Reservoir Geomechanical Modeling Research Articles

Advanced three-dimensional reservoir geomechanical modeling for enhanced characterization and stress profile predication of oil and gas reservoirs

Advanced three-dimensional reservoir geomechanical modeling for enhanced characterization and stress profile predication of oil and gas reservoirs

Laboratory Measurements and Estimates of the Biot Coefficient of a Pre-Salt Oil Field, Santos Basin

The Biot’s coefficient is an important parameter in geomechanical models of hydrocarbon reservoirs, with direct influence over the stress distribution in space and time along the production history. We conducted stress-strain experiments (quasi-static measurements) to measure the Biot coefficient of rock samples from an oil field in the Santos Basin. We found strong correlations between these quasi-static measurements and the estimates from dry rock ultrasonic elastic velocities (dynamic measurements). Additionally, we observed good correlations between the Biot’s coefficients and the effective porosity of the rocks, as well as with the acoustic impedances. These findings suggest that it is possible to derive poroelastic parameter logs of Biot’s coefficient in well locations, which can be used as input for geostatistical interpolation between wells. This would help in constructing more accurate reservoir geomechanical models and may even enable the generation of a three-dimensional distribution of the coefficient based on acoustic inversion of seismic data.

3D Geomechanical Finite Element Analysis for a Deepwater Faulted Reservoir in the Eastern Mediterranean

AbstractHydrocarbon reservoir structures are subjected to tectonic forces along the geological time that cause rock deformation and break into faulted zones. Faulted reservoirs, enclose certain complexity in terms of the distributed effective stresses, rock plastic alteration, slipping and fault block displacement. In this study, we develop a three-dimensional (3D) geomechanical reservoir model with faulted and compartmentalized geometry, located in the offshore deepwater environment of the Levantine basin in the Eastern Mediterranean, based on non-linear finite element analysis (FEA). A regional structural and stress map was also constructed, integrating various data sources, to present the regional stress setting to enhance this work. The assessment of the geomechanical impacts on the reservoir provides important information in reservoir studies, that can analyze potential stability issues during the depletion to optimize the field production planning. Stress–strain evolution in the reservoir is primarily affected by the in situ stresses, the geometry of faults, and the degree of compartmentalization. The results demonstrate clearly the mechanism of stress transfer transmission and the impact between the fault block compartments in the reservoir. Fault contacts exhibit a higher tendency for rock displacements and deformations. Plastic yielding develops at a narrow extent along the faults. The risk of fault slipping depends on the depletion strategy, but it is low in all cases. No significant reduction in permeability was found at the end of reservoir depletion. Overall, geomechanics integration enriches and improves the dynamic reservoir models and applications.

Coupled hydro-mechanical simulation in the carbonate reservoir of a giant oil field in southwest Iran

The Asmari reservoir in southwest Iran has been producing oil continuously for over 50 years. However, due to an essential pressure decline, the reservoir is now a potential candidate for injection projects. The geomechanical analysis is essential for a successful injection operation to enhance reservoir production and address possible challenges. An accurate estimation of the injection pressure is necessary to maintain optimal conditions during the injection process and reduce possible risks. In this work, a coupled reservoir-geomechanical model, as well as rock mechanical tests, is performed to evaluate not only pressure variation and the associated in situ stress changes but also their potential influences on fault reactivation, reservoir–caprock stability, and surface displacement. For geomechanical evaluation, empirical correlations are derived between static and dynamic rock properties based on core data and existing petrophysical logs for the studied reservoir–caprock system. Based on the hydro-mechanical results, the maximum displacement is limited to the vicinity of the injection wells, where the highest pressure changes occur. The geomechanical analysis of the reservoir–caprock system shows that this system is stable until the injection pressure reaches 4.3× the initial reservoir pressure. Also, the injection pressure is not high enough to compromise the integrity of faults, indicating that the loading on the fault planes is too low to reactivate the pre-existing faults. The approach followed in this study can be applied to future field development strategies and feasibility considerations for CO2 sequestration and underground gas storage projects.

