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.
Calling all technology champions! A few years ago, I ran across the seven steps to stagnation,
which was a list originally compiled by Erwin M. Soukup. I got a feeling of déjà
vu reading through this list because I had heard these same words spoken from many
managers and peers over my career. If you search for these seven steps on the Internet,
you will find different variations; however, the message is the same. The seven
- We have never done it that way.
- We are not ready for that yet.
- We are doing all right without it.
- We tried it once, and it did not work out.
- It costs too much.
- That is not our responsibility.
- It will not work.
Great ideas for technology improvement or development can have an early demise
when faced with feedback similar to what is on this list. Even with a patent, a product
may never be commercialized without someone to be its champion. While we are fortunate
to have many technology champions in the area of artificial lift, we need more.
The best way to meet and learn from our industry’s best artificial-lift champions
is by attending some of the artificial-lift forums, workshops, and conferences coming
up in 2012 and 2013. Please check out the global events calendar on www.spe.org.
One major SPE artificial-lift event you will not see on the global calendar, however, is
the 2013 Electric Submersible Pump (ESP) Workshop. This is still a section-sponsored
event; however, it has grown to be the primary conference for the ESP industry (the
most-recent event had 560 attendees from 24 countries). Please go to this address for
more information: http://www.spegcs.org/committee/esp-workshop/.
The first paper highlighted features the use of a downhole linear motor to drive a
reciprocating-pump system. This is a new technology that is also featured in two papers
to be presented at the 2012 Annual Technical Conference and Exhibition in San Antonio,
Texas, this October. The two other highlighted papers focus on offshore artificial-lift
systems and discuss the unique challenges and concepts being applied.
Read the paper synopses in the July 2012 issue of JPT.
Shauna Noonan, SPE, is a staff production engineer for ConocoPhillips, where she works as an artificial-lift specialist in the Completions and Production Technology group. Noonan’s responsibilities include development and validation of artificial-lift and completion systems for thermal applications and improving artificial-lift reliability. She has worked on artificial-lift projects worldwide at ConocoPhillips and previously at Chevron for more than 18 years. Noonan has been chairwoman of industry forums and committees and has authored or coauthored numerous papers on artificial lift. She serves as a member of the SPE Production and Operations Advisory Committee, as an Associate Editor for the SPE Production & Operations journal, and as a member of the JPT Editorial Committee. Noonan began her career with Chevron Canada Resources and holds a BS degree in petroleum engineering from the University of Alberta.
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.
Well stimulation continues to be a hot topic in our industry, particularly with hydraulic fracturing of shales. Having been in the industry since the Dark Ages, (at least, it seems like it at times), it is interesting to see the technology changes over time and what areas are currently in the spotlight. Certainly, hydraulic fracturing continues to lead the industry interest; however, we do pump a lot of acid, and we have not forgotten its importance. Our acid blends have not changed much since the very early days— the late 1800s—of acidizing. Hydrochloric acid has been the mainstay, with primarily hydrofluoric acid and formic and acetic acids being the complimenting acids. Specialty acids, such as phosphonic, sulfamic, and others, have also been playing a role.
Major technology developments in nonproppant-fracturing well stimulation, as evidenced by the numerous publications over the last few years, have been primarily in carbonate acidizing. This is a continuing trend brought about by the significance of the carbonates to the world’s oil supply. However, our industry does use a lot of acid in the noncarbonates. One of those areas is in spearheading fracturing treatments to reduce near-wellbore tortuosity, most of these in sands and shales. My experience with this approach in horizontal shale wells has not always been successful; however, one of the papers selected for this month’s feature shows a unique acid blend that has shown some success in tight-gas-sand fracturing. Perhaps this and other unique acid blends could provide increased success in shales.
Horizontal wells in all reservoir types are now quite common, allowing our industry to exploit lesser-quality reservoirs economically. Shales are excellent examples. Many reservoirs have a high water cut, and stimulating wells in these reservoirs can be a real challenge. Acid-placement techniques, as well as diagnostics while acidizing, are a significant challenge to our industry. Of course, in our industry, challenges beget solutions. A recent development helping with well stimulation and production diagnostics is distributed temperature sensing (DTS) and distributed acoustic sensing (DAS). From reviewing numerous technical papers from worldwide SPE meetings held in the last year or so, the development and application of DTS and DAS appear to be in the forefront. Two of the papers selected for this month’s feature reflect on these developments and applications.
