Geomechanical Finite Element Models Research Articles

Investigating the Susceptibility to Failure of a Rock Cliff by Integrating Structure-from-Motion Analysis and 3D Geomechanical Modelling

Multi-temporal UAV and digital photo surveys have been acquired between 2017 and 2020 on a coastal cliff in soft rocks in South-Eastern Italy for hazard assessment and the corresponding point clouds have been processed and compared. The multi-temporal survey results provide indications of a progressive deepening process of erosion and detachment of blocks from the mid-height portion of the cliff, with the upper stiffer rock stratum working provisionally as a shelf against the risk of general collapse. Based on the DEM model obtained, a three-dimensional geomechanical finite element model has been created and analyzed in order to investigate the general stability of the cliff and to detect the rock portions which are more susceptible to failure. Concerning the evolving erosion process, active in the cliff, the photogrammetric analyses and the modeling simulations result in agreement and a proneness to both local and general instabilities has been achieved.

Near-salt stress-induced seismic velocity changes and seismic anisotropy and their impacts on salt imaging: A case study in the Kuqa depression, Tarim Basin, China

It has been recognized that stress perturbations in sediments induced by salt bodies can cause elastic-wave velocity (seismic velocity) changes and seismic anisotropy through changing their elastic parameters, thus leading to difficulties in salt imaging. To investigate seismic velocity changes and seismic anisotropy by near-salt stress perturbations and their impacts on salt imaging, taking the Kuqa depression as an example, we have applied a 2D plane-strain static geomechanical finite-element model to simulate stress perturbations and calculate the associated seismic velocity changes and seismic anisotropy; then we used the reverse time migration and imaging method to image the salt structure by excluding and including the stress-induced seismic velocity changes. Our model results indicate that near-salt stresses are largely perturbed due to salt stress relaxation, and the stress perturbations lead to significant changes of the seismic velocities and seismic anisotropy near the salt structure: The maximum seismic velocity changes can reach approximately 20% and the maximum seismic anisotropy can reach approximately 10%. The significant changes of seismic velocities due to stress perturbations largely impact salt imaging: The salt imaging is unclear, distorted, or even failed if we exclude near-salt seismic velocity changes from the preliminary velocity structure, but the salt can be better imaged if the preliminary velocity structure is modified by near-salt seismic velocity changes. We find that the locations where salt imaging tends to fail usually occur where large seismic velocity changes happen, and these locations are clearly related to the geometric characteristics of salt bodies. To accurately image the salt, people need to integrate results of geomechanical models and stress-induced seismic velocity changes into the imaging approach. The results provide petroleum geologists with scientific insights into the link between near-salt stress perturbations and their induced seismic velocity changes and help exploration geophysicists build better seismic velocity models in salt basins and image salt accurately.

Representation of faults in reservoir-scale geomechanical finite element models – A comparison of different modelling approaches

Different approaches exist to incorporate faults in reservoir-scale geomechanical models. Challenges are the proper representation of the fault geometry as well as the small-scale variations in the internal architecture and the mechanical properties of the fault zone regarding the typical size of such models, i.e., kilometres to tens of kilometres. The present study utilizes a simple generic fault zone model to compare three different possibilities commonly used to represent faults in finite element reservoir models. Two differ in the basic grid geometry and the arrangement of mechanically weak fault zone elements, respectively. The third uses a discontinuous grid and contact elements to represent the fault. Modelling results show remarkable differences in the calculated stress and strain patterns. The relatively strongest perturbations result for a continuous curvilinear grid adapted to the fault geometry. In contrast, the fault implementation has the least impact on local stresses and strains if it is represented as a stair-step structure contained in a rectangular grid. The use of contact elements has an intermediate effect. Modelling results are used to infer some general recommendations concerning the appropriate approach of representing faults in a numerical-geomechanical reservoir models depending on fault geometry, model scale and scope of interest.

Proposed Refracturing-Modeling Methodology in the Haynesville Shale, a US Unconventional Basin

