Please join SPE in congratulating the 2012 SPE International Award recipients. The SPE Board of Directors approved the 2012 International Award recipients at their recent meeting. Seventeen international award committees recommended these winners to the board because of their outstanding and significant technical, professional, and service contributions to SPE and the petroleum industry. The winners were chosen from a pool of first rate candidates. SPE President Ganesh Thakur will present the awards to the winners at ATCE in San Antonio Texas.
Reservoir Description and Dynamics Award
Robert A. Wattenbarger, Texas A&M, College Station, Texas, USA
Formation Evaluation Award
Leif Larsen, Kappa Engineering, Royenberg, Norway
Last year in this focus on CO2 applications, I (as others have) connected enhanced
oil recovery (EOR) as an enabling business foundation and a possible way forward
to accomplish carbon capture and storage (CCS) as a business investment. This year,
in an address to the CCS conference in Pittsburgh, Pennsylvania, US Department of
Energy (DOE) Assistant Secretary of Fossil Energy Charles McConnell encouraged the
CCS industry to help operators establish a salient business case between CO2 EOR and
usage and sequestration. Creating a technical lead in CO2 EOR and other usage technologies
establishes an opportunity to commercialize the technologies that could be
in high demand in the years to come, particularly in coal-reliant developing countries
such as China and India.
The technologies needed to accomplish carbon capture, utilization, and storage
(CCUS) require expertise in science and engineering that, in some cases, are not completely
matured or, at least, require a different focus and commitment in science and
business to affect CCUS. An acceptable return on investment will depend on economic
CO2 capture and largely on regulatory stability.
Administratively, the US Environmental Protection Agency proposed a carbon
pollutions standard for new power plants, which will have to meet 1,000 lbm
of CO2 per electrical megawatt-hour produced. Older coal plants average approximately
1,768 lbm of CO2 per megawatt-hour but are exempt from the standard, as are
plants permitted to begin construction within a year. A typical natural-gas electricitygeneration
plant emits 800 to 860 lbm of CO2 per megawatt-hour.
Legislatively, the proposed US Senate Clean Energy Standard Act of 2012 would
implement a credit system to reduce CO2 emissions. A study by the DOE and the Energy
Information Agency (EIA) to evaluate the effects of this policy concluded that virtually
no electrical generation will occur in 2035 from US coal plants that use CCUS
technology even though CCUS is awarded nearly a full credit under the proposed policy.
The policy predicts a significant shift in the long-term electricity-generation mix
in the US by 2035, with coal-fired generation falling to 54% below the reference-case
level. Combined heat and power generators fired by natural gas increase substantially
through 2020, and nuclear and nonhydropower renewable generation plays a larger
role between 2020 and 2035. The proposed policy could reduce US electric-power-sector
CO2 emissions to 44% below the EIA’s reference case in 2035. National average
delivered electricity prices could increase gradually to 18% above the reference case
by 2035. However, there will still be a need to use the CO2 from the gas-powered plants
in the US and coal-powered plants worldwide by CCUS or other methods. These conclusions
concur with recent reports published by some major oil and gas entities on
the future of natural gas for electrical generation in the US.
The need for pure CCS in developed countries such as the US may not be as great
as in developing countries; but, the US and other developed countries have the ability
and capability to implement CCS through CCUS.
Read the paper synopses in the July 2012 issue of JPT.
John D. Rogers, SPE, is vice president of operations for Fusion Reservoir Engineering Services. With 30 years of experience, he previously worked as a production/operations engineer for Amoco, as a research scientist for the Petroleum Recovery Research Center of New Mexico Tech, and for the National Energy Technology Laboratory of the DOE. Rogers holds BS and PhD degrees in chemical engineering from New Mexico State University and an MS degree in petroleum engineering from Texas Tech University. Rogers has contributed to more than 30 publications and has served on several SPE editorial and conference committees. He currently serves on the JPT Editorial Committee.
“Geology drives technology,” and “the best solutions are multidisciplinary.”
Understanding the best way to develop an unconventional reservoir requires an
understanding of the rocks and a close interaction between the geosciences and engineering.
