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The idea is to create Poor quality sands often contain interbedded shales with sufficient increase in horizontal stress to induce shear areal extent which can significantly impair vertical failure and increase in vertical permeability across the communication and drastically reduce recovery in barrier. The implementation could be via induction or conventional SAGD or related hybrid processes. Several microwave electric heating, or one can also consider use methods have been envisioned to provide vertical of resistive heating elements in the wells with heat communication through the shales, but none of these transfer into the formation mainly by conduction.
- North America > United States (1.00)
- North America > Canada > Alberta (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.94)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.94)
ABSTRACT ABSTRACT: The main goal of this research was to investigate the risk of caprock failure due to the SAGDOX process, a hybrid steam and in-situ combustion recovery process for oil sands. A temperature dependency extension to the linear and non-linear constitutive models was developed and implemented in the GEOSIM software. The analysis has shown that there is no increased risk of caprock failure for SAGDOX process compared to SAGD. The study has shown that the overlying Wabiskaw formation experiences shear failure during both SAGD and SAGDOX due to its low initial cohesion, friction angle and proximity to pressure and temperature front, although the failure was mainly driven by pressure propagation. However, Clearwater shale above Wabiskaw can still provide proper zonal isolation to the steam/combustion chamber under SAGDOX operating conditions. Uncertainty in the analysis is due mainly to the sparse nature of geomechanical properties data for the oil sand reservoir and the caprock formations, especially at temperatures over 200 C. 1. INTRODUCTION Nexen Energy ULC (Nexen) has been evaluating SAGDOX - a post SAGD oxidation process (Kerr, 2012; Jonasson and Kerr 2013) - to improve the recovery and project economics of its Long Lake SAGD operation. SAGDOX is meant to be used after several years of SAGD operations when the bitumen between two SAGD well-pairs is mobile. In SAGDOX process (applied to a row of parallel well pairs) oxygen is coinjected with steam in every other SAGD injector well and starts an oxidation process by reacting with residual oil around the injection well. At this point the SAGD production well below the oxygen-steam injector is shut in and steam along with oxygen and combustion gasses fill the steam chamber voidage and push hot bitumen towards the neighbouring SAGD well-pair. The neighbour injection well is also shut-in and could be converted to a producer if need be. Various other well arrangements have been considered including those with vertical injection wells and infill horizontal production wells. Since oxygen is co-injected with steam, very high oxidation temperature of a pure combustion process are not generated as steam carries a large portion of the heat of combustion away from reaction front and temperatures are thereby moderated. Nonetheless, temperatures in the range of 400-600 deg C are expected in the oil sand zone. The high temperature combustion front where the oxidation reactions are active moves away from the oxygen injection wells as the residual oil left behind after steam displacement is consumed. The high temperature reaction zone has a tendency to move upward towards the cap rock under the influence of gravitational forces.
- North America > United States (0.93)
- North America > Canada > Alberta (0.71)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.76)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.67)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabiskaw Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.98)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.97)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.94)
Abstract This paper describes a workflow involving a reservoir flow simulator coupled with a finite element geomechanical simulator. Multi-stage hydraulic fracturing jobs are modeled by simulating injection of water into the reservoir - using stage spacing, stage sizes and pump rates as parameters to the well models. Constitutive models are specified for fracture propagation and shear failure due to induced stress changes in the reservoir. Coupling is also provided through stress dependent flow transmissibility multiplier tables. Simulation based sensitivity studies are carried out on stage spacing and stage size as well as strength of the reservoir rock . Maps of the ratio between deviatoric stresses (at the actual stress states) and failure are built as a function of space and time (for the duration of the fracturing job). These maps can be correlated against maps of recorded microseismicity and used to better understand the mechanism and growth of the stimulated reservoir volume. This workflow attempts to reconcile flow and geomechanical behavior of the reservoir without requiring detailed reservoir characterization.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.41)
ABSTRACT: When cold fluid is injected into a hot reservoir, secondary cracks may be created perpendicular to the main crack. The difference between the temperature of the fluid in the main crack and the temperature of the formation along with the increase of pressure due to poroelasticity cause a decrease of initial effective stress in the direction parallel to the main crack. The secondary crack is initiated when the value of the minimum effective stress is lower than the rock tensile strength. This crack continues propagating into the formation when constant pressure and temperature are maintained at the main crack surface. The effect of flow into the secondary crack is also examined. Crack initiation, crack width and crack length are discussed. A 2D plane strain simulation model used for this study is presented and its results for a variety of conditions are discussed such as initial effective stress in the formation, Young’s modulus, leak-off, no leak-off and temperature difference. The results demonstrate that i) thermal stresses are the dominant cause of secondary fracturing, and ii) the initiation and propagation of secondary cracks is possible even in short term injection typical of hydraulic fracturing treatments. 1. INTRODUCTION Recently, geomechanics has played an important role in understanding petroleum production in diverse areas such as reservoir compaction and subsidence (Chin and Nagel [1], Sen and Settari [2]), well damage, casing collapse and sand production (Settari et al. [3], Fung et al. [4], Wang and Lu [5]). Geomechanics is also extensively used in the study of man-made fractures as well as fracture orientation in reservoirs. Cold fluid injection in a hot naturally fractured reservoir has attracted attention of the upstream petroleum industry since it has caused an unexpected increase in oil and gas recovery.
