bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Private Equity View of the North Sea
Authors: Sword Graeme 
Published: February 2015

In the past year, significant developments have occurred regarding the prospects for North Sea oil and gas from a private equity viewpoint. Sustained high oil prices have led to a dramatic tightening of the North Sea assets market, making it tough for new, small oil companies to secure starter stakes. This has led to a large fall in the number of such companies seeking a North Sea position, and their focus has switched to areas of significant geopolitical risk backed by investors willing to accept greater uncertainty. However, considerable opportunities remain for novel hybrid oil and gas service/investor solutions that enable financially stranded North Sea assets to be developed. There has been a sharp improvement in prospects for the U.K.-based oil and gas supply chain, although strategic consolidations are important for capitalizing on emerging opportunities. Meanwhile, Norway is emerging as a place for private equity to invest in supply-chain opportunities.

Uncharted Waters
The global upstream oil and gas industry has entered uncharted waters with an unprecedented run of nearly 6 years of high crude prices. While crude oil prices have been higher than U.S. $50/bbl in the past—equating to U.S. $70 in today’s money—those were brief spikes. This time high prices are persisting, with agencies and analysts revising projections upward time and again. There is growing talk of oil shortages, if not raw resources then certainly supplies to the market, and energy conservation has re-emerged as a big issue. But it is only since late 2004 that broad-based confidence has returned to the Northwest Europe Continental Shelf and the U.K. sector especially. An indicator of this is the way in which drilling activity has picked up significantly, with no fewer than 70 exploration and appraisal wells predicted for the U.K. North Sea sector this year and 40 for Norway.
In the longer term, the operating expenditure and capital expenditure outlook to 2010 reflects returning confidence to a province regarded as mature and in sharp decline. The drop in U.K. oil production from January 2004 through January 2005 is 15.6%. Encouragingly, the U.K. Offshore Operators Assn. says in its 2005 survey that the North Sea remains a world-class basin that will pro-duce about 3.6 million BOE/D this year. Indeed, the now exceptionally positive outlook has driven demand for mobile drilling units to the point where the North Sea now faces an acute shortage of working rigs. Because of its close linkage with drilling activity, the offshore support-vessel market also has taken off, though construction remains relatively subdued.
Overlaying the North Sea is the global marketplace. Business is booming just about everywhere, especially in west Africa, the Caspian, the Indian subcontinent, East/Southeast Asia, and the Americas. Opportunities were excellent in 2004 and are now unprecedented for the industry, though possibly not for the investment community. Therein lies an irony.
Deployment of Swelling-Elastomer Packers
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92346, "Deployment of Swelling Elastomer Packers in Shell E&P," by Martijn Kleverlaan, SPE, Roger H. van Noort, and Ian Jones, SPE, Shell Intl. E&P, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
Shell E&P has deployed swelling elastomers in a variety of applications: as a means to establish zonal isolation in liner completions, as a production separation packer, and as an integral part of expandable openhole clad tubulars. In these applications, the elastomers were run in various openhole, casing, and tubing sizes. Approximately 60 deployments have been recorded, all of which were successful.

Introduction
In most areas where Shell operates, especially in the more mature oilfield environments, there is a high focus on well-cost reduction. Various technology applications have been identified to meet this business need and allow the operator to drill wells cheaper and smarter, making the most of existing infrastructure. One technology that is experiencing a rapid uptake is the application of swelling-elastomer packers. These packers, which swell naturally when exposed to the appropriate swelling agent, have been used successfully as a replacement for traditional mechanical packers and cement. The business case for using swelling-elastomer packers is different for each application and can include time savings as well as direct tool-cost savings. Shell used swelling elastomers in combination with a solid-expandable-tubular (SET) system called openhole clad (OHC) in July 2002. First application of swelling packers for zonal isolation was in the South Furious field in Malaysia in June 2003. Since then, more than 60 deploy-ments have taken place in Malaysia, Brunei, Nigeria, Gabon, Oman, and the U.K.
Advanced Completions Maximize Reservoir Potential in the Snorre Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92255, "Use of Advanced Completion Solutions to Maximize Reservoir Potential - Experiences in the Snorre Field," by L.T. Skarsholt, SPE, A.F. Mitchell, and A.H. Bjornsgaard, SPE, Statoil ASA, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
Snorre Blocks 34/4 and 34/7 were the first in the Norwegian North Sea to have sur-face-operated zonal control installed to allow selective production from different sections of the reservoir. The concept of downhole instrumentation and control systems (DIACSs) has been further developed and refined and today is used by many operators. The Snorre field remains at the forefront of this development, and the technology has been used in an additional 17 wells across the field. The full-length paper focuses on the use and advantages of advanced completions.

