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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145518, ’KP4: Aging and Life-Extension Inspection Program - The First Year,’ by Alexander Stacey, UK Health and Safety Executive, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. With a significant proportion of the UK’s offshore infrastructure having exceeded the original design life, the aging population of offshore installations presents a growing challenge to safety. Aging is characterized by deterioration that, in the severe operational environment offshore, can have serious asset-integrity consequences if not managed properly. The UK Health and Safety Executive (HSE) Aging and Life Extension Inspection Programme, also known as Key Programme 4 (KP4), was launched in July 2010 to the UK offshore industry. Introduction The purpose of KP4 is to Determine whether the risks to asset integrity, which are associated with aging and life extension, are being controlled effectively. Raise awareness of the need for specific consideration of aging issues as a distinct activity within the asset-integrity-management process and of the need for senior management to demonstrate leadership on this matter. Identify shortcomings in duty-holder practices in the management of aging and life extension, and enforce an appropriate program of remedial action. Work with the offshore industry to develop a “best-practice” common approach to the management of aging installations and life extension. More than 50% of offshore installations in the UK sector of the North Sea have exceeded the original design life, typically specified as 20 or 25 years, and this proportion is increasing steadily with time. The majority of installations are likely to remain operational for many years, and, thus, the aging offshore infrastructure presents a growing challenge, particularly as reserves decline and the nature of companies in the market changes. In the extreme case, failure could cause the total loss of an installation with little chance of survival. Thus, the management of aging and life extension must be an integral part of the asset-integrity-management system (AIMS) to ensure continued safe performance. Integrity management of aging installations and successful implementation of an asset-integrity-management plan for life extension depend on understanding the degradation processes, on accurate knowledge of both the condition of the asset and its response in the aged condition, and on an implementation strategy to deal with the increasing risk of failure with time, which enables the greater likelihood of deterioration to be predicted, detected, and assessed. Risk-based goal-setting regulations, supporting guidance, industry standards, risk assessments, and performance standards provide the basis on which owner/operator policies can be developed.
- Health, Safety, Environment & Sustainability > Safety (1.00)
- Facilities Design, Construction and Operation (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (0.35)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (0.35)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148626, ’The Frigg Cessation Project,’ by Jean-Claude Berger, Total S.A., prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. The Frigg Cessation Project included the removal of six topsides, three steel jackets, and sealines with an estimated weight of 87 000 t. The project is unique because the field straddles the border between Norway and the UK. Both Norwegian and British statutes apply, depending on the location of the platforms. The main execution phases are described, from the offshore latch down, removal, and transportation to the onshore disposal of the installations. Introduction The Frigg field was a natural-gas reservoir on the North Sea continental shelf. The field was discovered in June 1971 in the Norwegian Block 25/1. In April 1972, gas was encountered in the neighboring UK Block 10/1. In July 1973, the Frigg licensees signed a unitization agreement regulating the split of the reserves between Norway and the UK. In May 1976, the Norwegian and British governments signed an agreement, known as the Frigg Treaty, under which Elf Norge (now Total E&P Norge) was defined as the operator of the Frigg field while Total Oil Marine (now Total E&P UK) was defined as operator of the gas-export system. Development of the Frigg field took place between 1973 and 1977 and consisted of five platforms (Fig. 1). Three platforms were in UK water—one drilling-and-production platform (CDP1), a treatment platform (TP1), and a living-quarters platform (QP). The two other installations were in the Norwegian sector—one drilling-and-production platform (DP2) and one treatment-and-compression platform (TCP2). Three of the platforms, TP1, QP, and TCP2 were linked permanently and formed what was known as the Frigg Central Complex. Three of the platforms—CDP1, TP1, and TCP2—and the intermediate platform MCP01 had concrete gravity-base substructures; QP and DP2 had steel-jacket substructures. The topsides of all platforms consisted of steel decks supporting several modules and pieces of equipment. First gas was produced from Frigg to St. Fergus in September 1977. In October 2004, the Frigg reservoir was finally shut in, having delivered approximately 192×10 std m of gas to the UK domestic market.
