bluuebunny/crossref_metadata_2025_split huggingface dataset:
Focus on Africa: Betting Big on Africa
Authors: Marks Harvey 
Published: February 2015

Chevron has deep roots in Africa. The company began marketing operations on the continent in 1911 and drilled its first well there in 1958. From these relatively modest beginnings, Chevron's commitment to Africa—as well as that of other major operators—has grown as the continent's stature as a major petroleum province has risen. In the last five years, Chevron has invested more than USD 13 billion in Africa, including deepwater projects in the Congo, Nigeria, and Angola, as well as operations in Chad and Libya.
In 2008, those countries represented 15% of companywide production, including oil sands, and that figure is certain to increase as new African projects ramp up production.
By 2011, new projects in Africa are expected to add another 620,000 BOPD to the company's output. On top of that, there are ongoing discoveries. These include the Moho Nord Marine-4 well in the Republic of the Congo, which was confirmed in May. It is located in the Moho-Bilondo license approximately 46 miles offshore in 3,537 ft of water. Drilling was to a total depth of 13,907 ft and proved a 535-ft column of high-quality oil flowing at 8,100 B/D. Partners in the Moho-Bilondo field include Total E&P Congo, the field's operator, and Société Nationale des Pétroles du Congo.
"This exciting discovery emphasizes the future potential of this region in which Chevron and its partners have already made significant energy investments," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production. He added that maximum total daily production of 90,000 bbl of oil from Moho Nord Marine-4 is expected in 2010.
This discovery follows two previous successful exploration wells, Moho Nord Marine-1 and -2, drilled in the permit area in 2007, and the positive appraisal well Moho Nord Marine-3 in 2008. The Moho-Bilondo field, which consists of subsea well clusters that flow into a floating processing unit, was discovered in 1995 and began production in April 2008.
New Training Alliance Focuses on Industry's Skills Shortage
Authors: Edmundson Henry 
Published: February 2015

Talent & Technology
In recent times, it has become commonplace to read of the oil and gas industry's skills shortage. E&P projects large and small have been severely limited by supply-chain shortfalls of all kinds, but most notable has been the lack of availability of petrotechnical expertise. Known so familiarly as the "great crew change," our expertise shortage today is due mainly to the industry's poor or nonexistent recruiting in industry-periodic downturns, particularly during the late 1980s.
The age demographics of petrotechnical professionals in different operating companies vary enormously, but three factors are usually present. First, the midcareer range tends to be depleted everywhere. Thus, companies are under huge pressure to develop their young people faster than they are accustomed. Second, companies have been very actively recruiting in recent years, at least until the global recession and associated oil and gas price fall, and therefore the number of young recruits requiring professional development is larger than ever before. Third, companies cannot ignore the development of personnel of any age and experience as new technology continually comes into play and must be learned.
So how to get the most bang for our buck when it comes to professional development? Numerous studies have sought to understand the return on investment in training. Time and again, it has been shown that training based on a competency model provides the surest route to spending training money wisely. Competency models provide a firm baseline for assessing skill levels and ensuring training is fit for purpose. It has been shown that training based on a competency model shortens time to professionalism, or time to autonomy as it is also referred to, by at least two years.
Studies also point to the advantage of using a mix of learning methods rather than relying on just one method such as classroom learning. The traditional classroom environment has its place, but so does e-learning, on-the-job learning, case-study learning, and for disciplines such as geosciences, instructional seminars in the field. Finding the right combination at the right time in the development cycle is what counts.
Finally, coaching and mentoring remains an essential requirement in any training program. Training must develop both discipline knowledge and the experience to apply that knowledge. Gaining experience takes time, but it can be dramatically accelerated if a coach is present to provide guidance and a helping hand. Good technical coaching and mentoring is a recognized attribute of all leading training programs.
Technology Focus: Horizontal and Complex-Trajectory Wells (November 2009)
Authors: Conran Greg 
Published: February 2015

