bluuebunny/crossref_metadata_2025_split huggingface dataset:
Q&A with J. Larry Nichols, CEO, Devon Energy
Authors: Nichols J. Larry , Donnelly John 
Published: February 2015

How have recent high oil prices affected your E&P program?
Our capital budget has tripled over the past 5 years. Part of that has come from higher oil and gas prices, but part of that has been because we have been growing the size of the company. While oil and gas prices have had some impact, we recognize that prices are volatile, and we are not relying on them staying at their current elevated level.
How did last year's hurricanes in the Gulf of Mexico affect your operations?
We were affected some, but not as badly as a lot of other companies. We had three platforms that suffered damage—they actually sank—but they were not critical platforms. They were in the area of other platforms, and we just rearranged our production scheme without having to rebuild those platforms. We were affected by some third-party pipelines that resulted in about 80,000 BOPD being suspended for a period. We have restored all but 6,000 BOPD of that now.
You recently acquired Chief Holdings and have made major acquisitions in the past. What is Devon's philosophy regarding growing through acquisitions or through the drill bit? Does that philosophy change in a high-price environment?
We have always stated that we like both; it depends on the circumstances whether acquisitions are attractive. We certainly have done a lot of acquisitions since we went public in 1988. But because of high oil prices, they are now increasingly difficult. One of the things we have done with our acquisitions is that each time we have bought a company, we have turned around and sold the bottom part of our portfolio, resulting in an ever-increasing quality of our portfolio. It is now difficult to find transactions that are accreting in value and that improve the quality of our portfolio. Chief was one of those rare exceptions.
What is your outlook for oil and natural gas prices?
You have to start with oil because that has such an influence on gas prices. It involves huge political questions that are very difficult to answer. Obviously, the world supply of oil is tight, and in the countries where one could increase production, many of them are difficult to do business in. That is why oil is trading where it is now, because of the political uncertainty of the Middle East, Venezuela, now Bolivia, and Nigeria. Long-term, we think that oil in the area of U.S. $50–55/bbl is probably a reasonable number, but that is not to say that there might not be huge volatility both above and below that number.
Gas is also challenged. In the U.S., companies are denied access in many areas where they could expand production, which has resulted in the supply of natural gas being very tight. We had a mild winter last year, and that helped.
The CO2 Pilot at Lacq: An Integrated Oxycombustion CO2-Capture and -Storage Project
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 11737, "The CO2 Pilot at Lacq: An Integrated Oxycombustion CO2 Capture and Geological-Storage Project in the South West of France," by Nicolas Aimard, Marc Lescanne, Gerard Mouronval, and Claude Prebende, Total, originally prepared for the 2007 International Petroleum Technology Conference, Dubai, UAE, 4-6 December. The paper has not been peer reviewed.
In 2006, Total launched an integrated carbon-capture and -storage (CCS) project in southwest France. It entails the conversion of a steam boiler into an oxyfuel combustion unit, with oxy-gen being used for combustion rather than air to obtain a more-concentrated carbon dioxide (CO2) stream that is easier to capture. The pilot plant, which will produce some steam for use by other facilities, will emit up to 150,000 tons of CO2 over a 2-year period, which will be compressed and conveyed by pipeline to a depleted gas field, 8 miles away, where it will be injected into a deep carbonate reservoir. CO2 injection is scheduled to begin by the end of 2008.

Introduction
For decades to come, oil and gas will remain an energy source of choice. But oil and gas operators have to develop fields that require much more processing and energy while reducing greenhouse-gas emissions to mitigate climate-change consequences. Among the options, CCS is an important option for tackling greenhouse-gas emissions. While the worldwide CO2 atmospheric emission was approximately 30 billion tons in 2005, CO2 geological-storage capacity could be very significant: approximately 600 to 1,200 billion tons in depleted oil and gas fields, 3 to 200 billion tons in unmineable coal seams, and as much as 1,000 to 10,000 billion tons in deep saline formations. This represents 70 to 500 years of storage at current production rates.
Industry pilot plants are necessary to ensure that CCS technology will be reliable, energy efficient, accepted by the public, and commercially viable. At the end of 2006, Total launched an integrated CCS project in southwest France that entails the conversion of a steam boiler into an oxyfuel combustion unit, with oxygen being used for combustion rather than air to obtain a more-concentrated CO2 stream that is easier to capture. The pilot plant will produce steam for use by other facilities and will emit 150,000 tons of CO2 over a 2-year period at the Lacq facilities. The CO2 will be treated, com-pressed, and conveyed by pipeline to the depleted Rousse gas field 18 miles away to be injected into a deep carbon-ate reservoir (Fig. 1).
Overview: Intelligent Fields Technology (August 2006)
Authors: Gomersall Sam 
Published: February 2015

