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Collaborating Authors
Angola
Abstract Surfactants systems have been used in oil well drilling and completion fluids for several decades and have been used for numerous applications, including emulsification of brine for invert emulsion fluids, emulsion prevention in completion fluids, wellbore clean-up in spacer trains, flowback enhancement in drill-in fluids, etc. In recent years, the use of specialized designer surfactant blends to remove formation damage and dramatically improve production in cased hole and open hole completed wells has prompted field personnel to expand the range of target applications of this technology. The aforementioned specialized surfactant blends have several unique functional characteristics that make them ideal for multiple uses in the field. Generally, these systems solubilize oil, remove oil from surfaces, remove emulsions, water-wet and disperse solids, reduce interfacial tension and mobilize in-situ fluids. With a full understanding of the mechanistic ways that these surfactant blends function under downhole conditions and when confronted with various operational issues in the field, this technology was successfully used to free stuck pipe, to free blocked completion screens of heavy oil sediments and to prepare a well for water injection. This paper presents some of the technology associated with specialized designer surfactant blends and the case studies where the technology was applied in the field to enable project successes.
- South America (0.68)
- North America > United States (0.68)
- South America > Colombia > Llanos Basin (0.99)
- Africa > Angola > South Atlantic Ocean > Kwanza Basin > Block 17 > Rosa Field (0.99)
Abstract Kotabatak field, Sumatra, Indonesia is a heavily-faulted field undergoing an aggressive drilling and development campaign. Nine horizontal wells had been drilled with four more planned in 2008. One of the horizontal wells recently experienced well collapse (and sudden productivity decline) after some time on production, with cavings being flushed out during coil tubing workover operations. In addition to horizontal well drilling, feasibility of open horizontal well completions, hydraulic fracturing design and sanding onset prediction also warranted rock mechanics analyses. To make sound decisions on those issues, building a well-calibrated geomechanical model was critical. In this study, we reviewed the drilling, completion, logging and production information from several wells across the field. We found that (1) The Kotabatak field has a general maximum horizontal stress orientation of NESW. However, there could be localized stress orientation variations depending on structure complexity near a specific well. (2) There was no consistent evidence indicating a significant contrast between the maximum and minimum horizontal stresses. Using a maximum/minimum horizontal stress ratio of 1.05 yielded a consistent calibration result for the wells studied. (3) Sand minimum horizontal stress for the Kotabatak field was calibrated against available closure stresses from hydraulic fracturing and mini-frac data. (4) Rock mechanical properties were calculated with openhole logs based on a Rock Mechanics Algorithm that is closely linked to Chevron's worldwide rock mechanical property database. Consequently, even though there were no core test data available from the Kotabatak field to calibrate rock mechanical properties directly, the log data set provided the means to estimate reliable formation mechanical property values that are consistent with Chevron's worldwide database. Furthermore the entire geomechanical model was calibrated against offset drilling performance measures resulting in a high degree of confidence in the predicted values. Using the calibrated geomechanical model, horizontal well stability predictions were performed and indicated that horizontal sections can be drilled with low mud weight allowing the well to have some yield/failure. Open horizontal well sanding onset prediction indicated that the depth and width of a breakout (or plastic zone if reservoir sand behaves plastically) increase with increasing pressure drawdown. Since water flooding is used in the field to maintain reservoir pressure, sand control may not be needed if an appropriate Bottomhole Flowing Pressure (BHFP) is applied. Introduction The Kotabatak field, Sumatra, Indonesia is a heavily faulted field undergoing an aggressive drilling and development campaign ((Figures 1 and 2). Nine horizontal wells had been drilled (as of the end of 2007) with four more planned in 2008. One of the horizontal wells recently experienced well collapse (and sudden productivity decline) after some time on production, with cavings being flushed out during coil tubing workover operations. In addition to horizontal well drilling, feasibility of open horizontal well completions, hydraulic fracturing design and sanding onset prediction also warranted rock mechanics analyses. To make sound decisions on those issues, building a well-calibrated geomechanical model was critical.
- Asia > Indonesia > Riau Province (1.00)
- Asia > Indonesia > Riau (1.00)
- North America > United States > Montana > Rosebud County (0.45)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Kotabatak Field (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Area B > Block 0 > Greater Vanza Longui Area (GVLA) Field > Pinda Formation (0.99)
Abstract Consideration of the full cycle asset development plan from appraisal through abandonment reduces the risk of missed future opportunities due to well systems design constraints. For example, reservoir pressure depletion and subsidence can impact borehole stability to the extent that complex well designs are necessary to fully exploit the asset. Well placement not only depends on the subsiding reservoir section, but also on the reaction of the overlying geological section that must be drilled through to reach the reservoir. For land based operations, the consequences of well complexity may be more easily addressed, the downside being a poor estimate of field recovery that can either rob opportunities for outlying prospects or, in the worst case, cause the asset to be uneconomic. For major capital projects (MCPs) such as deepwater subsalt fields, the capital outlays are immense, with single wells costing up to ﹩100,000,000. For these deepwater MCPs, fewer wells are required to produce reliably for longer periods of time. The capability to characterize rock mechanical properties from the standard P-wave acoustic data sets, either seismic or open hole log derived, enables well planners to link the Explorationist and Well Engineer's visions using mechanical earth modeling technology. The accurate assessment of formation rheology, or stiffness, and architecture (distribution and structure), allows the asset team to optimize well systems design, considering placement and production management practices over time. The presentation will introduce acoustics based rock mechanics concepts, describe the acoustics based rock property prediction technique, and present field applications that demonstrate the impact of the subsurface model to the corresponding well systems design. Introduction The involvement of the Well Engineer (WE) competency from the earliest phases of Exploration is reaping economic benefit for major capital projects (MCP) at Chevron. This early involvement insures the maturing well system design maintains the flexibility to accommodate design base change that often occurs as the subsurface picture evolves over project time. This early WE involvement enables:Proper alignment and the rigorous application of well engineering risk assessment processes for MCPs, Balanced functional objectives in conceptual field development plans, Proper alignment of management expectations, setting of project objectives, and benchmarking for well engineering activities, Appropriate management of well design changes and execution team handoffs. The schematic in Figure 1 shows the increased value derived from Good Project Definition in the early project planning phase (red and yellow shading). When good project definition is achieved in the early phases, there can still be relatively high value creation even if the project is poorly executed (see blue shaded area). This important learning, i.e., poorly executed projects can generate significantly more value than superbly executed projects that have been poorly framed, has been identified by a widely used 3rd party INDUSTRY benchmarking consultancy, as a MCP execution improvement opportunity.
- North America > United States (0.46)
- Asia > Middle East > Saudi Arabia (0.29)
- Africa > Angola > Cabinda (0.29)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.71)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.48)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Carnarvon Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
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