Without this base understanding and creative tension, unlocking the full
potential of any play will not be achieved. Some of the greatest results in my career
have come when working in a cross-functional team where all members were sufficiently
aware of the geology to then apply the most appropriate technology for extraction.
Interaction was open, robust, and balanced, and amazing results were produced.
The most successful field developments that are being proposed today in unconventional
gas use this model. For example, horizontal wells with multistaged stimulation
that use image logs to identify and target existing rock fabrics highlight the close
working relationship between drilling, geology, stimulation, and geomechanics.
“Geology drives technology,” and “the best solutions are multidisciplinary”—
this has never been more true than when developing and appraising on the challenging
Read the paper synopses in the July 2012 issue of JPT.
Simon Chipperfield, SPE, is team leader of central gas exploitation at Santos. During the past 15 years, he has held positions in petroleum engineering (drilling, completions, and stimulation) and reservoir engineering. Chipperfield previously worked for Shell International E&P. He was awarded the 2007 SPE Cedric K. Ferguson Medal. Chipperfield has authored more than 20 technical publications in the areas of hydraulic fracturing, reservoir engineering, completion technology, and sand control. He holds a petroleum engineering degree with honors from the University of New South Wales. Chipperfield serves on the JPT Editorial Committee and the SPE International Awards Committee and has served as a reviewer for the SPE Production & Operations journal.
This year, there were approximately 200 papers on simulation to select from—and that is after a separate feature on history matching. So, the discipline continues to be active. A noticeable feature is the growing number of simulation papers that use different technology, in the broadest sense of the term—for example, using concepts from signal processing and electrical engineering to model subsurface flow or related phenomena. However, the dominant technology remains finite different representations of Darcy’s law, conservation of mass, and a fluid model.
What is also heartening is the fact that all significant papers on case studies start with descriptions of the geology and often include detailed description of 3D geological modeling. Any simulation that is based on a physical model of the field must surely depend on the quality of the geological model used as input; yet, not that long ago, it was normal to pay only scant regard to the geology when constructing a model and even less when altering it during history matching.
Recent discussion within the SPE Simulation Technical Interest Group has raised the issue of pseudorelative permeabilities, with some arguing that they are obsolete and others strongly disputing the claim. Sadly, there were no papers on the subject that I could include in this feature. The relative permeability curve is where engineering meets geology; anyone involved in complex projects—and who of us is not— knows that it is at the interfaces that complexities arise and are too often ignored. The same is true in our models, so surely relative permeabilities and their multiphase upscaling are topics worth renewed investigation.
All three of the case studies I have selected, which are all from very different settings and parts of the world, were studies directed toward making tangible decisions (e.g., selecting well locations and completion intervals). This highlights once again that good simulation studies are directed toward decision making; having a clear sight of the purpose of the work improves the quality of the work and, thus, of the ultimate decision. The converse is also true.
View the paper synopses in the July 2012 issue of JPT.
Martin Crick, SPE, is chief petroleum engineer with Tullow Oil, responsible for all aspects of reservoir and production engineering in the group worldwide. Previously a principal reservoir engineer with Schlumberger, he was responsible for the design of the reservoir-engineering features in Petrel and, most recently, for a review of well test interpretation workflows within Schlumberger. Crick’s experience over 24 years in the industry has focused on reservoir engineering and, especially, simulation in support of field development planning initially with AEA Technology on contract to the UK government on a wide range of North Sea fields and then with Texaco on Erskine, the first high-pressure/high-temperature field on production in the UK North Sea, and on Karachaganak, the giant gas/condensate field in Kazakhstan. He holds a BS degree in physics from the University of Bristol.
On behalf of the Technical Directors (TD), I would like to draw your attention to a new article series in JPT called the Young Technology Showcase. This showcase is part of the TD’s Technology Pipeline strategy and is focused on bringing young technology to the SPE membership. Young refers to early in the technology life cycle where a technology first becomes commercially available.
