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SPE Economics & Management

View the January 2012 issue

153117-PA – Decision Criteria for Climate Projects
P. Osmundsen, University of Stavanger, and M. Emhjellen, Petoro A/S

139716-PA – Perspectives on CCS Cost and Economics
H.S. Kheshgi, SPE, and H. Thomann, ExxonMobil Research and Engineering Company; N.A. Bhore, Exxon Mobil Corporation; R.B. Hirsch, ExxonMobil Gas and Power Marketing Company; M.E. Parker, ExxonMobil Production Company; and G.F. Teletzke, SPE, ExxonMobil Upstream Research Company

158241-PA – Geologic Heterogeneity and Economic Uncertainty of Subsurface Carbon Dioxide Storage
J.E. Heath, SPE, P.H. Kobos, J.D. Roach, T.A. Dewers, SPE, and S.A. McKenna, Sandia National Laboratories

139616-PA – Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East
S. Sahin, U. Kalfa, and D. Celebioglu, Turkish Petroleum Corporation

133246-PA – How Significant Is the P90 Value as a Measure of the Reserves’ Downside?
S. Gupta, SPE, University of Western Australia; R. Gupta and J.F. van Elk, Curtin University of Technology; and K. Vijayan, University of Western Australia

143950-PA – Implementing i-field-Integrated Solutions for Reservoir Management: A San Joaquin Valley Case Study
A. Popa, SPE, K. Horner, SPE, S. Cassidy, SPE, and S. Opsal, SPE, Chevron Corporation

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Well Testing

The value of information has a ubiquitous and sometimes pervasive role in modern well testing. From exploration to field management to surveillance, well-test practitioners deal with a wide array of measurements (e.g., pressure, flow rates, temperature, and fluid analysis) that, more often than not, encompass large amounts of data. This is particularly true for long-term-production-data analysis of established fields, and one can argue the same for any current pressure-transient analysis that also has benefited from improved and more-robust data-acquisition available today. Likewise, dynamic information through downhole testing equipment can be acquired in real time—wirelessly and at sampling frequencies that were not possible only a decade ago.

Yet what seems to be a relative abundance of data often is challenged by the complex environments in which we operate and by our need to assess its value against associated costs and business risks. One way to look at this is under the premise that, while “perfect” information is beneficial to have, it also is costly to acquire and economically inefficient. Is there a unique answer in our choice of type curves, material balance, or specialized graphs? Should we account for multiphase flow or rock compaction? More importantly, what is the value of the next-best substitute for the information we require? And can this substitute information still allow us to meet our testing objectives? Herein lies the delicate balance between our choices of risk and uncertainty, which brings us to the message of this feature: We should not look for data-rich, but information-rich, content that meets our testing needs.

The papers selected for this feature describe exciting advances and opportunities in well testing. They also show that the proper use of advanced techniques can lead to maximizing the value of the information at hand, even in hostile and unconventional situations.

Read the synopses in the February 2012 issue of JPT.

Renzo Angeles, SPE, is a Senior Engineering Specialist with ExxonMobil Upstream Research Company. His 12 years’ experience includes technical consulting in North and South America, the Middle East, Europe, and Asia. Angeles works with the unconventional-resources integrated project, and his areas of interest include well testing, formation testing, hydraulic fracturing, and near-wellbore modeling. Angeles holds MS and PhD degrees in petroleum engineering from the University of Texas at Austin, and has published 16 papers. He serves on the JPT Editorial Committee.