Interaction of natural and hydraulic fractures: the impact on reservoir pressure buildup and risk of shear fault reactivation in the Upper Devonian Duvernay Formation, Fox Creek, Alberta

The interaction of natural and hydraulic fractures may facilitate lateral fluid propagation in an unconventional reservoir resulting in fast fluid pressure transmission from treatment wells to a fault zone and potential fault shear slip reactivation and associated induced seismicity. Several induced earthquakes (up to 4.1 Mw) occurred since 2013 during hydraulic fracturing of the Upper Devonian Duvernay Formation in the Western Canada Sedimentary Basin. The mechanism of lateral fluid migration in the unconventional reservoir is not well understood. The current study aims to investigate the interaction of natural fractures and hydraulic fractures for the case study in the area south of Fox Creek, where a linear zone of induced earthquakes (up to 3.9 Mw) occurred along a fault in 2015 during hydraulic fracturing of horizontal wells. We analyze the growth of hydraulic fractures in presence of natural fractures, the impact of resulting complex fracture network on fluid transmission and fluid pressure buildup around the treatment wells. Hydraulic fracture modeling (HFM), reservoir simulations and 3D coupled reservoir-geomechanical modeling are applied to match the timing of hydraulic fracture propagation and transmitted fluid pressure increase in the fault zone versus induced earthquake occurrence. HFM results are verified by microseismic clouds distribution. Reservoir simulations are validated by a history matching of fluid injection volume and bottomhole pressure data. Additional HFM simulations are carried out to optimize the pumping schedule in the studied well pad that would help to prevent hydraulic fractures reaching the fault and minimize the risk of induced seismicity.Article highlightsStress anisotropy and simulated natural fractures impact lateral growth of complex hydraulic fractures and reservoir pressure buildup.Predicted fluid pressure transmission to a fault zone results in fault dextral shear slip reactivation matching induced seismicity.Optimized pumping schedule helps to minimize risks of fault reactivation and induced seismicity while preserving overall pad performance.

3D reservoir simulation of CO 2 injection in a deep saline aquifer of the Lower Paleozoic Potsdam Sandstone of the St Lawrence Platform, Gentilly Block, Quebec

Increasing demand in carbon dioxide storage volumes to reduce greenhouse gas emissions to net zero by 2050 implies assessment of CO 2 storage capacity, including deep saline aquifers, even in tight sandstone reservoirs. 3D reservoir simulations of supercritical CO 2 injection were carried out in the Lower Paleozoic Potsdam Sandstone of the St Lawrence Platform (Gentilly Block), Quebec to predict safe CO 2 injection rates, evaluate reservoir pressure build-up in the presence of sealing and permeable faults, and estimate the gas injection cumulative. 3D one-way coupled reservoir–geomechanical modelling helped to analyse the interaction between reservoir pressure build-up and changes in in situ stresses, and estimate the risk of top and bottom seal failure and fault shear-slip reactivation. It is shown that a safe CO 2 injection rate per well for 20 years of continuous injection is estimated to range from 0.7 kg s −1 (22.1 kt a −1 ) to 10 kg s −1 (315.4 kt a −1 ) depending on the porosity and permeability of the Potsdam Sandstone varying from core-derived matrix values to ‘fracture-enhanced’ values. The corresponding injection CO 2 cumulative for 20 years ranges from 432.2 to 6013.5 kt per well. The implementation of a multiple-well injection plan will help to increase the injection CO 2 cumulative, given the considerable thickness and basin-scale dimensions of the Potsdam reservoir (3440 km 3 ).

