Development and Use of High-Density Fracturing Fluid for Deepwater Frac Packs
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2009
- Document Type
- Journal Paper
- 61 - 63
- 2009. Society of Petroleum Engineers
- 2 in the last 30 days
- 75 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116007, "Development and Use of High-Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs," by L. Rivas, SPE, G. Navaira, SPE, and B. Bourgeois, SPE, Chevron, and B. Waltman, SPE, P. Lord, SPE, and T. Goosen, SPE, Halliburton, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 December. The paper has not been peer reviewed.
There has been an increase in the number of wells drilled to depths greater than 20,000 ft in the Gulf of Mexico (GOM). Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0- to 1.04-specific-gravity (SG) fracturing fluid would require surface treating pressures greater than 15,000 psi, which exceeds the limit of the flexible treatment line. To solve this problem, a borate-crosslinked high-density fracturing (HDF) fluid with SG of up to 1.38 was developed to reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure.
The Tahiti field is in the GOM in the Green Canyon area where water depths range from 4,000 to 4,300 ft. The discovery well was drilled in 2002. Total depth was more than 28,000 ft. Initial evaluation indicated approximately 400 ft of net pay in the high-quality reservoir sand that was encountered. Subsequent appraisal drilling over the next 2 years resulted in confirmation of the size of the Tahiti field and its status as one of the most significant net-pay accumulations ever discovered in the GOM. The discovery well was re-entered in 2004, and a well test was performed to verify deliverability, dynamic well data, and reservoir properties. A stacked frac pack in the Miocene M21A and M21B sands was planned for the well test. The Tahiti M21A sand averages 60 to 80 ft thick, and the M21B sand averages 120 to 150 ft thick. Permeability ranges from 600 to 800 md. The decision was made to complete both intervals with a single, high-rate frac pack. At the time, at a depth in excess of 25,800 ft, it was the deepest successful well test and frac-pack completion ever carried out in the GOM. The HDF fluid was a key component of the successful Tahiti well test. The well-test results led to the development of the Tahiti field, which began in February 2006.While planning the Tahiti well test, several factors influenced the decision to develop a suitable HDF fluid that would minimize surface treating pressures and allow the fracture job to be pumped at pressures below the 14,000-psi limit. Uncertainty regarding Miocene-pay-sand fracture gradients, and required treating rates, coupled with high friction losses in the treating string led to the desire to find an HDF fluid that would allow the fractures to be pumped at 40 to 45 bbl/min while staying within surface-treating-pressure limitations.
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