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• W1976804518 abstract "Summary The successful hydraulic fracturing program at Prudhoe Bay would not have been possible without an effective coiled-tubing-unit (CTU) cement-squeeze program. Many fracture stimulation candidates were wells that had been squeezed previously. Therefore, squeezed perforations were exposed to higher differential pressures during fracturing operations than normally were seen at Prudhoe. At the outset of the fracture stimulation program in 1990, squeeze perforations failed when subjected to fracture job pressures. It quickly became clear that more aggressive CTU squeeze techniques resulting in stronger squeezed perforations would be necessary if the Prudhoe fracture program were to achieve its goals. Arco Alaska Inc. implemented a more aggressive CTU squeeze program in the Eastern Operating Area (EOA) in mid-1990. This paper documents the results of the new squeeze program, in which increased surface coiled-tubing squeeze pressures from 1,500 to 3.5(X) psi for 1 hour were used. More resilient, acid-resistant latex cement also became the standard in late 1990 for squeeze cementing. Implementation of this program has resulted in a squeeze success rate approaching 90%. Introduction Prudhoe Bay is the largest producing oil field in the U. S. 1989, it became apparent that many wells at Prudhoe were experiencing rapid production declines and no longer were treatable by conventional matrix stimulations. By 1990, an aggressive hydraulic fracturing program was in place, and many wells that needed cement squeezes before they could be fractured were identified. Other wells to be fractured had already been squeezed. The low permeability of the remaining gas-free interval in these wells was insufficient to maintain flow. Although the remedial CTU squeeze program had been very successful in the past. CTU squeezes rarely had been subjected to the differential pressures needed in a hydraulic fracture treatment (2,000 to 2,500 psi). In most cases, relevant pressures during a CTU squeeze are measured with a static seawater column in the production-tubing/ coiled-tubing annulus. Therefore, measured surface pressure and differential pressure across the formation are approximately equal. For a typical well at 8,800-ft true vertical depth (TVD) at Prudhoe, the pressure at the formation measured with a static seawater column in the tubing is 3,887 psi. This is close enough to formation pressure to assume a balanced seawater column to the surface. Therefore, in this paper, CTU squeeze pressure, measured surface pressure, and differential pressure across the formation are considered equivalent for practical purposes and are used interchangeably. The typical low-pressure CTU squeeze pressure used in the EOA in early 1989 is summarized below. Early 1989 General Procedure The following procedure was more than adequate for many production wells before the onset of the hydraulic fracturing program at Prudhoe Bay. In early 1990, it became apparent after several aborted fracture treatments that otherwise adequately squeezed perforations would break down when subjected to fracture pressure, 1. After any necessary presqueeze acid work, the well was fluid packed with heated seawater, and controlled-fluid-loss cement was spotted from total depth (TD) up across the perforations with coiled tubing. 2. A differential pressure below the fracture pressure was established across the formation. This usually translated to about 1,500-psi differential pressure and was maintained for roughly 45 minutes to dehydrate the cement and build nodes. 3. Excess cement left in the wellbore was contaminated with a bentonite/borax mixture. The next day, a xanthan- or welan-gum biopolymer was pumped down the coiled tubing to jet out the diluted cement in the wellbore. A 500-psi differential pressure relative to formation pressure was maintained during this process. Seawater was left in the wellbore across the perforations while the cement cured. 4. The well generally was reperforated no earlier than 2 weeks after the squeeze owing to the use of borax as a retarder. Prudhoe Fracture Gradients A typical well at Prudhoe his a 0.62-psi/ft fracture gradient and has about an 8,800-ft TVD. As noted, in early 1989, squeeze pressures generally were maintained below the formation fracture gradient by limiting differential squeeze pressure at the formation face to 1.500 psi. Fracture stimulation pressures, on the other hand, can range from 2,000 to 2,500 psi above formation pressure. Prefracture breakdown treatments, used to establish adequate formation communication and to quantify perforation friction before fracture stimulations, were performed as high as 3,500 psi above formation pressure. North Slope Field Trials and Model Study In the past, CTU squeezes had been maintained below the formation fracture gradient. It was thought at the time that higher squeeze pressures would result in fracturing cement into the formation. Not only would this cause extensive formation damage, but the squeeze would he lost once the fracture opened. A secondary consideration was that high squeeze pressures held for long periods of time might result in excessive node buildup that could cause cleanout problems after the squeeze. In addition, mechanical stresses on the production tubing resulting from higher internal pressure could cause the tubing to stroke out of the packer. The first concern, cement fracturing into the formation, was substantially alleviated when BP Exploration, operator of the Prudhoe Western Operating Area, performed a high-pressure (3,500-psi) squeeze for 50 minutes in early 1989. The success of the squeeze and maintenance of formation integrity during the squeeze, despite being above the fracture gradient for the well, were both very encouraging. Arco model studies done later in 1989 on the North Slope with a pressurized CTU squeeze model indicated that squeeze pressures could he increased substantially without causing excessive node buildup. Although these studies were aimed primarily at determining the maximum wash rates that could be performed during cleanout operations, a differential squeeze pressure of 3,000 psi held for 1 hour using 35.2-cm3/30-min fluid-loss cement resulted in an 0.8-in.-high node with a 1.75-in. diameter. Earlier work with the same model produced similar nodes with only 1.500-psi differential pressure and 50- to 70-cm3/30-min fluid-loss cement. The results of this testing indicated that node buildup would not be a severe problem. SPEPF P. 260^" @default.
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• W1976804518 date "1993-11-01" @default.
• W1976804518 modified "2023-09-27" @default.
• W1976804518 title "New Coiled-Tubing Cementing Techniques at Prudhoe Developed To Withstand Higher Differential Pressure" @default.
• W1976804518 doi "https://doi.org/10.2118/24052-pa" @default.
• W1976804518 hasPublicationYear "1993" @default.
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