Abstract Some rock masses are characterized by joints, fractures and other plane of weakness which reduce the strength and deformation properties of rock structure. Under different loading conditions, joints with weaker normal and shear strength undergo a relatively higher strain than intact rock. Since permeability of jointed rock masses in fractured reservoirs is a strong function of joint aperture size, one may expect a major change in the permeability when subjected to confining load variation. Therefore, it is very important to establish the relation between the stress-strain of the jointed rock mass and the reservoir permeability. This relation is particularly important to model hydraulic fracturing and productivity decline in tight gas wells. In this paper, a new relation is proposed to model pre-peak shear stiffness of the joint based on the conventional joint surface parameters and the confining load. Furthermore, constitutive matrices for evaluating deformation behavior of single joint and regularly jointed rock are presented as the results of an analytical study. Based on the concept of joint stiffness, an equivalent stiffness for regularly jointed rock masses was derived, assuming that the deformation of the jointed rock mass equals the sum of the deformation of the rock matrix and the joints. Finite element technique is used to numerically model the deformation behavior of the jointed rock under various loading conditions. The applicability of the constitutive model to represent jointed rock mass was confirmed from comparison of the numerical results with some of the existing experimental data. The model presented here will be the key element for integrated geomechanical modeling of tight gas wells, naturally fracture reservoirs, and other fracturing processes in stresssensitive reservoirs. Introduction Mechanical behavior of the jointed rock in naturally fracture reservoirs or in rock bodies stimulated by hydraulic fracturing (i.e., an artificially fractured well in a tight gas reservoir) is highly influenced by the presence of joints. Since joints are the main flow conduit in jointed rocks and the joint permeability is a quadratic function of its aperture size, it is crucial to investigate the variations in a joint aperture size under different loading conditions. Mechanical behavior of a joint is characterized by its normal-shear mechanical deformation and is defined in the form of a joint constitutive model. Here we will first review the literature related to rock joint normal and shear deformations. Different techniques by which the composite system of rock and joints (jointed rock) are mechanically modeled will be reviewed in the next section. Normal deformation of a joint has been the subject of many studies in the early investigations on the jointed rock mechanical behavior. It was first formulated by Goodman (1976) and later by Swan (1980) in an empirical approach by Power law mathematical functions. Afterward, based on numerous experimental results, Bandis et al. (1983) proposed an empirical hyperbolic model for normal deformation of rock joint. This model is similar, in both formulation approach and functional form, to Goodman's model; however, each fits best their own experimental results.
