Oil Sand Reservoirs Research Articles

Muddy interlayer forecasting and an equivalent upscaling method based on tortuous paths: A case study of Mackay River oil sand reservoirs in Canada

Abstract Based on the abundant core data of oil sands in the Mackay river in Canada, the termination frequency of muddy interlayers was counted to predict the extension range of interlayers using a queuing theory model, and then the quantitative relationship between the thickness and extension length of muddy interlayer was established. An equivalent upscaling method of geologic model based on tortuous paths under the effects of muddy interlayer has been proposed. Single muddy interlayers in each coarse grid are tracked and identified, and the average length, width and proportion of muddy interlayer in each coarse grid are determined by using the geological connectivity tracing algorithm. The average fluid flow length of tortuous path under the influence of muddy interlayer is calculated. Based on the Darcy formula, the formula calculating average permeability in the coarsened grid is deduced to work out the permeability of equivalent coarsened grid. The comparison of coarsening results of the oil sand reservoir of Mackay River with actual development indexes shows that the equivalent upscaling method of muddy interlayer by tortuous path calculation can reflect the blocking effect of muddy interlayer very well, and better reflect the effects of geological condition on production.

Emulsion-assisted thermal recovery method in heterogeneous oilsands reservoir

To prevent the steam from channeling and breakthrough in heterogeneous oil sands reservoirs, oil-in-water (O/W) emulsion is proposed and developed as a plugging agent in this study. However, one suspects that increased temperature destabilizes emulsion, promoting oil/water separation and thus to lose its plugging benefits induced by “Jamin effect”. This intuitive picture changes when the emulsion flows through heated porous media. In this paper, we show that increasing temperature enhances emulsion plugging effect, after a critical temperature reaches. O/W emulsions were firstly prepared at room temperature (~20 °C) individually using eight different surfactants and then injected in sandpacks at temperatures ranging from 20 °C to 140 °C. Experimental results show that the emulsion plugging strength at temperature of 140 °C is three times greater than that at room temperature (20 °C) and still shows a rising trend with temperature up to 140 °C. Measurements of the median droplet sizes of the effluents at different temperatures showed that there was no phase separation during the flow tests. This is because that the “snap-off” and “fingering induced break-up” processes keep the emulsion droplets dynamically stable during the flowing process. It is the changing hydrophilic-lipophilic characteristic of the surfactant molecules, as the temperature increases, that causes a parabola trend with a minimum of IFT and thus influences the emulsion plugging effect. What we expect following steam injection into the reservoir is that the achieved emulsion plugging strength could still be maintained or even enhanced so that the emulsion slug will not be easily displaced away by further steam injection, thus optimizing thermal recovery performance. By carefully selecting surfactant on the basis of its hydrophilic-lipophilic characteristic, an optimum emulsion system, contributing expected plugging strength at elevated temperatures, was designed, applied and verified for effective conformance control in heterogeneous parallel-sandpack. The experimental results demonstrate the designed emulsion can achieve conformance control in parallel-sandpack with a permeability ratio of 10 Darcy: 5 Darcy at room temperature and the conformance performance is still maintained as the temperature increases, up to 99 °C.

Theory-guided data science-based reservoir prediction of a North Sea oil field

Data science-based methods, such as supervised neural networks, provide powerful techniques to predict reservoir properties from seismic and well data without the aid of a theoretical model. In these supervised learning approaches, the seismic-to-rock property relationship is learned from the data. One of the major factors limiting the success of these methods is whether there exists enough labeled data, sampled over the expected geology, to train the neural network adequately. To overcome these issues, this paper explores hybrid theory-guided data science (TGDS)-based methods. In particular, we build a two-component model in which the outputs of the theory-based component are the inputs in the data science component. First, we simulate many pseudowells based on the well statistics in the project area. The reservoir properties, such as porosity, saturation, mineralogy, and thickness, are all varied to create a well-sampled data set. Elastic and synthetic seismic data are then generated using rock physics and seismic theory. The resulting collection of pseudowell logs and synthetic seismic data, called the synthetic catalog, is used to train the neural network. The derived operator is then applied to the real seismic data to predict reservoir properties throughout the seismic volume. This TGDS method is applied to a North Sea data set to characterize a Paleocene oil sand reservoir. The TGDS results better characterize the geology and well control, including a blind well, compared to a solely theory-based approach (deterministic inversion) and a data science-based approach (neural network using only the original wells). These results suggest that theory and data science can complement each other to improve reservoir characterization predictions.

