bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Thinking Boosts Maturing UK Continental Shelf
Authors: Sheehan John 
Published: February 2015

With the record oil prices of recent years, major operators in the UK North Sea have been holding onto assets and extracting as much value from them as they can. Companies such as BP, Shell, Total, and Chevron are applying new technologies to increase recovery rates and prolong the life of their existing assets.
This is a reversal of the trend of just a few years earlier when smaller independents came in to the region and snapped up producing assets that were deemed noncommercial by some of the indigenous oil companies. As a result, the UK North Sea is now being given a boost by both the established players and the independents, which are also applying innovative thinking and technology to tap the basin's existing reserves.
Malcolm Webb, Chief Executive of Oil & Gas UK, the leading representative body for the UK offshore oil and gas industry, has always been wary of tales of the bigger players turning their backs on the North Sea.
"I would say the stories of the majors leaving the North Sea were always slightly overdone," he said. "I think what we saw was a rebalancing of their portfolios. We saw some rather good asset deals for the basin going ahead and newcomers like Apache and Talisman coming in, picking up older assets, and bringing in new vitality and reworking them. Underneath all that we saw a continuing determination of the majors to go on working the basin generally and they have continued to invest. I think the view they were on a mass departure route was always overplayed.
"I think there are very positive signs that they are continuing to invest. If we look at majors like Total, Chevron, and BP, it is very interesting that they are all involved in the West of Shetlands activity. Total is looking to take forward some significant investments out there and Chevron has made good discoveries there as well, so there is lots of activity going on. They are also active elsewhere in the central and northern North Sea."

Moves to Reverse Production Decline
The UK Continental Shelf (UKCS) has so far had approximately 38 billion bbl of oil produced and the consensus among geoscientists is that another 25 billion bbl are still in play. But there is an alarming 7% annual production rate decline on the UKCS, a rate that Webb says must be pegged back.
Technology Focus: Reserves/Asset Management (December 2008)
Authors: Rietz Dean 
Published: February 2015

Technology Focus
As a consultant who routinely is asked to assist clients on reservoir management (through reservoir studies), it is sometimes surprising when the usefulness of reservoir studies is questioned. First, it should go without saying that a reservoir study should be embarked on only to answer specific questions such as:How much oil or gas will be recovered from a particular asset?Can the same amount be recovered with less investment?Can more be recovered by use of optional operating approaches?
But the real question is, Why conduct a study in the first place? After all, once we find the asset, the reservoir properties (e.g., its size and the rock and fluid characteristics) are "what they are" and we cannot change them. Can we affect recovery by managing the reservoir, or must we simply accept what we get?
This brings us to a simple comparison with hurricanes. Earlier this year, the Houston area was impacted significantly by Hurricane Ike. Hurricanes, like petroleum reservoirs, occur naturally, and the characteristics (the fundamental properties that define them) are unique to that entity and are uncertain. In both cases, however, we can use tools (such as numerical models) to project and forecast their future behavior.
In the case of Ike, the weather models forecasted landfall in the vicinity of Galveston—well in advance, which enabled making decisions and taking action. To save lives, much of the anticipated impact area was evacuated. In addition, relief supplies, equipment, and personnel were prepositioned (out of harm's way) to respond quickly. The result was fewer casualties than experienced with earlier devastating hurricanes and an immediate response to begin the recovery process.
Just like preparing for the inevitable landfall of a hurricane, companies can plan for the inevitable depletion of a reservoir. Reservoir models, for example, can and do help identify more-efficient methods of hydrocarbon recovery. So, why are studies performed and reservoir-management strategies implemented? There are two main reasons: to improve recovery efficiency and/or maximize the return on investment of a particular asset. Our industry has the technology and the know-how.
Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org
SPE 112932 • "Simplified Country-Entry Risk-Assessment Model for Global Petroleum Investments" by Surya Rajan, SPE, Marathon Oil Company, et al.
SPE 113260 • "Reservoir Management of the Gullfaks Main Field" by Saifullah Talukdar, SPE, StatoilHydro, et al.
SPE 111717 • "Real-Time Reservoir Management From Data Acquisition Through Implementation: Closed-Loop Approach" by Saeed M. Mubarak, SPE, Saudi Aramco
Additional reading available at OnePetro: www.onepetro.org
OTC 19644 • "International Risk Management" by Daniel V. Murphy, Systech International
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2008)
Authors: Mensa-Wilmot Graham 
Published: February 2015