Technology Focus
The past year has experienced dramatic changes in industry activities. Despite the downturn, it has been encouraging to see that there has remained an active interest through various industry events and discussions in improvement in the delivery of complex wells.
I had the opportunity to participate in several SPE Advanced Technology Workshops (ATWs) and Forums related to this topic, and it was great to see record attendances, which provided for a diverse, yet high-quality, discussion and interaction. Design factors, improving drilling execution, and complex-well design, along with maximizing reservoir contact for horizontal and complex wells, are still major industry drivers, even though the industry has already drilled and completed many thousands of these wells.
Every year, new technology enters the market place providing potential for improvement of all aspects of horizontal-well operations, but on the basis of excellent and open discussions at SPE events, there still are further challenges to overcome. Conclusions from several meetings included positive reactions to the introduction of new technologies in helping drive performance to new levels, but it was highlighted that the repeatability depended upon good knowledge capture and transfer of learning.
Development of the structured approach, focused on continuous improvement, is as relevant today as it was 20 years ago. This message was echoed at all ATWs and Forums. The reduction in nonproductive time and overcoming operational challenges through better planning, although well known, are still a required focus.
As the industry adapts to a constantly evolving horizontal- and complex-well environment, positional accuracy and placement of the well trajectory are critical to better reservoir contact and production.
One interesting conclusion was that the successful drilling of many highly challenging wells appears to have been taken for granted. However, delivering the completion phase on long-stepout wells and management of the reservoir remain challenges for the future.
Horizontal and Complex-Trajectory Wells additional reading available at OnePetro: www.onepetro.org
SPE 118809 • "Beyond the Technical Limit: Turbodrilling—A Paradigm Shift to World-Class Horizontal-Well Construction" by Todd Mushovic, BP plc, et al.
SPE 119599 • "Inflow-Control Device: An Innovative Completion Solution From Extended Wellbore to Extended Well Life Cycle" by Saif Ali Al Arfi, ADCO, et al.
SPE 120579 • "A Comparison Between Multifractured Horizontal and Fishbone Wells for Development of Low-Permeability Fields" by Xiance Yu, University of Louisiana at Lafayette, et al.
SPE 123008 • "First Applications of Inflow-Control Devices (ICDs) in Openhole Horizontal Wells in Block 15, Ecuador" by P. Roman, Petroamazonas, et al.
OTC 19910 • "The Longest Challenge: Overview of a Groundbreaking Horizontal Well in Gimboa Field, Angola" by K.D. Contreiras, Sonangol Pesquisa & Produção, et al.
Continuous Improvement Led to the Longest Horizontal Well
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119506, "How Continuous Improvement Led to the Longest Horizontal Well in the World," by Kumud Sonowal and Bjarne Bennetzen, Mærsk Oil Qatar A/S; Patrick Wong, K&M Technology Group; and Erhan Isevcan, Schlumberger, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17–19 March. The paper has not been peer reviewed.
In May 2008, Mærsk Oil Qatar completed drilling its Well BD-04A with a horizontal length of 35,770 ft. It was reported that this well set records for both the longest well, at 40,320 ft measured depth from the rotary table (MDRT), and the longest along-hole departure of 37,956 ft. The use of new techniques allowed existing constraints to be challenged and overcome successfully. These achievements were possible by applying sound engineering principles and continuous optimization during the field-development phases. Even when constrained by limitations, such as rig capacity, major step changes were achieved by optimizing basic operating parameters.

Introduction
The Al-Shaheen field is approximately 80 km northeast of the Qatar peninsula, Block 5 in Fig. 1. The Kharaib formation is a laterally uniform carbonate deposition generally 80 ft thick and has a reservoir target of approximately 25 ft. The Shuaiba formation exhibits lateral facies changes and permeability contrasts. Its thickness generally is 200 ft, with a reservoir target of approximately 20 ft. The Nahr Umr formation is a 20-ft sand sequence with reservoir targets of 5 ft of permeable sand or less.
The decision to develop this field by use of long-reach horizontal wells was driven primarily by the large aerial extent of the accumulation, poor productivity of vertical wells, and the number of platform locations required if a conventional approach with vertical or slant wells was pursued. The length of these horizontal wells has been extended during the course of the development, and some of these wells are pushing the limit that can be achieved with today's technology. To further enhance oil recovery from the Al-Shaheen field, it was decided, in 2007, to drill even longer wells and initiate measures with detailed engineering analysis to expand the horizontal extended-reach-drilling (ERD) envelope beyond industry experience.

Well BD-04A
At 40,320 ft MDRT, Well BD-04A was the longest well drilled, achieving the longest reach of 36,238 ft. The horizontal section was 35,770 ft [i.e., from the first survey with inclination above 86.0° at 4,550 ft MDRT to total depth (TD) at 40,320 ft], with 35,449 ft of continuous reservoir exposure.
Downhole Gas Compression: A New Artificial-Lifting System for Gas Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121815, "Downhole Gas Compression: World's First Installation of a New Artificial-Lifting System for Gas Wells," by M.T. Di Tullio, SPE, S. Fornasari, and D. Ravaglia, Eni SpA E&P Division, and N. Bernatt, SPE, and J.E.N. Liley, SPE, Corac Group plc, originally prepared for the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed.
Downhole gas compression (DGC) is a new artificial-lift technology designed specifically for natural-gas wells and is an as yet unrealized opportunity within the upstream gas industry. The technology offers the opportunity to increase production by 30 to 50%, improve reserves significantly, and delay the onset of liquid loading. Although it can be used at any time during the life cycle of a gas asset, it will find particular favor during the decline phase.