A Novel sand control testing facility to evaluate the impact of radial flow regime on screen performance and its verification

Optimum design of the sand control devices in oil sand reservoirs plays a vital role in minimizing the sand production and increasing the reservoir productivity in Steam-Assisted Gravity Drainage (SAGD) operations. Various sand control testing facilities have been developed to evaluate the performance of sand control screens, such as the pre-packed Sand Retention Test (SRT). Current testing apparatuses are based on the linear flow regime. However, fluid flow around SAGD production wells is radial flow, not linear. This study introduces a Full-scale Completion Test (FCT) facility to emulate the radial-flow condition in SAGD wells. Instead of using a disk-shaped screen coupon, this facility utilizes a cylindrical-shaped screen. A couple of tests were carried out to determine the flow uniformity inside the cell and identify the test repeatability. Test results show that flow is distributed uniformly inside the cell, and experiments are repeatable in terms of differential pressures, fines production, and sanding levels. Therefore, this innovative FCT experimental setup and procedure allows a more realistic evaluation of the liner performance by emulating the real SAGD flow regime around the liner. Testing results obtained from the FCT can be used to complement and validate the current testing procedures. These tools can be adopted for an objective custom-design and selection of standalone screens in SAGD.

Look Ahead of the Bit While Drilling: Potential Impacts and Challenges of Acoustic Seismic While Drilling in the McMurray Formation

SummaryThe oil and gas industry, operating and service companies, and academia are actively searching for ways to look ahead of the drill bit while drilling to reduce the risks and costs of the operation and improve the well-placement process. Optimal drilling in challenging and highly heterogeneous reservoirs, where geological data cannot adequately constrain high-frequency variations in rock properties, requires reliable subsurface information from around and ahead of the drill bit. To provide this, we have developed a seismic-while-drilling (SWD) imaging algorithm using signal processing, drillstring modeling, and prestack wave-equation migration.To extend the visibility ahead of the bit, we use the drill bit as a seismic source and image the changes in acoustic properties of rocks both around and ahead of the drill bit. The common practice is to build reverse vertical seismic profile (R-VSP) gathers. Here, we use a blind deconvolution algorithm to estimate the drill-bit source signature from the data directly. Alternatively, we can estimate such a signature through drillstring modeling and surface measurements (i.e., hookload and hook speed). The drillstring dynamics are modeled and analyzed using Riemann's invariants and a backstepping approach in a field-verified model. Next, we enter the estimated source signature into the prestack wave-equation depth-imaging workflow. Our simulations show that providing the drill-bit source signature to the prestack wave-equation depth migration consistently delivers reliable subsurface images around and ahead of the drill bit.The output of our workflow is a high-resolution subsurface image, which is then applied to provide vital information in oil-sands reservoirs for placement of steam-assisted-gravity-drainage (SAGD) well pairs. Compared with conventional practices, the proposed methodology images around and ahead of the drill bit enable interactive decision making and optimal well placement. The key feature of the presented methodology is that instead of cross correlating the SWD data with the pilot trace and building R-VSP gathers, we use the estimated drill-bit source signature and deliver high-resolution prestack depth-migrated images.Through numerical modeling, we tested the potential impacts, validity, and challenges of the proposed methodology in drilling horizontal wells in SAGD settings with an emphasis on the McMurray Formation. We further compared the results with the conventional drilling practice. In contrast to existing tools that have limited depth of penetration, interpreting SWD data in real time confidently maps key target features ahead of the drill bit. This imaging workflow provides sufficient time to precisely control the borehole trajectory and stay within the desired reservoir zone. Accordingly, it mitigates the risk of intersecting mudstone-filled channels and lean zones.

Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier

A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.