Technology Focus

Performance Drilling—Taking the Next Big Steps
Drilling continues to be pushed into harder, deeper, and sometimes depleted environments. In addition, well profiles have become more complicated. As a result, footage drilled per bottomhole assembly (BHA) and rate of penetration (ROP) usually are low. These issues, if left unattended, will drive up drilling costs exorbitantly. Solutions are needed that will increase both footage drilled and ROP.
Researchers focusing on these issues have identified three key findings. First, performance improvement is a drilling-system problem (i.e., drill bit, BHA, and drive system) and is less dependent on individual components. Second, optimization of performance qualifiers (specifically footage, ROP, vibrations control, directional effectiveness, and borehole quality) is not an exclusive process. Third, real-time identification and remediation of drilling dysfunctions are critical to the drilling process.
The design and selection of drill bits must evolve from a feature-based approach to a technology-driven process. Drill-bit manufacturers need to move away from the current "me, too" approach, when it comes to product development. Local field knowledge, in terms of dips and behaviors, is critical and must be incorporated into BHA design. The BHA-design process must be fast, practical, and reliable. Drive systems (e.g., rotary-steerable types, mud motor, and turbine) must be selected on the basis of their effectiveness and relevance to project success. In this effort, rig specifications, operational hydraulics, formation drillability, and well profiles must be considered also. Offset performances should guide, but not drive, decisions made for subsequent wells.
Real-time data acquisition and interpretation are critical for the industry's next big steps in drilling performance. These data will guide the drilling process, in terms of anticipated formations, identification of dysfunctions, and parameter selections. As an industry, we have all the pieces—we need to bring them together quickly, to solve the puzzle.
Bit Technology and Bottomhole Assemblies additional reading available at the SPE eLibrary: www.spe.org
SPE 112647 • "A Systematic Approach to a Better Understanding of the Concentric-Hole-Opening Process Utilizing Drilling-Mechanics and Drilling-Dynamics Measurements Recorded Above and Below the Reamer" by Ian Thomson, Baker Hughes, et al.
SPE 112731 • "Optimization of Deep-Drilling Performance With Improvements in Drill-Bit and Drilling-Fluid Design" by Alan D. Black, SPE, TerraTek, et al.
SPE 115395 • "The Use of the Industry's First 3D Mechanical-Caliper Image While Drilling Leads to Optimized Rotary-Steerable Assemblies in Push- and Point-the-Bit Configurations" by Junichi Sugiura, SPE, PathFinder Energy Services, et al.
Multidiameter Tools Deliver Lower Cost Per Foot
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112785, "Multi-Diameter String Tools Deliver Lower Cost- Per-Foot in Demanding Rotary-Steerable Applications," by Steve Barton, SPE, Wayne Jones, SPE, and Rick Young, ReedHycalog, and Helge Rorvik, SPE, Halliburton, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
Use of hole-opening tools in conjunction with rotary-steerable systems (RSSs) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternative options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run. The most popular current option involves a weight- or hydraulic-actuated under-reamer. However, fixed-blade, multidiameter reaming tools have been developed recently for use within rotary-steerable (RS) assemblies.

Introduction
Hole-opening tools fall into two main categories: eccentric and concentric. Eccentric reamers are fixed reamers that are dominated by bicenter drill bits or "wing-like" string reamer tools using polycrystalline-diamond-compact (PDC) cutters. They are developed for applications where hole enlargement is required but where the tool has to pass through a smaller-diameter restriction than that of the final hole size. The concentric tools are more diverse and range from fixed designs such as concentric drill bits and string tools (that could be either PDC or roller-cone cutting structures) to more-complex tools that open on demand by either mechanical or hydraulic control.
The growth in the use of hole-opening devices over the last few years was driven predominantly by the growth of deepwater drilling. The lessons learned from innovations in the deep water have extended those applications to shallower waters and even to selected land wells. Hole-opening-while-drilling devices have enabled operators to set larger strings of casing deeper in holes where hole stability, lost circulation, and high-pressure zones are a constant problem. This has the advantage of eliminating trips while leaving sections of open hole exposed over shorter durations, as well as providing a larger annulus for better cement jobs. The ability to reach extremely deep reservoirs with 12 1/4-, 10 5/8-, and 8 1/2-in. wellbores enables operators to run larger and more complex production strings, and this in turn has had an enormous effect on exploration-and-production economics.
Technology Focus: Production/Facilities (December 2008)
Authors: Skeels Brian 
Published: February 2015

