bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research Funded by DOE/RPSEA Advances Ultradeepwater Technology
Authors: Long Roy 
Published: February 2015

Technology Update
A number of research projects awarded by the Research Partnership to Secure Energy for America (RPSEA), with funding and oversight by the United States Department of Energy’s National Energy Technology Laboratory (NETL), have shown solid potential to advance deepwater and ultradeepwater (UDW) oil and gas development.
The DOE/RPSEA projects are among more than 15 to be featured in a session on funding new E&P technologies on 7 May at the Offshore Technology Conference (OTC) in Houston. Chairing the session will be James Pappas, vice president of ultradeepwater at RPSEA. Nine of the technologies developed through this research are discussed herein.
One of the projects, highlighted on the cover of the January 2014 issue of JPT, is the Lockheed Martin Marlin autonomous underwater vehicle. This system has the following advantages over remotely operated vehicle (ROV) systems: 3D model generation in hours vs. days; the use of smaller vessels with fewer crew members; no need for umbilical management; realtime change detection, enabling on-site assessment of survey results and structural anomalies; rapid assessment capability of potential environmental damage; and the ability to generate accurate, geo-registered models for structural integrity assessment.
Also under consideration is the inclusion of high-resolution visual imaging to enable accurate subsea measurement of flow rate from a blowout or from ocean floor seeps for predrilling site investigations. The project is in its final phase of development and scheduled to be complete by June.
Another interesting set of projects deals with metocean issues that affect UDW development. Studies in this area have continued since the early days of UDW research and development within RPSEA. The first efforts studied the US Gulf of Mexico (GOM) loop currents to develop a better hurricane forecasting model, because these relatively warmer currents often increase hurricane intensity.
The goal of these projects was to develop a better long-range forecast (of up to 90 days) of hurricane activity in the GOM. The newer models with higher resolution potentially could better describe the density of the spiral rain bands caused by higher wind velocities farther from the center of the storm. The spacing of these bands appears to have a greater influence on the extent of damage sustained by an offshore vessel than hurricane classification or size, as the spacing more directly affects seawater wave height.
Techbits: Workshop and Survey Focus on SPE Petroleum Resources Management System
Authors: McMillan Don 
Published: February 2015

Techbits
An SPE workshop titled “Application of the SPE Petroleum Resources Management System (Unconventional Resources),” was held 14 November, the day after the 2013 SPE Unconventional Resources Conference and Exhibition–Asia Pacific in Brisbane, Australia. The workshop attracted 83 participants from nine countries and speakers from the exploration and production sector, the finance sector, service companies, consultancies, and academia.
The goal of the workshop was to highlight the challenges faced by the industry in estimating unconventional resources. The SPE-PRMS, published in March 2007, endeavors to encompass the full life cycle of all types of petroleum resources. Since 2007, the industry has experienced remarkable growth in unconventional resources. Unconventional plays challenge the fundamental conventional definitions of reserves and resources estimation, including the definitions required to demonstrate a discovery and commerciality. Within the investment and regulatory community, the growth and importance of unconventional reserves and resources have fueled discussion on the credibility and dependability of oil and gas estimates. To assist in the application of the SPE-PRMS, a second document called Guidelines for Application of the Petroleum Resources Management System was published by SPE in 2011. Based on discussions I have noted in the industry, it seems there is a need for further clarification in the interpretation and application of the PRMS.
The workshop gave an opportunity to gauge participants’ perception of the SPE-PRMS. A survey was sent to the 83 participants; 37 responded. The results of this small survey are set out below. The demographics and experience level of the respondents were not captured and, therefore, the results are conditional. The comments are the author’s interpretation of the survey results. As with all surveys, it is possible that how the respondents answered questions may apply to a broader population. The goal here, though, is to provoke discussion and debate that could contribute to future improvements in the SPE-PRMS.
The survey asked the participants to indicate agreement, disagreement, or neutrality to a series of statements. Respondents’ answers were intended to provide insight into how clear the SPEPRMS is, how well understood it is, and respondents’ level of confidence in it.
Ideally, interpretation and implementation of the SPE-PRMS in estimating reserves/resources is independent of the reserve estimator. The first two survey statements endeavor to gauge the perception of consistency between reserve estimators in estimating conventional and unconventional reserves.
Q&A: Qatar's Oil and Gas R&D Push
Authors: Saleh Youssif 
Published: February 2015

Youssif Saleh, general manager of Qatar Shell Research and Technology Centre in the Qatar Science and Technology Park, discusses the R&D strategy of the center and in Qatar.