Summary During the downturn in the oil and gas industry, many operators have chosen to refracture their previously underperforming wells to boost economics with lower investment compared to drilling new wells. More than 100 horizontal wells have been refractured using chemical diverters across multiple basins in North America since the second half of 2013. Many papers have been published discussing these case studies. However, the refracturing results have been inconsistent. One of the biggest challenges of refracturing with chemical diverters is not knowing what is actually happening downhole. To understand what is happening better, more refracturing modeling should be performed to more reliably predict production results before spending the upfront capital for a refracturing treatment. We propose a refracturing numerical simulation methodology to take into account the historical production depletion using the calculated pressure and stress measurements along the lateral and in the reservoir. The altered stress fields resulting from reservoir depletion are calculated through a comprehensive workflow coupling simulated 3D reservoir pressure with a geomechanical finite–element model described in a previously published paper. After the stress and pressure are updated, the new approach outlined in this paper is validated by production history matching real data from a previously refractured well in the Haynesville Basin to provide greater confidence in the end results. The main uncertainty in the process is how much of the lateral was stimulated. In this paper we also provide a sensitivity example to show how the model can be altered to predict different lateral coverage percentages. Refracturing modeling still poses a major challenge for engineers because of the reservoir complexity and uncertainty downhole while refracturing (e.g., reservoir heterogeneity, isolation efficiency). However, our proposed refracturing approach provides a basic guideline on how to model refracturing treatments in a numerical simulator with the help of altered stress fields caused by reservoir depletion. This can be used to better understand why previously refractured wells perform the way they do and to better predict the performance of future refractured wells in both gas and liquid reservoirs.

An integrated workflow for stress and flow modelling using outcrop-derived discrete fracture networks

Fluid flow in naturally fractured reservoirs is often controlled by subseismic-scale fracture networks. Although the fracture network can be partly sampled in the direct vicinity of wells, the inter-well scale network is poorly constrained in fractured reservoir models. Outcrop analogues can provide data for populating domains of the reservoir model where no direct measurements are available. However, extracting relevant statistics from large outcrops representative of inter-well scale fracture networks remains challenging. Recent advances in outcrop imaging provide high-resolution datasets that can cover areas of several hundred by several hundred meters, i.e. the domain between adjacent wells, but even then, data from the high-resolution models is often upscaled to reservoir flow grids, resulting in loss of accuracy. We present a workflow that uses photorealistic georeferenced outcrop models to construct geomechanical and fluid flow models containing thousands of discrete fractures covering sufficiently large areas, that does not require upscaling to model permeability. This workflow seamlessly integrates geomechanical Finite Element models with flow models that take into account stress-sensitive fracture permeability and matrix flow to determine the full permeability tensor. The applicability of this workflow is illustrated using an outcropping carbonate pavement in the Potiguar basin in Brazil, from which 1082 fractures are digitised. The permeability tensor for a range of matrix permeabilities shows that conventional upscaling to effective grid properties leads to potential underestimation of the true permeability and the orientation of principal permeabilities. The presented workflow yields the full permeability tensor model of discrete fracture networks with stress-induced apertures, instead of relying on effective properties as most conventional flow models do.

Directionless fracture stability assessment based on a 4D geomechanical model of a SAGD scenario

In SAGD operations the injection of steam leads to thermally induced stresses and pore pressure changes in the subsurface. Although the pressure and temperature can be modelled with reservoir simulators, the change of the stress field in relation to these properties can impact the stability of faults and fractures, which in turn have effects on the fluid transport properties. To assess the potential for fault and fracture (re-)activation we create a model of a SAGD operation by coupling the outcome of a reservoir simulation to a 4D geomechanical finite-element model. The model reveals the bounding faults to have critically stressed. A second, more conservative, approach uses a directionless assessment without the need of discrete fractures. It shows extensive critically-stressed regions above and below the injection at much earlier stages, which extend far into the cap-rock. The model shows the importance of creating integrated 3D or 4D models honouring overburden stiffness and vertical load in the same way as the locally induced stresses. A challenge remains in quantifying the input rock parameters for the entire vertical column. The outcome of the model stresses the need for a detailed discussion of the cap rock thickness and the impact of potential of fractures.

Investigation of caprock integrity for CO2 sequestration in an oil reservoir using a numerical method

Geological sequestration of carbon dioxide is a mitigation method for reducing greenhouse gas emissions to the atmosphere. Success and safety of a CO2 sequestration operation is strongly dependent on the mechanical stability of the caprock overlying the storage reservoir. Subsurface CO2 injection results in a pore pressure increase and thereby a decrease of the effective stresses, which may lead to caprock failure and subsequent CO2 leakage. In this study, a three-dimensional geomechanical finite element model was built by using Abaqus software to investigate the geomechanical effects of CO2 injection on the caprock and to estimate the risk of caprock failure. The CO2 injection induced pore pressure increase, vertical displacement of the caprock, and the effective stress decrease have been investigated. The results show that the caprock remains stable during the 10-year injection period under the considered conditions. Through quantitative sensitivity analysis, the effects of the input parameters are ranked. CO2 injection rate and initial stress state were found to have the most significant impact on the caprock failure tendency. Results of the numerical model were also validated against analytical solutions.