Technology Focus
Subsea processing is one of the most interesting technologies being introduced to the oil and gas industry. Treating the production flow at the seabed opens up opportunities to more-remote oil and gas reservoirs around the world. This operation is especially important because the industry is running out of reservoirs that are easy to produce, meaning that the focus is placed on how to produce oil and gas from longer-offset offshore fields in deeper reservoirs with difficult bathymetry.
A growing number of subsea multiphase pumps have been in operation around the world for several years to address less-than-ideal natural-reservoir-drive conditions. This growth has been followed by successful installation of subsea separation in the North Sea to address less-than-ideal flow characteristics and production of sand and unwanted byproducts. These technologies are being combined at a systems level to optimize reservoir recovery and management. Recent startups of combined subsea-separation, -boosting, and -injection systems offshore Africa, Brazil, and the deepwater Gulf of Mexico are adding to subsea processing's maturity and widespread acceptance.
Subsea processing continues to take steps into the future with project sanctions that use gas/liquid separation and oil/water separation. The next generation of processing systems will focus on more-compact solutions that will be well suited for deepwater applications. In addition, considerable effort is being made in the area of raw-water injection, low-/no-oil-fraction discharge, and subsea gas compression, all promising great potential for greater hydrocarbon extraction, saving the costs for additional surface infrastructure.
Production/Facilities additional reading available at the SPE eLibrary: www.spe.org
IPTC 12377 • "Plant Integrity and Reliability are the Keys To Improving Profitability" by S.D. Kapusta, Shell, et al.
SPE 115074 • "Corrosion and Hydrate Control in Wet-Sour-Gas Transmission Systems" by J.J. Moloney, SPE, Baker Hughes, et al.
Offshore-Connectivity Solutions for the Oil and Gas Industry
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117254, "Offshore Connectivity and Ultra-Long Tiebacks Solutions for Oil & Gas," by A. Lecroart, R. Michel, and J.P. Odier, Alcatel-Lucent Submarine Networks, originally prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.
The oil and gas industry is forced to go into deeper water further offshore to find new oil or gas. At the same time, the industry is placing more emphasis on integrated operations driven from onshore control centers. Highly reliable communications solutions are required to fulfill these objectives. Large bandwidth and low latency links between offshore facilities and the shore are essential for communications to all company personnel and contractors engaged in the offshore development areas. The full-length paper describes overall solutions to address these needs and reviews available technologies.

Introduction
Exploration and production of offshore fields is evolving and makes use of various modes of communication. Many oil companies are establishing operations centers where technical expertise is located. Telecommunications from the field to these centers is becoming critical, and solutions exist to make communication both efficient and dependable, with a choice of different technologies listed in Table 1 in the full-length paper.

Dry/Dry Solutions
The dry/dry solutions adapt the traditional shore-to-shore telecommunication application so that it can be used with different types of offshore assets such as a fixed platform or floating assets such as a tension-leg platform, a spar, or a floating production, storage, and offloading vessel (FPSO). One would prefer ring or loop architectures connecting each asset with its own spur by use of a branching unit (BU). The system is designed to allow the platforms to be independent and limits the number of risers per asset to one, compared to a simple daisy chain. For the last-mile connection, a dynamic riser is required to access floating assets, while a simple J-tube may be sufficient with shallower fixed structures. Another complexity may come from the use of fiber-optics (FOs) rotating joints because the latest generation of FPSOs tends to adopt a turret architecture, allowing the vessel to rotate freely. In most cases, studies are required to validate and qualify the riser design according to the requirements of the structure and the local weather conditions. A second approach is to equip an umbilical with fiber and allow the last-mile connection to take place subsea with a combination of wet-mate connectors and subsea manifold. In this case, a special cable termination is provided allowing remotely-operated-vehicle (ROV) handling of the wet-mate connector by use of a length of flexible hose. Both approaches are valid and will solve the last-mile issue adequately.
Cryogenic Technology for Processing High-CO2 and -H2S Gas Reserves
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12708, "Controlled Freeze ZoneTM Technology for Enabling Processing of High CO2 and H2S Gas Reserves," by J.A. Valencia, P.S. Northrop, and C.J. Mart, ExxonMobil, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
Global natural-gas reserves increasingly are reported with significant CO2 and/or H2S content. Concentrations of 20 to 40% are not uncommon. Commercialization of such resources poses significant economic and technical challenges. Approximately one-sixth of ExxonMobil's hydrocarbon resources are categorized as sour gas. With these volumes, ExxonMobil has the industry's largest sour-gas resource base and has more than 50 years experience in managing sour gas.