Geomechanical Characterization of Inclined Heterolithic Stratification Lithosome and Its Permeability Evolution under SAGD Stress Paths

SummaryA sizeable portion of the Athabasca oil sand reservoir is classified as inclined heterolithic stratification lithosomes (IHSs). However, due to the significant heterogeneity of IHSs and the minimal experimental studies on them, their hydrogeomechanical properties are relatively unknown. The main objectives of this study are investigating the geomechanical constitutive behavior of IHSs and linking their geological and mechanical characteristics to their hydraulic behavior to estimate the permeability evolution of IHSs during a steam-assisted gravity drainage (SAGD) operation. To that end, a detailed methodology for reconstitution of analog IHS specimens was developed, and a microscopic comparative study was conducted between analog and in-situ IHS samples. The SAGD-induced stress paths were experimentally simulated by running isotropic cyclic consolidation and drained triaxial shearing tests on analog IHSs. Both series of experiments were performed in conjunction with permeability tests at different strain levels, flow rates, and stress states. Additionally, an analog sample with bioturbation was tested to examine the hydrogeomechanical effects of bioturbation. Finally, the hydromechanical characteristics of analog IHS were compared with its constituent layers (sand and mud).The microscopic study showed that the layers’ integration and grain size distributions are similar in analog and in-situ IHS specimens. The results also revealed that geomechanical properties of IHSs, such as shear strength, bulk compressibility, Young's modulus, and dilation angle, are stress-state dependent. In other words, elevating the confining pressure could significantly increase the strength and elastic modulus of a sample, while decreasing the compressibility and dilation angle. In contrast, the friction angle and Poisson's ratio are not very sensitive to changes in the isotropic confining stress. An important finding of this study is that the effect of an IHS sample's volume change on permeability is contingent on the stress state and stress path. Volume change during isotropic unloading-reloading resulted in permeability increases, and sample dilation during compression shearing resulted in permeability decreases, especially at high effective confining stresses. Moreover, the tests revealed that the existence of bioturbation dramatically improves permeability of IHSs in comparison to equivalent nonbioturbated specimens but has negligible effects on its mechanical properties, which remain similar to nonbioturbated specimens. The results also showed that bioturbation had minimal impact on permeability changes during shearing. Lastly, experimental correlations were developed for each of the preceding parameters mentioned.For the first time, specialized experimental protocols have been developed that guide the infrastructure and processes required to reconstitute analog IHS specimens and conduct geomechanical testing on them. This study also delivered fundamental constitutive data to better understand the geomechanical behavior of IHS reservoir and its permeability evolution during the in-situ recovery processes. Such data can be used to accurately capture the reservoir behavior and increase the efficiency of SAGD operations in IHS reservoirs.

Design of warm solvent injection processes for heterogeneous heavy oil reservoirs: A hybrid workflow of multi-objective optimization and proxy models

Injection of warm solvent vapor into the formation is often considered as a cleaner alternative for heavy oil production. However, the design of relevant operational conditions is challenging, as it involves the optimization of multiple distinct objectives including oil production and solvent-oil-ratio (solvent usage efficiency). This work develops a hybrid optimization framework involving Pareto-based multiple-objective optimization (MOO) techniques for the design of warm solvent injection (WSI) operations in heterogeneous reservoirs. First, a set of synthetic models are constructed based on field data gathered from several typical Athabasca oil sands reservoirs. Models with different heterogeneity settings and the impact of solution gas on WSI production are examined. Next, non-dominated sorting genetic algorithm II (NSGA-II), is employed to optimize two operational parameters, i.e., bottom-hole pressures, based on multiple design objectives. Several proxy models are integrated into the optimization workflow to evaluate the objective functions at reduced computational costs. The performance of the proposed workflow is validated via both homogeneous and heterogeneous cases, and it is demonstrated that a set of Pareto-optimal operating conditions for different reservoir settings can be obtained. The results reveal that the optimal bottom-hole pressure of the producer should be kept at a minimum, while there is more flexibility in the injection bottom-hole pressure. Compared with other conventional optimization strategies, the proposed workflow requires fewer costly simulations and facilitates the optimization of multiple objectives simultaneously. The result demonstrated a great potential for extending the developed MOO framework to optimize operational conditions for other natural resource extraction processes.

Optimization strategies and impact of low oil price on long term SAGD projects

AbstractSteam assisted gravity drainage (SAGD) has been known as a commercially proven high ultimate recovery process for bitumen and heavy crudes. It is an energy intensive process, which is economical when oil price is above certain value. When the oil price goes below the economic threshold of project, steam injection can be decreased or completely stopped for a certain period of time, and can resume thereafter when the condition alters. The objective of this study is to provide comprehensive information about the effect of steam injection interruptions on thermal project performance. An optimization strategy for the SAGD process, in cases where steam injection interruption occurs, is discussed using actual reservoir models of different geological formations. An economical model is used to evaluate operating strategy effect on the net present value (NPV) of the project. The parameters, like shut‐in period, initial steam injection period, etc, are optimized for Athabasca type oil sand reservoirs. The results show several key mechanisms exist in the life cycle of the SAGD process that must be included to reflect the field scale behaviour; otherwise, the mechanistic simplicity of the models could lead to directional and semi‐quantitative conclusions. Among the mechanisms, temperature effect on basic petrophysical properties of reservoir rocks was found to have an important role in the oil recovery, and considerably impacts the results of optimization. When the steam injection is interrupted, an optimum shut‐in period can be determined to maximize the oil recovery. The optimum length of steam injection interruption depends on the initial steam injection period.

