bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: CO2 Applications (July 2008)
Authors: Gomersall Sam
Published: February 2015

Technology Focus

In my view, carbon capture and storage* (CCS) will provide a significant global contribution to help mitigate climate change. However, the magnitude and timing of the contribution CCS can depend on several factors.

Making Action on Climate Change More Urgent.

While the science linking global warming with manmade CO2 emissions is clear, the pace of national and international political agreements for action requires time. As such, the framework for a post-Kyoto agreement is still unclear. While it is likely such an agreement will be reached, the exact nature will drive the level of urgency on climate-change action.

Creating a Commercial Value for Carbon.

The key to action in a commercially driven world is a valid cost on CO2 emissions. While a CO2 tax provides a predictable cost for industry, it does not provide governments with clear emissions-reduction levels. Conversely, CO2 cap-and-trade systems can provide governments with clearer emissions-reduction levels, but they leave industry with uncertain carbon prices. Therefore, industry often "favors" a tax-based approach and governments favor a cap-and-trade approach. The challenge for CCS is to have a sufficiently high price to justify the major capital investment. Experience indicates that the cap-and-trade approach takes many years to introduce and many additional years to adjust caps to create a market price that could justify investment in CCS.

Establishing Early Uptake of CCS.

Long-term investments in CCS are hampered by the lack of long-term political agreements and an appropriate carbon price, as outlined above. Early uptake of CCS, however, is required to prove the technology and ensure that supporting legislation can be put in place. Several projects are in advanced stages of engineering in Europe, the US, and Australia. Making these projects happen is crucial. With such early action, CCS has the potential to mitigate global CO2 emissions by 28% or more by 2050.

*CCS involves capturing flue-gas CO2, initially from large point sources such as power stations, and compressing the CO2 for transport before injecting it into the deep subsurface for indefinite storage. Most of the technologies required are available, but not all have been implemented commercially at the required scale. The situation is different for most currently operating projects, which involve separating CO2 from produced methane and then reinjecting that CO2 for long-term storage.

CO2 Applications additional reading available at the SPE eLibrary: www.spe.org.

SPE 108924 • "Geoengineering and Economic Assessment of a Potential Carbon-Capture-and-Storage Site in Southeast Queensland, Australia" by Y. Cinar, University of New South Wales, et al.

SPE 114028 • "CO2 Storage in Low-Permeability Formations" by Y. Cinar, University of New South Wales, et al.

SPE 108540 • "Simulations for CO2-Injection Projects With Compositional Simulator" by S. Hurter, SPE, Schlumberger Carbon Services, et al.
EU Policy Options for Regulating Carbon Capture and Storage
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 111824, "Policy Options in the EU for Regulating Carbon Capture and Storage," by David J. Williamson and Paul Zakkour, Environmental Resources Management Ltd., originally prepared for the 2008 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Nice, France, 15-17 April. The paper has not been peer reviewed.

Carbon capture and storage (CCS) represents a potentially useful tool to enable the European Union (EU) to manage its emissions of carbon dioxide (CO2) as it transitions from a fossil-fuel to a renewables energy strategy. The full-length paper examines the regulatory requirements for effective operation of CCS by identifying the issues and risks associated with the capture, transport, and storage of CO2, and reviews the regulatory options available and their applicability to the operation, management, and control of CCS.

Introduction

CCS is a widely recognized opportunity to enable EU member states to lower emissions of CO2 by the capture of carbon from large-scale emitters (e.g., power stations) and provide for the long-term, safe storage of this material in underground reservoirs. The EU has set targets for member states to reduce their total volume of CO2 emissions by 20% of 1990 levels by the year 2020. Achieving these targets in the time scales involved by reducing overall energy consumption or by transferring generation capacity to noncarbon-emitting alternatives is not a feasible option, and, therefore, alternatives must be sought.

While the EU will seek to provide a legislative framework that will enable and encourage the development of the infrastructure required to operate CCS effectively across its sphere of influence, there are particular challenges to be faced in drafting policy and regulation related to the unique nature of the CCS process.

Approach

The CCS process must be described and reviewed to outline the various technical tasks that must be carried out to achieve the goals of the process. In this case, there are three main areas that must be reviewed:CO2 capture.CO2 transport.CO2 storage.

