No abstract

Epoxy acrylate‐based sterolithography resins have been used successfully as tools for injection molding. Molds made out of these resins fail at distinct times: during the first injection of plastic; during the first part first ejection; during either injection or ejection, but after a certain number of parts have been produced, which can be compared to a fatigue process. This paper presents corelations between measured properties of stereolithography molds and injection molding processing conditions so as to understand and predict mold failure. The study focuses on two stereolithography resins (SL 7510 and SL 7510) and one epoxy‐based composite material used for the high speed machining of prototype molds (Renboard). Rapid tooling materials are studied in fatigue, tensile, and fracture at injection molding operating temperatures and at room temperature. Finally, a method to address failure of molds is proposed using the theory of fracture.

TAO field is a high rate gas development in the Mediterranean Sea, operated by North Sinai Petroleum Company (NOSPCO), a joint venture of Perenco and EGPC. The field comprises multichannel sandstone reservoirs from the Nile Delta depositional environment. Earlier exploration and appraisal stages had proven reserves for three of the six sands, with the remaining three identified as potential (unconfirmed) gas bearing reservoirs, all of which require sand control.A multidisciplinary project team put forward and implemented a field development plan to maximize profitability through effective measures for overall cost reduction, while ensuring sustained delivery of the production commitment. This paper will detail the field development plan, implementation and results, along with the case histories. This plan included:• Batch drilling and batch completion to minimize drilling and completion costs, and maximize data gathering as early as possible. • Completing two of the four wells as openhole gravel packs targeting the most prolific sand to ensure that the production target is met with the productivity benefit of an openhole completion and reliability of gravel packing as a sand control technique. • Completing the remaining two wells as cased hole gravel packs in squeeze mode to increase well productivity by ensuring maximum amount of gravel behind casing and targeting the two remaining sands with proven reserves as well as the sands with potential reserves in order to sustain the production commitment over project life, while avoiding to drill two dedicated appraisal wells.All gravel packs were performed with filtered seawater as the base brine and mesh type sand control screens, with the exception of one of the zones, where alternate path screens were used in conjunction with a seawater compatible viscoelastic surfactant carrier fluid. Openhole gravel packs utilized a service tool that allowed post-gravel-pack filtercake cleanup treatment.Post completion multi-rate tests concluded that both openhole gravel pack wells fulfilled the required productivity, showing potential productivity above 110 MMSFCD per well. In addition, the two of the zones tested in each of the cased-hole gravel packs showed potential productivity above 50 MMSCFD per zone.

The Ompoyi and Orindi fields are located 5 km offshore Gabon in a water depth of 20 m. The high oil density (23° API) and high produced water salinity (150 kppm) combined with reservoir pressure depletion meant that primary production of the Ozouri reservoir required artificial lift. Initially, progressing cavity pumps (PCPs) were selected, however, following failures of the elastomers, electric submersible pumps (ESPs) were deployed to produce at higher rates with high gas/oil ratios (GORs). The production instability associated with the dual-porosity reservoir behaviour and high free-gas content in both the inflow and outflow of the wells presented the main challenge to ESP design and operation. Additionally, most of the wells were remote from the main production facility and were produced via multiphase subsea flowlines, which made well testing difficult due to the phase segregation in the flowlines. To achieve economically viable production utilizing ESPs, innovative use was made of a range of existing technology. Operationally, however, real-time monitoring was essential to setting wellhead pressures and pump speed to maximize drawdowns. Key technology elements were monopods to minimize the offshore structure cost, fit-for-purpose subsea power cable and helicoaxial downhole pumps for high gas void fraction operation. Key lessons were learned following the trial of several completion architectures to find the optimal combination of gas venting, reservoir access, and a dual barrier mechanism. The first well was put on production in 2002. Since then a further 10 wells have been drilled to reach a total liquid production of 8,000 B/D with a 60% water cut. Production has been economical and thus confirmed ESPs as being the right solution for this reservoir. The lessons learned prove that the application of ESPs is not limited to traditional waterfloods and that it is feasible to produce challenging reservoirs with ESPs.