Numerical modeling of electromagnetic-based thermal recovery techniques combined with solvent injection

Electromagnetic heating (EMH) has been the focus of ever-increasing theoretical and experimental studies to examine if it can be used to heat geomaterials at the field scale. Bitumen recovery process using EMH technique assisted by solvent injection, such as that used in Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH®) pilot in currently being conducted in the Athabasca oil sands, utilizes radiofrequency waves to generate a moderate amount of heat in the reservoir. In conjunction with dilution effect of solvent the generated thermal energy reduces the viscosity of highly viscous bitumen leading to its mobilization.Electromagnetic (EM) wave propagation in a reservoir is a coupled multiphysics process that involves not only the heat transfer and fluid flow, but also EM field distribution. Currently, a coupled approach is followed by industry using a commercial reservoir simulator (CMG-STARS) and another commercial software (ANSYS-HFSS) or in-house electromagnetic wave solver with different gridding system where both are linked through a property mapping interface (CEMRS or AxHeat). The coupled scheme utilizes the interface to map parameters from two different gridding structures which causes an additional computational load on the simulation process and could be a source of error. This study presents an alternative integrated compositional numerical modeling approach to explore the EM heating phenomena pertinent to fluid flow and heat generation and transfer in oil sand reservoirs in the same grid structure. Energy balance and EM wave propagation are derived using Maxwell's equations in the frequency domain. Then, the newly developed numerical simulator is validated using benchmark problems and used to demonstrate the physics of EM-induced volumetric heat generation in multi-phase oil sand reservoirs. Finally, the developed numerical model is applied in a case study of propane injection along the antenna to achieve oil recovery and the results are compared with the analogous Steam Assisted Gravity Drainage (SAGD).

IDENTIFIKASI CEKUNGAN HIDROKARBON “RAE” BERDASARKAN DATA MAGNETOTELURIK DI DAERAH BULA, MALUKU

The research had been performed using Magnetotelluric to get a 2D model based on variations in resistivity of the subsurface rock. The purpose of this study was to determine the hydrocarbon formation zone. The research method to achieve the research objectives, among others, the first filtering performed on the data with a robust process. This process consists of Robust No Weight, Robust Rho Variance and Ordinary Cohenerency. The second step is done to change the format Selection XPR And Edi. A third inversion resistivity model for the review get a 2D cross section. Based on the findings of the eight data processing methods of measurement points obtained information Magnetotelluric rock formations. Formation hidrokrabon What are the areas is research a reservoir and caprock. The layer in 1600 m – 2700 m depth from the surface which resisvity 12 -33 m assumpted as clay cap. While the layer in 2700 m – 5000 m depth from the surface with high resistivity 41- 250 m is assumpted as oil sands (reservoir). The trap zone of this hidrocarbon formation categorized into structural trap which is the trap of anticline.

Impacts of pore size distribution on gas injection in intraformational water zones in oil sands reservoirs

Intraformational water zones are widely reported in Canadian oil sands fields. In order to pressurize a thief zone, one of the initiatives is to inject gas. However, the evaluation of gas injectivity based on a pore size distribution is still a big challenge. This study provides a multi-scale approach to study the effect of a pore size distribution on gas injectivity in intraformational water zones. The results indicate the gas effective permeability increases in a less complex and more discrete pore network. The enhancement of gas effective permeability with increased gas saturation weakens with higher complexity and lower discreteness of a pore network. A less complex and more discrete pore network better benefits the gas injectivity index.