Location, Location, Location
A key issue to be addressed by companies facing the challenge of the digital oil field is: What is the best location to store data? The key should be storing data to maximize the return on investment in digital data collection, and in today's world of the digital oil field, there is a lot you can do with data. The location of the data will determine its ultimate value to the organization.
The digital-oilfield step change is as significant as the introduction of PCs into the oil field or the introduction of effective internal networks and the Internet. Both technologies changed the types of data available, how the data are stored, and how security is managed. What does the next step change of the digital oil field require?
Today's challenge is to manage distributed and global organizations, involve internal and external experts, and collaborate effectively with partners. Data volumes have increased by orders of magnitude and will continue to do so with the increasing volumes of real-time data. The number of expert resources inside oil companies has generally decreased, increasing dependence on external experts and partner companies. At the same time, information and communications technology (ICT), including oil/gas software, has developed significantly.
However, the ICT philosophy and practices of most companies do not reflect this new reality of industry's need or ICT capability. Oil industry ICT practices are inhibiting effective implementation of the digital oil field.
Part of the solution for the digital oil field is to move data and applications outside our traditional organizational structures. Having data and applications on the network enables providing appropriate secured access for experts and collaboration partners and makes use of the available advances in ICT.
Maximizing the value of data and enabling the digital oil field will require significant change, which will include moving our data and applications onto the network. Data location will be critical.
Intelligent Fields Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 99963 "Continuous Well-Production Flow Monitoring and Surveillance" by H. Poulisse, Shell Intl. E&P B.V., et al.
SPE 99243 "Integration of People, Process, and Technology for Right-Time Production Management and Optimization in Brunei Shell Petroleum" by S. AlKhadhuri, Brunei Shell Petroleum, et al.
SPE 99850 "ISIS—A Real-Time Information Pipeline" by J. Foot, BP plc., et al.
IPTC 10319 "Automatic Optimization of Infinite Variable Control Valves" by S.M. Elmsallati, SPE, Heriot-Watt U., et al.
How Processes Will Contribute to the Next Trillion Barrels
Authors: Miller Jeffrey A. 
Published: February 2015

Guest editorial
When our industry talks about technology, the discussion quickly moves to game changers and specific events in which a new widget does something new. These widgets are generally successful but are usually applied to relatively narrow applications. While I absolutely agree that such innovations are extraordinarily important to our industry, I believe that the humble, unheralded technology of process innovation will provide an equally important contribution to how we produce the next trillion barrels of oil. Our ability to take broad areas of technology and to reliably and rapidly customize very specific wellbore solutions will become increasingly important to our industry.
In my job, I get to talk with clients all of the time, and I recently had the chance to listen to a group of successful operators discuss a resource play. The conversation quickly turned to how they planned to drill the asset, and I asked them about mud systems. They indicated that they planned to use oil mud, even though they believed water-based fluid would likely get the job done more efficiently. Why is this? The real reason was because the first well drilled successfully in this resource play was drilled with oil. This is an example of a situation where we are effectively doing what we have always done based on observation of a successful phenomenon.
We can rely on observable phenomena as long as all of the "right" drilling parameters somehow remain consistent. I see the challenge less as one of new technology development, but rather as one more closely aligned with how we reliably apply mass customization of technology (in this case, chemistry) to reliably customize broad areas of science to specific wellbore challenges. Nevertheless, it is the rare drilling fluid system that is simply pulled off the shelf, sent to a location, and run successfully without some level of customization—one exception being possibly the soap stick, and even that was only under specific conditions.
So, how do we effectively customize solutions on a large scale? First, we must understand why systems behave and perform the way they do at an elemental level. Next, we must execute stable processes that allow us to reliably investigate observed phenomena.
Efficient customization of technology is increasingly important; additionally, complexity and drilling envelopes are pushed to the technical limits of the industry's current capability. By integrating engineering tools into the customization process, it becomes possible to more efficiently and reliably distill broad technology systems down to a very specific and customized solution that maximizes the operator's wellbore value.
Guest Editorial: The Promise of New Reservoir- Monitoring Technologies
Authors: Warpinski Norm 
Published: February 2015