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 10/1 > NOAKA Project > Frigg Field > Frigg Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/5 > NOAKA Project > Frøy Field > Brent Group Formation (0.89)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/2 > NOAKA Project > Frøy Field > Brent Group Formation (0.89)
- (2 more...)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119140, "Multiple Transverse Fracturing in Open Hole Allows Development of a Low-Permeability Reser voir in the Foukanda Field, Offshore Congo," by Alberto Casero, SPE, Loris Tealdi, SPE, Roberto Luis Ceccarelli, SPE, Antonio Ciuca, SPE, Giamberardino Pace, SPE, Eni; Brad Malone, SPE, Schlumberger; and Jim Athans, SPE, Packers Plus Energy Services, prepared for the 2009 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 19–21 January. The paper has not been peer reviewed. During the past decade, multiple transverse fracturing in horizontal wells has been applied successfully in onshore low-permeability reservoirs. The reasons for the success of this technique are related to the effectiveness of hydraulic fracturing for production enhancement and to the relatively low cost of pumping services onshore. Offshore, high direct and indirect costs and the risks associated with operations have limited the use of this technology. This study documents the successful effort of taking these techniques offshore. Transverse fracturing with multistage completion—with properly engineered design of the well trajectory—can provide economic success of field development of low-permeability reservoirs. Introduction The Foukanda marine field is 20 km north of the Kitina platform and 52 km west of the city of Pointe Noire, Congo. Average water depth is 100 m. The field was discovered in 1998, with initial production in June 2001. That year, one well was drilled in the D reservoir, but it had very poor reservoir characteristics, and this level was abandoned. The well was recompleted in the shallower B4 reservoir. The low-permeability D reservoir (less than 10 md) was abandoned. Successful fracture treatments in the Kitina field in May 2007 proved the possibility of obtaining economical rates from a marginal reservoir. It was decided to test the multistage hydraulic-fracturing technology on the previously abandoned D reservoir in the Foukanda field. Synergy from early cooperation among drilling, reservoir, and production-enhancement engineers proved key for the operation. An optimum process path was followed: reservoir assessment, selecting optimum fracture(s) configuration, providing input for the drilling plan, selecting the proper completion to allow optimum fracture(s) placement, and, finally, plan execution. The original plan on Foukanda was to drill a new vertical or deviated well with one or two fractures. Fracturing engineers suggested changing this plan and drilling a horizontal well and completing it with multiple transverse fractures. The deviated well was discarded because of complex fracture-growing issues, which, in the best case, could have transverse fractures that are not properly spaced, resulting in fracture/production interference. The advantage of having transverse fractures in a horizontal well is the possibility of proper spacing and deciding the optimum number of fractures that are required.
- Africa > Republic of the Congo > South Atlantic Ocean (0.46)
- North America > United States > Illinois > Madison County (0.25)
- North America > United States > Texas > Montgomery County > The Woodlands (0.24)
- Africa > Republic of the Congo > Pointe-Noire > Pointe-Noire (0.24)
- Africa > Republic of the Congo > South Atlantic Ocean > Lower Congo Basin > Foukanda Field (0.99)
- Africa > Republic of the Congo > Kitina Field (0.99)
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19082, "Espirito Santo: The New Deepwater Frontier in Brazil," by Marcio Felix Carvalho Bezerra, SPE, and Nery Vicente Milani De Rossi, SPE, Petrobras, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May. Petrobras has been active in five simultaneous exploration and production frontiers in the Espirito Santo basin, namely gas in shallow water, light and heavy oil in deepwater, and light oil in ultradeep water and onshore. Petrobras has invested in new infrastructure projects including pipelines, processing plants, and a new port to support offshore operations. The company also has participated in research projects in partnership with the Federal University of Espirito Santo. Introduction Petrobras' activities in the state of Espirito Santo, in southeastern Brazil, encompass the Espirito Santo basin (onshore and offshore) and the northern portion of the Campos basin (offshore). Activities began in 1957 with an onshore focus. In 1968, Brazil's first offshore well was drilled in the Espirito Santo basin. In 1978, the Cacao field was the first offshore commercial discovery in the Espirito Santo basin, in a water depth of 19 m. Onshore production began in 1973, reaching maximum production of 25,000 BOPD in 1984, declining to 9,000 BOPD in 1998, when new fields were discovered by use of new technologies (e.g., 3D seismic). In early 2001, the first commercial deepwater discovery was the Jubarte field in the northern Campos basin, followed in 2003 by the discovery of light oil in deep waters in the Espirito Santo basin (Golfinho field). Projects Jubarte. Production began with a 2-month extended well test (EWT). This field produced approximately 20,000 BOPD through the Seillean floating production, storage, and offloading (FPSO) vessel. Phase-1 field development began December 2006 through FPSO P-34 with a production capacity of 60,000 BOPD. Phase 2 is planned for 2010 through FPSO P-57, with a capacity of 180,000 BOPD. Heavy-oil-production technologies include use of long horizontal wells to increase the production, use of electrical submersible pumps (ESPs) installed on the seabed as the main artificial-lift method with gas lift as backup, and the conversion of the FPSO P-34 to process heavy oil. Neighboring the Jubarte field, Cachalote, Baleia Franca, and Baleia Ana fields were discovered in 1500-m water depth. Production is scheduled to begin in 2012. The Baleia Azul field (1300 m water depth), south of Jubarte, may begin operation in 2014. The Caxareu, Pirambu, and Manganga fields were discovered in 2006 and are in the study phase to define the production systems. The Nautilus, Abalone, Ostra, and Argonauta fields are being developed in two phases, with the first phase in 2009, through an FPSO with capacity for 100,000 BOPD. Catua. The Catua field (in water depth of 1800 m), is 50 km southeast of Jubarte and contains 42°API oil in a carbonate reservoir. Discovered in 2005, an EWT is planned for 2008 to define the technical and commercial feasibility.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.89)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Espirito Santo Basin > Peroá Field (0.99)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Espirito Santo Basin > Canapu Field (0.99)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Espirito Santo Basin > Cacao Field (0.99)
- (5 more...)