Building 1D and 3D static reservoir geomechanical properties models in the oil field

Reservoir geomechanical models provide valuable information for various applications ranging from the prediction of surface subsidence to the determination of pore pressure and induced stress changes, wellbore stability, fault reactivation, and caprock integrity. Three-dimensional geological modeling of reservoir geomechanics is an essential tool to predict reservoir performance by considering the geomechanics effects. Thus, this study focuses on the application of 3D static reservoir geomechanical model workflow by using 3-D seismic and well log data for proper optimization in the Volve oil field, Norway. 3D Seismic data are applied to generate the interpreted horizon grids and fault polygons. The horizon which cut across the nine wells is used for the detailed topographic analysis. The workflow includes 1D geomechanical and petrophysical models which are calculated at well locations by using log data. Structural and property modeling (pore pressure, vertical and horizontal stresses, elastic properties, porosity, permeability, and hydrocarbon saturation) is distributed by geostatistical methods such as Kriging and Gaussian. This study indicates the effectiveness of the three-dimensional static modeling technique as a tool for better understanding of the spatial distribution of reservoir geomechanical properties, hence, providing a framework for analyzing future activities in the reservoir such as proposal position and trajectory of new wells for future field development and assessing arbitrary injection-production schedules.

Evaluation of the impact of strain-dependent permeability on reservoir productivity using iterative coupled reservoir geomechanical modeling

Permeability an important property plays a key role in reservoir performance, numerical reservoir simulation, drilling and production planning. In such reservoirs, stress and strain alters induced by extraction and injection of fluid may substantially change permeability in an irreversible manner. With regard to this phenomenon, several reservoirs may require to consider straindependent permeability, in order to have an accurate performance. In such reservoirs, especially carbonate reservoirs which are a significant proportion of the world’s hydrocarbon reserves, to present the mechanical behavior of rocks, the cap elastoplastic model is may be required. Therefore, the goal of this paper is to evaluate the strain-dependent permeability using coupled reservoir geomechanical modeling with considering the cap elastoplastic model. This coupling is implemented using a fixed stress iterative coupled scheme. In this coupling, the governing equation for fluid is presented by Darcy’s law in which the permeability is nonlinear. The geomechanical module is analyzed using Biot’s theory and cap elastoplastic model. To indicate the mechanical behavior of reservoir rock, the DiMaggio-Sandler elastoplastic model which is a cap envelope is selected. The numerical approximation is done by employing mixed finite element for reservoir module and a continuous Galerkin finite element for geomechanics. Several numerical simulations are performed to verify the models and analyze the effect of strain-dependent permeability on reservoir productivity.

Present-day stress field and stress path behaviour of the depleted Mishrif reservoir from the super-giant Zubair oilfield, Iraq – A geomechanical case study

Accurate understanding of the reservoir pore pressure and in-situ stress behaviour in response to depletion has critical effects in production optimization and field redevelopment while ensuring reservoir integrity. This work presents the first reservoir geomechanical modeling from the supergiant Zubair oil field, southern Iraq to decipher the pore pressure, in-situ stresses and depletion stress path of the middle Cretaceous Mishrif limestone reservoir. Vertical stress (Sv) has 0.97–0.99 psi/ft gradient. Minimum horizontal stress (Sh) estimated from effective stress ratio and Poisson's ratio-based approaches yielded an about 0.58–0.76 psi/ft gradient and validated with C-category fracture closure pressure data available from mini-frac tests. In absence of image log-based breakout widths, maximum horizontal stress (SH) is estimated from three approaches, which provided a gradient range of 0.89–1.21 psi/feet. Relative stress magnitudes (SH ≥ Sv >Sh) indicate a normal to strike-slip faulting transitional tectonic state in the study area. C-quality wellbore breakouts, interpreted from the oriented four arm caliper data infer a mean N60°E SH orientation, which is parallel to the movement direction of the Arabian plate towards the Eurasian plate. Recent downhole measurements indicate that the primary producer Mishrif limestone is in depleted condition. Stress path, interpreted from the reduction of pore pressure (Δpp) and minimum horizontal stress (ΔSh), yields average values of 0.65 and 0.62 for upper and lower Mishrif, respectively. Deformation analysis in reservoir space indicates stress path in depleted Mishrif formation of Zubair oil field is less than the normal faulting limit (0.71) and depletion-induced faulting is therefore unlikely to occur.

