Summary This paper presents drilling, completion, well-performance, and reservoir-characterization results of a recently drilled maximum-reservoir-contact (MRC) well in the Shaybah field with a total of eight laterals and an aggregate reservoir contact of 12.3 km (7.6 miles). The well was drilled as part of a pilot program to evaluate both the practical challenges and the reservoir performance impact of MRC wells. The results to date on eight MRC wells in Shaybah indicate significant sustainable gains in well productivities as well as reductions in unit-development costs. A useful byproduct of MRC drilling is the enhancement achieved in reservoir characterization. These benefits point to MRC wells as disruptive technologies (DTs)1,2 that have positive implications for developing tight-facies reservoirs.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIntelligent wells are becoming the buzz word in the oil and gas industry. Today the development and deployment of smart technologies are important drivers for improving well productivity and delaying early water or gas breakthrough in tight and challenging reservoirs.
Summary Multiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. However, their in-situ determination is practiced only in isolated instances, and these have used array resistivity logging. Although wireline dualpacker formation testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation-tester pressure and water-fraction measurements with openhole array resistivity measurements to obtain zonal relative permeabilities of oil and water. It has been demonstrated previously that the filtrate-invasion process, although uncontrolled, contains quantitative information about fractional flow. The sampling process is similar; it is described by the multiphase/multicomponent flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase-flow properties and drilling-fluid loss and carry out a simulation exercise, including generation of resistivity logs. The fractional-flow parameters estimated by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Simultaneous matching of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of this methodology will be discussed.
This paper highlights the development of a coupled poroelastic geomechanical and fluid flow model which incorporates field and lab data with the objective to constrain the full in-situ stress tensor and rock strength in order to predict the stability of open hole horizontal completions during reservoir depletion. Results of a four-year comprehensive testing and monitoring program conducted to assess the extent of hole instability during shut-in and flowing periods1 indicated that there was no immediate hole collapse. However, the study revealed the need to assess the long-term impact of reservoir depletion and pressure drawdown on wellbore stability. The results of this study indicate that the in situ stress state can be characterized by a normal faulting environment with low differential stresses in which the maximum principal stress is approximately equal to the overburden. Furthermore, a detailed analysis of wellbore stability during production supports openhole completion for horizontal wells under the condition that reservoir depletion is limited to a maximum pressure drop of 1,500 psi. This finding is independent of well azimuth. Pressure drops exceeding 1,500 psi in the reservoir are likely to cause considerable wellbore instabilities. These results were achieved under the assumption of moderate to more pronounced amounts of drawdown (500–1000 psi) in the near wellbore region. The study also highlighted that laboratory-derived rock strength values from triaxial tests, are low and are not consistent with the drilling and production experiences to date in the field. Rather, the formation appears to behave in a plastic manner that strengthens the wellbore. Introduction Hole stability concerns in the Shu'aiba reservoir, Shaybah Field, Saudi Arabia, first surfaced during the drilling and logging of two development vertical evaluation/production wells where a logging tool was stuck in one well due to tight hole, and indications of tight hole were encountered while drilling another well. The two incidents signaled the need to investigate hole stability in the Shu'aiba reservoir. A review of all the vertical delineation wells drilled in the 1960's for problems associated with hole fill and/or collapse during drilling and production found no conclusive evidence for stability problems. Cores taken in the mud-rich, high porosity rock of the Shu'aiba formation have been described as having a "toothpaste-like" texture and behavior. Preliminary laboratory rock mechanics studies indicated that the Shu'aiba carbonates are mechanically weak with the majority of the rocks tested yielding very low strength values (less than 2000 psi) when compared to samples from other carbonate reservoirs. In light of the gathered field and geomechanics data, a comprehensive hole stability monitoring program was formulated and initiated with the objective to investigate the extent and implications of hole stability on field development and deliverability. Results of which are summarized in SPE 565081 indicating, at least in the short term, no impact of production on wellbore stability. Furthermore, a long term study, which is the focus of this paper, was initiated to constrain the full in situ stress tensor (i.e., orientation and magnitude), reservoir pore pressure, and rock strength in order to build a geomechanical model of the Shaybah Field and predict the stability of openhole horizontal wells during reservoir depletion. To achieve these goals, a broad suite of available data from wells drilled in Shaybah Field were utilized such as electrical FMI image data, four-arm caliper logs, minifracs, wireline logs (e.g., density, neutron, and sonic logs), and pore pressure information obtained by direct measurement were studied. This data - sufficient to constrain the full stress tensor and pore pressure - was then augmented by information on uniaxial compressive strength derived from laboratory measurements and log data to build the full geomechanical model, which was then used as a basis to predict wellbore stability during reservoir depletion.