Introduction
The Snorre field, operated by Statoil ASA, is in Blocks 34/4 and 34/7 of the Norwegian North Sea, approximately 150 km northwest of Bergen. Snorre A, which started production in 1992, consists of a tension-leg platform and a subsea production system in a water depth of approximately 350 m. Produced oil is exported to Statfjord A, while part of the gas is reinjected and part is exported to Statfjord A. As of November 2004, Snorre A consisted of 30 oil producers and 23 injectors, including subsea wells. Snorre B, which came on stream in June 2001, is a semisubmersible drilling, process, and accommodation platform. Oil is exported to Statfjord B, and the produced water and gas are reinjected. Currently, six production wells and three injectors are connected to Snorre B.
The Snorre field is a complex reservoir consisting of fluvial sandstones representing various fluvial styles and subfacies. The lateral extent of the channel belts varies from 300 m to several kilometers and the permeability from a few hundred millidarcies to several darcies. The channel belts are stacked and interbedded with mudstone, and under dynamic flowing conditions, several pressure regimes have been developed because of the limited vertical and lateral communication. It was originally planned that the undersaturated oil would be recovered with downdip water injection as the drive mechanism, but this was changed at an early stage to water-alternating-gas (WAG) injection to improve oil recovery as well as provide a method to use excess gas.
As of November 2004, the Snorre field had an expected stock-tank oil originally in place of 532×106 m3, with expected oil reserves of 242×106 m3.
Overview: Reservoir Performance and Monitoring (September 2005)
Authors: Potsch Klaus 
Published: February 2015

We Still Don’t Know Enough
This year, the selection process was a major effort. A sizable pile landed on my desk. Going through the topics, I encountered very familiar subjects, subjects that I thought had already been dealt with and solutions made available. I cannot, of course, check all the papers for their innovative content, so there are several factors that could have influenced the process.
- The authors did not perform a literature search and reinvented the wheel.
- The process of approaching the solution is cumbersome and the incremental gain of knowledge is small.
- The authors need publications to survive; therefore, they release only a portion of what they already know to keep a reserve for future publications.
- I am not aware of how complicated the problem is.
With the easy and quick wins in the applications and the theory being already gone, the focus turns more and more to the hard parts and pieces. In comparison with the clastic reservoirs, the carbonates demand more care, diligence, and thinking. The pore system is no longer a single one. Matrix properties are easily accessible in laboratory measurements. But what everybody wants to know is how much is in the fractures and how easily the fluid will flow. However, especially these parameters hide behind other data. Put a condensate-fluid system into such a porous medium and the challenge is complete.
The engineers need to plan future production carefully. Therefore, attempts are increasing to improve the flow assurance and the surveillance of the wells. Permanent downhole devices produce more data than we can handle, which leads to another need: namely, data reduction. Further, there also are cases in which the well data and the production figures are scarce. The engineers will have to deal with both.
Available from the SPE eLibrary: www.spe.org
SPE 92060 - “Finding Natural Fractures and Improving Reservoir Performance in Western Venezuela: An Integrated Approach,” by Franco, A., Repsol YPF, et al.
SPE 93297 - “A Mechanistic Model To Evaluate Reservoir Souring in the Ekofisk Field,” by Burger, E.D., SPE, EB Technologies, et al.
SPE 94995 - “A Case History of Value Generation With Intelligent-Well Technology in a High-Productivity Thin-Oil-Rim Reservoir ,” by Elmsallati, S.M., SPE, Heriot-Watt U., et al.
Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2005)
Authors: Goodman Harvey E. 
Published: February 2015

My October 2004 Overview “Wellbore Stability and Sand Control” began with a narrowly focused comment on near-well-bore-failure modeling and the difficulty of predicting the consequences of this failure to operations. I then introduced my opinion that the key value of geomechanics technology is to provide a consistent reference frame against which well failure-to-production trends can be measured.
This year’s Overview “Wellbore Integrity, Sand Management, and Frac Pack” continues to broaden the science of well failure, reaching out beyond the failure event to understand the effect on the entire production system. The operational goal is to ensure that the well system designs provide production reliability, availability, and maintainability throughout the economic life of the asset.
To achieve this goal, one must be able to characterize wellbore integrity reliably and understand completion dynamics, from sand failure and sand production to sand management in the production system. It is of particular interest to characterize completion-performance behavior reliably over time, including near-completion reservoir flow mechanics. The papers selected for this month’s review begin to satisfy these rigorous goals.
Available from the SPE eLibrary: www.spe.org
SPE 90164 - “Novel Perforating System Used in North Sea Results in Improved Perforation for Sand-Management Strategy,” by Hillestad, E., Statoil A/S, et al.
SPE 90530 - “The Significance of Non-Darcy- and Multiphase-Flow Effects in High-Rate Frac-Pack Gas Completions,” by Lolon, E.P., SPE, Texas A&M U., et al.
SPE 94758 - “3D Analysis for Wellbore Stability: Reducing Drilling Risks in the Oriente Basin, Ecuador,” by Torres, M.E., SPE, Schlumberger, et al.
Management: Building the High-Performance E&P Company
Authors: Close Deborah 
Published: February 2015