Lateral fluid propagation and strike slip fault reactivation related to hydraulic fracturing and induced seismicity in the Duvernay Formation, Fox Creek area, Alberta

SUMMARY Fault shear slip potential is analysed in the area where induced earthquakes (up to 3.9 Mw) occurred in May–June 2015 approximately 30 km south of Fox Creek, Western Canada Sedimentary Basin, Canada. The induced earthquakes were generated by the hydraulic fracturing of the Upper Devonian Duvernay Formation. Interpretation of a 3-D seismic survey and analysis of the ant tracking attribute identifies a linear discontinuity that likely represents a subvertical fault with strike length of 1.4 km, which is aligned with the zone of induced earthquake hypocentres. 1-D–3-D geomechanical modelling is conducted to characterize mechanical rock properties, initial reservoir pressure and stress field. Hydraulic fracture propagation and reservoir pressure buildup simulations are run to analyse lateral fluid pressure diffusion during well treatment. The interaction of natural fractures introduced as Discrete Fracture Network and hydraulic fractures is tested. 3-D poroelastic reservoir geomechanical modelling is completed to simulate slip reactivation of the identified fault zone. The obtained results support that additional pressure buildup of 20 MPa in treatment wells can propagate laterally along hydraulic fractures (and potentially natural fracture network) for about 550 m and reach the fault zone. The increase of fluid pressure by 20 MPa in the fault zone results in dextral slip along the fault, mostly in the interval of the Duvernay and overlying Ireton Formations, corroborating prior focal mechanism results and hypocentral depths. The simulations indicate that lateral transmission of additional fluid pressure from the fracturing stimulation area to the fault zone could happen in a few days after the treatment of lateral wells that is supported by the observed induced earthquakes. This study helps to quantify changes in fluid pressure and stresses that may result in fault shear slip during hydraulic fracturing and predict the potential of induced seismicity connected to hydrocarbon production from the Duvernay Play.

Impact of formation dilation-recompaction on cyclic steam stimulation in reservoirs with bottom water: Application of an integrated coupled reservoir-geomechanical modeling workflow

To optimize Cyclic Steam Stimulation (CSS) in areas with thicker bottom water, it is crucial to examine the correlation of the bottom-water encroachment to changes in pay-zone pressure due to dilation-recompaction cycles and intermittent sequences of stress and fluid transfers. This study outlines an integrated workflow for the modeling and uncertainty assessment of CSS in heterogeneous reservoirs through coupled geomechanical-flow simulation, Latin hypercube design, and response surface methodology to probe into dilation-recompaction effects in presence of bottom water, by incorporating the oil-viscosity variation due to biodegradation and compositional variation, presence of water pockets due to compartmentalization, dilation-recompaction, and relative permeability hysteresis. The results suggest that the CSS performance is most sensitive to dilation pressure and the interaction of recompaction pressure-water pockets. While increase in dilation pressure and compressibility improves CSS, the recompaction pressure is negatively correlated with its performance. This is related to the underlying water pockets compression due to reservoir dilation during injection and water encroachment as a result of the rise of bottom water level. Higher dilation pressure and lower recompaction pressure delay the compression of the underlying water pockets. On the contrary, in the absence of bottom water, CSS is improved with lower dilation pressure and higher recompaction pressure. Clearly, the presence of bottom water reverses the favorable geomechanical envelope during the injection and production cycles.

Strike-slip reactivation of a high-angle normal fault induced by increase of reservoir pore pressure: insight from 3D coupled reservoir-geomechanical modeling