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90325, "Offshore Processing Options for Oil Platforms," by Mark Bothamley, SPE, John M. Campbell and Co., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
- Europe > North Sea (0.55)
- Europe > United Kingdom > North Sea (0.22)
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86685, "North Caspian Project: Challenges and Successes," by Lyazzat Sarybekova, Agip Kazakhstan North Caspian Operating Co. N.V., prepared for the 2004 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Calgary, 29-31 March.
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- Asia > Kazakhstan > Atyrau Region > Caspian Sea (0.16)
- Well Drilling (1.00)
- Reservoir Description and Dynamics (1.00)
- Management (1.00)
- (3 more...)
The Malampaya development is in be achieved through the vent tubing remote deepwater offshore the in the umbilicals. The paper has not been peer reviewed. The Malampaya subsea development oilfield activity and devoid of any customary requires high overall system availability infrastructure. The nearest oilfield to ensure continuity of gas supply. Key elements of key spare parts and backup equipment surface imperfections on the connector included simplicity, redundancy, be procured and held offshore to hub sealing faces.
- Asia > Philippines > Palawan > South China Sea > West Philippine Sea > Northwest Palawan Basin > Block SC 38 > Malampaya Field (0.99)
- Asia > Philippines > Palawan > South China Sea > Quezon > Northwest Palawan Basin > Block SC 38 > Malampaya Field (0.99)
- Asia > Philippines > Palawan > Palawan > West Philippine Sea > Northwest Palawan Basin > Block SC 38 > Malampaya Field (0.99)
- (5 more...)
More Currently, this approach limits for conversion into synthetic hydro-than one-half of these discovered gas reserves is stranded gas, unmarketable because of prohibitive transportation costs, and one-half of this stranded gas is located offshore. Economical GTL technology could turn unmarketable natural gas reserves into a form that overcomes prohibitive transportation costs and satisfies the demand for cleaner fuels. The petroleum industry is investigating the new generations of GTL technology to provide profitable ways for monetizing reserves already discovered and to meet growing market demands for cleaner fuels that are becoming more expensive to produce from available oil. Taking any new process technology offshore for the first time is challenging. This article is a synopsis of paper OTC 10762, "Taking GTL Offshore," by M.A. Agee, Syntroleum Corp., originally presented at the 1999 Offshore Technology Conference, Houston,
Many types of structures have been fabricated weather, wave heights, and sea state influence structural members greatly affects the all over the world for use in the lifting and securing the structure. North Sea, including fixed, floating, modular, Dynamic-positioning systems are required In the 100-to 1,000-ton range, heavylift deck, deepwater, shallow, subsea structures, for landing large structures. Structures have been Use of lower-cost equipment and smaller Trailers require access onto the barge, and designed for a life span of 25 years, and cranes with lower overhead costs may ballasting systems are required for heel final decommissioning depends on recoverable be possible. However, because of crews, and trim of the vessel. Many of the module reserves, recovery rates, and commercial logistics, and maintenance, these items structures have piping systems and issues.
- Europe > United Kingdom > North Sea (0.26)
- Europe > Norway > North Sea (0.26)
- Europe > North Sea (0.26)
- (2 more...)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (0.49)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (0.35)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (0.35)
- Health, Safety, Environment & Sustainability > Environment (0.31)