bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Storage in Natural-Gas-Hydrate Reservoirs Benefits From Associated Methane Production
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18087, "Environmentally Friendly CO2 Storage in Hydrate Reservoirs Benefits From Associated Spontaneous Methane Production," by A. Graue, SPE, and B. Kvamme, U. of Bergen; B.A. Baldwin, Green Country Petrophysics LLC; J. Stevens, SPE, and J. Howard, SPE, ConocoPhillips; E. Aspenes, SPE, G. Ersland, SPE, and J. Husebo, U. of Bergen; and D. Zornes, SPE, ConocoPhillips, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.
Carbon dioxide (CO2) sequestration in natural-gas-hydrate reservoirs may offer stable long-term storage of a greenhouse gas with the additional benefit of methane (CH4) production. The sequestration process may thus offer large amounts of energy for the future while providing a more thermodynamically stable gas hydrate that is less sensitive to global temperature changes.

Introduction
CO2 storage in natural-gas-hydrate reservoirs by replacing the CH4 in the hydrate with CO2 has attractive potential because it would produce free natural gas and establish a more thermodynamically stable hydrate accumulation. Natural-gas hydrates represent an enormous energy potential because the total energy corresponding to natural gas entrapped in hydrate reservoirs may be more than twice the energy of all known coal, oil, and gas energy sources. Natural-gas-hydrate accumulations rarely are completely stable in a strict thermodynamic sense. Typically, the hydrate is trapped between clay layers or other low-permeability structures. Gas hydrate exposed to the seafloor will dissociate because of the very-low hydrocarbon content in the surroundings. Though some of the released methane will be consumed by biological and chemical ecosystems, the methane reaching the surface represents an environmental concern because CH4 is a more aggressive (approximately 25 times) greenhouse gas than CO2.
However, a more serious concern is hydrate-formation stability. Changes in local temperature and pressure conditions or surrounding fluids or minerals change the system dynamics and can lead to catastrophic dissociation. The Storegga slide offshore Norway was created by several catastrophic hydrate dissociations. The largest of these is estimated to have occurred 7,000 years ago and is believed to have created a massive tsunami. The environmental disaster related to such enormous amounts of methane released into the atmosphere can have dramatic effects on the greenhouse scenario. The replacement of natural-gas hydrate with CO2 hydrate will increase the stability of hydrate formations. The hydrate content in the Storegga area is still significant and estimated to be on the order of 1012 m3 distributed over 4000 km2. Hydrocarbon exploitation in hydrate regions creates some additional concerns. Drilling operations produce heat and risk of local hydrate dissociation.
Operations Management Extends Field Life of a Long-Distance Subsea Tieback in Ultradeep Water
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18830, "Innovative Operations Management and Flow-Assurance Strategies Extend Field Life and Increase Ultimate Reserves of a Long-Distance Subsea Tieback in Ultradeep Water," by Aditya Singh, SPE, and Kevin Hannaford, Total E&P USA, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
In 2004, the subsea fields comprising the Canyon Express system were declining and water-production rates were increasing. To halt the fast decline and extend the life of the field, flow-lines were reconfigured to separate the depletion-drive wells from waterdrive wells. A real-time production-management tool for enhanced production planning, monitoring, and trouble-shooting was implemented.

Introduction
The Canyon Express transportation system consists of two 12-in. flowlines running parallel from Camden Hills through Aconcagua and Kings Peak to Canyon Station platform. The three subsea fields—Camden Hills, Aconcagua, and Kings Peak—are in 6,200 to 7,250 ft of water. The Canyon Express subsea tieback, at 56 miles from Camden Hills to Canyon Station platform, is one of the longest subsea tiebacks in the Gulf of Mexico. Production from the fields is predominantly gas with condensate and produced water. The wells are tied together by means of a daisy-chain arrangement. Fig. 1 shows a Canyon Express schematic.
During midlife operations, increasing water production from waterdrive reservoirs (Aconcagua AC1 and AC2, Camden Hills CH1 and CH2, and Kings Peak KP1 and KP2) and declining reservoir pressures of depletion-drive reservoirs (Aconcagua AC3 and AC4) led to high liquid rates and lower gas rates. The declining depletion-drive wells were restricted by higher water rates and liquid holdup in the flowlines. To optimize production during this period of increasing water rates and declining gas rates, several production options were considered. Detailed flow-assurance analysis was performed for each of the proposed options, and a recommended solution was reached on the basis of clearly identified advantages and disadvantages for each operating scenario. Flow-assurance evaluations were used on a continuous basis for operations planning to optimize and maintain production during this period.