How would high-angle normal faults be reactivated under a present-day strike-slip tectonic regime if reservoir pore pressure (Pp) increased during injection operations? What parameters would control shear slip localization? To answer these questions, 3D one-way coupled reservoir geomechanical modeling of potential fault reactivation in the St. Lawrence Platform, Quebec is performed. We evaluate the risk of shear failure along the pre-existing subsurface Yamaska high-angle normal fault under the present-day strike-slip tectonic regime. Slip may be generated by pressure perturbations in deep saline aquifers of the Early Paleozoic sedimentary basin; this has implications for the assessment of risks associated with CO2 storage and deep geothermal energy potential. The Yamaska Fault is oriented NE-SW with a strike varying from subparallel to ∼35° to the orientation of maximum horizontal stress (NE63°) and dips to the SE at ∼60° with ∼800 m of vertical throw. Multiple runs of the 3D model simulate steps of increasing Pp by 4, 6, 8 and 15 MPa in the footwall sandstone reservoir at a depth of 1.25-1.5 km. Our modeling results show plastic shear deformation along the Yamaska Fault is initiated by pressure increase of 4-6 MPa. More model fault cells fail when pore pressure is increased by 8 MPa, when the reservoir pressure reaches ∼21-24 MPa, and a larger area slips during the next injection stage. The non-linear geometry of the fault results in localization of plastic shear strain on the fault segments optimally oriented, while other segments remain inactive. The dextral plastic shear deformation occurs mostly at the depth of the injection interval, propagating upward to the caprock in highly stressed fault segments. Our study helps to quantify the risk of fault reactivation induced by injection operations.

Impact of Formation Dilation–Recompaction on Cyclic Steam Stimulation

SummaryAn integrated modeling of the cyclic steam stimulation (CSS) at the Peace River heavy-oil/oil-sand deposits in Alberta, Canada, is challenging because of the presence of compositional gradient, faulting, and bottomwater pockets, and the variations in the oil viscosity, rock dilation, fracturing, and the pay-zone-thickness variation. Both gravity and viscosity are marked by declining quality with depth, biodegradation, and compartmentalization.The high oil viscosity and low water mobility at Peace River cause low initial injectivity. High injectivity during the CSS is achieved by high-pressure injection to fail the formation mechanically and trigger fracturing and pore deformation. Moreover, the pore dilation/recompaction triggers relative permeability hysteresis.History matching of high steam injectivities is challenging when reasonable fracture lengths and rock compressibilities are used. To match injectivities, most reservoir simulations have used either a larger compressibility (“spongy-rock” approach) or long fractures. The spongy-rock approach predicts a steady increase in injection pressure, whereas during the early time of the injection cycles, injection pressures increase and then level off for most of the cycle.We describe the enhancements made in an iteratively coupled geomechanical–flow model to incorporate the modeling of both pore deformation and relative permeability hysteresis to match the injection pressures, steam injectivity, and oil/water productions from CSS at Peace River that are otherwise difficult to reproduce. The geomechanical model explains surface heave and high injectivity caused by dilation attributable to shear failure, increase in pore pressure/formation compressibility, and decrease in effective stress. A dilation pressure is specified, below which the behavior is elastic and above which a higher compressibility is used. Above a maximum porosity, further dilation is not permitted. Also, the hysteresis model calculates gridblock relative permeabilities that lie on or between the imbibition/drainage curves, making it possible to use the laboratory-derived two-phase oil–water relative permeabilities and still match the field-measured water- and oil-production volumes.By combining an iteratively coupled reservoir–geomechanical model for the CSS with stochastic workflows, including the Latin-hypercube design (LHD) and response-surface methodology (RSM), the impacts of dilation/recompaction factors (fracturing pressure, maximum injection pressure, dilation pressure, recompaction pressure, and formation compressibility) are quantified through history matching the field results and automated stochastic sensitivity analysis and uncertainty assessment.

Stress Path Analysis for Characterization of In Situ Stress State and Effect of Reservoir Depletion on Present-Day Stress Magnitudes: Reservoir Geomechanical Modeling in the Gulf of Suez Rift Basin, Egypt