Readers are advised to review the following synopsized papers as well as the recommended additional reading to gain information on recent advancements in well stimulation.
Read the paper synopses in the June 2012 issue of JPT.
Gerald R. Coulter, SPE, is a consulting petroleum engineer and president of Coulter Energy International. He is involved in consulting and technology transfer of well-completion, formation-damage, and well-stimulation technology. Coulter is currently an instructor with PetroSkills. His industry experience includes work with Sun Oil/Oryx Energy Company, Halliburton, and Conoco. Coulter has authored numerous technical papers and holds numerous patents, has been chairman of and has served on numerous SPE committees, and is currently serving on the JPT Editorial Committee. He holds a BS degree in geology and a BA degree in chemistry from Oklahoma State University and an MS degree in petroleum engineering from the University of Oklahoma.
At the 2011 SPE Annual Technical Conference and Exhibition (ATCE) in Denver, a panel discussed the question, “10 Years of Digital Energy: What Have We Learned?” Those leading the discussion, mostly experts from major operators and service companies, centered on two main themes:
- Consolidating and Institutionalizing Successful Patterns
- Handling of Large, Disparate Data Sets
As an industry, we clearly have moved beyond the heady first years of the digital transformation, where the anticipation from many was that within a few years we would have a consolidated software solution spanning the scope of E&P workflows. While the stories told by such a panel naturally focused more on success cases (particularly for large greenfield applications), what emerges is evidence of large-scale benefits when a company invests in repeating successful patterns at its scale of operation—this is found to be true for both operators and service companies. The clearest examples of such success were on the fundamental aspects of data quality, exception- based surveillance, standardization of human workflows, and large-scale applications of focused software solutions, often having required an investment cycle of at least 5 years. Focusing on the scaling of fundamental aspects to broad application provided significant return while managing risk, with the result of sustaining those programs that delivered benefits. If the human workflow failed to rely on any new technology deployment, any gains found in the first year or two following the deployment were not sustained. So, a simple, “fast follower” approach is unlikely to be successful, unless the follower can adapt the leader’s success to their own culture and processes well.
Of course, the challenges are becoming more complex. Scaling successes from large, greenfield applications (in which initiatives may be justified easily) to brownfields, “difficult oil and gas,” and IOR/EOR will require us to focus more on the “big- data” challenge and the efficient application of qualified data to improve reservoir management through better daily decisions and more-accurate forecasting. In many cases, the problem has moved from a lack of data to an inability to contextualize the available data quickly into a particular decision process. As a result, information relevant to a decision may be available to some extent within the organization, but not easily applied to the decision because it first must be found and qualified, often through an undocumented process, before it can be used.
Once organizations can depend on a service level for qualified data, they can begin to exploit the data by use of established patterns, such as those outlined by the ATCE panelists, and emerging patterns, as illustrated by the papers in this feature.
Read the paper synopses in the May 2012 issue of JPT.
John Hudson, SPE, Senior Production Engineer, Shell, has more than 25 years’ experience in multiphase-flow research, flow-assurance design of deepwater production systems, and development of model-based real-time operations- decision systems. Since joining Shell, he has held technical and managerial positions in Europe and North America, including leading a team that developed a model-based, cloud computing solution that was deployed globally to gas plants with a total production capacity in excess of 10 Bcf/D. Hudson currently provides production-engineering support for the development of a next-generation simulator. He holds a PhD degree in chemical engineering from the University of Illinois. Hudson serves on the JPT Editorial Committee.
- Well Performance
- Scale and Sand Control
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View the entire February 2012 issue.
See the current issue at http://www.spe.org/go/spepo.