A parallel linear solver exploiting the physical properties of the underlying mechanical problem

The iterative solution of large systems of equations may benefit from parallel processing. However, using a straight-forward domain decomposition in “layered” geomechanical finite element models with significantly different stiffnesses may lead to slow or non-converging solutions. Physics-based domain decomposition is the answer to such problems, as explained in this paper and demonstrated on the basis of a few examples. Together with a two-level preconditioner comprising an additive Schwarz preconditioner that operates on the sub-domain level, an algebraic coarse grid preconditioner that operates on the global level, and additional load balancing measures, the described solver provides an efficient and robust solution of large systems of equations. Although the solver has been developed primarily for geomechanical problems, the ideas are applicable to the solution of other physical problems involving large differences in material properties.

A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin

Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

Modeling Horizontal-Completion Deformations in a Deepwater Unconsolidated-Sand Reservoir

Summary We present the development and results of geomechanical models and analyses used to assess the risks of compaction-induced deformation and potential failure of horizontal gravel-pack completions in a field located in deep water but at shallow depth below the seafloor. The target reservoir consisted of high-porosity, underconsolidated stacked turbidite sandstones, which are comparable to some of the more well-known, problematic compactive reservoir sands. The formations indicated a high level of risk of depletion- induced compaction, which could produce large deformations and potential failure of completion equipment in horizontal wells. Coupled poroelastoplastic geomechanical finite-element models were constructed to assess the risks of completion-equipment damage because of depletion-induced reservoir compaction. Both openhole and cased-hole gravel-packed completion configurations were analyzed. Details of the prepacked-screen assembly components were included in the models, such as the ribs between the base pipe and inner screen and the deformable epoxied sand between inner and outer screens. Model results presented in this paper include deformations of the completion equipment and stresses in the screen components, as a function of reservoir-depletion pressure. The results of the geomechanical modeling indicated that the overall compaction loading should not cause significant deformation of the specified completion equipment.

Predicting Accelerating Subsidence Above the Highly Compacting Luconia Carbonate Reservoirs, Offshore Sarawak Malaysia

Summary Sarawak Shell Berhad has a number of offshore gas fields that produce from the Luconia carbonate formation, which can exhibit high-compressibility pore-collapse deformation. Recent accelerated subsidence has been observed at several of these fields, which extrapolates to final subsidence values well above previous estimates. This paper describes a geomechanical study involving core work to determine if the Luconia formation compressibility is sensitive to brine flow from the rising aquifer and a 3D geome-chanical finite-element model developed to predict future subsidence and lateral movements for the F23 platform. Compaction tests were performed on the Luconia core from three different gas fields. Tests on twin plugs were conducted—one plug undergoing a standard uniaxial zero-lateral-strain compaction test, while its twin has several pore volumes of simulated-formation brine flowed through it (at virgin in-situ stress conditions) before the compaction loading. Four sets of compaction tests on twin plugs were completed. The higher-porosity samples showed characteristic pore-collapse behavior consistent with previous measurements on Luconia mouldic limestone core. No sensitivity to brine flow was observed. In-situ compaction logs in the field also do not show increased compressibility in sections flooded by the rising gas-water contact (GWC). The geomechanical model uses a relatively simple structural model comprised of four layers—two overburden formations, the Luconia carbonate and one underburden formation. A nonlinear deformation model for the Luconia formation captures the accelerating pore-collapse response observed in the core and in-situ compaction measurements. The model is calibrated to GPS-measured platform subsidence and is consistent with measured core- and field-compaction properties. The results predict that platform subsidence rates with depletion would level off, with a maximum subsidence of 18.5 ft +/− 1 ft at an abandonment pressure of 300 psi. Platform subsidence in the two years following the work continues to follow the predicted values. This work illustrates the importance of integrated geomecha-nical core testing, field-monitoring measurements, and modeling to accurately predict compaction and subsidence effects in highly compacting environments.

Fluid injection and surface deformation at the KTB location: modelling of expected tilt effects

