bluuebunny/crossref_metadata_2025 huggingface dataset:
Overcoming Shallow-Gas Drilling Difficulties
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87179, "Overcoming Shallow-Gas Drilling Difficulties in the Gulf of Thailand," by Pornpoch Tiraputra, SPE, Pattanapong Thiravutpinyo, SPE, and Sunchai Pongorapin, PTT E&P; Bernard Fraboulet, SPE, Total E&P; and Mohammed Dooply, SPE, Walter Friedl, SPE, and Youssef Elmarsafawi, Schlumberger, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.

Shallow gas-bearing formations in the Gulf of Thailand present numerous drilling and cementing challenges. In the first three wells drilled on platform WP11 in Bongkot field, initial cementing of surface casing did not achieve effective zonal isolation of the shallow-gas zone. Use of conventional lightweight gastight cement slurries, two-stage cementing operations with conventional gas-migration-control slurries, and injection of sodium silicate to damage the shallow-gas sand failed to control the gas migration through permeable upper sand layers. The full-length paper presents case histories describing the solutions-oriented approach to this problem that resulted in changes to the drilling program and cementing operations.

Introduction

Bongkot field is in the Gulf of Thailand approximately 600 km south of Bangkok and 180 km off the coast of Songkhla province. Following discovery of the field in 1973, it was delineated by drilling 23 wells. In 1990, the concession development rights were transferred to a joint venture group comprising PTT E&P plc (PTTEP), Total E&P Thailand (TEPT), British Gas Thailand Ltd., and Statoil Thailand Ltd. The field was operated by TEPT from the beginning until mid-1998, when the operatorship was transferred to PTTEP.

In 1995, the shallow-gas anomaly was discovered in the Tonsak south area of Bongkot field. Drilling through the shallow gas was proved technically feasible and safe after a pilot hole, Tonsak SG, was drilled in 1996. The shallow-gas-anomaly characteristics were verified with logging-while-drilling information. This well was abandoned safely.

In 1998, the decision was made to set a platform over the shallow-gas anomaly. The motivation was a projected cost saving of approximately U.S. $20 million, in part because the gas could be drained with a single wellhead platform instead of three small wellhead plat-forms outside the shallow-gas anomaly.
Stand Tall and Speak Up: No "Free Lunches" in Energy
Authors: Sprunt Eve S.
Published: February 2015

A few months ago, I read an online report that said "Automakers are all investing heavily in what they think will be the next big breakthrough in cars, emission-free fuel cells. These fuel cells, which run on hydrogen and produce nothing but water vapor, are expected to power a new generation of cars that will free the world from reliance on oil."

Many of us have read similar news clips or seen equivalent television coverage. If only it were so easy. Remember, there's no such thing as a free lunch. Everything has some kind of environmental impact. If a sunbeam is deflected from its previous path or if water is diverted, something changes. The issue is whether, in the grand scope of things, society finds the cost/benefit ratio of the change to be acceptable.

To compare different methods of powering transportation, the correct approach is to look at the full life cycle and to compare all the options on a common basis. Evaluation of everything involved in all the components that lead to the end product is a huge undertaking, so usually the comparison focuses on specific aspects—for example, the fuel supply chain. The differences in the emissions associated with manufacturing different components of the vehicle—for example, fuel cells or batteries as opposed to an internal combustion engine—are not included.

In the example quoted, the hydrogen fuel-cell vehicle is like an electric vehicle. It is not a zero-emission vehicle when evaluated on a full life-cycle basis, but rather a remote-emission vehicle. Just as the emissions associated with an electric vehicle depend on the source of the electricity, the emissions involved in use of hydrogen depend upon how the hydrogen is generated.

On earth, hydrogen is almost always found in combination with other elements, as for example in water. Therefore, it is more appropriate to view hydrogen not as an energy source, like hydrocarbons, but rather as an energy carrier, like electrons. Decarbonization of the energy supply may lead us not to a hydrogen economy, but to an electron economy.

