A fit-for-purpose integrated subsurface study was carried out in a tight gas field in Oman to evaluate the stimulation process in horizontal wells. The objective is to explore the role of vertically and laterally heterogeneous in situ stress for hydraulic fracture (HF) propagation, and to quantify its effect on hydraulic fracture stimulation efficiency using a 3D fully-coupled hydraulic fracturing simulator for complex geological conditions. The use of advanced simulation tools that realistically predict the evolution of stresses in 3D allows us to explore the parameter space required to optimally design stimulations for complex tight and unconventional field development [Izadi et al. 2017; Cruz et al. 2018; Izadi et al. 2018]. The goal of this study is to test scenarios that increase production through reservoir contact by use of various fracturing techniques that improve the Stimulated Rock Volume (SRV). The modeling scenarios include an assessment of: The impact of high vs. low in situ stress on pressure response, proppant placement and near wellbore conductivity The impact of in situ stress magnitude in near wellbore conductivity The impact of fluid properties and landing zone on proppant transport The effect of laminations on proppant transport The impact of HF/natural fracture interactions on SRV This study illustrates that for complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, advanced 3D modeling provides insight critical to optimize development strategy. Through parametric stimulation modeling design, mechanisms driving drilling, completion, stimulation and productions processes can be honed to optimize and better manage the primary risks to development in tight/unconventional reservoirs .
Majority of oil wells operated by Petroleum Development Oman (PDO) are produced by beam-pumps (BP). Average water cut in a number of fields in South of Oman reaches 95%. Increasing water production overloads processing facilities leading to handling and disposal constrains requiring wells to be shut-in. BP completions are not surveillance friendly making production logging to identify water entry for optimization (water shut-off) a challenge. The current technique to acquire production logs requires recompletion to dual-string completion to allow logging: BP short-string and surveillance conduit long-string. This is resource intensive, high cost, restricts production and limited to 9-5/8in. cased wells. Moreover, new wells are completed with dual 9-5/8in. × 7in. casing for well life-cycle integrity management. A novel solution was developed and part-funded by PDO consisting of a jet-pump (JP), 1in. inside 2in. concentric-coiled tubing (CCT) strings, power cable and production logging tools (PLT). This cost-effective real-time surveillance technique will facilitate routine production logging in BP wells, significantly reducing well intervention time and cost (50% reduction) as only the rod string is retrieved by light-hoist in preparation for logging. Wells completed with dual-string completions, which have previously been production logged were selected for field trial. These existing logs were used as a baseline for new log comparison. The technique was successfully deployed in a 3 well field trial campaign for the first time in southern oilfields (industry first). The new production logs compared very well to existing logs (same water signature observed), proving the techniques robustness to identify water entry in different production environments. We preset advantages of the new technique over conventional, candidate selection, logging tool options, interpretation methodology, field trial results and comparison logs. This new system is being deployed across PDO and is applicable to other fields being produced by BP, progressing-cavity pump (PCP) or electrical submersible pump (ESP) to identify water entry for production enhancement or reservoir monitoring.
Several wells have been drilled and stimulated in a tight gas field in Middle East, however, very few have been economic. Many wells encountered difficulties pumping the required treatment and a number of horizontal wells did not produce as expected. A fit-for-purpose integrated subsurface model coupling geophysical, petrophysical, and geomechanical models with fully 3D hydraulic fracture simulation modeling was carried out to provide the operational path forward to overcome these challenges. This study is a showcase of the applicability of our integrated approach to simulate fluid flow and proppant placement within complex, naturally fractured reservoirs where the interaction between induced fractures and natural fractures dominates hydraulic fracture propagation [Izadi et al. 2015; Cruz et al. 2016; Izadi et al. 2017; Izadi et al. 2018; Cruz et al. 2018]. Seismic data calibrated with rock physics analyses were used to delineate structural components and incorporate rock properties into the high-fidelity 3D subsurface model. High porosity zones and areas of high natural fracture intensity were identified with seismic acoustic impedance and geometric attributes. Reservoir properties of porosity, permeability and gas saturations vary across this field. Variations in geomechanical parameters correlate spatially with variations in porosity and permeability. This paper demonstrates a methodology to evaluate reservoir heterogeneities on hydraulic fractures propagation through fully 3D simulations at a planned well's location.
As part of a multi-disciplinary investigation to optimize a tight reservoir development in the Sultanate of Oman, a comprehensive geomechanical characterization was performed and its results used as input for 3D non-planar hydraulic fracturing simulations. The simulation results led to better understanding of the reservoir response during hydraulic fracturing stimulation and thereby improved the decision making process for future field development. The focus of this paper is to highlight the geomechanical aspects of the analysis which explained several of the difficulties encountered during stimulation. Geomechanical models were constructed covering the target sandstone and overlying clay-rich formation for ten horizontal and vertical wells by integrating diverse data including openhole logs, core rock mechanical tests, stress-induced failure interpretations from image logs, and stress measurements from mini-frac data. The geomechanical models were further supported by the results of available temperature, tracer and production logs. 3D geomechanical models were created by capturing the lateral and vertical variations of rock and geomechanical properties from these 1D models away from the wellbores, guided by the variations in seismic attributes using a co-simulation method. 3D modeling revealed a number of stress barriers supported by location of microseismic events in the target reservoir. The geomechanical setting of the target formation is found to be complex with significant variations laterally and vertically. The West area of the field was found to have relatively lower stress compared to the Main area. Also, the Middle and Lower intervals of the target formation were shown to have considerably higher horizontal stresses (strike-slip/reverse faulting regime) compared to the Upper interval (normal/strike-slip faulting regime). The high stresses in Middle and Lower sections have the negative consequence of reducing the fraccability of these intervals as they require high breakdown pressures. In some cases, where breakdown was achieved, the resulting horizontal hydraulic fracture yields disappointing production results due to its inability to connect the reservoir vertically. Another important lesson learnt from geomechanical characterization in this field was the role of high angle bedding in truncating the vertical growth of hydraulic fractures. This understanding can further help to optimize the location of perforation intervals in stimulation designs of future development wells in this field. Geomechanical characterization of this reservoir demonstrated considerable lateral and vertical heterogeneity that could only be captured by very detailed integration of well-based and seismic scale data. In addition, the effects of the in situ stresses on high angle beddings demonstrated the importance of these features on geometry and efficiency of created hydraulic fractures. From the 1D to 3D geomechanical modeling we show that characterizing formation heterogeneity, in situ stress variability, and bedding structures is critical to the creation of any predictive hydraulic fracturing model in this field.
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