If you are looking for new technology to apply to your fields, check out two sections of the June 2012 issue of JPT Online: Young Technology – Editor’s Column on page 16 and Young Technology Showcase article, starting on page 40. Additional information regarding Young Technology is provided in the President’s Column of the December 2011 JPT Online.
Papers in this volume are on the topic of Tight/Shale Gas.
Read the latest content at www.spe.org/go/speree
Enhanced-oil-recovery (EOR) operations are what moves EOR processes from the laboratory to the field. They involve a series of activities, from a detailed planning stage to efficient application, consistent monitoring, and results analysis. When reviewing results from field pilots or full-field applications, it is noticeable that significant technical hurdles such as facilities, drilling and completion, and production-technology developments need to be overcome in order to deploy and run a successful EOR operation. Technology developments in water management, intelligent-well completions, and downhole innovation are key for EOR operations to achieve the expected increases in reserves.
Over the past year and during the first quarter of 2012, SPE was host to several events focusing on EOR operations, and more than 400 papers were presented. Several of them explored topics related to enhancements associated with the three key areas mentioned. Emphasis in many papers concerns extending the use of smart-well completion technologies to EOR operations, targeting customization to set out an EOR process and provide more flexibility for the solution to unexpected setbacks during process startup. Also, several publications stress the importance of downhole innovation aiming at oil- and gasfield production maximization by continuous optimization of steam and CO2 downhole injection rates in heavy-oil recovery and CO2-EOR processes, respectively.
Dealing with EOR operations adequately is a great challenge, and a broad and integrated set of competencies is required. Nevertheless, as some of the papers featured in this issue illustrate, success is attainable with the right use of technology and creativity. I hope that you enjoy reading these paper highlights and will search for additional interesting contributions available in the OnePetro online library.
Read the paper synopses in the June 2012 issue of JPT.
Luciane Bonet-Cunha, SPE, is a senior reservoir engineer for Petrobras America in Houston. She has 27 years of experience in applied research and development related to reservoir engineering in exploration and exploitation projects in Brazil, Canada, and the US Gulf of Mexico. Before joining Petrobras America, Bonet-Cunha was an associate professor of petroleum engineering at the University of Alberta, Canada. She also worked for 16 years with Petrobras, Brazil. Bonet-Cunha holds a PhD degree in petroleum engineering from the University of Tulsa and serves on the JPT Editorial Committee.
- Reservoir Modeling
- Heavy-Oil Recovery
- Chemical EOR
- Unconventional Gas
Read the latest content at www.spe.org/go/speree.
Many reservoir engineers dislike the very idea of automatic history match- ing applied to real full-field studies. They believe there is no artificial substitute for experienced reasoning, deep understanding of the reservoir mechanisms, and atten- tion to real-life practical aspects of the problem. Some use terms such as art and intu- ition. For them, even if computers long ago learned to play chess, computers will never be able to perform real-case history matching on their own or at least they are still too far from this achievement. Very often, during technical sessions, immediately fol- lowing an advanced mathematical presentation on history matching, someone in the audience makes his or her point about the limits of automatic approaches. To avoid disputes, experienced speakers prefer less pretentious expressions such as assisted or semiautomatic history matching.
Indeed, history matching can be seen as a two-step iterative process, normal- ly requiring many cycles to be completed. Broadly speaking, the first step is about analysis and setting the problem parameters, and the second step is about search- ing for and computing solutions. We start our discussion with the second part, which has a more obvious algorithmic nature. There has being a great deal of research and progress in this area. The ensemble Kalman filter is dominating the scene, but gradi- ent-based methods and global-optimization stochastic methods are attracting mer- ited attention. Most published contributions come from universities, and, typical- ly, papers include examples to demonstrate successful algorithm application. These examples can be simple synthetic or somewhat-more-realistic cases, but the discus- sion is naturally focused on the solution method and not on the entire problem as found in the field.