Introduction
The upstream gas industry often is faced with the challenge of selecting an optimum artificial-lift system from various alternatives available for gas-well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well.
Application of DGC technology in suitable wells offers value for the following reasons.Acceleration of early production and extension of production plateau in new gas developments.Cost-effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation in wells.Improvement of gas-well production and maximization of recovery factor from gas reservoirs with low environmental impact.Identification of incremental reserves and for monetization of stranded gas.
As part of an ongoing development through a joint-industry program, the first field trial of the new technology was conducted in an onshore gas well. The program has been completed in phases, including the design, building, and testing in a full-scale flow loop that closely replicated downhole conditions. The prototype has been tailored to suit the expected gas-flow range, composition, and condition of the selected field-trial well. Fig. 1 shows an internal view of one of the three compressor modules, with the gas path indicated in red.

Why Compress Gas Downhole
Operators of a producing asset always are seeking to maximize its value. In natural-gas fields, optimum gas production at low intervention cost and frequency is the ultimate objective in gas-well production management. To maximize production, the flowing bottomhole pressure (FBHP) should be kept as low as operationally possible. There are many challenges to achieving this objective.
Stand Tall and Speak Up (December 2005)
Authors: Sprunt Eve S. 
Published: February 2015

As SPE members we have a lot to be happy about. Our Society is thriving. Our membership is approaching 65,000, which includes some 14,000 students, thanks in large part to Halliburton’s generous sponsorship of student dues. Also, 2005 SPE President Giovanni Paccaloni’s passion for young professionals has created many new programs to entice new graduates to take advantage of the low membership fees for those under the age of 30. Moreover, we are an increasingly global Society, with over half of our members outside the U.S., 156 sections in 62 countries, members in more than 100 countries, and 131 student sections in 42 countries. Our eLibrary contains more than 40,000 papers. Together we have accomplished a lot, but that doesn’t mean we should rest on our laurels.
To better serve our membership, the SPE Board of Directors, past SPE Presidents, and other leaders of our Society have worked together to draft a new 10-year plan for the period 2005–15.
In the past, four Long Range Plans have been created, covering proposed strategies, tac-tics, and activities to guide the Society forward. The plans have covered the periods 1975–85, 1982–92, 1991–2000 (adopted in 1994), and 2000–10. These plans have played a major role in making SPE the financially sound, technically robust, and internationally respected and valued organization it is today. A long-range plan guides and focuses individual decisions by placing them in the framework of long-term goals. A plan also channels the energy and resources of the Society’s members and staff into addressing the highest priority goals.
Our industry is faced with many challenges, including the “big crew change,” the constant pressures of a commodity business to accomplish more with fewer people, rapidly changing technology, and a public that both worries that the world is running out of oil and fears that continued use of fossil fuels will create an environmental disaster. SPE’s Long Range Plan must simultaneously address all of these issues. Let me share with you some of the things in the plan that I think are most important.
Programs to attract young people to the industry and to train and retain young members.
Programs about reserves definitions and classifications for industry experts, nonexperts in the industry, and the public, including investors, to build support for new reserves and resources standards and to improve public understanding of the future of our industry.
Shortened Modeling Time Seen With Suite Concept in Reservoir Sampling
Authors: JPT staff _ 
Published: February 2015

Wireline-testing-tool capabilities and efficiencies are dramatically changing the value of formation-sampling and -testing programs. As real-time pressure-volume-temperature (PVT) simulation and collected formation samples are obtained closer to in-situ conditions, the accurate determination of produced-fluid composition is affecting project cycle times and reducing developmental risks, offering a narrow window of opportunity for operators to improve cost-efficiency.
While the value of formation characterization and samples remains in identifying the production potential of targeted reservoirs and design and development of production facilities, sampling is also an effective means of identifying water aquifers that require isolation during completion and confirming gas/oil/water contacts. In the past, it has been necessary for engineers to first understand the reservoir’s characterization and sampling needs, then define the proper tools or services, and finally to locate compatible tools.
Replacing traditional drillstem tests with a combination service portfolio that includes a wireline single-phase sampling program, real-time PVT predictions, and real-time contamination monitoring can potentially improve the accuracy of reservoir data and the quality of fluid samples and have a beneficial impact on essential design needs. Accurate determination of produced-fluid phase behavior and composition are valuable data used in designing completions, production facilities, and flow-assurance programs.
A combination service package, RESolution, was recently launched by Baker Atlas and consists of reservoir-fluid characterization, testing, and sampling services that provide real-time reservoir pressures, in-situ fluid samples, and fluid characterization. The portfolio service uses one logging instrument, the RCI Reservoir Characterization Instrument, with single-phase tanks that gather fluid samples downhole and then overpressure them to preserve the samples at in-situ conditions. By creating a state of overpressure before bringing the sample to the surface, the typical loss of pressure and cooling effect during the journey out of the wellbore results in retrieval of the sample at reservoir conditions.
Overview: Production/Facilities (December 2005)
Authors: Richards Simon W. 
Published: February 2015

