Abstract:
Mensa project is a remote subsea gas development in 5300' of water in the
offshore Gulf of Mexico. Planning and execution of the project required a
challenging balance between the desire to utilize proven solutions from Shell
Offshore's Popeye project, the requirements to extend and develop new
technology, continuing emphasis on cost and cycle time reductions, and
working within a newly created subsea systems alliance. Mensa was successfully
installed, and the first well started up in July 1997. It represented
application of an innovative, cost-effective field development system, that
established dramatic new offshore standards for water depth and offset distance.
Mensa's History of Development:
In 1987, Shell Offshore discovered Mensa, a gas field in the Mississippi
Canyon area. A second appraisal well was drilled in 1988, confirming a large
gas discovery. However, since the find was in water much deeper than any
offshore development at that time, its development feasibility was uncertain.
Joint subsurface and development feasibility studies were initiated in 1989,
including consideration of a tension leg well jacket and subsea options.
By early 1991, it was apparent that a satellite subsea development was the only viable economic solution, but the technology was not fully created. Deepwater diverless, subsea technology had been demonstrated by this time, however, the applications had been in less than 3000' of water with relatively short offsets, were lower pressure (5000 psi systems), and had utilized guidelines for guiding/positioning drilling and subsea equipment to the seafloor. Mensa was much higher pressure, had a very long offset, and was well beyond the practical water depth limit for using these guidelines. The basic strategy adopted was to develop Shell Offshore's Popeye prospect so that it could serve as a technological stepping stone to Mensa. Mensa was put in the long range operating plan to follow Popeye.
In 1993, Shell Offshore completed a trade with leaseholders of the two blocks north of the Mensa exploration wells, and a four block unit was formed. SOI is the operator and has a 100% ownership of the unit. As interest increased in accelerating all of SOI's deepwater prospects, additional preliminary design trade-offs and operability studies were conducted for Mensa, including consideration of a Spar buoy to provide local chemical injection and controls. A subsea system was selected by late 1994, and a development plan with conceptual design was formed by spring of 1995.
Although accelerated by two years from the original long-range plan, it was felt that the technology development for Mensa could be achieved within acceptable risks. The Mensa project team was formed and the project approved in late May of 1995. First production was achieved in July 1997, several months ahead of the base case schedule.
Geology and Well Plans:
The Mensa reservoir was deposited as a single, thick turbidite reservoir in
Mississippi Canyon blocks 686, 687, 730 and 731. The ultimate recovery from
the field is 720 BCF. The development plan includes three subsea wells
directionally drilled from a spread well cluster area on block 687 to
bottomhole locations on blocks 686, 687, and 730. These wells are connected
to a subsea manifold five miles to the west in block 685. The 68 mile tieback
distance to the host platform is the longest in the world by a factor of two
or more.
The system was designed to produce up to 300 MMCFPD of high pressure gas with no associated condensate. Condensate rates of about 2 bbl per MMSCF proved problematic when encountered on the first well. No more additional wells are planned.
Biographical Sketch:
Dennis C. McLaughlin has over 24 years of offshore engineering and management
experience. He joined Shell Offshore, Inc. in 1990 and has worked on the
deepwater division's subsea activities in the Gulf, most notably as the Popeye
project leader and later as Mensa project leader. He is currently subsea
engineering manager for Shell Deepwater Development Systems, Inc.
After earning a B.S. in mechanical engineering from Michigan State University, he started his career with Exxon and spent six years as a reservoir engineer in Gulf of Mexico fields. Dennis then worked for ten years with Seaflo Systems, specializing in subsea and floating systems technology for international clients. He was Houston operations manager at Seaflo for five years.
Abstract:
The new OCENSA pipeline now connects the Cusiana oil fields in central Colombia to an offshore tanker loading facility at the port of Cove-as on the Caribbean Sea. The 780 km long pipeline will ultimately transport 320,000 barrels per day. The pipeline is constructed of 30 and 36 inch, Grade X-70 steel pipe with a wall thickness of up to 0.812 inches. A 218 km section of the pipeline between the pump station at El Porvenir and the pressure regulation station at La Belleza crosses rugged Andean mountain terrain. Along this section, eight zones were identified which pose potential landslide hazards to the pipeline.
OCENSA (Oleoducto Central S.A.) is a joint stock company consisting of the oil field developers and several pipeline companies. Dames & Moore was contracted by OCENSA to assess the landslide risk to the pipeline in each zone and to recommend remedial measures, if necessary.
First, a series of field reconnaissances were undertaken to identify individual landslide-risk sites within each zone. Then, for each site, a geological and geo-technical evaluation was performed. Site evaluations included topographic and geologic mapping, hydrological studies, subsurface exploration, field and laboratory testing, slope stability analyses, and the installation of piezometers, slope inclinometers and survey monuments.
Ideally, landslide risk could have been computed from a probabilistic point of view. However, probabilistic analysis requires a very significant amount of data. It would have been prohibitive from a schedule point of view to obtain enough geotechnical data to choose an appropriate probability distribution function and to accurately compute standard deviations of the relevant parameters. For this reason, landslide risk to the pipeline was assessed using a factor of safety approach in conjunction with engineering judgement.
