High-Pressure/High-Temperature Consolidated Completion in the Gulf of Mexico
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 2008
- Document Type
- Journal Paper
- 96 - 100
- 2008. Offshore Technology Conference
- 1 in the last 30 days
- 59 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18976, "High- Pressure,High-Temperature Consolidated Completion in the Continental Shelf Environment of the Gulf of Mexico: Case History," by Richard E. Patterson, SPE, and Trevor J. Willms, SPE, El Paso E&P, and Keith Foley, SPE, and Jason Edwards, SPE, Halliburton, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Decades after the first completion in the Gulf of Mexico (GOM) continental shelf, the logical expansion of these mature assets has extended into reservoirs that are deeper, hotter, and higher-pressured than wells completed previously. These high-pressure/high-temperature (HP/HT) wells can cause extreme completion challenges. HP/HT formations also tend to have low permeabilities, which is the opposite of most GOM reservoirs. To make these low-permeability formations economical in an offshore environment, it is imperative that stimulation treatments be completely effective.
The West Cameron 62 field, on the continental shelf just south of Louisiana at a water depth of 35 ft, had its first well completed more than 20 years ago. Since that time, more than 30 different intervals have been completed at depths ranging from a few thousand feet to more than 10,000 ft. In recent years, it has become necessary to focus on reservoirs that exist in the 18,000 to 20,000 ft true vertical depth (TVD) range. At these depths, the pressures and temperatures of the formation trend toward the limit of what current technology allows when completion equipment and fluids are considered. The West Cameron 62 Well A-2 was completed at these depths in the Cris R formation.
The Cris R sand is located between 17,843 and 18,021 ft TVD, which correlates to 19,789 and 19,976 ft measured depth (MD), respectively. The initial bottomhole pressure (BHP) for the Cris R formation was measured at 16,500 psi at midperforation. The bottomhole temperature (BHT) at midperforation was 356°F.
Contrary to conventional GOM reservoirs, which typically have average permeabilities greater than 50 md, the permeability of the Cris R sand averaged only 0.64 md. The 18% porosity also was significantly lower than that of the well-sorted formations found at shallower depths. In fact, along with permeability and porosity, the rock mechanics falls more in line with typical south Texas “hard rock” reservoirs such as the Wilcox and Frio formations.
Despite the low permeability and porosity, the production of the well before the hydraulic-fracturing treatment was 12.0 MMscf/D and 396 B/D of condensate at a 8,572-psi flowing tubing pressure (FTP). Use of fracture models and nodal analysis led to the belief that the production rates could be increased by at least two-fold through implementation of a hydraulic fracture. However, very little information on HP/HT fracturing treatments in the GOM was available.
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