- North America > United States (0.46)
- North America > Canada (0.28)
Abstract Sand production is a problem that plagues many reservoirs and has strongly affected benefit-cost relationships in the oil industry for years. Research dating as far back as the early 1930s has documented sand-production problems in unconsolidated formations. These problems are not related to one specific location or area, and although sand production is a worldwide problem, the major documented areas of sand production are in the USA, Canada, the North Sea, Europe, Venezuela, Bolivia, Brazil, and Colombia. Major causes of sand production include depletion, a change in flowing fluids, a change in stresses, and wellbore- stability failure. Failure to manage sand production can have a significant impact on the productivity of the well with the possibility of causing an eventual well collapse. In this paper, the application of a numerical simulator used for sand prediction in a gas well is presented. The simulator predicts the amount of produced sand and its effect on the productivity of the well. The model is based on the hydro-erosion model, first proposed by Vardoulakis in 1996 (Vardoulakis et al. 1996). The model is based on rigid, porous media (no skeleton deformation), in which mass balance is applied to a three-constituent system comprised of solid, fluid, and fluidized solid using the homogenization-mixture theory. Subsequently, Wan and Wang (2002) extended this pure-erosion model to include the effects of the deformation of porous media in a consistent manner. A single-phase flow is iteratively coupled with geomechanics within a continuum mechanics framework. Furthermore, Wang (2004) extended previous work to develop a fully coupled reservoir-geomechanics model to account for the effects of multiphase flow and geomechanics in a consistent manner. By using this numerical simulator application, the severity and quantification of the problem of sand production were resolved, resulting in an acceptable economical return. The results of this field case are documented below in further detail. The Sand-Production Process Sand production occurs when the stresses of the formation exceed the strength of the formation. The formation strength is derived from the natural cementing material that bonds the sand grains together. Sand grains are also held together by the cohesive forces caused by the immobile formation water. The stress of the formation-sand grains is caused by many factors, such as tectonic actions, overburden pressure, pore pressure, stress changes from drilling, and the drag forces of the producing fluids. Sand production is rate-sensitive in that there is a rate below which no sand production occurs. This reduced producing rate can be uneconomical because some formation sands might be produced with a fairly low fluid velocity. In some unconsolidated sands, the cementing agent is clay and mud that forms a weak material that provides little or no strength to withstand the formation stresses. In such a case, a wellbore might produce sand even during the production tests. Other formations might initially produce sand-free hydrocarbon, but can later fail and begin to produce sand. It has been observed that sand-production problems become more serious as water breakthrough occurs. This is probably caused by the increase of total fluid production that consequently increases the drag forces across the sand. Water breakthrough can also contribute to dissolution of the natural cementing material.
- South America (1.00)
- North America > United States (0.88)
- North America > Mexico (0.64)
- (4 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
- South America > Venezuela (0.89)
- South America > Colombia (0.89)
- South America > Brazil > Brazil > South Atlantic Ocean (0.89)
- (5 more...)
Abstract Despite the economics and environmental benefits of PWRI (Produced Water Re-Injection) projects, the permeability reduction due to deposited particles is a persistent problem. Various models for permeability damage calculation are available. Most of them are based on one-dimensional laboratory parameters and have not considered the anisotropy of the media. In previous attempts at anisotropy modelling, the initial anisotropy of the media has been considered. However, when it comes to the damage intensity calculation, isotropic parameters have been used for the entire media. As a result, the relative damage in these models is isotropic. In this paper, a robust approach for anisotropic permeability impairment is developed based on micromechanical considerations. The damage mechanics is coupled with numerical flow code. The model formulation has been successfully tested in 1D flow against the core flood tests from the Masila Block onshore Yemen. Then, the damage model has been extended to 3D using pseudo directional parameters to capture the anisotropy. A dynamic anisotropic mathematical formulation for damage intensity has been derived, implemented in a 3D numerical code and successfully tested on a field case study. The new model exhibits the expected anisotropy of damage. Introduction Anisotropic formation damage has been studied by many researchers, especially for horizontal wells. However, in all previous work it has been assumed that the damage intensity in different directions (defined as a ratio of the damaged permeability to the original permeability) would remain the same in all directions(1, 2). This assumption (sometimes clearly stated, sometimes not) means that, although the damage profile and front would be dissimilar in different directions (sometime considered to be anisotropic damage), the ratio of the damaged permeabilities in the horizontal and vertical direction kh/kv (called "anisotropy ratio") stays constant. The common result of this assumption for a horizontal well is to have an elliptical cross-sectional damage profile, which will grow with time proportionally in both directions. The hypothesis for the mechanics of real anisotropic damage is obtained by starting with an elliptical cross-section for the damage profile. The following phenomenon is plausible. Since we have a higher velocity (and volume) of damaging water flowing in the direction of higher permeability (horizontal), we would continue to have a deeper invasion in this direction compared to the direction of lower permeability. Therefore, the anisotropy persists as the damage grows. However, we would expect the intensity of damage to be higher in the vertical direction because of lower initial permeability and, therefore, smaller pore throats. Hence, the anisotropy ratio (kh/kv) is expected to increase with time, rather than to stay constant. To be able to model the anisotropy phenomenon, consider the velocity-based damage model (VDM). First, we note that in isotropic permeability, it was proven that the use of the vector of velocity would create the correct solution for a multidimensional case. In an anisotropic situation, the original model produces a constant anisotropy ratio. We therefore need to have different initial damage coefficients a for different directions and they need to be changed with time in a different fashion.