A reservoir geomechanical modeling has been attempted in the hydrocarbon-bearing Miocene formations in the offshore Badri field, Gulf of Suez, Egypt. Pore pressure established from the direct downhole measurements indicated sub-hydrostatic condition in the depleted mid-Miocene Hammam Faraun and Kareem reservoirs. Vertical stress (Sv) estimated using bulk density data yielded an average of 0.98 PSI/feet (22.17 MPa/km) gradient. Magnitudes of minimum (Shmin) and maximum (Shmax) horizontal stresses were deduced from the poro-elastic model. Relative stress magnitudes (Sv ≥ Shmax > Shmin) reflect a normal faulting tectonic stress in the Badri field. Pore pressure and stress perturbations (ΔPP and ΔSh) in the depleted reservoirs investigated from actual measurements recognized ‘stress path’ values of 0.54 and 0.59 against the Hammam Faraun and Kareem Formations, respectively. These stress path values are far away from the normal faulting limit (0.68), indicating induced normal faulting or fault reactivation to be unlikely at the present depletion rate.

Investigation of Production-Induced Stress Changes for Infill-Well Stimulation in Eagle Ford Shale

Summary Heterogeneous stress has a great effect on fracture propagation and perforation-cluster efficiency of infill wells. Principal-stress reorientation induced by depletion of parent wells has been investigated by previous numerical studies assuming uniform biwing fracture geometry along the horizontal wells. However, recent field diagnostics indicate that fractures along the horizontal wells are generally nonuniformly developed. In this study, we investigated the impact of depletion of parent wells with complex fracture geometry on stress states, and analyzed stimulation efficiency of infill wells by using an in-house reservoir geomechanical model for Eagle Ford Shale. The model fully couples multiphase flow and rock deformation in three dimensions based on the finite-element method, incorporating complex fracture geometry and heterogeneity. We used this model to accurately characterize pressure distribution and to update stress states through history matching production data of parent wells in Eagle Ford Shale. Depletion of parent wells with nonuniform fracture geometries, which has not been researched thoroughly in the literature, is incorporated in the study. Results show that magnitude and orientation of principal stresses are greatly altered by depletion, and the alteration is uneven because of nonuniform fracture geometries. Stress reversal monitored at the center of the infill location starts after 1 year of production, and it takes another 8 months to be totally reversed for 90°. We also performed sensitivity studies to examine effects of parameters on changes of magnitude and orientation of stress at the infill location, and found that effects of bottomhole pressure (BHP), differential stress (DS), and fracture geometry of parent wells are all significant, whereas effects of the reservoir elastic property are limited. Effects of production time of parent wells are also noticeable in all sensitivity studies. This work analyzes stress-state change induced by depletion of parent wells in Eagle Ford Shale, and provides critical insights into the optimization for stimulation of infill wells.

Sensitivity of Induced Seismic Sequences to Rate‐and‐State Frictional Processes

AbstractIt is well established that subsurface injection of fluids increases pore fluid pressures that may lead to shear failure along a preexisting fault surface. Concern among oil and gas, geothermal, and carbon storage operators has risen dramatically over the past decade due to the increase in the number and magnitude of induced earthquakes. Efforts to mitigate the risk associated with injection‐induced earthquakes include modeling of the interaction between fluids and earthquake faults. Here we investigate this relationship with simulations that couple a geomechanical reservoir model and RSQSim, a physics‐based earthquake simulator. RSQSim employs rate‐ and state‐dependent friction (RSF) that enables the investigation of the time‐dependent nature of earthquake sequences. We explore the effect of two RSF parameters and normal stress on the spatiotemporal characteristics of injection‐induced seismicity. We perform >200 simulations to systematically investigate the effect of these model components on the evolution of induced seismicity sequences and compare the spatiotemporal characteristics of our synthetic catalogs to observations of induced earthquakes. We find that the RSF parameters control the ability of seismicity to migrate away from the injection well, the total number and maximum magnitude of induced events. Additionally, the RSF parameters control the occurrence/absence of premonitory events. Lastly, we find that earthquake stress drops can be modulated by the normal stress and/or the RSF parameters. Insight gained from this study can aid in further development of models that address best practice protocols for injection operations, site‐specific models of injection‐induced earthquakes, and probabilistic hazard and risk assessments.