Evaluation of Late-Life Options
Scenarios of the operating conditions to be studied were defined. Sensitivities on arrival pressures, gas-production rates, and water-production rates were developed from time points in the production forecast for evaluating the possible late-life operating techniques. A matrix of cases to be evaluated was developed.
Kikeh Development: Malaysia's First Deepwater Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19637, "Kikeh Development: Subsea-Equipment-Installation Challenges for Malaysia's First Deepwater Development," by G. Murray and D. Lowther, Technip Subsea 7 Asia Pacific, and A. Ledingham and T.J. Stensgaard, Murphy Sabah Oil Co. Ltd., originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The Kikeh development, the first deepwater project in Malaysia, is offshore eastern Malaysia in the South China Sea with a water depth of 1320 m. Kikeh is to be developed with 34 wells, and initial production was in August 2007. The full-length paper discusses the offshore-installation-vessel selection process including the effects on the decision process of using local equipment vs. mobilizing deepwater construction equipment from other deepwater basins around the world. With deepwater Sabah being a greenfield deepwater basin, a number of challenges arose in relation to equipment availability within the region and logistics to support deepwater construction operations.

Introduction
While these types of deepwater subsea developments have been brought on production in other deepwater basins for a number of years, particularly in West Africa and the Gulf of Mexico, the Kikeh development, as a first for Southeast Asia, brought about a number of challenges to and specific requirements for both opera tor and contractor that necessitated close cooperation in terms of sharing of installation assets across a number of contracts associated with the Kikeh development to meet the overall project schedule.
Because of the nature of this type of deepwater subsea project, involving the supply and installation of flexible flowlines and risers, the engineering, procurement, construction, installation, and commissioning (EPCIC) contractor elected to use a joint-venture partnership to execute the project on its behalf. The project team was established in Perth, Western Australia, where all design engineering, procurement activities, and preparation of installation procedures were undertaken.

Offshore-Vessel Selection
The primary vessel-capacity requirements were crane-lift capabilities, flexible-pipe lay tensions, and overall deck-storage capacity to handle the products to be installed. To determine the installation-vessel requirements, some initial engineering was conducted to better understand maximum lift and deployment loads associated with the installation program.
Your SPE: A Year Is Too Short
Authors: Roodhart Leo 
Published: February 2015

President's column
Time flies for SPE presidents; a year is nothing. Geologists know that very well, but I am a production engineer, so how could I know? As I assumed the post of SPE President on 24 September last year I felt, as I said in my maiden speech, an over-riding sense of awe and eager anticipation. Awe when I thought of the richness and diversity that our SPE represents, as well as my responsibility to the global membership and to our industry as a whole. Eager anticipation when I thought of helping to realize the Society's dreams at the beginning of the 21st century.
I started out with three key objectives: to grow membership in the developing regions to make SPE a truly global organization; to develop more online resources for members; and to reach out to the young, who are essential to the future of our industry.
However, the moment I started my Presidency, the credit crunch, as it was called then, hit the world and developed rapidly into a global financial recession. Many companies reacted immediately with travel bans and cost cutting, and the consequences of those were quite dramatic for SPE. However, the SPE Board and staff reacted very swiftly, bringing meetings and workshops to where the members are, in practical, lower-cost places. We also accelerated the use of new communication technology. During my acceptance speech in Denver, I made a joke about organizing an SPE conference in Second Life, so guess my delight when the Digital Energy Conference did just that.
Overall, I believe SPE will rise from this recession much stronger, with an even leaner cost structure and with a new habit of utilising new technologies like web streaming conferences, the use of Webex and Skype, and the creation of "virtual presentation rooms" in place earlier than planned. So in the end, I am proud of the resilience of our Society, which cannot claim to be unaffected by the downturn but which can claim to have continued to deliver excellent programs and to attract high-quality audiences at worldwide events. It seems that senior management in our industry still values SPE's offer when it comes to technology dissemination and learning. My grandmother used to say that the heavier the cross you are carrying, the stronger you get.
Technology Focus: Formation Evaluation (August 2009)
Authors: Harrison Bob 
Published: February 2015