Numerical modeling on thermoelastoplastic responses of Karamay oil sand reservoir upon steam circulation considering phase change of bitumen

Steam assisted gravity drainage technology has been widely applied to bitumen recovery in Karamay, northwest China. Steam circulation prior to production is designed to establish the thermal inter-well communication, aiming to create a desired initial steady steam chamber. Phenomenologically, the in situ immobile extremely viscous bitumen undergoes the change from solid to fluid state due to rheological fusion, and correspondingly the pay zone displays heated fusion and cold solid regions, within which thermal and mechanical properties differ considerably. To investigate these complex geomechanical responses, the heat transfer with phase change here was treated as a heat conduction with a moving boundary, and the modified Drucker-Prager model with cap plasticity was adopted to depict the mechanical behavior of oil sands. All models here used temperature-dependent constitutive parameters. This contribution coupled heat transfer, phase change and thermoelastoplastic deformation behaviors using a finite element code. A case study on SAGD well pairs using field operation parameters was conducted, and all reservoir information concerning temperature, phase change, deformation, stress and plastic zones were predicted. Temperature, deformation and stress along some typical paths at varying circulation periods were exhibited and discussed. The evolutions of phase change interfaces and plastic zones were provided. The changes of reservoir temperature as well as bitumen fluidity have significant impacts on the geomechanics, characterized by these interesting phenomena such as a maximum reservoir uplift occurring right above injection well, a high stress interference zone with shapes of arch or ellipse, and a plastic zone related to temperature distribution. This paper provides a coupled approach for the evaluation of reservoir thermoelastoplastic responses in steam circulation process, and it can also predict deformation change in permafrost and hydrate formation where transient heat transfer occurs incorporating phase change behavior.

Overburden characterization with formation pore pressure and anisotropic stress field estimation in the Athabasca Basin, Canada

One of the challenges encountered during the life cycle of an oil-sand thermal-production reservoir is the prediction of the formation pore pressure and in situ stress regime during the assessment phase of the reservoir development and, more importantly, during the development phase. We have investigated the state of formation pore pressure and stress in the overburden — represented by the Clearwater Formation, Grand Rapids Formation, and Colorado Group — of a preproduction oil-sands reservoir situated in the Athabasca Basin of Alberta, Canada. Our methodology integrates pressure data from piezometers, stress data from mini-frac (MF), dipole sonic logs, and elastic properties obtained from multicomponent 3D seismic inversion data. It combines the Terzaghi effective stresses with the Schoenberg and Sayers elastic stiffness matrix for horizontal transversely isotropic fractured materials. The total principal stresses (vertical, minimum, and maximum horizontal stresses) are expressed as functions of the normal fracture weakness (anisotropic correction factor), formation pore pressure, seismic data (Lamé constants), and the Biot-Willis coefficient. The effective principal stresses are estimated from the equivalent total principal stresses and the formation pore pressure multiplied by the Biot-Willis coefficient. On all three overburden intervals analysed, the relations between principal stresses indicate a normal stress regime. The estimated total minimum horizontal stress matches the MF values within 10%. The formation pore pressure, along with the 3D seismically derived estimates of the total and effective principal stresses, allows for better assessment of the caprock integrity and for operational savings based on a reduced number of MF tests. It can also be used for stress estimation within the formations hosting aquifers, which is so important for thermal production. Understanding the subsurface on the reservoir area is important for efficient production, but knowing the subsurface of the overburden is equally important for reducing potential issues due to production.

Modeling of reservoir temperature upon preheating in SAGD wells considering phase change of bitumen

Steam circulation prior to production is usually employed to establish inter-well thermal communication and create an expected initial steam chamber in the process of bitumen recovery using steam assisted gravity drainage (SAGD). To realistically evaluate the efficiency of steam circulation, and to find the indicator for terminating the steam circulation and switching to SAGD production, modeling of the temperature propagation considering the bitumen-rich oil sand reservoir properties and oilfield operations is required. This study proposed two new modified methodologies, including an analytical model as well as a numerical model, in which the latent heat effect caused by the phase change of bitumen was involved for thermo-phase change coupled analyses. The modeling was conducted for a real SAGD steam circulation project in an oilfield located in Karamay, northwest of China, using oilfield operation parameters and thermo-dynamical properties obtained from laboratory tests. The models can predict the temperature propagation and bitumen phase change behavior in the domain encompassing dual wells. In general, the predicted results obtained from both analytical and numerical approaches agree well with those in published articles in terms of the cooling time derived from temperature falloff tests and inter-well midpoint temperature. The modeling draws major conclusions that the temperature drops rapidly with the distance to wellbore in the fusion zone, but decreases slowly in the solid zone. The heat flux on wellbore exhibits an exponential reduction in the beginning, but ultimately tends to be a constant. The moving speed of phase change interface decreases with injection time, and finally increases up to only a short distance. The inter-well midpoint temperature is heated to exceed the threshold temperature, and the whole inter-well area is ultimately occupied by the fusion zone. These findings not only can provide a criterion for evaluating the efficiency of steam circulation and an indicator for terminating the steam circulation and switching to production, but also the approaches proposed may be used to analyze these heat injection and phase change problems occurring in other types of oil and gas-rich reservoirs like the natural gas hydrate formation.