With current technology, the most cost-effective method of producing hydrogen is from natural gas and water at high temperatures in catalytic reactors using a process called steam reforming. The hydrogen is subsequently further purified to minimize damage to fuel-cell membranes from contaminants. Worldwide, extensive research is underway to produce hydrogen from renewable sources on a cost-competitive basis, but additional technical breakthroughs are needed to achieve that goal.
Management: Plugging the Knowledge Gap
Authors: Davidson John
Published: February 2015

There once was an engineer who had an exceptional gift for understanding and fixing any kind of machine. After a long career with the same company, he happily retired. Several years later, the company contacted him regarding a problem with a piece of production equipment that seemed to be impossible to fix. They had tried everything, but nobody could return the equipment to full capacity. After much persuasion, the engineer flew out to the platform and spent a day studying the equipment. At the end of the day, he marked a small "x" on a component and stated that replacing this component would solve the problem. The component was replaced and full production was restored.

Shortly after, a bill for U.K. £50,000 was received. Very unhappy with this, the company asked for an itemization of the bill. The engineer responded briefly:

One chalk mark: £1.

Knowing where to put it: £49,999.1

While this story is fiction, the problems described are real. Organizations that do not make a concerted effort to plug the knowledge gap will find themselves relearning, or renting, old knowledge at a high cost. It is no secret that the demographic profile of the oil industry is heavily weighted toward the baby-boom generation. What is not clear is the impact that this will have on the industry in years to come. Will the demographic time bomb go off and leave the industry in crisis or is this an overly pessimistic viewpoint? There is a real issue here that needs to be tackled, and the tools and techniques for doing so are well established and easily implemented. The key to avoiding critical knowledge loss, however, is a strategic framework that weaves together the ability to learn with the ability to retain key staff and to make a knowledge-sharing culture a reality.

Framework for Knowledge Retention

For a business to avoid knowledge loss, a strategy needs to be in place with the following key objectives for the organization:

The organization must be able and willing to learn, in addition to the individual.Knowledge must be recoverable from staff and contractors.It must be easy to transfer knowledge when required.Human resources (HR) processes and practices must help knowledge retention.Information technology (IT) applications must support retention practices.

Organizational Learning

Kim2 defines individual learning as "increasing one's capacity to take effective action." If we assume that this definition can also apply to organizations, then organizational learning is about increasing the organization's capacity to take effective action—including maintaining aging platforms. The question then is, When we look at organizational learning, who is doing the learning?
Overview: Mature Field Revitalization (January 2006)
Authors: Lagerlef David
Published: February 2015

The challenge. It has always been before us, but it is now asked of us by family members, neighbors, and total strangers once they find out we work in the petroleum industry: "Can the oil and gas industry meet world demand over the next few years?" I think the answer can be found in the papers selected for this feature and in other quality technical presentations on this subject. Projects around the globe are discussed, which have been implemented to maximize the use of existing infrastructure and improve recovery by revitalizing mature fields.

Paper presentations and displays on the exhibit floor at the SPE 2005 Annual Technical Conference and Exhibition in early October also served as a solid indicator that the industry is poised to meet the challenge successfully. Individual companies continually strive toward ensuring that the energy supply meets demand; replacing reserves is a high-profile key performance indicator. SPE plays a vital role in aiding the effort. The technology, techniques, and talent shared in the various SPE venues are sometimes applied directly in another field, but more often, improvements in these three areas are made with subsequent applications. Innovation flourishes as applications that worked in one mature asset are modified to fit the specific requirements for another mature asset. The specifics cannot always be applied directly, but the process of studying about production improvements, having a service company representative explain details of a tool with the help of a cut-away model, or witnessing the enthusiasm during a well-prepared paper presentation can lead to the derivation of new approaches to revitalizing mature fields. So, when you have finished reading the summaries of the selections, and perhaps downloaded the full-length papers as well as some of the other technical references, I hope you arrive at the same answer to the question that I did. We will meet the challenge.

Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org

SPE 93697 "Integration Tools To Streamline Reservoir Management and Field-Development Workflows for Mature Fields in South Oman," by M.A. Naguib, SPE, Petroleum Development Oman, et al. [See JPT (October 2005) 56.]

SPE 94360 "Significant Production Enhancement in Uzen Field, Kazakhstan, Through Surface and Subsurface Optimization," by S.J. Sparke, SPE, Gaffney, Cline & Assocs., et al.
Overview: EOR/IOR (January 2006)
Authors: Pitts Malcolm J.
Published: February 2015

Papers in this feature discuss the incremental oil production from three field projects that use three different enhancement technologies: biotechnology, or microbial enhanced oil recovery (MEOR); miscible gas; and mobility-control polymer.