Technology Focus
Generally, the entire interval between the surface casing and total depth is logged, but far too often we neglect to take core. While the expense of coring and core analysis is not small, it usually is only a fraction of total well cost; yet it remains an uphill struggle to convince management that the project will benefit from the knowledge gained. With the quest for reserves leading to exploration for and development of reservoirs with ever-more-complex porosity systems at greater depths and higher temperatures where log responses become suspect, I would argue that taking core has never been more important.
There is no denying that logs provide greater statistical coverage of a larger volume; have a better depth reference; can identify fluid contacts, missed pay, and swept zones; measure reservoir pressure; and can be calibrated to seismic data for reservoir-property mapping. However, visual inspection and laboratory analysis of core provide many key data that logs simply cannot provide, with applications for every discipline.
Core confirms the lithology and mineralogy of reservoirs; calibrates estimates of fundamental rock properties such as porosity, saturation, and net thickness; and remains the only true measure of permeability. Core shows how fluids occupy and flow within the reservoir pore space; enables formation-damage studies; and supplies mechanical properties to allow faster and safer drilling and better-designed completions.
Despite issues with cleaning, storage, restoration to native state, and scaling up, core still provides the best estimates of many of the crucial inputs for accurate reservoir modeling, even though logging-contractor marketing literature would have us believe otherwise. Logs cannot characterize a reservoir if knowledge of the rock is absent, so subsequent modeling must rely on uncalibrated and unverified log-derived correlations and analogs. The inevitable consequence is greater uncertainty.
Formation Evaluation additional reading available at OnePetro: www.onepetro.org
IPTC 12837 • "Accurate NMR Fluid Typing Using Functional T1/T2 Ratio and Fluid-Component Decomposition" by Boqin Sun, Chevron Energy Technology, et al.
SPE 117728 • "Reservoir Rock Typing From Crest to Flank: Is There a Link?" by R.E. Mahmoud Basioni, Abu Dhabi Company, et al.
IPTC 12328 • "Data-Acquisition and Formation-Evaluation Strategies in Anisotropic, Tight Gas Reservoirs of the Sultanate of Oman" by H.J. de Koningh, SPE, Petroleum Development Oman, et al.
Evaluating Implications of Hydraulic Fracturing in Shale-Gas Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121038, "Evaluating Implica tions of Hydraulic Fracturing in Shale- Gas Reservoirs," by J. Daniel Arthur, SPE, Brian Bohm, Bobbi Jo Coughlin, and Mark Layne, SPE, ALL Consulting, prepared for the 2009 SPE Americas E&P Environmental and Safety Conference, San Antonio, Texas, 23-25 March. The paper has not been peer reviewed.
Exploration, drilling, and production of shale-gas plays such as the Barnett, Fayetteville, and Haynesville have changed the unconventional-gas industry. Two technologies that enhanced shale-gas development are horizontal drilling and hydraulic fracturing. Hydraulic fracturing of horizontal wells completed in shale reservoirs often requires larger volumes of fracturing fluid than conventional vertical-well stimulations. Rapid development of shale gas across the country has created concerns about the use of infrastructure and about environmental effects.

Introduction
The Barnett-shale play began in the Fort Worth, Texas, area in the 1980s. Continued improvements in hydraulic-fracturing techniques and technology enhanced development of the Barnett shale. Development uses horizontal drilling and sequenced multistage hydraulic-fracturing technologies.
Another source of technological advances in horizontal drilling and hydraulic fracturing is the Bakken shale of the Williston basin in Montana and North Dakota, which produces more oil than gas. Each shale-gas basin has a unique set of exploration criteria and operational challenges. However, the combination of horizontal-well completions and sequenced hydraulic-fracture treatments has been crucial in facilitating the expansion of modern shale-gas development to other shale plays. The low natural permeability of shale has been the limiting factor to production.

Shale-Gas Geology
Shale gas is natural gas produced from shale formations, and these shales function as both source rock and reservoir for the natural gas. Typically, shale gas is dry gas composed primarily of methane (90% or more). However, some shale-gas formations do produce water.
Gas shales are organic-rich formations traditionally viewed as source rocks and seals for stratigraphic gas accumulations. The thin layers, as shown in Fig. 1, that make up shale result in a rock with limited horizontal permeability and minimal vertical permeability. Unfractured shales typically have permeabilities on the order of 0.01 to 0.00001 md, limiting production.
The natural matrix permeability of shale sometimes is overcome by natural-fracture networks that developed when overburden pressure was reduced as a result of erosion of overlying rock formations. Other tectonic activity also can cause a change in the pressure, creating additional fractures. Often, fractures are key sources of permeability, facilitating the migration of fluids through fine-grained rocks such as shales.
Technology Focus: Drilling Management (August 2009)
Authors: Cunha J.C. 
Published: February 2015