This paper is an update of previous SPE technical papers1,2 highlighting the results of 25 Maximum Reservoir Contact (MRC) wells drilled in the Shaybah Field either as new wells or part of a workover strategy to convert existing weak 1-km single lateral wells to MRC wells with reservoir contacts ranging from 5 to 9 km. Shaybah field, a low permeability reservoir overlain by a huge gas cap was initially developed in 1996 with 1-km single lateral horizontal wells to effectively drain the hydrocarbon while reducing gas coning. A step development approach by increasing the reservoir contact to improve well productivity and performance was the basis for the MRC concept. Results to date from 25 MRC wells have indicated a four-fold increase in well productivities and a three-fold decrease in unit development cost when compared to the one-km single lateral wells. A useful by-product of MRC drilling is the enhancement achieved in reservoir characterization. In addition to MRC wells, smart technologies such as downhole flow control systems (smart completions), expandable liners, and production equalizers were deployed in Shaybah Field. These technologies have shown major improvements to well performance and recovery. Smart controls assisted in optimizing production from each lateral in a multi-lateral well in the event of premature gas or water coning. In addition, downhole smart completions improved well productivity in multi-lateral wells through an improved well cleanup process. Production equalizers when deployed in high GOR wells reduced gas coning and improved well productivity. To date over 21 expandable liners have been deployed as enablers to a workover strategy to convert single lateral wells to Multi-lateral/MRC wells thereby providing the platform for installation of downhole flow control systems. Introduction MRC well concept initiated in early 2002 by Saudi Aramco was based on the horizontal well technology as a disruptive technology1 to challenge the current practice with the objectives of improving well performance and ultimate recovery. An MRC well is defined as a well with an aggregate reservoir contact of 5 km or more either as a single lateral or multi-lateral configuration. The concept that was first tested in the Shu'aiba carbonate reservoir of the Shaybah field (Saudi Arabia) has been extended to cover several fields and rock types in both onshore and offshore environments. The majority of MRC wells were initially drilled as tri-lateral configuration. This configuration is now being challenged; quad and penta-lateral well types are being drilled to further improve well performance by increasing well productivity index and thereby lowering the drawdown pressures resulting in high well potentials and improved long term performance in terms of recovery and sweep. As in the mid-90s where the oil and gas industry was moving to horizontal well applications as the norm, today Saudi Aramco is leading the way in deploying MRC wells, where applicable, across most of its fields to ensure improved well performance and ultimate recovery. This paper will reflect on the performance of Saudi Aramco MRC wells over the past four years and the different technologies implemented, and highlight the way forward. Background Shaybah field, dominated by the low permeability Shu'aiba reservoir overlain by a huge gas cap, was initially developed in 1996 with one-km single lateral horizontal wells to effectively drain the hydrocarbon while reducing gas coning. Following the initial development and based on wells and field performance, reservoir contact was gradually increased by drilling 2 km and 3+ km single lateral wells. From 1998–2001 this step approach resulted in significant improvements to well performance in terms of increased PI, lower drawdown, and further delays in gas coning. This success led to the birth of the MRC well concept.
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