The first part of the problem is less mathematized, for now, and involves essen- tial tasks such as to be clear about the practical purposes and requirements in the par- ticular context; to have a full understanding of the quality of the reservoir model and the production data; to design or redesign well-justified objective functions; to set adequate parameterization, considering the main uncertainties and their effect on the simulation results; to represent properly and sample the uncertainty space; and to evaluate results from the previous steps of the history-matching process judiciously. Unfortunately, the strategies used to consider this part of the problem are much less discussed and documented. In fact, many of these tasks are open to further formal- ization and, ultimately, can be automated also. We definitely need more papers illu- minating these other aspects of the reservoir-engineering problem, instead of relying on intuition.
Read the paper synopses in the April 2012 issue of JPT.
Régis Kruel Romeu, SPE, is a Senior Consultant at Petrobras Research Center (CENPES) in Rio de Janeiro. With 31 years’ experience in petroleum engineering, he has worked mostly in reservoir- characterization and -simulation applied research. Romeu’s main activities and areas of interest are heterogeneities representation, scale up, history matching and optimization, integrated reservoir studies, coordination of research projects, relationship with Brazilian universities, and reservoir studies related to Brazilian presalt fields. He holds a BS degree in civil engineering from Universidade Federal do Rio Grande do Sul, Brazil; an MS degree in petroleum engineering from Universidade Federal de Ouro Preto, Brazil; and a PhD degree in quantitative geosciences from the Université Pierre et Marie Curie, Paris. Romeu has served as Editor for SPE Res Eval & Eng and serves on the JPT Editorial Committee.
Exciting operations are ongoing on the shallow-water US offshore continen- tal shelf (OCS) that will influence the entire high-pressure/high-temperature (HP/HT) community going forward. McMoran and their operating partners are actively drill- ing, evaluating, testing, and bringing to production several deep HP/HT plays. These prospects are named in the Treasure Island theme with identities such as Davy Jones, Blackbeard, and Lafitte. The Davy Jones 1 is in the completion phase, incorporating multiple Eocene Wilcox sands, and it represents the first 25,000-psi completion of its kind in the world. The Davy Jones 2 encountered confirmed pay and is progressing well. The original Blackbeard well was taken to 32,997-ft total depth, and operations on Blackbeard East have been permitted to 34,000 ft. As with Davy Jones, these wells represent substantial extensions to or step changes in current HP/HT technologies.
To address the substantial engineering challenges associated with these wells, the operator formed a significant project team and is drawing on the expertise of several vendors in a collaborative manner to make the many advances necessary in HP/HT drilling and completion procedures and in production equipment and proce- dures. Downhole tools have been upgraded to 30,000 psi and 500°F. It will take con- siderable effort to catalog all of the “industry firsts” and “Serial-Number 1s” associat- ed with these ongoing operations. Both Davy Jones wells are expected to be flow tested and put on production later this year.
HP/HT continues to be of international interest, with global operations ongoing from the North Sea, to Latin America, to the Middle East, and of course in the “ring- of-fire” regions in Southeast Asia. Operators, service companies, equipment suppli- ers, drilling contractors, and other involved parties share a common goal of address- ing the many HP/HT challenges successfully and in a safe and efficient manner. These goals create a need to exchange information effectively, openly share lessons learned, and embrace a collaborative spirit that respects the competitive nature of business while valuing the shared interest that we all have in safe and reliable operations. Thus, the industry looks forward to learning more from the success of these HP/HT step changes in the US OCS ventures and from advances in other HP/HT operations around the globe.
Read the paper synopses in the April 2012 issue of JPT.
Mike Payne, SPE, is a Senior Advisor in BP’s Exploration and Production Technology group. He has 29 years’ experience including drilling operations, computing technology, and consulting. Payne holds BS and PhD degrees in mechanical engineering from Rice University, an MS degree in petroleum engineering from the University of Houston, and an Executive Business Education degree from the University of Chicago. He has extensive industry publications and has held key leadership positions with the American Petroleum Institute and the International Organization for Standardization. Payne has been an SPE Distinguished Lecturer and received the SPE International Drilling Engineering Award in 2000. He has chaired or cochaired several SPE Advanced Technology Workshops and serves on the JPT Editorial Committee.