Gulf of Mexico Deep Ultra-HP/HT Completions - Current Technology Gaps
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2006
- Document Type
- Journal Paper
- 74 - 77
- 2006. Society of Petroleum Engineers
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- 57 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97300, "Gulf of Mexico Shelf Deep Ultra-HP/HT Completions - CurrentTechnology Gaps," by D. Hahn, SPE, APA Petroleum Engineering Inc.; M. Atkins, SPE,and J. Russell, SPE, BHP Billiton Petroleum (Americas) Inc.; and B. Pearson, SPE, APA Petroleum Engineering Inc., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October.
Numerous operating companies are pursuing new and much deeper geologic horizons on the Gulf of Mexico (GOM) continental shelf. However, as well depths increase, wellbore construction and production operations become much more challenging because of high-pressure/high-temperature (HP/HT) extremes. These wells can be drilled safely, but there are significant well-completion-technology gaps that require design and development. The full-length paper details requirements for the production tubulars as well as for downhole and surface completion equipment.
Maturation of the existing, more traditional GOM shelf oil- and gas-producing fields has provided a significant network of subsea pipelines and offshore platforms. Many of these facilities have excess capacity.
Some of the primary targets are of similar geologic age to the onshore Wilcox trends but at much deeper burial depths, frequently exceeding 30,000 ft within the shelf area. It is probable that the prospective sand bodies deeper than 25,000 ft will have pore pressures equivalent to 18-lbm/gal mud weights. Expected temperature gradients could range from 1.2 to 1.4°F/100 ft.
Because well simulations predict surface shut-in pressures of approximately 24,000 psi, sour-specification materials are required when hydrogen sulfide (H2S) levels exceed 2 ppm. Because of the unknown fluid compositions for these much deeper horizons, a prudent well design should assume that sour-specification materials should be used throughout the downhole
system. Moreover, there is evidence of H2S in other Wilcox producers.
The initial target gas-production rates exceeding 50 MMscf/D are achievable through a 3-in.-internal-diameter (ID) tubing string to a depth of 30,500 ft. Fig. 1 shows that even at a lower formation permeability, 57 MMscf/D can be produced through 3-in. tubing with a 6,000-psi wellhead flowing pressure (WHFP) and a 50% drawdown at the formation face. When the reservoir pressure has depleted to a normal water gradient, this zone, with unchanged formation permeability, still is capable of producing 15 MMscf/D at the same WHFP. The asset team determined that these gas rates could provide sustainable development economics. Smaller tubing strings were considered in an attempt to reduce the production-casing tieback diameters. These tubing sizes were eliminated, primarily because of significant operational and performance risks.
After determining that sour-specification material was required, the next area of concern is corrosion. The expected presence of carbon dioxide (CO2) at elevated temperatures combined with formation water or condensation water creates a very corrosive environment that necessitates use of corrosion-resistant alloys (CRAs) for the production liner, tubing, and associated equipment. Resistance to sulfide stress cracking is paramount to the design criteria for these ultradeep overpressured wells.
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