- Asia > Middle East > Yemen (0.24)
- North America > Canada > Alberta (0.16)
Abstract Despite the economics and environmental benefits of PWRI projects, the permeability reduction due to deposited particles is a persistent problem. Various models for permeability damage calculation are available. Most of them are based on 1D laboratory parameters and have not considered the anisotropy of the media. In previous attempts at anisotropy modeling, the initial anisotropy of the media has been considered, but when it comes to the damage intensity calculation, isotropic parameters have been used for the entire media. As a result, the relative damage in these models is isotropic. In this paper a robust approach for anisotropic permeability impairment is developed based on micromechanical considerations. The damage mechanics is coupled with numerical flow code. The model formulation has been successfully tested in 1-D flow against the core flood tests from Masila Block onshore Yemen. Then the damage model has been extended to 3D using pseudo directional parameters to capture the anisotropy. A dynamic-anisotropic mathematical formulation for damage intensity has been derived, implemented in a 3D numerical code and successfully tested on a field case study. The new model exhibits the expected anisotropy of damage. Introduction Anisotropic formation damage has been studied by many researchers, especially for horizontal wells. However, in all previous work it has been assumed that the damage intensity in different directions (defined as a ratio of the damaged permeability to the original permeability) would remains the same in all directions. This assumption (sometimes clearly stated, sometimes not) means that, although the damage profile and front would be dissimilar in different direction (sometime considered to be anisotropic damage), the ratio of the damaged permeabilities in horizontal and vertical direction Kh/Kv (which will be called "Anisotropy ratio") stays constant. The common result of this assumption for a horizontal well is to have an elliptical cross-sectional damage profile, which will grow with time proportionally in both directions. The hypothesis for the mechanics of real anisotropic damage, is obtained by starting with an elliptical cross section for damage profile. The following phenomenon is plausible. Since we have a higher velocity (and volume) of damaging water flowing in the direction of higher permeability (horizontal), we would continue to have a deeper invasion in this direction compared to the direction of lower permeability; therefore the anisotropy persists as the damage grows. However, the intensity of damage would expect to be higher in the vertical direction because of lower initial permeability and therefore smaller pore throats. Hence the anisotropy ratio (Kh/Kv) is expected to increase with time, rather than to stay constant. To be able to model the anisotropy phenomenon consider the velocity based damage model (VDM). First, we note that in isotropic permeability, it was proven that the use of the vector of velocity would create the correct solution for multidimensional case. In an anisotropic situation, the original model produces constant anisotropy ratio. We therefore need to have different initial damage coefficients α for different directions and those need to change with time in different fashion.