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Drilling Technology

Since the first downhole electric measurement was made in 1927 by the Schlumberger brothers (first electrical-resistivity well log), the oil/gas industry has been striving to develop and improve new tools and sensors for downhole measurements. Indeed, these sensors aim at measuring many parameters, such as physical properties of rocks and fluids (formation evaluation), wellbore position (inclination and azimuth), or downhole drilling-mechanics conditions. Over the last 12 months, I have been impressed by the number of papers and news articles dealing with drilling mechanics and with vibration-data measurement, transmission, processing, and interpretation. Dynamics and vibration events still are responsible for high nonproductive time (NPT) (e.g., tool failures in many cases) and suboptimal drilling performances. With advances in electronics components, tool reliability, battery technology, and sensors, many companies have begun to develop their own memory-based drilling-measurement tools and to offer the associated service (data processing and interpretation) to operators to maximize drilling efficiency and, thus, reduce NPT.

These downhole drilling-mechanics-measurement tools, rated up to 150°C, generally integrate the following sensors: bending moment, vibration (three-axis accelerometers), weight on bit, torque on bit, annular pressure, temperature, and magnetometers (downhole rotational speed). Data are stored in a memory-based subassembly powered by a lithium-based battery (capacity up to 200 hours), or are transmitted to the surface (by use of mud-pulse, electromagnetic, or wired-pipe telemetry). The latest developments include ingenious sensors placed in the pin of the drill bit (avoiding an extra subassembly in the bottomhole assembly). Though measurements originally were captured close to the bit in the bottom portion of the drillstring, the industry has identified the need to have multiple sensors deployed all along the string (from the bit to the topdrive) to monitor continuously and anticipate any drilling event.

This outbreak of downhole-sensor technology is good news for the industry because it will probably accelerate the understanding of what is happening downhole even more, thus improving the overall drilling efficiency. Downhole drilling measurements should not be limited to only high-cost environments, but should be used in the early stage of the field development to accelerate the learning curve and, thus, optimize the drilling process for the next wells. Even though some downhole drilling and dynamics tools were developed in the 1980s, the industry now has more-accurate sensors, better physical models, and more computational power to process and analyze this huge amount of drilling data.

Read the synopses in the February 2012 issue of JPT.

Stéphane Menand, SPE, is Managing Director of DrillScan US. Previously, he held a research position at Mines ParisTech University. Menand has 14 years of experience as an R&D project manager in drilling engineering–more specifically in directional drilling, drillstring mechanics (torque, drag, and buckling), drilling dynamics, and drill-bit performance. He has authored several SPE and other technical papers and holds several patents. Menand earned a PhD degree in drilling engineering from Mines ParisTech University. He serves on the JPT Editorial Committee, the SPE Books Development Committee, and the SPE Drilling and Completions Advisory Committee.

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Offshore Facilities

Last year, we reviewed some of the more-prominent examples of how the industry continues to respond to the need for safe and cost-effective production facilities in ever-more-challenging environments. We also highlighted the increasingly important role that constructive collaboration can play in facilitating the desired outcomes for all parties.

This year, we illustrate how this same theme of constructive collaboration has been applied effectively at the other end of an offshore facility’s life span, in the major decommissioning program for the Frigg field. Most of us are very familiar with the term offshore hookup, but soon we may become equally familiar with what offshore “hookdown” really involves.

We also take a look at an approach for safely extending the useful life of aging offshore- production infrastructure, in locations where the subsea tieback of new fields warrants the associated investment.

Our focus is not entirely on end-of-life scenarios though. New offshore-platform concepts continue to evolve to suit the changing needs of operators. Some of these aim to offer the reduced well cost of fixed structures with the redeployment advantages offered by floating structures.

One of the most challenging new frontiers for the offshore industry and for society at large is the Arctic region. More specifically, it is development of underwater hydrocarbons where the presence of ice affects the nature of the development. Moving into any new frontier first requires gathering sufficient environmental data to be able to predict quantitatively the character and envelope of conditions at that location throughout the field’s production lifetime. We take a look at how these issues are being addressed in the specific case of the proposed Shtokman-field floating production facility.

As we return for this annual JPT Focus on the technology associated with offshore oil/gas facilities, it is timely to mention the launch of the new SPE magazine Oil and Gas Facilities, primarily geared toward the whole offshore-facilities sector. This effort represents a significant initiative to broaden the appeal and relevance of SPE to the wider oil/gas community, and any feedback that you may have in this regard would be welcomed warmly.

