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.
Summary “Worst-case discharge” is a relatively new term given to a hypothetical event that is deemed to be of low probability but of high impact. The consequences of such a discharge are substantial on drilling and completion operations for a specific well. It may also have significant implications on a fieldwide and, perhaps, companywide basis. This paper assesses, hypothetically, the circumstances that lead to such an event and the occurrence's subsequent impact on the subsurface. A hypothetical worst-case-discharge incident could be started by a kick (influx of high-pressure fluid into the wellbore during drilling). In such a hypothetical event, casing collapse could occur under the differential load (pressure within the casing is reduced significantly whereas pressure outside the casing remains high). After capping and controlling the well occur, pressure buildup occurs. Fluid could escape through the collapsed casing and migrate to surface, by means of conduits such as open annuli, unconsolidated sedimentary sequences, fractures, and salt sutures. For example, an open annulus can displace fluid to shallower horizons. Alternatively, the fluid pressure can propagate a fracture that could then broach to the surface or mudline. The paper reviews such a hypothetical event and discusses design changes targeted at mitigating and/or remediating potential negative impacts. The concept presented revolves around the positioning of casing shoes to force fracture propagation into particular horizons, thus minimizing and remediating the effects of the discharge event.
Geomechanical modeling is playing an increasingly important role at Saudi Aramco during the earliest phases of field development planning. Field development decisions are aided by an accurate assessment of well design options that are closely tied to the existing geological and engineering data set using geomechanics technology. Beginning at the reservoir, completion design in highly productive mechanically weak sandstone formations, and stronger - less productive formation intervals that must be fracture stimulated to produce, depend heavily on the accuracy of the Pre-Khuff geomechanical model that recognizes the complexity of this geological environment.1 The Pre-Khuff model finds formation layer stress and rock strength to be to extremely anisotropic, with stress magnitude and horizontal stress differences linked closely to formation layer stiffness, namely, static Young's modulus. The impact of interval stress and strength complexities to sanding potential, frac-pack design in sand-prone intervals, and hydraulic fracture stimulation design in stronger sanding-free intervals, is modeled using commercially available petrophysics and fracture stimulation design software. Perforation stability is modeled by customized and calibrated numerical modules developed by Saudi Aramco specialists and ChevronTexaco's Rock Mechanics Analysis group. An overview of the Pre-Khuff geomechanical earth model is presented in the paper. Perforation stability forecasts, including the impact on perforation design and completion type selection is also presented with field performance results. Calibration to the geomechanical model for various fields and reservoir conditions are also illustrated. Introduction Pre-Khuff gas reservoirs are found in the eastern region of Saudi Arabia, underlying the giant Ghawar oil field. The Pre-Khuff reservoirs are a deep sequence of Permian and Devonian sandstones saturated with condensate rich gas with a large degree of variation in permeability and porosity. Average reservoir pressure high and average temperature is 300°F. The 3D seismic survey reveals that the Pre-Khuff gas reservoirs are highly faulted and reservoir evaluation indicates the high level of vertical and lateral heterogeneity. The variation in reservoir quality has been linked to variation in reservoir mechanical character and in-situ stress properties. The Pre-Khuff geomechanical model and detail sensitivity runs have been summarized in an earlier SPE papers.2,3 Attempts to improve reservoir characterization using logs and core data have also been documented.4 This paper further describes the Pre-Khuff geomechanical model, finding formation stress magnitude and horizontal stress anisotropy to be governed by formation layer stiffness. This layer stress and strength model is central to optimal perforation placement to control sanding potential. For the purpose of selecting correct completion, formation layer stress, rock strengths, and stiffness are evaluated and used to identify formation competency, perforation stability, and safe drawdown pressure to avoid sanding. Models developed for such calculation have been calibrated against field data. Due to the lateral and vertical variation of formation properties, the calibration coefficients depend upon field, area, and reservoirs. The forecasted reservoir properties from geomechanics model are used for the selection of perforation intervals, completion types, and optimizing stimulation designs. Earth In-Situ Stresses Prior to drilling, formation rocks are in a balanced or nearly balanced stress state with little to no movement occurring in the rock system. The three principal stresses prior to drilling are called in situ stresses. In situ stresses consist of one vertical stress and two horizontal stresses, as shown in Figure 1.1,5
Sand control risks, costs, and alternatives are significant factors in the planning phase of a field development. A mechanical earth model (MEM) which includes in-situ stress and rock strength should be constructed and used to evaluate potential for rock failure during production. Fully integrating and calibrating strength, stress, and failure models is crucial to correctly characterize sanding potential. The MEM for the Tombua-Landana Development in deepwater Block 14, offshore Angola will be presented to illustrate the methodology of this approach. In this field case: In addition to conventional triaxial core tests which provide rock strength in a limited number of samples, core scratch test data was used to establish continuous rock strength over most cored intervals. A log based neural network was used to extend the rock strength information to the non-cored intervals. Comparison between log, scratch test, and triaxial core test strengths will be presented. Acoustics based stress computations are calibrated to leak-off test and mini-frac stress measurements. Calibration of failure models to both drilling wellbore stability and completion safe drawdown pressures verifies the validity of the mechanical earth model. Both openhole and cased and perforated sanding potential were evaluated using the fully integrated earth model. Oriented perforations have the potential to significantly reduce the risk of sanding in completions without gravel packs or screens. Introduction The Tombua-Landana field is located in Block 14, offshore Angola with water depth approximately 800 to 1,300 ft. The Tombua and Landana central reservoirs are composed of high quality sands deposited in a deepwater slope valley environment on the northwestern flank of the Congo River Fan. The producing reservoirs are Lower Miocene CN3 in age and form moderately thick successions of sand sequences. The overall Tombua-Landana depositional system comprises a series of large, stacked, offset channels. Tombua-Landana development is the third major field development in Angola's Block 14, after Kuito and Benguela-Belize-Lobito-Tomboco. It is a major capital project that will have expenditures in the order of billion dollars for all components. Geomechanical modeling played an important role during the early phase of field development planning. Completion decisions are aided by an accurate assessment of sanding characteristics of various well designs. A MEM was constructed to estimate sanding potential for the Tombua-Landana field. This MEM was then calibrated to field data. An overview of the building of the Tombua-Landana MEM is presented in this paper. Building a Mechanical Earth Model (MEM) A MEM consists of in-situ stresses and rock strength linked with a failure model. These are all calibrated to wellbore observations of rock failure behavior. Sand production results from rock failure caused by the imbalance between the local stress state near the wellbore and rock strength. In this section, the process and method of determining in-situ stresses and rock strengths will be shown. It will also be shown that the sand production predicted using the in-situ stresses and rock strengths matches the core tests, well test results, and drilling performance. Therefore, the in-situ stresses, rock strengths, and failure model are most likely valid and can be used for the field sanding potential analysis. Earth In-Situ Stresses The in-situ stress magnitudes and orientations can affect the sanding potential of wells. In most cases, principal in-situ stresses can be expressed as:Overburden stressMaximum horizontal stress (SHmax)Minimum horizontal stress (Shmin) The overburden stress is in the vertical direction and is generally, as in this case, calculated by vertically integrating the density log. Two horizontal stresses are the two principle stresses perpendicular to each other on a horizontal plane. The larger horizontal stress is called maximum horizontal stress and the lesser one is called minimum horizontal stress.
Consideration of the full cycle asset development plan from appraisal through abandonment reduces the risk of missed future opportunities caused by 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. The capability to characterize rock mechanical properties from the standard P-wave acoustic datasets, either seismic or openhole 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 MCPs 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 third party industry benchmarking consultancy, as a MCP execution improvement opportunity.
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