In the Gulf of Mexico, there has been an increase in the number of wells drilled to depths greater than 20,000 ft with bottomhole pressures exceeding 20,000 psi. These deeper wells present drilling and completion challenges to the industry. Two of these challenges include fracture stimulation for low permeability and frac and pack sand control for higher permeability. Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0 to 1.04 SG fracturing fluid would require surface treating pressures greater than 15,000 psi. In the offshore marine environment, 15,000 psi pressure is the current limit of the flexible treatment line that transmits fluid from the stimulation equipment on the marine vessel to the wellhead on the rig.To solve this limitation, a borate-crosslinked high-density fracturing (HDF) fluid with of up to 1.38 was developed to harnesses the power of gravity and reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure without exceeding the safety limits of the surface equipment. In numerous wells, a minimum of 20% reduction in surface treating pressure over the conventional 1.04 SG was recorded.This paper summarizes the well conditions, extensive fluid qualification testing, procedures, and selected job results along with final completion performance indicators.The HDF fluid enables treatment of these deep offshore wells by lowering surface treating pressure. Conventional 15,000 psi equipment could be used, less horsepower was required, and creating a safer work environment was achieved.

It has been observed that pumping a mini-frac prior to a TSO Frac-pack can impact the effectiveness of the frac-pack. The calculated fluid loss parameters determined in the diagnostic test are often not valid for the main fracture design due to the residual effect of the mini-frac and/or step-rate fluids. A technique will be presented in this paper which allows the calculated fluid loss parameters from the diagnostic test to be used reliably without excessive waiting time for the reservoir to recover to its original leak off characteristics. Fifty plus treatments were evaluated to develop a technique which makes this possible. The use of this technique resulted in a significant change in the success of the TSO designed treatments - success being a TSO type pressure increase while pumping. The success rate to achieve designed TSO, by incorporating the changes described in the paper, was increased over 20 percent with a reduction in time between diagnostic tests and the main frac. In the wells associated with this paper, a borate-crosslinked fluid was used for a mini-frac treatment followed by a step-rate test prior to the main proppant laden frac-pack. The fluid was designed with minimal polymer loading for the well conditions. The resulting mini-frac tests had low fluid efficiencies. It was originally thought that using this fluid, followed by injection of a linear step-rate fluid, would minimize the changes observed in fluid efficiency between the diagnostic test and the main fracture treatment. However, the effect of the diagnostic test on fluid leak off still resulted in less than desired TSO predictability. A technique of adding a pH control additive into the final portion of the step-rate test fluid was found to successfully allow the use of the observed diagnostic test results, honoring the efficiency from the mini-frac test. The quantity and placement of the pH control agent in the step-rate protocol were dependent upon well conditions. The waiting time between the diagnostic test and the main treatment was reduced since a positive, controlled change was applied. The optimum pH reduction for the desired effect was determined in the laboratory and designed into each treatment depending upon well conditions.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSingle selective gravel pack completions can be very expensive in offshore environment due to high rig costs. Conventional techniques for such completions involve multiple trips in and out of the hole. A typical procedure consists of the following 6.5 round-trips excluding a wire-line trip to set the sump packer: (1) Perforate the lower zone, (2) Gravel pack the lower zone, (3) Run and set the packer plug to isolate the lower zone, (4) Perforate the upper zone, (5) Retrieve the packer plug, (6) Gravel pack the upper zone, with a GP assembly that includes an isolation assembly for lower zone, and (7) Run the production tubing. This process typically takes 8-10 days, prohibiting the completion of zones with marginal economics.

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Few wells in the world have been completed at the depths and pressures required for the Tahiti Field. This combination of depth and pressure has stretched existing drilling and completion technologies to the limit. Efficiently drilling and completing the Tahiti wells required extensive engineering to design, select materials, and fabricate and test the highly specialized equipment needed to accomplish this daunting task. Along the way numerous experts have been employed to identify the technology and equipment upgrades required for successful implementation in the field. This paper will discuss the technology development from identification through implementation.