This year’s selection of papers is a mixed bunch that I thought would appeal to a wide audience. I deliberately chose papers to encourage as many as possible to read them. The broad theme is environment and sustainability. We have a duty to limit gas flaring as much as practicable to limit emissions and conserve fuel. A little-known effect of excessive flaring is addressed in the first paper. It’s a common saying that oil and water don’t mix. Well, the truth
is that sometimes they do. The food-processing industry spends a lot of time mixing oils and water that they sell us as food. However, in this industry, our problem is often finding ways to separate oil and water. No two sets of oil and water are the same, and the second paper looks at experiences in a Saudi Arabian field.
As our supply of high-quality light sweet crude oil is depleted, we start to produce the heavier sour grades of crude oil around the world. One of the problems with these fields is disposal of the large quantities of elemental sulfur that are recovered during the processing. Until now, it has often been stockpiled with, in my view, huge safety and environmental risks. Our third paper presents some novel means to dispose of this sulfur.
Our final paper deals with the end time for a production facility. Whether onshore or offshore, the production and processing facilities must be removed in accordance with local regulations. This task is clearly more difficult offshore, and this paper explains how it was handled offshore California.
I hope that you enjoy reading them as much as I enjoyed choosing them.
Available from the SPE eLibrary: www.spe.org
SPE 93653 “ExxonMobil’s Advanced Gas-to-Liquids Technology—AGC-21,” by R.A. Fiato, ExxonMobil Research and Engineering Co., et al.
SPE 93817 “Restoring Integrity to Aged Petroleum Production Facilities,” by S.W. Ciaraldi, BP Indonesia, et al.
SPE 96403 “Turning a North Sea Oil Giant Into a Gas Field—Depressurization of the Statfjord Field,” by R. Boge, SPE, Statoil, et al.
SPE 96504 “Canopy Bridges Along a Rainforest Pipeline in Ecuador,” by M. Thurber, SPE, Walsh, et al.
New PDC Technology Delivers Significant Savings in Oman
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97340, “An Alternate Approach: Utilizing New PDC Technology for Drilling Deep LNG Wells Delivers Significant Savings for Major Operator in Oman,” by P. Teasdale, SPE, N. Riley, and P. Mackinnon, ReedHycalog, prepared for the 2005 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, UAE, 12–14 September.
A major operator has been drilling deep gas wells for several years in central Oman. These wells are drilled vertically through a complex geological sequence that provides a significant challenge to bit performance. Historically, these wells have been drilled in 90 days with tungsten-carbide-insert (TCI) bits on packed rotary assemblies to the 9⅝-in. casing shoe and diamond-impregnated bits on turbine assemblies with occasional TCI-bit runs in the 8⅜-in. section. A detailed study of the wells focused on optimizing drilling performance in each of the three hole sizes in a typical well profile. The findings suggested that the introduction of new polycrystalline-diamond compact (PDC) -bit technology was viable over much of the intervals and that significant savings in terms of time and cost could be achieved.
Trial Well 1
The initial trial well began in August 2003. Performance had been benchmarked and objectives were established for each hole section.
Top 17½-in. Hole. The following objectives were agreed upon.
- Complete 950-m interval in single run.
- Rate of penetration (ROP) greater than 14-m/h benchmark.
A premium Intl. Assn. of Drilling Contractors (IADC) code 415 TCI bit with a total flow area (TFA) of 7.19 cm2 was run on a rotary pendulum assembly with a single stabilizer positioned 27 m above the bit. The TCI bit features an extremely durable roller bearing for extended life and an optimized geometric hydraulic design with precisely angled nozzles to prevent bit balling and increase ROP.
The section was completed in 14 days compared to the planned 6 days, with 6½ days of lost time spent curing losses. A total of 16 trips and 9 bit runs was required to complete the interval because of hole problems. The 415-type bit drilled the 944-m interval as planned with an average ROP of 13.2 m/h that was slightly lower than the 14-m/h target established before the run. At surface, the bit was balled up but in good condition and was graded 2-2-CT-A-E-I-NO-TD. Consideration of the controlled parameters applied in the upper section to minimize the risk of losses, and the excellent performance achieved in the lower section where flow rates were optimized and ROP increased to more than 20 m/h demonstrated the potential for better performance in this section.