What are the main drivers behind the decision to establish an R&D center in the Middle East?
We are pleased about the role that Qatar plays in Shell’s overall technology strategy through our world-class research and development program based at the Qatar Shell Research and Technology Centre (QSRTC). This makes QSRTC a member of Shell’s wider R&D community, which includes technology centers in cities such as Amsterdam and Houston. QSRTC’s mandate is to provide a home for research that adds value both to the state of Qatar, to Shell, and to our partners. Therefore, our work is focused on the development and implementation of technologies that support Qatar’s specific needs, as well as support Qatar’s role as the world’s largest liquefied natural gas exporter and the gas-to-liquids (GTL) capital of the world. Moreover, we work with many of Qatar’s universities and academic institutions abroad, and provide training in R&D to Qatari national staff as part of Shell’s support for Qatar’s journey toward a knowledge-based economy.
When was QSRTC established and on what specific areas of R&D does it focus its efforts?
We have been an anchor tenant at the Qatar Science and Technology Park (QSTP), a home for technology-based companies from around the world, since 2008 with a USD-100-million funding commitment over 10 years. That was also the year we became the first tenant of QSTP to file a patent based on research conducted in Qatar. The center’s current activities build upon Shell’s extensive experience in the GTL field and focuses specifically on catalyst testing, product development, and GTL byproduct research, including water treatment and reuse. Catalysts are a key focus area since they are essential to the process that converts natural gas into liquid fuels and other products at our Pearl GTL facility, the largest GTL plant in the world. Our researchers have also worked on developing new uses for sulfur, a coproduct of the GTL process, and are collaborating with scientists from around the world on improving the understanding of carbonate reservoirs.
Technology Focus: Offshore Drilling and Completion (April 2014)
Authors: Rylance Martin 
Published: February 2015

Technology Focus
As the saying goes, “Necessity is the mother of invention.” And never were truer words spoken regarding the oil field and new frontiers. Indeed, as the industry significantly increases the number of work fronts in both the established and the new deepwater frontiers, ever-more-innovative approaches are being developed to address the challenges faced.
However, innovation in isolation is not sufficient. As we push the envelope of application, it is a necessity that the equipment and approaches being applied be fit for purpose, robust, and engineered. In support of this, while a model is a useful tool and plays a role as part of a development process, such complex engineering can best be implemented efficiently through obtaining actual performance data, which may then be used as a basis for improvement and expanded qualification.
Data play a key role in two distinct and principal areas of technology development: data that are obtained and used to demonstrate the initial qualification (surface) and in-situ performance (deployed) data that are used to calibrate simulations and models and to allow further efficiencies to be securely achieved.
As a technical advisor in hydraulic fracturing and unconventionals, I fully appreciate the plan/do/measure/learn cycle because this is fundamental to our overall efficiency. However, deepwater drilling and completion operations are quite different from those in unconventionals. With few wells and much higher costs, the statistical multiwell approaches taken onshore with unconventionals simply do not apply to deepwater efforts. While approximately 20,000 unconventional wells are drilled per year in North America, fewer than 200 deepwater wells have been drilled in the Gulf of Mexico to date. This makes each opportunity to gather data in deep water particularly valuable. And the key to maximizing industry efficiency will be to make sure that data gathering is part of our everyday business. Of course, this is best achieved by embedding the opportunities to gather such data within our standard practice. In this way, we improve incrementally.
The following papers provide just a small snapshot of the areas in which incremental improvements are being achieved, allowing the deepwater drilling and completions envelope to be pushed further. It is very likely that such data-driven innovation will continue to be the lifeblood of the business. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 24275 Real-Time Drilling-Data Diagnosis Implemented in Deepwater Wells—A Reality by R.A. Gandelman, Petrobras, et al.
OTC 24081 Concept Alternatives and Feasibility Analyses of Deepwater Dual-Gradient Drilling-Riser Systems by Atul Ganpatye, Stress Engineering Services, et al.
SPE 166554 Low Cycle Fatigue Analysis of Threaded Connectors for Subsea Drilling and Production by B. Zhu, GE Oil and Gas, et al.
SPE 166589 Structural Response Monitoring of Huntington HP Drilling and Completion Riser by A. Rimmer, 2H Offshore Engineering, et al.
Case Study: Foaming During Startup of Karan Nonassociated Gas
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17175, ’Khursaniyah Gas-Plant Experience With Foaming During Startup of Karan Nonassociated Gas,’ by Mohammed Hussain Al-Qahtani, Saudi Aramco, and Paul Garland, INEOS, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.