Each of these parts of the process represents varying health, safety, and environmental (HSE) risk profiles. Each of these areas has regulatory analogs in which similar or related processes are subject to current EU and member-state regulation.
Ghana's Jubilee Celebration Nears
Authors: Sheehan John
Published: February 2015

After more than 100 years of oil exploration and the drilling of 90 wells, the Republic of Ghana is now on the verge of truly benefiting from its offshore oil and gas riches. The partners in the country's Jubilee field—one of the most exciting developments offshore west Africa in recent times—are on track to produce first oil in the second half of 2010.

The speed of progress on the USD 3 billion development has been exceptional since the initial discovery was made with the Mahogany-1 well in 2007. The field, which is being developed with a conventional subsea system with 17 wells initially, tied back to a turret-moored floating production, storage, and offloading (FPSO) vessel, is located 60 km offshore in 4,101 ft (1250 m) of water and straddles two deepwater blocks—Tano and West Cape Three Points offshore Ghana.

Partner Tullow said this month that conversion of the Ohdoh VLCC tanker into an FPSO to tap the field and the fabrication of subsea equipment are well advanced. Five development wells have been drilled on the field, with a further seven wells planned for the remainder of this year.

The need for speed means that everything for the development is being kept as simple as possible, said Dave Hanley, Tullow's subsurface manager for Ghana. "Due to the compressed time frame for the development of phase 1 on Jubilee we are using designs for everything that are off the shelf. We are not really pushing the boat out in terms of technology. I do not think we could claim that we are on the cutting edge.

"We have a very tight time frame for construction and installation, which really prevents us from doing that. We are doing a tanker conversion for the FPSO to a design that is off the shelf and all the other equipment is well proven and readily available for this sort of water depth. Future phases may of course use more technology, based on learning from phase 1, but everything we are doing is well proven and has been done many times before."
Experimental Design Reduces Risks of a Siberian Development Having Subsurface and Financial Uncertainties
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115575, "Experimental Design Reduces Risks of a Siberian Development With Subsurface and Financial Uncertainties," by David E. Tipping, SPE, TNK-BP; Franz X. Deimbacher, SPE, and Dmitry Kovyazin, Schlumberger; Alexey Medvedev, SPE, Landmark; and Randy Valencia, TNK-BP, prepared for the 2006 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed.

Experimental-design methodologies were used to evaluate development options in a Siberian field having major uncertainties in geological, reservoir, and financial parameters. The approach demonstrated that an inverted seven-spot injection pattern would yield 11% more oil than a conventional linedrive method. For decision making, the analysis predicted that the expected net present value (NPV) of the seven-spot pattern would be 46% more than that of the linedrive pattern.

Introduction

The primary reservoirs in this Russian field consist of stacked fluvial, delta-distributary-channel, and mouth-bar sands. Exploration tests confirmed oil rates exceeding 120 tonnes/d. Recognizing this risk to project success, an experimental-design technique was developed for quantifying the uncertainties in oil-rate predictions.

The experimental-design techniques, integrated with advanced computer technology, reduced evaluation times from months to weeks. More importantly, they provided unbiased probabilities of production profiles and NPV so that downside risks can be quantified.

Development Context

The proposed development area encompasses two oil-bearing zones. The shallow zone consists of sand-stones with thicknesses varying from 0.5 to 3 m with numerous interbedded siltstones. The deep zone is in an underlying incised-valley-fill complex surrounded by impermeable siltstone.

Although the 2D seismic could delineate the boundaries of the incised valley, its resolution did not permit differentiating the sand bodies from the surrounding siltstone within the valley fill. A subsequent sedimentological review of core data revealed promising reservoir sands. Well tests of the valley-fill sand bodies yielded promising initial oil rates that exceeded 120 tonnes/d. However, major uncertainties existed.

Although the well tests confirmed the presence of an oil/water contact (OWC), given the thin nature of the sand bodies, the OWC response on the wireline logs was suppressed by surrounding siltstones. As a result, an OWC uncertainty of 4 m existed with potential adverse effect on the estimated oil initially in place.

Seismic data also revealed anomalies, possibly indicating faults acting as flow barriers. The seismic did not have sufficient resolution within the incised valley to differentiate sand bodies from the surrounding siltstones.
Results of the Brugge Benchmark Study for Flooding Optimization and History Matching
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119094," Results of the Brugge Benchmark Study for Flooding Optimization and History Matching," by E. Peters, TNO; R.J. Arts, TNO and Delft University of Technology; and G.K. Brouwer and C.R. Geel, SPE, TNO, prepared for the 2009 SPE Reservoir Simulation Symposium, The Woodlands, Texas, 2-4 February. The paper has not been peer reviewed.