In the E&P industry, the product is the same for all companies: oil and gas, or some form of them. So unlike, for example, the automotive or pharmaceutical industry, E&P companies cannot differentiate themselves by producing a new and exciting product. Rather, E&P companies differentiate themselves based on their ability to find and produce oil and gas more efficiently than their competitors. Even though the E&P industry is in many ways unique, there are lessons to be learned from studying other industries and the characteristics of their high-performing companies.

Lessons Learned From Dell and Wal-Mart
Michael Hammer is a well-known business author who has written a number of books and articles on high-performing companies. He has studied in depth companies such as Dell and Wal-Mart, two companies that are held up as shining examples of high performance and leadership in their respective industries. What might Dell and Wal-Mart have in common with the E&P industry?
First, like oil and gas companies, these companies are not differentiated by their products. Dell is the leader in the personal computer industry, an industry the product of which is considered to be a commodity. Wal-Mart is the premier retailer in the world, but Wal-Mart does not sell unique products. In both cases, the products they sell are not easily differentiated, so these companies have had to establish a competitive advantage in other ways. Certainly, they have developed unique features in their business models and customer interface. For example, Dell has focused on a mail-order or online customer interface and delivery mechanism. Wal-Mart, on the other hand, is known for its friendly service, employee training programs, and store greeters. But surely, these are characteristics or strategies that could be replicated by competitors. Moreover, in both the computer and retail industries, competition is fierce, and margins are paper thin. What is it that consistently sets these leaders apart from their competitors in such a tough environment?
Hammer refers to a characteristic he calls "operational innovation," which he defines as "the invention of new ways of doing work." When examining Dell and Wal-Mart, one finds that these companies did not grow through diversification of businesses, nor did they grow through merger and acquisition. On the contrary, both companies have "stuck to their knitting" and have grown by systematically and organically increasing market share. They have been able to do this because they have practiced operational innovation, which has produced superior profitability compared with their competitors. For example, both Dell and Wal-Mart are recognized leaders in supply-chain management. They have integrated and innovated the processes for engaging and communicating with their suppliers, and have done so in a way that their competitors have been unable to replicate. That is because the process changes are not incremental or evolutionary; they reflect a completely new way of interacting with suppliers. They are revolutionary.
Laboratory Perforating Tests in Coal Results in Lower-Than-Expected Penetration
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102309, "First Laboratory Perforating Tests in Coal Show Lower-Than-Expected Penetration," by P.M. Snider, SPE, Marathon Oil Co.; I.C. Walton, SPE, Schlumberger; T.K. Skinner, Marathon Oil Company; and D.C. Atwood, SPE, B.M. Grove, SPE, and C. Graham, SPE, Schlumberger, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
The full-length paper describes a laboratory-testing program to investigate shaped-charge penetration in coal targets. Mechanical properties of the coals tested and penetration results for different shaped charges shot at various stress conditions are described. Preliminary experiments indicate that shaped-charge penetration in coal is significantly less than expected, considering the density and strength of the target.

Introduction
Estimates of world coalbed-methane (CBM) reserves range from 4,416 to 8,556 Tcf, with 749 Tcf located within the US. Production of CBM has increased steadily in the last decade, particularly in the US, which would seem to justify additional perforating research.
The coal samples used in the present testing program came from a producing formation in Wyoming's Powder River basin, which covers approximately 4.3 million acres and contains an estimated 800 billion tons of subbituminous coal. This CBM resource consists of many shallow seams from 200 to 3,000 ft deep. An estimated 12,000 wells are in production in the Powder River basin, and an estimated 50,000 more wells will be drilled in the next 5 to 10 years. Average well production is 163 Mcf/D, with an average estimated life of 8 to 10 years. Gas produced from Powder River basin coal is almost 100% methane, with an estimated 25 to 50 ft3 of gas per ton of coal, although gas content varies appreciably among the various coal formations.