All amines are subject to foaming in industrial applications given certain conditions and circumstances. Methyl diethanolamine (MDEA) is like other types of amine that can experience major foaming upset, especially in high-pressure sweetening units. However, MDEA is one of the most popular solvents for gas treating, with several advantages over other amines, particularly its ability to remove hydrogen sulfide (H2S) and slip carbon dioxide (CO2) from sour gas. This paper describes Saudi Aramco’s efforts to eliminate early foaming incidents during the commissioning stage of the Karan nonassociated (NA) sour-gas field.
Introduction
The Karan field was discovered by Saudi Aramco in 2006. This newly developed offshore field is located 120 km northwest of Jubail Industrial City in eastern Saudi Arabia. Produced sour gas is coblended at a tie-in offshore platform through five 20-in. subsea flowlines. From the tie-in offshore platform, the gas is sent through a 38-in. subsea pipeline to the onshore gas-treatment facilities at the Khursaniyah Gas Plant. Karan facilities consist of three gas-treatment-processing trains, each designed to process 620 MMscf/D of NA sour gas, producing sales gas and acid gas.
Karan NA sour gas is a CO2-rich stream. Formulated MDEA was selected for sweetening in Karan gas-treating facilities to enhance the H2S / CO2 ratio in acid gas and to meet the required sales-gas specification before sending the gas to the Saudi Master Gas System.
The Problem of Foaming
Karan’s three gas-treating trains have a total rated capacity of 1.86 Bcf/D of sour feed gas. Each train consists of an MDEA-based acid-gas-removal (AGR) unit, a triethylene-glycol (TEG) dehydration unit, and an acid-removal (AGE) unit (Fig. 1). In addition, propane is used for process-stream cooling at various points throughout the process, where temperatures of less than 140°F are required. A dedicated propane-compression system runs continuously to cool each process train.
Modeling and Analysis of Salt-Cavern Natural-Gas Storage
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164489, ’Modeling and Analysis of Salt-Cavern Natural-Gas Storage,’ by P. Barajas and F. Civan, SPE, University of Oklahoma, prepared for the 2013 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, 23-26 March. The paper has been peer reviewed and published in the February 2014 SPE Production & Operations journal.
A rigorous modeling approach is developed for effective management and inventory analysis of natural-gas storage in underground salt caverns. Computational-fluid-dynamics and heat-transfer modeling approaches are implemented to simulate the strongly coupled fluid-mechanics and heat-transfer problems involving cavern gas storage. Accurate prediction of natural-gas storage performance and inventories made on the basis of the present comprehensive simulation approach can be instrumental in effective management and balancing of natural-gas supply and demand.
Introduction
Gas-storage caverns are typically developed through drilling of a wellbore to reach the salt formation and subsequently injecting and circulating hot water to dissolve and remove the salt and create a cavity intended for gas storage by a process known as solution mining. Gas-storage-cavern facilities consist of three subsystems: the wellbore that connects surface facilities with the cavern, the cavern itself, and the surrounding salt formation enclosing the cavern (Fig. 1). Accurate prediction of cavern-gas pressure is important for avoiding improper gas-storage-operation parameters and thus the fracturing and failure of the salt formation (and hence cavern-roof collapse, which can lead to catastrophic incidents where the stored gas migrates toward the ground surface and causes harm to field personnel and the nearby population or damage to surface facilities). On the other hand, loss of volume caused by creep closure can occur when the cavern-gas pressure drops below the minimum allowable cavern pressure. Effective management and inventory analyses of underground natural-gas storage are generally accomplished by modeling and simulation of the gas conditions in the storage media.
The increasing popularity of salt caverns is attributed to their flexibility to switch quickly from gas injection to gas production. The void space of the cavern does not cause pressure loss from flow restrictions in contrast to depleted reservoirs or aquifers. Ideally, stored gas cannot leak into the surrounding naturally fractured salt formation because of the essentially negligible porosity and permeability of the formation. Thickness of salt formations can vary typically from a few meters in salt beds to thousands of meters in salt domes.
Challenges in Testing and Completion of an HP/HT Reservoir in Kuwait
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167647, ’Challenges in Testing and Completion of Highly Sour HP/HT Reservoirs in the State of Kuwait,’ by Y. Al-Salali, H. Al-Bader, V. Duggirala, M. Ayyavoo, P. Subban, A.R. Al-Ibrahim, and A. Rajkhowa, Kuwait Oil Company, prepared for the 2013 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 7-10 October. The paper has not been peer reviewed.