The landslide risk to the pipeline at each site was categorized as low, moderate, or high. This ranking was based on the following factors:
Biographical Sketch:
Jonathan Motherwell has been vice president of Dames & Moore for the past eight years. He is general manager of the firm's Latin American region. As manager, he is responsible for the firm's business from Mexico to Argentina. He has over 20 years of technical and managerial experience with large-scale engineering projects related to oil and gas, mining, power, and chemical manufacturing industries in the United States, Latin America, Europe, and the Middle East. Mr. Motherwell received a Master of Science in engineering from the University of Texas at Austin and a Bachelor of Science in civil engineering from the University of Missouri-Rolla. He is a registered professional engineer in four states, including Texas.
Dames & Moore, Inc. comprises a global network of companies known as the Dames & Moore Group. The companies include: Dames & Moore; Walk, Haydel & Associates; O'Brien-Kreitzberg; DecisionQuest; BRW Group; and Dames & Moore Ventures. These companies provide discrete as well as integrated full-service engineering, environmental,construction management and litigation support services, and also undertake equity investments related to their areas of expertise. The D&M Group companies and their subsidiaries have offices in 136 cities in 26 countries staffed by over 5,300 employees.
Hyatt Regency, 1200 Louisiana. Social period at 11:15am. Meeting starts at 11:45am.
Abstract:
The Hoover field discovery represents the largest of a string of recent
successes in the sand-rich, Plio-Pleistocene, Diana field intraslope basin of
the western Gulf of Mexico. Hoover is located 160 miles south of Galveston and
120 miles offshore in 4800' of water. The discovery is an amplitude-supported,
oil and gas discovery located in Alaminos Canyon Blocks 25 and 26; an
anticlinal closure in the central portion of the Diana basin. Hoover contains
reserves in excess of 100 MBOE in two zones. The first is a shallow,
Pleistocene gas sand. The second, and most prolific, is a Pliocene oil zone
with very good reservoir quality. Both zones have significant amplitude
expression with apparent flat events related to hydrocarbon/water contacts.
The discovery well, the Exxon/BP AC 25 #1,(Figure 1) drilled in early 1997, found 47' of gross gas pay in the Pleistocene and 97' of gross oil pay in the lower portion of the Upper Pliocene. The discovery well found the hydrocarbon/water contact in both zones and confirmed the amplitude-based areal extent for each accumulation. Although high quality reservoir was predicted, the Pliocene reservoir quality exceeded expectations. The reservoir has average porosity in excess of 30% and average permeability over 1000 md.
The Hoover discovery is in stark contrast to the largely unsuccessful Rockefeller prospect, five miles west. Although an anticlinal closure like Hoover, Rockefeller had no thermogenic hydrocarbons. In late 1995, Exxon drilled the Exxon EB 992 #1 and #1 ST which found full saturation biogenic gas in only one of four objectives. The remainder were water sands with low saturations of biogenic gas.
A detailed vertical and lateral migration analysis of the entire Diana intraslope basin was undertaken to insure Hoover and the surrounding prospects had adequate migration to warrant investment. The study found Rockefeller to be heavily dependent upon a single fault for vertical migration from the Early Tertiary source. Hoover, however, had several prospective vertical migration conduits within its lateral migration drainage basin. In addition, all the closures along this migration pathway had amplitudes to their structural spill points. This analysis was provided the critical technical justification to proceed with exploration at Hoover. The presence of thermogenic hydrocarbons in the Hoover's Pliocene reservoir confirmed our current model for vertical and lateral migration of hydrocarbons in the Diana intraslope basin. It also lowers the source risk of other closures within the same migration system.
With these latest discovery volumes, the Exxon/BP partnership should be able to fully exploit Hoover, the sizable Diana reserves discovered in 1990, and surrounding satellite discoveries and prospects.
Biographical Sketches:
Jim Higgins received a B. S. in geology from Oklahoma State University in 1981.
He started with Exxon as a geologist working onshore basins (Gulf Coast,
Anadarko basin, Williston basin, and several Rocky Mountain basins) from 1981
to 1989 in both the exploration and production departments. From 1989 to 1993,
Jim was in Exxon's Midland production office as a supervisor of geologists and
engineers responsible for new field development and secondary recovery
implementation. Since 1993, Jim has been working as a geologist and geophysical
interpreter in Exxon Exploration where he has been developing and drilling
several prospects in the western Gulf of Mexico.
Dean Chergotis, BP Exploration, no biography available.
Jay C. Nania received a B. S. in geology in 1984 and a M. S. in geology in 1987 from the University of Wisconsin, Madison. He started with BP Exploration working as a wellsite geologist, and geoscience operations coordinator for activities throughout the lower 48 and offshore Gulf of Mexico. From 1990 to 1994, Jay worked as a production geologist and reservoir modeler on several of BP's Gulf of Mexico Shelf and Flex Trend fields. Since 1995, Jay has been senior geologist, responsible for exploration and appraisal of BP's interests in the Diana/Hoover sub-basin in the deepwater (>4000') western Gulf of Mexico. He is currently assigned to the Exxon/BP Diana and Hoover Integrated Project team.