Reservoir monitoring is a fast-developing area of production technology that has the objectives of measuring, controlling, and predicting the performance of the reservoir. From the measurement perspective, reservoir monitoring may include temperature, pressure, flow rate, composition measurements, periodic logging, 4D seismic, microseismic, deformation measurements, and a host of other possibilities. Most of the measurements made in reservoir monitoring today are wellbore-specific, targeting the conditions in a production or injection wellbore. On the other hand, technologies such as 4D seismic, microseismic, and surface deformation have the potential to image a volume of the reservoir away from wellbores, providing an understanding of how the reservoir is performing as a complete system. It is these imaging technologies that hold great promise for the future improvements in the understanding of overall reservoir performance. It is my opinion that as surface-deformation monitoring is better understood by the industry, there will be a trend toward its use over 4D seismic on many onshore fields because of its low cost, fast turnaround, and wide areal interrogation of the reservoir.
The first recorded instance of surface-deformation monitoring that I am aware of was associated with the disposal of low-level radioactive waste in cement fractures at Oak Ridge in the 1960s. The leveling-type measurements were relatively crude, but the fractures were shallow and wide, and the results were reasonably good. Today, surface-deformation measurements are quite sophisticated, using tiltmeters for precision measurements, interferometric synthetic aperture radar (InSAR) for large-scale reconnaissance, and global positioning systems (GPS) for a host of intermediate and combined applications. Currently, these types of measurements are limited to onshore applications, but subsea measurements are possible in some cases.
Tiltmeters measure the horizontal gradient of the vertical displacement with great precision (up to one nanoradian), and an array of tiltmeters properly situated over a reservoir can be used to extract the surface deformation that is taking place because of processes occurring deep underground. These tools are sensitive enough to pick up Earth tides caused by the moon's pull on the Earth's crust over time. Results can be processed to calculate reservoir-level volumetric changes. GPS and InSAR, on the other hand, measure the actual displacement of the surface, but with considerably less precision. InSAR has the least resolution of the techniques, but it has great appeal for the large areal extent that can be covered and minimal (often zero) ground equipment. Being able to identify subcentimeter ground deformation over hundreds of square kilometers for a few thousand dollars has great appeal.
Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2007)
Authors: Goodman Harvey E. 
Published: February 2015

Reviewing papers for this month's Wellbore Integrity, Sand Management, and Frac Pack feature finds our industry hard at work to improve understanding of the complexities of formation failure in the near-wellbore region. This work involves hole-failure modeling and mitigation in the shale sections through the overburden and in the reservoir, with a strong focus on solids-production risk.
On the theoretical side, shale-instability mechanisms from purely mechanical failure to accounting for chemical and thermal effects are being modeled and consequences are being addressed in the well-engineering plan. The complexity of predicting wellbore-stability behavior is daunting when the "wish list" of model-prediction input-data requirements is considered. Even so, these comprehensive theoretical approaches to hole-failure modeling provide critical insight to complex formation-failure processes that then is used to underpin the shortcuts we are often forced to take in hole-instability prediction because of a lack of data. Furthermore, this research provides guidance in determining the measurements operators should invest in (e.g., cores, logs, and well tests) to achieve the desired hole-instability-prediction uncertainty range for a specified well plan.
This paper review also finds exploration- and development-prospect environments to be increasingly complex. Deepwater subsalt plays are becoming more common. The trend in technology development and application for these harsh and correspondingly expensive projects finds extensive early-project predrill performance modeling the norm, not the exception. However, even with the most comprehensive predrill model prediction, uncertainty still is present. Often, the gap between predicted hole instability and reservoir-sand production vs. field-performance results is great, leading to heavy R&D on tools and techniques that can preserve hole integrity while ensuring that the hole size needed to install sand-control completions, including frac packs, is achieved.
Wellbore Integrity, Sand Management, and Frac Pack additional reading available at the SPE eLibrary: www.spe.org
SPE 100202 "Maintaining the Stability of Deviated and Horizontal Wells: Effects of Mechanical, Chemical, and Thermal Phenomena on Well Designs" by Jianguo Zhang, SPE, Baker Atlas and Baker Hughes Drilling Fluids, et al.
SPE 102626 "Remediation of Production Loss Due to Proppant Flowback in Existing Wellbores" by Philip D. Nguyen, SPE, Halliburton, et al.
SPE 108241 "Sustainable Deployment of Geomechanics Technology to Reducing Well Construction Costs" by Fersheed K. Mody, SPE, Shell, et al.
Technology Focus: Completions Today (September 2008)
Authors: Horvat Damir 
Published: February 2015

