Summary An increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deepwater and/or subsea environments in which completion reliability is paramount because of the prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oil-based (OB) fluids, with the common practice of switching to water-based fluids when the reservoir drilling starts. In the last several years, some operators started using OB drilling fluids in the reservoir section as well and gravel packed them with water-based fluids. In some cases, these practices required running predrilled liners in OB fluids and subsequently displacing to water-based fluids before running in hole with the sandface screens and gravel packing. In other instances, screens could be run in hole with OB fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zones can introduce serious concern, in the event that carrier-fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells. In this paper, we present a case history of the first successful application of drilling and completing in an all-oil environment, using a reversible OB reservoir-drilling fluid (RDF) (the filter cake of which reverses wettability from oil to water when exposed to an acidic fluid) and an OB gravel-packing fluid. The carrier fluid used in this application included a filter-cake cleanup solution in the aqueous internal phase of the OB carrier fluid, extending the application of simultaneous gravel-packing and cake-cleanup processes that have been successfully practiced in water-based-fluid environments to OB systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MM scf/D per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field. Introduction Openhole gravel packing is a proven sand-control technique from both productivity and reliability standpoints and has been the preferred method of sand control by many operators in deepwater/subsea developments (Price-Smith et al. 2003; Ali et al. 2001). Synthetic/oil-based (S/OB) fluids have traditionally been the preferred drilling fluids in these environments, although the operators have often been forced to switch from S/OB mud used to drill the tophole to a water-based fluid for reservoir drilling because of various concerns, particularly in wells that will be gravel packed. The drivers for S/OB drilling have been well documented and include a higher rate of penetration, excellent shale-inhibition characteristics unmatched by any commercially available water-based fluid, gauge hole, lubrication while drilling as well as while installing sandface completion, low maintenance costs (dilution and solids-control costs in reactive silt/shale environments), and so on (Gilchrist et al. 1998). In addition, switching to an S/OB RDF is much less time consuming and simplifies fluid management at the surface (intermixing of water-based and OB fluids vs. two OB fluids, storage space on the rig, etc.).
fax 01-972-952-9435. AbstractAn increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deep-water and/or sub-sea environments, where completion reliability is paramount due to prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oilbased fluids, with the common practice of switching to waterbased fluids when the reservoir drilling starts. In the last several years, some operators started using oil-based drilling fluids in the reservoir section as well, and gravel packed them with water-based fluids. In some cases, these practices required running pre-drilled liners in oil-based fluids, and subsequently displacing to water-based fluids, prior to running in hole with the sand-face screens and gravel packing. In other instances, screens could be run in hole with oil-based fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zone can introduce serious concern in the event that the carrier fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells.In this paper, we present a case history of the first successful application of drilling and completing in an all oil environment, utilizing a reversible oil-based reservoir drilling fluid and an oil-based gravel packing fluid. The carrier fluid used in this application included a filtercake cleanup solution in the aqueous internal phase of the oil-based carrier fluid, extending the application of simultaneous gravel packing and cake cleanup processes that have been successfully practiced in water-based fluid environments, to oil-based systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MMSCFD per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field.
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Wellbore cleanups are an integral part of the effort to reduce formation damage during completion operations. One operation that can significantly impact the cost of the well completion is the displacement from mud to completion brine. SBM (synthetic-based mud) cleanups pose unique challenges due to the emulsifying tendency of the additives to the synthetic base fluid. In deepwater, there are at least two displacements that compound an already difficult task, i.e., the riser and the casing. This paper demonstrates how a combination of software design tools, laboratory optimization and characterization, and post job evaluation led to improved displacement practices for the deepwater wells evaluated for this paper. Introduction In early 2001, the authors began an investigation of how to improve well cleanup and displacement techniques in conjunction with a deepwater project in the U.S. Gulf of Mexico. This investigation was commenced at the request of the operator following a failed attempt at well cleaning on this same project. Two goals were identified early on. First, a clear understanding of the impact of friction pressures related to the pumping of chemical spacers had to be achieved. This was important for reasons relating to cement-shoe integrity. This was achieved through computer wellbore modeling. Second, the high daily rig cost mandated that the well displacement have minimal impact on the critical path. This meant that the pipe must be cleaned on the first attempt while pumping at very high rates. This was accomplished through spacer compatibility and performance testing in the laboratory, taken through computer simulations, and then implemented in the field. In the failed attempt to clean the riser, it was felt that the chemical washes and related pumping rates had been least engineered in terms of appropriate pill size, chemical concentration, wall contact time, inter-chemical compatibility, and desired flow regimes. Using advanced computer wellbore simulation software, optimal pumping characteristics were modeled for each pill in specific pipe geometries. Once the modeling was complete, laboratory work began to develop technical limit criteria for each individual pill. In this fashion, the viscosity transfer and cleaning efficiencies were determined for the lead and secondary pills using optimal chemical concentrations. During the actual implementation of these displacements, numerous samples were caught for post-job analysis. This paper will show how, using these methods, very predictable results were achieved in these displacements. Rig time was also saved by the ability to pump these displacements at very high rates. As a result the engineers were better able to predict the timing of other completion operations and minimized the impact of the displacement on the critical path.
Economic success of deepwater and ultra-deepwater developments often depends on the use of innovative technologies that can increase production and minimize workover needs to achieve the sought-after field efficiency during the productive life of the field. Intelligent completion technology, a new concept for the oilfield, is one of the technologies that can support these needs. This well completion concept allows the operator to obtain real-time or near-real-time reservoir data, and then, to reconfigure the wellbore production/injection architecture to adapt to the information obtained. Along with pipeline, platform, and subsea system synergies, three fields in the Gulf of Mexico – Aconcagua, Camden Hills, and King's Peak – are using intelligent completion technology to optimize a marginal reserve base. Located in Mississippi Canyon Blocks 173, 217, 305, 348 and Desoto Canyon Blocks 133 and 177 in 6200- to 7200-ft of water, the production from the three fields will be tied to the Canyon Station host platform, 55 miles from the most distant well location. Though slight variations exist between the intelligent completion systems being installed in the three fields, the basic design in each consists of:A production packer with a hydraulic and electric bypassA gauge package for measuring shut-in and flowing pressure from two sand-controlled zones2 control valves with metal-to-metal seals to control flow from both production intervalsA shroud to isolate flow between upper and lower production intervals. The piston-actuated control valves will be functioned through a direct hydraulic link from the subsea control module. Pressure applied at the subsea control module will allow hydraulic fluid to be directed to the open side of one piston, the open side of the other piston, or the close line, which is common to both valves. Introduction The three individual offshore fields, King's Peak, Aconcagua, and Camden Hills, that will tie production to a common platform are described below. The field locations are shown in Fig. 1. King's Peak. Mississippi Canyon 173 and 217 and Desoto Canyon 133 and 177 comprise the King's Peak Field, operated and owned 100% by British Petroleum. Located in 6200–6800 feet of water, three of the four King's Peak wells will be completed using intelligent completion techniques. The dry gas field has an initial reservoir pressure of approximately 6800 psi. This water drive gas reservoir is part of a sub-salt development constrained by the deepwater depositional environment. The King's Peak basic configuration is shown in Fig. 2. Aconcagua. Located in Mississippi Canyon Block 305 at a water of depth 7000 ft and operated by TotalFinaElf, the Aconcagua Field will produce from four Text W aged reservoirs, designated as the Red, Green, Orange, and "C" sands. There are four production wells planned for this development owned by TotalFinaElf 50%, Mariner Energy 25%, and Pioneer Natural Resources 25%. The layered sands contain dry gas at approximately 6600 psi.
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