Recently, a new structure located in northwestern Kuwait was drilled and tested with a deep-drilling rig. Formations in this deep structure have very low porosity and permeability. During short-term testing, wells produced oil and gas with, unexpectedly, the highest hydrogen sulfide (H2S) content of any reservoir so far discovered in Kuwait. Because the reservoir was rated as high-pressure/ high-temperature (HP/HT) and sour, it was a challenge to test the wells safely and successfully.
Introduction
Jurassic carbonate reservoirs in Kuwait fields are deep, low-permeability, and HP/HT and generally contain sour volatile oil/condensate and gas. Formations containing these deep reservoirs are tight and naturally fractured carbonates. Najmah (NJ), Sargelu (SR), Upper Marrat, Middle Marrat, and Lower Marrat are the five formations proved to hold hydrocarbon- bearing reservoirs. NJ and SR formations are tighter than the three Marrat formations.
The NJ formation consists of limestone at the upper part and shale at the bottom. The SR formation consists mainly of shale and limestone. Both are naturally fractured reservoirs, so fractures play an important role in production. The Marrat formations consist mainly of limestone, occasionally with streaks of anhydrite at the top and with streaks of shale at the bottom. The core analysis of the Middle Marrat formation shows that dolomitization plays a major role for matrix-porosity enhancement, which is responsible for good reservoir character.
As part of an exploration strategy, a new structure in northwestern Kuwait was drilled to deep Jurassic formations. This new structure is a northwest/southeast- trending doubly plunging anticline and is intersected by a number of longitudinal- and transverse-fault sets. Earlier, a significant discovery of light oil and gas from the new deeper structure was made from an unsuccessful Paleozoic well through re-entry. After the discovery of light oil and gas, three more exploration/delineation wells were drilled to confirm the reserves potential of this structure. Some of the wells are located near the crest of the structure, whereas some are 1.5 km from the crest (Fig. 1).
Harvesting Oil in India's Rajasthan Desert
Authors: Kulkarni Pramod 
Published: February 2015

The Thar Desert in India’s western state of Rajasthan is a desolate region characterized by wind-blown sand dunes. The state is a major tourist attraction, drawing millions of visitors annually to tour forts of medieval kingdoms and visit camel fairs. It is here that Cairn Energy, a Scottish oil company, took over a production-sharing contract (PSC) from Shell in 2003 and developed a major oilfield that has recoverable reserves of at least 1 billion BOE.
The major oil companies have conducted little wildcat exploration in South Asia. From 1980 to 1991, the majors drilled 8,000 wells in Southeast Asia, but only 12 in South Asia. Indigenous exploration in Rajasthan began with an inconclusive exploration attempt by the government of India in 1955. In 1988, Oil India discovered natural gas near the town of Jaisalmer and has been producing 0.6 million sd m3/d since 1996.
Floated on the London Stock Exchange in 1988, Cairn Energy first entered South Asia by signing a PSC with the government of Bangladesh. In 1997, during a swap of properties with Shell, Cairn acquired a 10% interest in the Rajasthan PSC, which Shell had initially signed with the government of India in 1995. The PSC covered block RJ-ON-90/1 consisting of an initial area of almost 12 000 km2—3111 km2 is now included in the development area, with India’s public sector oil company, Oil and Natural Gas Corporation, holding 30% ownership. After the discovery of the Guda field in 1999, Cairn increased its participation to 50% and eventually took over Shell’s remaining share in 2003 at a cost of USD 7.25 million and became the block’s operator.
“Drill Till You Drop” Strategy
The geology of the block in Rajasthan’s Barmer basin consists of channel sands stacked on top of one another to create a fluvial reservoir that has high permeability (1–25 darcy) and high porosity. From 2004, Cairn adopted a “drill till you drop” strategy. In January 2004, the company made its initial Mangala discovery with the 16th well in the basin. Following the drilling of appraisal wells, 3D-seismic-data analysis, and well tests, Mangala was confirmed as the largest oil discovery in India since 1985. The Mangala reservoir has a 150 m oil column of medium gravity (20–28°API) viscous crude (9–17 cp) with sulfur content of about 0.1%. The crude has high paraffin content that makes it suitable as a secondary feedstock for refineries, but pipelines and trucks carrying the crude require heating and insulation. Up to 2005, the company drilled more than 140 wells in Rajasthan with a yield of 25 discoveries. In addition to Mangala, Cairn’s major discoveries are Bhagyam and Aishwariya, with 22 other fields including Guda, Saraswati, Raageshwari, Greater Raageshwari, and Kameshwari. In August 2009, the Prime Minister of India, Manmohan Singh, joined Cairn Energy Chief Executive Bill Gammell in inaugurating oil production from the Mangala field.