Completing CBM Wells
Unlike sandstones, which trap natural gas in the intergranular-pore spaces, coal adsorbs the gas onto its surface. Production of this gas is contingent on reducing the pressure in the reservoir to allow the gas to desorb off the coal face. Once the gas is liberated, it must be transported to the wellbore. Therein lies the second difficulty in completing coal reservoirs because the permeability of the coal matrix often is very small. Fortunately, coal has many natural fractures, or cleats, through which the produced gas can flow. One of the major objectives of a CBM completion design is to provide effective communication between the wellbore and the natural-fracture, or cleat, system.
Overview: Reservoir Performance and Monitoring (September 2007)
Authors: Clemens Torsten 
Published: February 2015

Optimizing hydrocarbon production and recovery requires fluid-production allocation from the different layers encountered in the wells. In recent years, downhole-monitoring systems have been used increasingly to unravel bulk production data measured at the surface. In particular, multilateral and "smart-well" technologies require much more-detailed spatial information about inflow than conventional wells.
One technology that has been improved significantly is the use of fiber-optic sensors. The first oilfield application of this technology was in steam-injection projects. With advanced understanding, improved sensors, and simulation of the well/reservoir coupling, fiber-optic sensor data can now be used for flow profiling, monitoring minifrac treatments, or diagnosing pumped wells, as discussed in the first featured paper.
On the reservoir scale, time-lapse (4D) seismic is used to monitor fluid movements directly. This method determines changes in seismic signals to infer fluid-saturation changes in the subsurface. However, techniques other than seismic can detect changes at the reservoir level. The second featured paper gives an example of such a technology: Surface-gravity measurements were used to monitor water injection into the gas cap of a large field.
The methods described above, for which gathering detailed downhole data or reservoir-scale time-lapse data is required, can be expensive and time consuming. However, a wealth of production data is continuously recorded at surface. These data are the key source for reserves evaluation by decline-curve analysis and for simple forecasting of hydrocarbon production. Paper SPE 107967, which is recommended for further reading, shows that much more information about the well and reservoir can be derived from these data by use of a new derivative function.
Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org
SPE 107967 "Application of the β-Integral Derivative Function to Production Analysis" by D. Ilk, SPE, Texas A&M University, et al.
SPE 107268 "Placement of Permanent Downhole Pressure Sensors in Reservoir Surveillance" by B. Izgec, SPE, Chevron, et al.
SPE 102801 "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity" by S.C. Maxwell, Pinnacle Technologies, et al.
4D Microgravity Surveillance of a Waterflood - Prudhoe Bay, Alaska
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101762, "Results of the World's First 4D Microgravity Surveillance of a Waterflood - Prudhoe Bay, Alaska," by J.L. Brady, SPE, BP Exploration Alaska; J.L. Hare, Zonge Engineering; J.F. Ferguson, U. of Texas at Dallas; J.E. Seibert, Seibert & Assocs.; and F.J. Klopping, T. Chen, and T. Niebauer, Micro-g Lacoste, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
A 4D surface-gravity surveillance of a waterflood was implemented at Prudhoe Bay, Alaska. This monitoring technique is essential for surveillance of the gas-cap water-injection (GCWI) project. Drilling numerous surveillance wells to monitor water movement adequately would have been cost-prohibitive. Field surveys showed conclusively that density changes associated with water replacing gas are readily detected by use of high-resolution surface-gravity measurements.

Introduction
The fundamental problem in monitoring the GCWI project is sparcity of monitoring wells and lack of producing wells in the gas-cap area of Prudhoe Bay. Distances between some monitoring wells are greater than 10,000 ft, and years would be required for the injected water to propagate these distances. Too few wells exist to monitor the water movement adequately with conventional downhole-logging techniques. Therefore, the Prudhoe Bay surveillance program uses a combination of conventional downhole logging in existing wells and 4D surface-gravity monitoring. The major monitoring concern with the waterflood is to ensure that water added in the gas cap does not prematurely flow downdip into the oil-producing portions of the field, where it could interfere with a highly efficient gravity-drainage mechanism.
Surface-gravity instruments measure the Earth's gravitational field at a specific point, or station. With an array of these measurements, local structural traps, stratigraphic traps, or fluid movement can be identified if sufficient density contrast exists between the feature of interest and the surrounding rock. The surface-gravity technique can be applied to any field, depending on reservoir thickness, size, depth of burial, porosity, and density contrast between the fluids. The surface-gravity technique requires that several time-lapse gravity surveys be made over the life of the field. The first survey should be performed before any change occurs in the fluid volumes to obtain baseline data. The baseline survey can be subtracted from future gravity surveys to obtain the gravity anomaly associated with the change in fluid volumes. The technique assumes that any other time-dependent gravity changes can be accounted for by measurement or modeling, and that noise caused by the measurement process and unmodeled (near-surface) density changes has tolerable characteristics.