Petro-Tech Peruana S.A. reported an impressive improvement after inoculating two pair of production wells in different offshore fields. Both fields contained a paraffinic crude oil that, when treated by conventional wellbore-cleanup technologies, simply maintained oil-production rates. Biotreating the producers resulted in improved oil rates, and subsequent radial inoculation further enhanced oil rates, approximately doubling the pre-MEOR rates.

A peripheral, downdip, high-pressure gas-injection project in the RKF field in Algeria also is impressive. The paper discusses the discovery, development, and operation of a miscible-gas-cycling project in a fluvial complex of carboniferous reservoirs of low-permeability, high-clay-content formation containing asphaltic crude oil and salt-saturated water. During 8 of the 9 years of operation, production was maintained at approximately 20,000 B/D. A tracer study to quantify well conductivity and help identify preferential flow was implemented early in the gas-injection phase. Additional laboratory studies to support continued numerical simulation were performed, with the objective of continued studies being to define and select options that would improve oil recovery as gas injection continues.

Three mobility-control pilot projects in Brazil complete the trio of papers. Four polymer pilot projects were started in 1997, 1999, and 2001 in the Carmopolis, Buracica, and Canto do Amaro fields, respectively. Mobility ratios ranging from 2 to 12 for water displacing crude oil provide a motive to implement the different mobility-control-polymer pilot floods. Injectivity changes and differences in interwell tracer studies are reported. Oil production increased, and declining water/oil ratios are discussed for each pilot and for well patterns within each pilot. These projects emphasize the importance of an ongoing evaluation and study of an EOR flood to maintain oil production and maximize oil recovery. Continual monitoring of project performance and reaction to what is happening in the field, making adjustments as necessary, and learning from performance are essential for successful expansion as well as for continued operation.

EOR/IOR additional reading available at the SPE eLibrary: www.spe.org

SPE 94139 "Application of Tracer Technology for Optimizing RKF Miscible-Gas-Injection Recovery—Field Case," by H. Cubillos, SPE, Cepsa, et al.

SPE 94808 "Twenty Years of Steam Injection in Heavy-Oil Fields" by J.C. de Souza, Petrobras, et al.

SPE 93100 "Sorption of Surfactant Used in CO2 Flooding Onto Five Minerals and Three Porous Media," by R.B. Grigg, SPE, New Mexico Recovery Research Center, et al.

SPE 93241 "Gasflood Flow-Pattern Evaluation: Mesozoic Chiapas-Tabasco Basin Field Revisited," by M. Mercado, Pemex, et al.
Overview: Well Intervention and Control (January 2006)
Authors: Barnett David
Published: February 2015

This year, we have witnessed the continuation of a general upward trend in the worldwide rig count that started in the second quarter of 2002. The Baker Hughes U.S. rig count published 11 November 2005 stood at 1,479. In the U.S. alone, this increase translates into at least 12,500 people being hired to work on the approximately 750 rigs put to work in the last 3 years. Almost 4,000 of those people were hired to man the 228 rigs placed in operation during the last year alone. One must wonder what effect this growth has on the number of well-control situations encountered.

The first line of defense against well-control events is a knowledgeable rig crew—not just the tool pusher and driller, but each person on the crew. Inexperience shows up in different forms at various levels. There have been many cases in which routine kicks were allowed to escalate into critical situations because someone did not report what should have been an obvious sign of the well flowing. An example: an inexperienced floor hand sees flow over the shale shaker with the pumps off but is not aware of the significance.

The upper-level positions of the rig crew and the drilling supervisor are expected to have the knowledge and experience to deal with influxes effectively when they occur. Inexperience at this level often results in kicks being taken that should have been avoided and routine kicks being allowed to escalate because of improper handling. Inadequate circulation before pulling out of the hole and improper implementation of kick-circulation procedures are often-cited examples that result in these situations.

Keeping experienced personnel on the rigsite during a sustained upswing, such as the one we have experienced over the last few years, is a monumental task. Fortunately, there seems to be an increased awareness of the importance of this experience compared with the last "boom" cycle. This awareness can be seen in the additional focus on rig-crew training and other structured programs designed to minimize well-control incidents. Consequently, the number of serious well-control events is, at least for now, well below the proportionate increase in the rig fleet. Operators and drilling contractors that are driving these efforts should be commended.