Introduction
Monetization of lesser amounts of saleable methane/hydrocarbons while at the same time producing, removing, and disposing of major quantities of acid-gas contaminants calls for technologies that can reduce capital and operating costs. The proper disposal of these contaminants adds to the challenge. Release of CO2 to the environment is not desirable, its geosequestration is a much better alternative, and it would be better yet if it can be turned into a product stream to be sold or used for enhanced-oil-recovery (EOR) purposes. Similarly, alternatives for the disposal of H2S are needed because the conventional conversion to elemental sulfur led to the saturation of many markets. While there has been a recent resurgence in the demand for sulfur, uncertainties about wide-spread demand sustainability encourages the development of alternative H2S-disposal options.
The cryogenic technology, developed at ExxonMobil Upstream Research Company, is being advanced to the commercially ready stage in response to these needs. The first choice for many separations in the gas industry are those that take advantage of the simplicity provided by differing relative volatilities and phase behavior and are implemented by flash drums, separators, and distillation and fractionation towers. In the presence of methane, and to yield sales-quality gas, such separations imply very low, cryogenic temperatures of −120°F and lower, depending upon the operating pressure. CO2 solidifies at these low temperatures. The experimental measurement and analysis of CO2-solidification conditions in the presence of methane were pioneered in 1954. Shortly thereafter, a new process was proposed for freezing CO2 from natural gas by flashing a cooled gas stream into solidification conditions and using a cyclonic device to separate the resulting slurry into solid CO2 and liquid methane.
Conversations: Globalizing SPE Awards
Authors: Fattahi Behrooz 
Published: February 2015

President's column
As I write this, we have just completed our Annual Technical Conference and Exhibition. A highlight of this event is always the presentation of international awards to our members for their technical and professional contributions.
SPE's international awards recognize the outstanding achievements of members who have given outstanding levels of technical knowledge, time, energy and expertise to SPE and to advancing the industry. These awards are particularly prestigious and meaningful because they are conferred by peers. As SPE has grown globally, we have made special efforts to ensure that the awards program engages our worldwide membership. Yet we know that many deserving individuals have not yet been recognized for their work. Although we have seen significant increases in the geographic diversity of the award recipients since 2001, we know we can and must do more to publicize our awards program to nurture global participation. A good start is to ensure that members understand the nomination and selection process.
The timing of this column is fortunate, since nominations for the 2010 awards are due no later than 15 February.
I'd like to discuss three important points about our awards program:How SPE goes about selecting award recipientsWhat you can do to prepare a nomination that will most effectively present the accomplishments of your colleague to the selection committeeWhat SPE is doing to improve the awards process

Award Selection Process
The selection of the SPE international award winners requires a huge volunteer effort. First, our members must step up to nominate their peers. These nominations are reviewed by the respective awards committees (15 of them!), made up of members from throughout the world who have the technical or professional qualifications relevant for the particular award. In 2009, 50% of award committee members were from outside the US, reflecting the makeup of our membership. Each award committee operates independently of the others, and does not know the geographic locations of the recipients selected by other committees. Each committee makes its selection only on the basis of the nominations received for its award. The committees are charged with identifying the most qualified recipient from among the nominations received. We do not have a quota system based on regions.
To further increase the number of international candidates, SPE expanded its regional awards in 2006 to include technical awards and additional service awards. The regional award recipients are automatically added to the nominations for the comparable international awards in the following year. The geographic distribution of the recipients changes from year to year, depending on the number of nominations submitted from around the world and the quality of the nomination information.
Note that, above, I said that committees select award winners from among the nominations received. So, first you have to nominate somebody. That leads to my second point: preparing an effective nomination is essential.