In preparation for the SPE Closed-Loop Reservoir Management Workshop held in Bruges, Belgium, in June 2008, a unique benchmark project to test the use of flooding-optimization and history-matching methods was organized in the form of an interactive competition during the months preceding the workshop. In total, nine groups participated and presented their results during the workshop.

Introduction

Before the Bruges workshop, participants were allowed to conduct a closed-loop waterflood-optimization case study. TNO prepared a high-resolution reservoir model, dubbed the Brugge field, which served as the truth, and a data set was made available in January 2008. The data set consisted of the first 10 years of the production history of the field (including measurement errors), inverted time-lapse seismic data in terms of (uncertain) pressures and saturations, 104 scaled-up realizations of a 3D geological model, all the input for creating a reservoir model, and economic parameters (price and discount rate) for oil and water to calculate net present value (NPV).

The goal for the participants was to optimize the field NPV for the last 20 years. To do this, they first had to create a history-matched model or set of models from the data provided. Next, they had to optimize the waterflood strategy for the 30 wells for the next 10 years. All 10 injectors and 20 producers could be operated with three separately operable completions. The optimization strategy for years 11 through 20 then could be sent to TNO for testing on the Brugge field. The response could be used to improve the history match and the optimization for the last 10 years. The control strategy for the last 10 years could again be sent to TNO for testing on the Brugge field.

The full-length paper presents a summary of the results presented at Session 2 of the workshop. Because several participants continued working on the problem after the workshop, a summary of those results also is provided in the paper. To make the exercise more representative of a true closed-loop optimization, the exercise was repeated with one participant with a higher frequency of feedback. These results also are presented in the paper.
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.
Higher Levels of Fluid Typing and Speed Deliver Robust Answers from Nuclear Magnetic Resonance Technology
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
Overview: Seismic Applications (August 2004)
Authors: Gibbons Kate
Published: February 2015

Overview - No abstract available.
Alpine Field Simultaneous Angle-Dependent Inversion
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16727, "Alpine Field Simultaneous Angle-Dependent Inversion," by Abhaya R. Badachhape, SPE, Daniel R. Therry, Herbert W. Swan, and Steve R. Moothart, ConocoPhillips, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Integrated Risk Analysis for Scale Management in Deepwater Developments
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87459, "Integrated Risk Analysis for Scale Management in Deepwater Developments," by E.J. Mackay, SPE, Heriot-Watt U.; M.M. Jordan, SPE, and N.D. Feasey, SPE, Nalco; D. Shah, SPE, and P. Kumar, SPE, ChevronTexaco Overseas Petroleum Co.; and S.A. Ali, SPE, ChevronTexaco Energy Technology Co., prepared for the 2004 SPE International Symposium on Oilfield Scale, Aberdeen, 26-27 May.
Analysis of Tensile-Strength Test Methods for Oilfield Cement
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84565, "Analysis of Tensile-Strength Test Methodologies for Evaluating Oil- and Gas-Well Cement Systems," by Thomas Heinold, SPE, Robert L. Dillenbeck, SPE, Windal S. Bray, and Murray J. Rogers, SPE, BJ Services Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
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
State of the Art of Ultradeepwater Production Technologies
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17615, "State of the Art of Ultra Deepwater Production Technologies," by J.M. Bell, SPE, Chevron; Y.D. Chin, SPE, Aker Kv ærner; and S. Hanrahan, SPE, Chevron, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.

The full-length paper summarizes some results of several recent joint industry projects (JIPs) on ultradeepwater field-development technologies. A review of emerging and existing technologies for deepwater development is presented, which would be of particular interest to technology-development personnel and asset-team personnel who are in the appraisal or concept-selection stages of a project.