The rapid growth in interest and in development activities related to unconventional oil and gas resources, including heavy oil, is clearly evident throughout the industry. One outcome has been a tremendous increase in the number of SPE papers written this past year on various topics associated with development and recovery optimization of heavy-oil reservoirs. Another is that petroleum-engineering departments at many more universities worldwide are actively engaged in teaching courses and performing research related directly to viscous- and/or heavy-oil recovery.
One topic in particular has gained more attention: development and application of enhanced thermal-recovery methods that use various solvents as a means to improve recovery and to reduce operating costs significantly relative to conventional thermal projects. Continued knowledge development in this subject area through a combination of reservoir-scale physics and chemical-process analysis, simulation capability advancement, laboratory testing, and field-piloting work is needed to enable operators to design and implement these methods effectively and commercially, especially for viable development of thinner, lower-quality heavy-oil reservoirs. One synopsis paper and a reading paper were selected to provide further insights regarding the potential and the challenges associated with the use of solvent-recovery techniques in such applications.
The other papers were chosen to illustrate the variety and significance of the challenges operators may encounter in assessing and/or pursuing the development of heavy-oil reservoirs under different settings and conditions. These include various problems that had to be dealt with during testing of a heavy-oil well in an offshore location; the many planning issues, design tradeoffs, and performance considerations associated with the sequencing and conversion of a heavy-oil-field development from cold to hot production; the difficulties experienced in planning and conducting
pilot operations in a high-viscosity oil field overlain by thick permafrost in the Russian Arctic; and the ability to achieve adequate recovery with steaming of fractured carbonate reservoirs.
Recent literature also describes several interesting technology developments, modeling studies, and field-trial activities related to the use of in-situ combustion and electrical-heating methods as alternative heavy-oil-recovery techniques. Several additional papers present results from investigations of CO2 injection into heavyoil or bitumen reservoirs to achieve both improved oil recovery and greenhouse-gas sequestration, while many others describe new developments and/or field experiences involving waterflooding and polymer flooding of heavy-oil reservoirs. The many papers written on these topics can be sourced through OnePetro.
Read the paper synopses in the March 2012 issue of JPT.
Cam Matthews, SPE, is Director–New Technology Ventures for C-FER Technologies, organizing R&D programs related to production operations and drilling and completions. He holds five patents on drilling and production processes. Matthews earned BS and MSc degrees in civil engineering from the University of
Manitoba and the University of Alberta, respectively. He serves as a Director of the SPE R&D Technical Section, on two ad hoc SPE Board committees, and on the JPT Editorial Committee.
At the 2011 SPE Annual Technical Conference and Exhibition in Denver, there were many interesting discussions on shale-gas (and/or liquid-rich) resources. While already an important part of the industry, we are just beginning to identify some of the challenges with these resources and how best to deal with them. With hydraulic fracturing being an integral part of these operations, one area of focus is how to optimize the well geometry and the fracturing treatment to achieve long-term production and high ultimate recovery. Nevertheless, two other key considerations concern where to obtain the huge volumes of water that are required for these fracturing jobs, and what water treatment is required to ensure a safe and problem-free operation. With the need to rely less and less on fresh surface water to minimize the environmental effects, operators have been forced to explore other options, including finding suitable aquifers and/or water-recycling technologies. Some of the papers featured in this issue (or listed as additional reading) illustrate some of these challenges and how companies are trying to address them.
During this last year, we also saw an increase in the use of inflow-control devices in conjunction with horizontal wells in a variety of applications throughout the world. One of the most interesting developments is that of the so-called “autonomous” devices, which should be capable of adjusting themselves on basis of the type of fluid flowing through them (i.e., applying more choking to less-viscous fluids such as water and gas). There also have been interesting advancements in sandface-monitoring systems, as illustrated in two of the papers in the reading list.
Read the paper synopses in the March 2012 issue of JPT.
Francisco J.S. Alhanati, SPE, is Director of Exploration & Production for C-FER Technologies. Previously, he was with Petrobras. Most of Alhanati’s 29-year career has been in applied R&D related to well construction and production operations. He has served on several SPE committees, as an SPE Distinguished Lecturer, and as a Technical Reviewer for the SPE Journal, and he serves on the JPT Editorial Committee. Alhanati holds a PhD degree in petroleum engineering from the University of Tulsa.