Technology Focus
Last April, I had the opportunity to attend the VI Technical Meeting on Well-Engineering Risk Analysis, at Petrobras University, Rio de Janeiro, Brazil, dedicated entirely to risk management in the area of well engineering. That 3-day meeting gave participants an excellent opportunity to exchange experiences, disseminate know-how and current procedures, and discuss problems and critical developments in the area of risk management for drilling and completion operations.
I was amazed by the number of diversified works as well as the quality of the presentations, panels, and roundtables. Several topics related to drilling management were presented including risk management for well-control operations, risks involved in the implementation of new technologies, risk analysis for prediction of time and costs in deepwater drilling and completion, the effect of drilling costs on the evaluation of new exploration opportunities, and many others.
It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results. Our featured papers bring some examples of better-quality results obtained through superior planning. Project managers, drilling engineers, drilling supervisors, and field engineers will all benefit from careful planning. As most of us should know by now: "If you fail to plan, then you plan to fail" (Saladis and Kerzner 2009).

References
Saladis, F.P. and Kerzner, H. 2009. Bringing the PMBOK Guide to Life—A companion for the Practicing Project Manager, 49. Hoboken, NJ: John Wiley and Sons.
Drilling Management additional reading available at OnePetro: www.onepetro.org
SPE 119287 • "Probabilistic Well-Time Estimation Revisited" by A.J. Adams, SPE, Nexen Petroleum, et al.
SPE 114797 • "Advanced Drilling Simulation Proves Managed-Pressure Drilling (MPD) Economical in Gasfield Developments in Western Canada" by Geir Hareland, SPE, University of Calgary, et al.
SPE 120848 • "Systems Approach and Quantitative Decision Tools for Technology Selection in Environmentally Friendly Drilling" by O.-Y. Yu, SPE, Texas A&M University, et al.
IPTC 12707 • "Automatic Calibration of Real-Time Computer Models in Intelligent Drilling-Control Systems—Results From a North Sea Field Trial" by H.P. Lohne, SPE, International Research Institute of Stavanger, et al.
HSE Management in a Drilling Environment
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117813, "HSE Management in a Drilling Environment," by Andrew May, Alain Moonen, and Stewart Logan, Qatar Shell GTL, and Jackie Allinson, CW International, originally pre pared for the 2008 Abu Dhabi In ternational Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3–6 November. The paper has not been peer reviewed.
Since the beginning of the Pearl gas-to-liquid (GTL) drilling activities in Qatar's North field in 2004, five drilling rigs have been used and, to date, it has been a 4-year, 3-million-man-hours lost-time-incident (LTI)-free operation. Recognizing the industry challenges of introducing large numbers of inexperienced staff on the drilling rigs, introduction of a pro-gram of proactive health, safety, and environment (HSE) management by engaging all levels of the organizations of the operator and contractors has resulted in a top-quartile HSE and operational performance.

Introduction
After drilling and testing an appraisal well in 2004 and a data-acquisition well in 2006, the Pearl GTL development campaign began in earnest with two rigs (one a new build) drilling over two offshore jackets. During 2008, a land rig was taken on contract to drill two water-injection wells to dispose of condensed water from offshore. Also in 2008, an ambitious project matured to perform simultaneous operations in a hydrogen sulfide environment, consisting of drilling and completing wells while simultaneously perforating, acid stimulating, and cleaning up precompleted wells from temporary decks on the platform jacket.

Creating an HSE-Enabling Environment
Creating an HSE-enabling environment that is conducive to open, honest, and no-blame relationships generating hazard-reducing ideas is a result of a mix of many elements that require continuous focus and buy-in.
The creation begins at the contract-tender stage where the minimum HSE requirements are set out as an initial qualifying hurdle and where the HSE performance of each contractor is reviewed during the evaluation process. Then, in the period between the award of the contracts and the start of operations, project-kickoff meetings with participation of the operator, drilling contractors, third-party contractors, subcontractors, and office and on-site staff are used as a vehicle to develop the "One Team" approach to HSE. Openness, honesty, mutual trust, and full commitment are the key requirements for all parties involved to accept HSE as a core value and have fully aligned HSE aspirations.
At the commencement of the operational phase, all the enabling elements of the preparation phases, including detailed hazard analysis and the generation of HSE cases, are approached with great enthusiasm. This enthusiastic approach is key and produces clear and effective outcomes.