Introduction

As offshore production moves from deep water (3,000 to 6,000 ft) to ultradeep water (6,000 to 10,000 ft) and moves farther away from infrastructures, many existing technologies reach their limits or must be improved. Several successful JIPs have demonstrated that in the high-expense and -risk environment of ultradeep water, structured collaboration aligned with business drivers is a successful formula for delivering the technologies required to meet the ultradeepwater challenge. The demand for critical technology and engineering systems to enable production from ultradeep water has triggered breakthroughs in many conventional technologies. The full-length paper focuses on sub-sea, flow-assurance, floating-production-system, and riser technology.
Guest Editorial: Sometimes Bigger Is Better: Big Oil as Radical Innovators in E&P
Authors: Perrons Robert K.
Published: February 2015

The 20th century economist Joseph Schumpeter famously aspired to be the greatest economist in the world, the greatest horseman in Austria, and the greatest lover in Vienna. He would therefore be quite pleased to discover that the first and most public of these objectives was at least partially achieved: One of his more famous economic predictions is apparently true. In the latter part of his career, Schumpeter postulated that large firms have many advantages over smaller ones in the development of radical new technologies. Whereas small and medium-sized enterprises frequently have to pay an undue amount of attention to their short-term balance sheets, large companies with deep pockets do not have to be nearly as sensitive to immediate profit constraints. Schumpeter accordingly reasoned that larger firms have both the resources and the time to pursue new ideas, and they are better positioned to explore the implications for their business of technological discontinuities before deciding whether to bring these technologies into the folds of the company's core activities and operations.

This is not to say that smaller firms will not have an important role to play in the development of new technologies within the E&P industry. Product and process life cycles are steadily growing shorter, and it is becoming increasingly difficult for any one company to support an aggressive R&D agenda single-handedly. Robert Z. Gussin, former Vice President for Science and Technology at Johnson & Johnson, once drove this point home by musing that technology in his industry "has become so sophisticated, broad, and expensive that even the largest companies cannot afford to do it all themselves." Responding to these same forces in the E&P industry, many large integrated majors have turned to their supply networks as a source of innovation.

Hit and Miss

To be sure, there is evidence from other industries that it is quite healthy for companies to rely to some degree on collaborative suppliers for new ideas. History has shown on many occasions that even the most focused R&D programs fail to guarantee results consistently. Many of the significant and commercially celebrated innovations that have emerged over the years have not been the result of tightly managed research agendas, but instead were brought about by a convoluted process of serendipity and unique circumstances. The hit-and-miss nature of R&D is such that managing science has been compared to herding cats: It is usually not done well, but one is surprised to find it done at all. Realizing that it is almost impossible to forecast where their next "new big thing" will come from, many companies across a wide variety of sectors are starting to broaden the radius of ideas that they might tap into by turning to their supplier base.
Subsea Smart Multilateral Wells Increase Reserves at Gullfaks South Statfjord
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95721, "Subsea Smart Multilateral Wells Increase Reserves at Gullfaks South Statfjord," by V. Haugen, SPE, A.-K. Fagerbakke, SPE, B. Samsonsen, and P.K. Krogh, SPE, Statoil ASA, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.

Production from the Statfjord formation in Gullfaks South (GS) field was limited by low connectivity, reservoir heterogeneity, and gas breakthrough. Surface-operated downhole inflow control and multilateral wells were identified as solutions to these limitations. Implementing a downhole-instrumentation and -control system (DIACS) and multilateral technology (MLT) in three horizontal subsea wells led to a two-fold increase in the reserves estimate to 5.4×106 m3 oil in the reservoir management plan for 2005.

Introduction

The GS field, operated by Statoil ASA, is in the Norwegian sector of the North Sea, approximately 150 km northwest of Bergen. The field is a subsea satellite tied back to the Gullfaks A and C plat-forms and consists of two independently developed reservoir units, the Brent and Statfjord formations. Production from the Statfjord formation, which began in 1999, is routed to Gullfaks A.

Fig. 1 shows the structurally complex Statfjord formation with many fault segments and indications of locally varying fluid contacts. The formation is approximately 300 m thick. Production experience, however, has shown less connectivity than expected. The initial reservoir pressure at 3300 m true vertical depth was 476 bar, and the reservoir temperature was 128°C.

In 1995, oil recovery from the GS Statfjord field was estimated to be approximately 40%. In 2001, after drilling the first three wells, further development of the field was postponed because of poor production performance, and the expected recovery factor was reduced considerably. In 2003, a project was established to improve the reservoir knowledge, identify cost-effective well solutions, and implement available technology suitable for further development of the reservoir. The project, with considerable support from the field partners, identified the need for more drainage points and robust solutions, particularly the use of MLT to account for geological complexity and reservoir uncertainty.

Multilateral and Smart Wells

Increasing exposure to the reservoir by increasing the number of drainage points is essential to maximize oil production and enable access to reserves that otherwise might be left behind. This solution minimizes the localized drawdown to help maintain an even pressure depletion in the reservoir.