Technology Focus
I am not here to discuss the process of detailing the optimum completion design. However, I do believe that there is no single parameter to serve as the "rule of thumb" to judge well-completion designs for the life of the field.
Earlier this year, I attended the first SPE Unconventional Reservoirs Conference at Keystone Resort and Conference Center, in Keystone, Colorado. Afterward, I attended a workshop presented by Shell Energy Canada and Calgary Research Centre. Both presentations highlighted the emerging and applied technologies in use worldwide for recovery of unconventional hydrocarbon resources.
As with all conferences, I had the opportunity to engage in discussion with many world experts from various operating/service companies and academia. After thorough discussions with all parties, I have reviewed an abundant reference list on well completions that use sonic stimulation. Many were anecdotal. Some may argue this was because of the nature of the studies, in which improved production was observed after some coincidental event that may or may not have been responsible for incremental hydrocarbon production. In my opinion, all studies should be scientific, not anecdotal, so long as the sonic stimulation was applied with the intent of enhanced hydrocarbon production.
Thorough discussions, backed with research on this subject, ensure that certain aspects of the well's operation, such as safety, availability, and efficient use of equipment inventory, are not overlooked. Many readers will agree that not all well completions achieve this objective. I have found that many unconventional-reservoir failures may not be a function of the manner in which they were designed, but may be simply the result of purely unknown complex reservoir-related mechanisms.
I advocate that operating companies use advanced diagnostic procedures that match and predict performance to estimate reservoir potential, well deliverability, and completion efficiency accurately. I believe in focusing on some of the best practices, such as economics (i.e., net present value), as the main driver. Hence, alternative completions such as sonic stimulation may be a viable alternative to reduce workover costs and improve ultimate hydrocarbon recovery.
Completions Today additional reading available at the SPE eLibrary: www.spe.org
SPE 113106 • "Optimization of Completion Interval To Minimize Water Coning" by M. Tabatabaei, SPE, University of Louisiana at Lafayette, et al.
SPE 113670 • "Through-Tubing Inflatable Technology Deployed on a Downhole-Tractor System Provides Real-Time Cost Savings" by Graeme M. Kelbie, SPE, Baker Oil Tools, et al.
SPE 108656 • "Harsh-Environment HP/HT Gas-Condensate Production Cleanup Experiences—Kristin Field" by Arild Fosså, Expro, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 19341 • "Expandable Screens: Optimized Horizontal Gas Production Through Collaboration" by Alejandro Lopez Lara, Pemex, et al.
FPSO Solutions for 10,000-ft GOM Field Development
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17200, "DeepStar - FPSO Solutions for 10,000-ft GOM Field Development," by J.E. Chitwood, Chitwood Engineers, and S. Hanrahan and G. Adhia, Chevron, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.
DeepStar has evaluated new and emerging technologies for developing small standalone (marginal) fields in 10,000 ft of water in the U.S. Gulf of Mexico (GOM). These studies identified viable field-development scenarios that improve field economics. Further, the studies identified knowledge gaps requiring further investment before these development systems are ready for field application. This paper describes the evaluation process and uses floating production, storage, and offloading (FPSO) vessel development alternatives to illustrate the identification of specific knowledge gaps for FPSOs in 10,000-ft water depths.

Introduction
Deepwater fields like Thunderhorse are being developed in water depths approaching 6,000 ft in the GOM, and discoveries have been made in water depths to 10,000 ft, with many intermediate-water-depth discoveries. A life-cycle economic model was prepared for alternatives considered viable by the technical committee. Where technology was extended or new technology assumed available, an estimated commercial cost was used. The realistic input yielded a mature concept comparison in which the field-development alternatives were compared on an equivalent basis. The most promising development scenarios could then be identified. Evaluation criteria included the following.
- Projected economic performance.
- Schedule through project qualification.
- Cost of the necessary technologies through project qualification.
Four surface-facility scenarios were studied.
- Semisubmersible—provides lowest motion solution.
- Spar—features low motion and dry trees.
- Tension-leg platform—requires new ten-don technologies for 10,000-ft water depths.
- FPSOs—use a gas-export pipeline and an oil shuttle tanker.
When extending these surface facilities to 10,000 ft, the following critical aspects must be understood fully.
- Station-keeping method.
- Riser system.
- Surface facility.
- How all these items interrelate and operate as an integrated unit through all phases of operation (i.e., design, construction, installation, normal production, storm conditions).
This understanding must be further communicated to the regulatory and classification agencies to obtain approvals. FPSO arrangements included the following.
- Permanently moored weathervaning FPSOs.
- Dynamically positioned (DP) FPSOs.