- North America > Canada (0.29)
- Asia > Middle East > Yemen (0.24)
Abstract Permeability decline occurs during injection of produced water and seawater, resulting in injectivity declines and significant cost increases in waterflooding projects. It is necessary to have a reliable model to predict injectivity decline for preventive water treatment and waterflood design purposes. A classical deep bed filtration (DBF) model has been widely used to predict the injectivity decline. According to this model, the injectivity decline can be characterized by two empirical parameters: filtration coefficient, λ, and formation damage coefficient, β. Different methodologies developed to extract these parameters involve expensive and difficult concentration measurements, laboratory-scaled pressure drop measurements (not truly representative of the real reservoir) and simplifying assumptions of analytical solutions. A simple empirical velocity-based damage model proposed by Bachman et al. is adopted in this work, and extended to multidimensional flow. This model is then compared to the deep bed filtration-based model. The advantage of the empirical model is that it can be easily tuned to either field or laboratory data, and can be easily implemented in reservoir simulators. The paper presents the formulation and numerical implementation of the two coupled reservoir flow and damage models. Different methods of implementing the velocity-based model in multidimensional flow are presented and evaluated. The comparison with the DBF model shows that the two models yield similar damage characteristics. Finally, application of the model to analysis of the published data for offshore Gulf of Mexico is presented. The relationship between the parameters of the two different approaches is validated for these case studies. Introduction As oil fields mature, the volumes of produced water requiring disposal increase significantly. Re-injecting produced water is an attractive, environmentally sound solution to water disposal problems, but entails the risk of poor injectivity. Produced water normally contains varying concentrations of particles, which have a direct effect on the injectivity decline (injectivity index is defined as the ratio of the injection rate to the given pressure head). It has been shown that declining well injectivity is the major cost-increasing item in the case of re-injection. Standard formulation of damage mechanics is based on the classical deep bed filtration (concentration-based) model (DBF). Injectivity decline is characterized by two parameters: filtration coefficient, λ, and formation damage coefficient, β. Methodologies developed to determine these parameters involve expensive and difficult measurements, scaling problems and simplifying assumptions of analytical solutions. Moreover, the model is not easily implemented in reservoir simulators. Bachman et al. proposed an empirical velocity-based damage model that could be easily tuned to field or laboratory data, and easily implemented in reservoir simulators. However, the model was formulated in 1D and its extension (and validity) in multidimensional flow was not shown. This paper presents the development of a 2D formulation and numerical implementation of permeability impairment based on the velocity-based model. The results will be compared with the classical DBF approach to validate the result against deep bed filtration theory. Application of the model to published data from offshore Gulf of Mexico is presented.
- North America > United States (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
Abstract This work examines methods for modeling reservoir flow in the presence of a permeability tensor. Usually, control-volume multipoint discretizations are used to simultaneously handle the tensor permeability and complex geometry. Instead, the method used in this work is based on a simple extension of the conventional finite difference method. It is shown that this method (which results in 9-point approximations with a full tensor) cannot accurately predict the behaviour of reservoirs which contain permeability anisotropy. It suffers from what we call a "tensor orientation " effect, in addition to the well known grid orientation effect. The tensor orientation effect introduces an error in the magnitude and shape of the pressure field, which depends on the relative orientation of the grid in relation to the principal axes of the permeability tensor. This problem has been solved by developing a 13-point extension of the conventional 9-point finite difference method for the tensor permeability, which essentially eliminates the tensor orientation errors. Since this difference scheme is not easily implemented in conventional simulators, an approximate semi-implicit method, in which only nine points are in the implicit mode, was also developed. The semi-implicit method provides a good match with the 13-point method for the test problem. However, further reduction to a 5-point implicit operator results in a loss of accuracy. Comparative evaluation against the Flux Continuous Scheme technique shows that while both methods are free of the tensor orientation effect, the 13-point method has a lower value for well block pressure. Lack of an analytical solution makes it difficult to determine which method is closer to reality. Introduction In complex reservoirs, orientation and magnitude of principal permeabilities may vary spatially, and also evolve in time due to geomechanical effects. In such cases, a formulation with a full permeability tensor should be used to model fluid flow. In this paper, we examine methods for modeling fluid flow with a permeability tensor, and in particular, the effect of the permeability tensor orientation on the results with various numerical methods. Dependency of simulation results of fluid flow in porous media to the type of the grid mesh is well known and called the "grid orientation" effect. This problem was first demonstrated for 5-point reservoir simulators by Todd et al. in 1972. They suggested using 2-point upstream mobility method to alleviate this effect. This problem is associated mainly with unfavourable mobility ratios which occur in most EOR isothermal processes and steam and combustion, and can very seriously alter the results and conclusions of simulation studies. The grid orientation effect is also severe for simulating miscible displacement. Settari et al. have shown that a standard 5-point approximation gives unacceptable results even for moderately adverse mobility ratios (M = 10). Until now, a completely satisfactory solution has not been found for finite difference simulators and the grid orientation remains one of the more difficult numerical research problems. Nine-point discretizations are the usual method for solving the problem. However, the 9-point method still has some orientation errors, which depend on the problem solved.
- North America (0.47)
- Asia > Middle East > Iran (0.46)