AbstractThis investigation is indented to explore the relationship between changes in pore fluid pressure and deformation of the land surface induced by a large‐scale injection experiment at the KTB site. Deformation will be monitored by ASKANIA borehole tiltmeters at five locations. During the year 2003, a network of borehole tiltmeters was installed, data transmission links established and tested, and recording of tilt data started. Our first main interest was to receive data sets of all stations well before the injection experiment to start in May 2004, to be able to evaluate local site effects. Thus, the separation of injection‐induced effects will be more reliable. Principal 3D numerical modelling (poro‐elastic modelling and investigations, using the finite element method, FEM) of poro‐elastic behaviour showed that significant tilt amplitudes can be expected during controlled fluid injection. Observed deformation will be investigated within the framework of the fluid flow behaviour and resulting deformation. Two models have been used: a coupled hydro geomechanical finite element model (abaqus) and, as a first step, also a multi‐layered poro‐elastic crust (poel). With the numerical model two effects can be quantified: (i) the deformation of the upper crust (tilt measurements) and (ii) the spatial distribution and the changes of material properties in the KTB area. The main aim of the project is to improve the knowledge of coupled geomechanic–hydraulic processes and to quantify important parameters. Thus, the understanding of fracture‐dominated changes of the hydrogeological parameters will be enhanced, geomechanical parameter changes and the heterogeneity of the parameter field quantified. In addition, the induced stress field variation can be explained, which is believed to be mainly responsible for the increase of local seismic activity. Here, we introduce the tiltmeter array at the KTB site, the modelling for a poro‐elastic crust and the preliminary FEM modelling.

Lateral clay injection into normal faults

ABSTRACT The clay content of fault gouge is one of the main factors controlling transport and mechanical properties of a fault zone. This paper addresses the process of lateral clay injection into normal faults, which is one of the many processes contributing to the development of clay smear, and can lead to local enrichment of clay in a fault gouge. We combined field observations with geomechanical models to quantify the parameters leading to lateral clay injection into fault zones. Detailed field study shows that a releasing fault bend in a clay layer is required for clay injection to occur. The clay injection process is often associated with the formation of a branch in the fault and the development of a “squeezing block” which injects the clay into the fault zone. A simple analytical model predicts the onset of clay injection when C = σ'v (1 - sin ϕ) / (2 cos ϕ), where C is cohesion (MPa), σ'v is vertical stress (MPa) and ϕ (°) is friction angle. More detailed analysis using 2-D geomechanical finite element models is in good agreement with the analytical models and allows study of the system at higher fault throw. Results of sandbox models containing layers of an elastoplastic clay analogue also compare well with field observations and numerical models, and show the initiation of the releasing step and the evolution of the clay injection process with increasing fault throw. Using our results it is possible to predict the likelihood of lateral clay injection in the subsurface, in settings like the Gharif formation of the Haushi group of Central and South Oman or the Natih formation of North Oman. This requires an estimation of the mechanical properties of the clays at the time of faulting; data which can be obtained from wireline logs and cuttings. This approach to fault seal analysis emphasizes the mechanical aspects of the clay smear process, in addition to the kinematics which were considered in previous analyses. Its application should lead to improved prediction of fault seal processes in the subsurface.

Key parameters controlling coalbed methane cavity well performance

Openhole cavity completions have proved to be remarkably successful in improving the coalbed methane well productivity in the “fairway” region of the San Juan basin, USA. This technique employs a series of controlled injection/blowout processes to create a cavity in the target seams to enhance the formation permeability around the cavity. The cavity wells in the “fairway”, which are characterised by overpressured, highly permeable thick coals, generally yield production levels several times greater than hydraulically fractured wells. In the areas outside the fairway, however, hydraulically fractured wells have generally proved to be more productive. This paper reports on the application of a geomechanical finite element model to a dedicated field research cavity well established in the fairway. Using the published field data as input, the model predictions are in good agreement with the field findings in terms of the cavity size and post-cavity permeability enhancement. The results of a parametric study demonstrate that the formation permeability is the most important parameter controlling cavity well performance. This result is consistent with the field experience in the San Juan basin.

Field-Scale and Wellbore Modeling of Compaction-Induced Casing Failures

Summary Presented in this paper are the results and verification of field- and wellbore-scale large deformation, elasto-plastic, geomechanical finite element models of reservoir compaction and associated casing damage. The models were developed as part of a multidisciplinary team project to reduce the number of costly well failures in the diatomite reservoir of the South Belridge Field near Bakers-field, California. Reservoir compaction of high porosity diatomite rock induces localized shearing deformations on horizontal weak-rock layers and geologic unconformities. The localized shearing deformations result in casing damage or failure. Two-dimensional, field-scale finite element models were used to develop relationships between field operations, surface subsidence, and shear-induced casing damage. Pore pressures were computed for eighteen years of simulated production and water injection, using a three-dimensional reservoir simulator. The pore pressures were input to the two-dimensional geomechanical field-scale model. Frictional contact surfaces were used to model localized shear deformations. To capture the complex casing-cement-rock interaction that governs casing damage and failure, three-dimensional models of a wellbore were constructed, including a frictional sliding surface to model localized shear deformation. Calculations were compared to field data for verification of the models.