Well Intervention and Control additional reading available at the SPE eLibrary: www.spe.org

SPE 92626 "Modeling Ultradeepwater Blowouts and Dynamic Kills and the Resulting Blowout-Control Best-Practices Recommendations," by Samuel F. Noynaert, SPE, BP, et al.

SPE 93956 "High-Pressure/High-Temperature Coiled-Tubing Intervention Operations in the North Sea Within the Past 2 Years," by A. Turner, SPE, Halliburton, et al.

SPE 92594 "Development of a Screening System To Identify Deepwater Wells at Risk for Annular-Pressure Buildup," by U.B. Sathuvalli, SPE, Blade Energy Partners, et al.
Guest Editorial: The Winds of Change: Resource Nationalism Shifts the Balance of Power to National Oil Companies
Authors: Stark Pete
Published: February 2015

The oil and gas industry is in the midst of a critical transition driven by a series of factors, including the Asian energy-demand crunch of 2004, the 2005 hurricanes in the Gulf of Mexico, and recent low discovery rates. These factors, coupled with political uncertainties, threats to petroleum infrastructure, production disruption resulting from civil unrest, and limited access by international oil companies (IOCs) to giant resources in the Middle East and the former Soviet Union, have ushered in what has been referred to as the "Age of Energy Supply Anxiety."

In addition, higher oil prices and mounting political pressures, combined with a bit of anti-Americanism and rapidly growing demand for energy in the Asian market (particularly in China), are stimulating producing countries to increase control of their oil and gas resources and move toward resource nationalism. The resulting global scramble by both IOCs and national oil companies (NOCs) to secure hydrocarbon resources has altered the industry's competitive landscape significantly, which in turn has caused a major shift in the balance of power favoring the NOCs, mandating new perspectives on negotiations and partnerships.

No longer are NOCs managing only state-owned hydrocarbon resources to their nation's long-term benefit, they are also expanding internationally to secure the additional energy resources necessary for sustainable economic growth for their countries. In other words, NOCs are becoming international exploration companies, competing with IOCs at home and in the world marketplace.

The Effect of a Paradigm Shift

Considering that governments and NOCs control more than 80% of the world's remaining oil reserves, are expanding and upgrading refineries and infrastructure, and are developing gas resources, the effect is considerable. But that has not always been the case. In the past, when oil prices were low, investments in exploration dropped, and governments were eager to create incentives to attract investments—including reducing tax rates and state participation, or providing royalty relief.

All that changed in 2003 when oil prices began to soar. Many countries—primarily those with immense resources such as Russia, Nigeria, Libya, Angola, and Venezuela—reversed gears and raised taxes and/or increased state participation in hydrocarbon licenses. In Latin America, where the public's perception was that oil and gas companies made excessive profits at their expense, energy policies have become highly regulated.

Increases in state-take range from 2% in Angola to 24% in Nigeria and 43% in Argentina. In Algeria—formerly known for being one of the most welcoming countries for foreign energy investors—a new government decree was enacted at the beginning of September 2006. Arguing that this decree safeguards the role of Sonatrach, Algeria's NOC, it specifies that Sonatrach will be given a 51% stake in all upstream development projects as well as midstream pipeline and refinery projects.
Overview: EOR/IOR (January 2007)
Authors: Pitts Malcolm J.
Published: February 2015

Reserves are a key factor for any oil company. This year's EOR issue highlights field projects that increased reserves by use of enhanced oil recovery. Economic incremental-oil production from field projects that used three different technologies [CO2 huff ‘n’ puff, mobility-control polymer, and steam-assisted gravity-drainage (SAGD)] is discussed.

Daqing Oilfield Co. Ltd., People's Republic of China, has several papers discussing its commercial polymer flood. An SPE Advanced Technology Workshop on chemical flooding in Daqing concluded with Daqing stating that 25% of its production results from polymer injection—250,000 B/D. One paper stated, "Unquestionably, the application is successful, and the accumulated output has exceeded 70 million tonnes" (more than 500 million bbl of oil). Of interest is a closely spaced pilot to expand the polymer flood to marginal reservoirs. The strategy was injection of different-molecular-weight polymers in a staged manner, from low to high molecular weight, into zones with permeabilities appropriate for the injected polymer. Reported oil rates increased 1.8 times in confined production wells. Ultimate oil recovery beyond waterflood was 11.7%, of which 5.2% resulted from polymer flooding.