Field-Scale Modeling of Hybrid Steam and In-Situ-Combustion Recovery Process in Oil-Sands Reservoirs Using Dynamic Gridding

Summary Hybrid steam and in-situ-combustion (ISC) recovery processes have shown advantages over pure steam injection for recovery of oil-sands resources, particularly with respect to reducing costs and lowering requirements for water and natural-gas use. However, it has been very challenging to predict the field performance of hybrid steam-and-combustion processes with a reasonable degree of confidence. Usually, a combustion front has a thickness of only a few inches and high-resolution grids are required to capture steep temperature, saturation, and fluid-composition gradients in the vicinity of the combustion front. Using high-resolution, fine grids (FGs) in an entire reservoir to improve the accuracy of simulation can involve excessive computation time and, therefore, might be impractical for field-scale modeling. It is important to have a robust simulation tool to accurately predict reservoir performance without compromising the computational efficiency. In this work, numerical modeling of a hybrid steam-and-combustion recovery process was performed in a typical Athabasca Oil Sands reservoir. A comprehensive reaction-kinetics model derived from laboratory results was incorporated to represent the complex chemical reactions in the combustion process. This hybrid recovery process used oxygen-enriched air coinjection after several years of a steam-assisted-gravity-drainage (SAGD) operation. In the numerical model, safe limits were set on producing well temperature and oxygen content of the produced fluids. The initial grid size in the numerical model was at the centimeter scale, resulting in long run time, so to improve the computational efficiency a dynamic-gridding (DG) feature was applied. Parameters for controlling the creation of a dynamic grid and subsequently reverting back to a coarse grid have been examined to properly trigger the DG feature in the model. Once the optimized DG parameters were determined, operating parameters were investigated, including well configuration, oxygen (O2) concentration, and steam concentration. Comparisons were made between SAGD and hybrid steam/combustion processes in terms of cumulative water (steam) injection, cumulative oil production, and a cumulative steam/oil ratio (cSOR). By comparing the simulation results from an FG model and a DG model, we found that a temperature gradient is the best criterion to use for controlling DG compared to fluid-saturation and/or composition criteria. The threshold value for the temperature criterion was determined to be 35°C. The model locates the FGs in close proximity to the combustion front where the temperature and fluid-saturation gradients are the steepest and it places the coarse gridblocks elsewhere in the model. Comparisons are made between the computation time and the accuracy of simulation, and they demonstrate that dynamic grid amalgamation reduces the computation time significantly while maintaining reasonable computation accuracy of the simulation. Different well configurations affect O2-injection timing, combustion-front sweep efficiency and, therefore, the overall performance. The suggested O2 concentration in the hybrid process is between 10 and 20%. Steam can also be replaced with nitrogen (N2) to further improve the performance. For all simulation scenarios considered in this work, the cSOR in the hybrid process was improved, illustrating the main advantage of the hybrid approach over steam-only injection as in SAGD.

Investigation on the flow-induced corrosion and degradation behavior of underground J55 pipe in a water production well in the Athabasca oil sands reservoir

The corrosion behavior of J55 carbon steel pipe was investigated in a water production well environment in the Athabasca oil sands reservoir. The corrosion morphologies and the chemical compositions of corrosion products were examined by surface analysis techniques. The protection performance of the formed corrosion scales was evaluated using electrochemical measurements. The results show that severe erosion corrosion occurs on the inner wall of the pipe and causes a significant thinning, which is the dominant reason for the pipe failure. Likewise, the failure of the thread zone is originated from the severe corrosion of inner wall as well. Localized corrosion of carbon steel occurs in the welding zone because of the galvanic effect between stainless steel and carbon steel. Furthermore, the distributions of corrosion products on the inner wall are notably affected by the flow. Dense and thick Ca-containing corrosion scales act as a physical barrier layer and prevent the steel from further corrosion, whereas localized corrosion occurs in the regions with loose and thin corrosion scales.

