from the SPE eLibrary: www.spe.org
SPE 90552 - “Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient,” by Chen, Zhongming, SPE, BJ Services, et al.
Available from the OTC Library: www.otcnet.org
OTC 17399 - “Subsea Gas Compression—Challenges and Solutions,” by Fantoft, R., FMC Kongsberg Subsea A/S
OTC 17397 - “Hybrid Riser Towers From an Operator’s Perspective,” by Sworn, A., BP plc