Sixteen CO2 huff ‘n’ puff projects were conducted on different wells in the Forest Reserve oil field in Trinidad and Tobago over the last 20 years. CO2 from an ammonia plant was injected into either inactive or poor oil producers. Average slug size was 1 MMscf of CO2 per foot of sand, with a 3- to 5-day soak period. Multiple huff ‘n’ puff cycles were effective in more than half the wells, with the second to fourth cycle being the most productive for the majority of wells. Oil-rate improvements from nothing to up to 60 times pre-CO2-injection values were observed.

During the startup and early operation of horizontal SAGD wells, it is important to understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood, the distribution of steam, injected either at the heel or toe of the steam injector, can be adjusted to optimize the startup and early operation of the SAGD pair. Total E&P Canada permanently installed optical fiber along its first Joslyn SAGD production well to monitor the temperature profile continuously during startup and production.

Thus, good engineering, technology, and a willingness to try different approaches can increase reserves in very large as well as smaller applications.

EOR/IOR additional reading available at the SPE eLibrary: www.spe.org

SPE 101202 "Study of High-Concentration Polymer Flooding To Further Enhance Oil Recovery" by Yang Fulin, Daqing Oilfield Co. Ltd., et al.

SPE 100117 "Application of Smart-Well Technology to the SACROC CO2 EOR Project: A Case Study" by J. Brnak, Kinder Morgan Production Co. LP, et al.

SPE 100346 "Suplacu de Barcau Field—A Case History of a Successful In-Situ Combustion Exploitation" by A. Panait-Patica, Petrom S.A., et al.
Screening Criteria for Carbon Dioxide Huff 'n' Puff Operations
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100044, "Screening Criteria for Carbon Dioxide Huff ‘n’ Puff Operations," by L. Mohammed- Singh, SPE, Petrotrin, and A.K. Singhal, SPE, and S. Sim, SPE, Alberta Research Council, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.

The full-length paper reviews design and performance data on 16 CO2 huff ‘n’ puff projects in the Forest Reserve oil field of Trinidad and Tobago from the past 20 years. Huff ‘n’ puff operations essentially are near-wellbore stimulation techniques that can lead to increased oil recovery by removal of productivity damage, reduced oil viscosity, increased dissolved-gas content, oil swelling, and vaporization of lighter oil components.

Introduction

The first huff ‘n’ puff experimental project in Trinidad and Tobago was conducted in 1984 in the Forest Reserve oil field. For the Forest Reserve reservoirs with medium-to-heavy crude oils, viscosity reduction and oil swelling aided by gravity drainage and water encroachment are believed to be the most significant mechanisms contributing to increases in oil recovery.

The literature contains many screening criteria for enhanced-oil-recovery processes. However, for CO2 huff ‘n’ puff operations, these are generally included in those for immiscible gas-flooding applications. The full-length paper proposes screening criteria for huff ‘n’ puff operations on the basis of results from the Forest Reserve oil field and other published field tests.

Reservoir Description

The Forest Reserve oil field contains multiple, stacked, complex deltaic reservoirs. The rock and fluid properties of the four reservoirs (targets for huff ‘n’ puff operations) are listed in Table 1 in the full-length paper. Oil gravity ranges from 14 to 25°API, with in-situ viscosities of 12 to 3,000 cp. Reservoirs are solution-gas drive with contributions from water influx.

Operations and Production Response

CO2 was compressed to 1,000 psi and injected until desired slug volumes were achieved. Wells were shut in, left to soak for 3 to 5 days, and back flowed. Wells were subjected to several cycles (5 cycles maximum). A total of 2,092 MMcf of CO2 was injected and 101,635 bbl of oil recovered from the 16 wells tested.

Responses varied from none to a maximum of 12,000 bbl in one cycle. The production cycle generally lasted more than 6 months and as much as several years in some wells. An average of 6,300 bbl per well was recovered, with one well achieving 31,000 bbl.

Some of the wells that showed good responses were in downdip locations and possibly benefited from water influx and gravity drainage during the puff phase. Updip wells that yielded good recoveries also were near faults, which may have helped in providing containment and efficient capture of the mobilized oil.

Five wells experienced mechanical difficulties and were excluded from the following analyses.
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.