A Reservoir–Geomechanical Model to Study the Likelihood of Tensile and Shear Failure in the Caprock of Weyburn CCS Project with Regard to Interpretation of Microseismic Data

According to poroelastic theory and also field observations, an increase in reservoir pore pressures can result in a decrease in horizontal stresses in the seal layers. This reduction is in favor of hydrofracture initiation and reactivation of weak planes and has to be studied in caprock integrity analyses. In this paper, a field scale reservoir–geomechanical (GEM-FLAC3D) model is developed for the Phase IB area of the Weyburn (Canada) CCS project that is located in Williston sedimentary basin. A one-way coupling has been conducted between the two codes for the period of CO2 injection in Phase IB area from 2000 to 2010. Therefore, the reservoir pore pressures at selected timesteps are unidirectionally fed to the FLAC3D. In order to study the likelihood of tensile and shear failure in the seal layer on top as a result of stress transfer due to poroelastic effects, two margin ratios are defined for tensile and shear failure and their variations are studied above the reservoir upon changes in pore pressures within the reservoir. The results show that overall; the likelihood of shear failure has been about 25% greater than that of tensile failure in Weyburn. However, between 2008 and 2009, the pressures were high enough to trigger both tensile and shear mechanisms above the reservoir. A discussion is also presented on relevance of this study for interpretation of microseismic data with regard to failure margin ratios, magnitudes and distribution of events recorded in each year.

4D Reservoir Geomechanical Modelling Provides Safe Drilling Operations in North Kuwait Stacked Reservoirs

4D Reservoir Geomechanical Modelling Provides Safe Drilling Operations in North Kuwait Stacked Reservoirs

Reservoir geomechanical modeling: In-situ stress, pore pressure, and mud design

This paper, demonstrated a scientific approach to prepare a geomechanical model for Bangestan reservoir in an oil well in the south-west of Iran. Bangestan is one of the most important oil reservoirs in the Middle-East that its geomechanical characters are not perfectly known. Moreover, unexpected problems such as casing collapse, production drop and land subsidence occurred in this reservoir that made it necessary to conduct a comprehensive geomechanical model. According to borehole failure observations from a formation micro scanner (FMS) image log, the direction of minimum and maximum horizontal in-situ stresses (Sh and SH) were N35E and N55W, respectively. Also, using poro-elastic formulations, in-situ stress regime was found to be strike-slip (i.e. SH>Sv>Sh). Besides, the optimum mud weight for safe drilling at borehole breakout based on Mohr-Coulomb and Mogi-Coulomb criteria were found 85.12 and 80.42 pcf, respectively, while 79 pcf had been applied in practice. Finally, the precision of the geomechanical model was evaluated using natural fracture observations in the FMS image logs. The FMS logs revealed a total of 510 natural fractures in five clusters. In case of all fracture intervals, petrophysical properties and in-situ stresses decreased and therefore, the model was adequately sensitive to the fractures.

A coupled geomechanical reservoir simulation analysis of CO2- EOR: A case study

Currently, there is a great interest in the coupling between multiphase fluid flow and geomechanical effects in hydrocarbon reservoirs and surrounding rocks. The ideal solution for this coupled problem is to introduce the geomechanical effects through the stress analysis solution and implement an algorithm, which assures that the equations governing the flow and stress analyses are obeyed in each time step. This paper deals with the implementation of a program (FORTRAN90 interface code), which was developed to couple conventional reservoir (ECLIPSE) and geomechanical (ABAQUS) simulators, using a partial coupling algorithm. The explicit coupled hydro-mechanical behavior of Iranian field during depletion and <TEX>$CO_2$</TEX> injection is studied using the soils consolidation procedure available in ABAQUS. Time dependent reservoir pressure fields obtained from three dimensional compositional reservoir models were transferred into finite element reservoir geomechanical models in ABAQUS as multi-phase flow in deforming reservoirs cannot be performed within ABAQUS. The FEM analysis of the reservoir showed no sign of plastic strain under production and <TEX>$CO_2$</TEX> injection scenarios in any part of the reservoir and the stress paths do not show a critical behavior.