Robert A. Wattenbarger, Texas A&M, College Station, Texas, USA
Dr. Robert A. Wattenbarger has more than 35 years’ experience in the petroleum industry. Reservoir engineering and computer software have been his specialties, with emphasis on reservoir simulation and well test analysis. He was vice president of Scientific Software Corporation in Denver for 10 years after being involved in the formation of that company.
With high oil prices, the field application of EOR has been on the rise. Please join me at ATCE in San Antonio where I will be moderating a special session titled “EOR – Out of the Lab and Into the Field.”
This session will cover some innovative applications of EOR; innovative in not just what was applied, but also how and where.
View more information on the ATCE schedule of events and find out what is really needed to deploy EOR in the field.
EOR—Out of the Lab and into the Field
Tuesday, 9 October | 0830–1155
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
When: 8 October 2012 | 1930 – 2200
Where: Iron Cactus Grill, San Antonio, Texas, USA
You are invited to join us for a reception to launch the NEW SPE Technical Section, Petroleum Data-Driven Analytics (PD2A), whose aim is to foster the application of data-driven modeling, data mining and predictive analytics in the upstream oil and gas industry.
This is the place to learn about this forward-thinking, exciting group and network with key decision makers in the E&P industry. Space is limited, so if you are not already a member, join the Technical Section and email your RSVP to firstname.lastname@example.org today!
Please submit your name and number of guests attending to be added to the guest list. (Note: Limit of two guests per Technical Section member.)
RSVP by 1 October.
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.