An analytical model of hydraulic dilation area for Karamay oil sand reservoir under water injection in SAGD wells

Based on the mechanical mechanisms of shear and tensile parting dilations, water injection into oil sand reservoirs prior to steam circulation can effectively establish inter-well hydraulic communication and create an expected initial steam chamber. To quantitatively evaluate the effectiveness of water injection, this paper defined some novel concepts including the effective permeability to injection water, hydraulic dilation area (HDA) as well as radius (HDR) incorporating longitudinal and lateral hydraulic dilation radii (HDRa and HDRb) for a more intuitive description of the hydraulic dilation behavior. An analytical model of hydraulic dilation area under water injection was established considering the interference effects of mudstone cap and base rocks, effective permeability to injection water, SAGD well geometry and operation parameters. The figures of analytical results are exhibited for evaluating the hydraulic dilation response under given geometry and flow properties and for finding an achievable path for improving the HDR and HDA through artificial operations for an operator. Major conclusions through an application on the wellpair A-2 in area A of Karamay Fengcheng oil field can be drawn that the HDR and HDA can be improved by increasing the injection pressure or decreasing the fluid viscosity and injection rate of unit well length. A higher effective permeability to injection water induced by a larger volumetric expansion is beneficial to the HDR and HDA. A larger wellbore radius, a closer distance between P well and base rock, and a closer well distance designed in the drilling process are advantageous to the HDR and HDA. The HDA and HDR are essentially controlled by the volumetric dilation resulting from pressure transfer capability and pressure interference by mudstones and SAGD wells. These findings provide an analytical approach for evaluating the efficiency of water injection, and offer some suggestions to improve the HDA by artificial operations for engineers.

Evaluation of elastic property changes in Karamay oil sand reservoir during thermal stimulation

AbstractTo obtain a good evaluation of oil sand reservoir deformation and its induced ground subsidence during thermal simulation, elastic property changes with reservoir temperature are desired. The Karamay oil sand was viewed as a composite geomaterial consisting of bitumen as matrix and grains as inclusion. The elastic properties of bitumen were expressed as a function of temperature and time, and the Eshelby, Mori–Tanaka, and differential methods were used to write the elastic properties of oil sand as a function of temperature and time. An equivalent static time was proposed to eliminate the effect of time. A temperature transform was established according to experimental data. The relation of elastic properties and temperature was applied on a field practice of steam circulation. The elastic properties in any reservoir position were given at varying circulation time and concluded that the elastic modulus drops from 663 to 360 MPa, and the Poisson ratio increases from 0.3 to 0.415 during circulation. The elastic deformation mechanisms for Karamay sand‐in‐bitumen and Canadian bitumen‐in‐sand oil sands were analyzed according to experimental data. Three possible deformation modes for sand‐in‐bitumen oil sands were exhibited, considering whether the intergranular bitumen is squeezed out and the grains are crushed.

Stable isotopes of clay minerals from autoclave tests of oil sands: Implications for clay formation during steaming of Alberta Clearwater oil sands

In an effort to evaluate mineral-water isotopic exchange during cyclic steam stimulation (CSS), solutions and <2 μm berthierine-dominated solids from the Clearwater Formation oil sands of Alberta, Canada were analyzed for stable isotope compositions before and after reaction in autoclaves for 1008 h at 250 °C. There was no significant change in solution δ18O and δ2H, which is consistent with the high water/mineral ratio used in the experiments. The solids showed a marked decrease in both δ18O and δ2H following the experiments. Pre-run solids have δ18O of +9.5 to +12.9‰ and δ2H of −114 to −113‰, whereas post-run solids have δ18O of −4.7 to +2.1‰ and δ2H of −147 to −128‰. Neither oxygen- nor hydrogen-isotope equilibrium was established between the solids and the solutions. Calculation suggests that oxygen-isotope exchange (44–58%) was greater between the solids and the solutions than was the case for hydrogen isotopes (23–50%). We propose that this behaviour resulted from partial inheritance of the pre-run berthierine structure during formation of the post-run smectite, chlorite-smectite and chlorite. This process confounds the use of clay mineral stable isotope compositions as a temperature indicator of in situ steam/steam condensate interaction with oil-sands reservoirs. The results also suggest an additional mechanism by which new clay minerals can be formed during CSS-related, artificial diagenesis.