Read the synopses in the February 2012 issue of JPT.

Ian G. Ball, SPE, is Technology Director with Intecsea (UK) Ltd. Previously, he was retained by Reliance Industries Ltd Bombay, and was with Shell with assignments in Norway, the UK, and the US Gulf of Mexico. Ball earned a BS degree in electrical engineering from the University of Manchester Institute of Science and Technology. He serves on the JPT Editorial Committee and chairs the Editorial Committee of SPE’s new Oil and Gas Facilities magazine, the inaugural edition of which is available this month.

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Trends in Monitoring: How to Use Real -Time Data Effectively

David Pritchard, Successful Energy Practices International, Jesse Roye, Digital Oilfield Solutions, and J.C. Cunha, Ecopetrol America

Real-time data is not about well control, it is about well control avoidance. Recent catastrophic blowouts have underscored the value of real-time data and, more importantly, they have also underscored the value of having the right kind of experience to understand well data interpretation in real time.

What is the well telling us? How do we use real-time data to ensure a stable wellbore? Real-time monitoring integrated with rigorous total well control analysis is required to embrace and achieve continuous improvement and ensure the safest possible environment. Next generation monitoring requires a step change that includes hazards avoidance as a precursor to drilling optimization.

Real-time data can be used effectively to avoid, minimize, and better manage drilling and completion operations. They can also provide the foundational support to improve training in the industry as well as develop hands-on simulators for hazards avoidance.

Read the entire article in the January 2012 issue of JPT.

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Reducing the Hidden Costs of Subsea Well Completions

Stephen Rassenfoss, JPT/JPT Online Staff Writer

Subsea completions have made it possible to produce oil in remote locations and from smaller reservoirs. But the cost of maintaining them may shorten their productive lives.

“Subsea wells have the same things that go wrong as other wells, but fixing them requires moving in a rig and the cost can often be USD 1 million a day,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “Where there is direct access from a production platform, there is generally regular well intervention. As a result, the recoverable reserves are higher.”

Major producers such as BP, Chevron, ExxonMobil, Statoil, and Shell are among those seeking to cut the cost of deepwater workovers by 50% or more to allow better maintenance. There is no accepted industry average for how much production can be gained from regular interventions. The consensus is that the potential impact on the thousands of subsea completions represents billions of dollars worth of hydrocarbons.

Read the entire article in the January 2012 issue of JPT.

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The Tantalizing Promise of Oil Shale

Robin Beckwith, Staff Writer JPT/JPT Online

A vast energy treasure lies within an 18,963-sq-mile area of Colorado, Utah, and Wyoming: an estimated 4.28 trillion BOE of in-place resources of oil shale, according to US Geological Survey (USGS) research geologist Ronald Johnson. He presented the new assessment at the 31st Oil Shale Symposium, held mid-October 2011 at the Colorado School of Mines.

In other countries, while far fewer oil shale resources are thought to exist, their presence is nonetheless formidable. China contains an estimated 333 billion BOE; Russia, 248 billion BOE; Democratic Republic of Congo, 100 billion BOE; Jordan, 90 billion BOE; Brazil, 82 billion BOE; Italy, 73 billion BOE; Morocco, 53 billion BOE; Australia, 32 billion BOE; and Estonia, 16 billion BOE. Israel indicated at the 30th Oil Shale Symposium that its resources may be as much as 250 billion BOE.

The CIA World Factbook estimates 2011 world proved reserves of crude oil at 1.47 trillion bbl. Total annual production of oil shale in the only three countries today where it is exploited for commercial use is 73% less than daily worldwide crude oil production of approximately 86.74 million B/D.

With oil shale estimates vastly overshadowing those for crude oil, why does oil shale remain a scarcely touched resource?

Read the entire article in the January 2012 issue of JPT.