Oil Sand Reservoirs Research Articles

In situ stress field in the Athabasca oil sands deposits: Field measurement, stress-field modeling, and engineering implications

In situ stress is one of the key engineering parameters that ensures caprock integrity in steam-assisted gravity drainage (SAGD) operations. Massive steam injections during an SAGD operation leads to significant changes in the pore pressure, temperature, stress, and volumetric strain in the rock formations. These changes trigger deformation and stress redistribution in the overburdened strata, which could lead to a containment breach of the caprock through shear or tensile failure. To ensure subsurface steam containment, both to satisfy public safety considerations and instill confidence that the steam containment will continue over the necessary timescales, the Alberta government requires every SAGD operator to measure the in situ stress conditions in the oil sands reservoir and its caprock. Minifrac test is a suggested method that can measure the minimum principal stress with high confidence. A safety factor (SF) of 80% is used to determine the maximum operation pressure (MOP) for safe SAGD operations; in other words, MOP = 80%*σmin, where σmin is the minimum principal stress at the base of the caprock. In most cases, this 80% SF safeguards the SAGD injection pressure to always remain lower than the σmin at the base of the caprock, ensuring that no tensile fractures are initiated at the caprock.In this study, we compiled a database containing in excess of 100 minifrac datasets across the Athabasca oil sands region and constructed an in situ stress map. Based on our in situ stress dataset, we developed a quantitative risk model to analyze the effects of uncertainties on the probability of exceedance (i.e., the probability that the MOP exceeds the fracture pressure at the base of the caprock). The risk model involves defining probability distributions to quantify the uncertainties at the shallowest depth and minimum stress gradient. The output of the risk model was a set of predictions of exceedance probabilities, which were computed using Monte Carlo simulations. Through a statistical analysis of this in situ database and risk-based simulation analysis, this study demonstrates the reliability of a SF of 80%.

Optimization of the Operating Envelope of a Hot-Solvent Injection Process for Bitumen Recovery

Summary Over the past two decades, there have been considerable efforts in the industry evaluating the use of pure solvents or solvent-assisted processes for the development of oil sands reservoirs in Canada. Replacement of conventional steam-based recovery with solvents can minimize the energy intensity of bitumen recovery and reduce the environmental footprint of the operation. Moreover, solvent-based processes can reduce the capital cost of handling large volumes of water and minimize water usage. In-situ heating techniques were also studied as an alternative means of delivering energy into the oil reservoirs while reducing the cost of surface heating facilities. One of the available in-situ heating options is electric resistive heaters (ERHs) deployed in the horizontal wells. This study examines many different aspects of bitumen recovery and process optimization by injection of superheated solvents along with the application of ERHs. New economic metrics were introduced to optimize the subsurface process performance. The study revealed that while ERH could help vaporize the injected solvents in the injector well, the induced solvent reflux subject to ERH installation in producer wells is a subeconomic strategy. Therefore, after the establishment of the initial communication between the well pairs, the producer heater is recommended to be turned off. Preheating modeling showed that the producer heater power rating could be ~1.3 kW/m. The process was optimized for pure butane and propane injection processes. The operating pressure range was found to be 500–800 kPa for pure butane and 1700–2300 kPa for pure propane in the reservoir of interest. The injector heater was set to deliver solvent at 250°C into the reservoir during the process, requiring ~1.2 kW/m power for butane and ~0.8 kW/m for propane vaporization. Finally, the requirement of water coinjection, well spacing, and uncertainty to reservoir attributes were also studied.

Experimental study on deformation and permeability enhancement of oil sand reservoir by hydraulic fracturing technique under true triaxial stress

AbstractHydraulic fracturing technology is often applied to form a permeable zone for geothermal resources near the borehole in tight reservoirs to improve the permeability and extraction efficiency. Steam or hot water is often injected to dissolve the heavy oil to increase its fluidity during the extraction. As the numerical simulation or two‐dimensional physical experiments have great limitations to simulate hydraulic fracturing of oil sand reservoirs, this study conducted a large‐scale three‐dimensional physical simulation experimental study of hydraulic fracturing with high temperature of oil sand reservoir under true triaxial stress state and monitored the water pressure change at various points inside the box during the hydraulic fracturing by laying pressure sensors. The experimental results showed that the hydraulic breakdown pressure of oil sands increases with the increase in σ2, which is related to the increase in σ2 limiting the fracture growth and the decrease in effective stress during fluid injection. To better describe the breakdown pressure variation, we developed a new oil sand breakdown pressure prediction model considering the true triaxial stress condition, which showed a good prediction effect. Due to the formation of fluid hysteresis zone during the fracture expansion, the fluid pressure recorded by the internal pressure sensor lagged behind the injection pressure. Hydraulic fracturing produced shear fractures inside the oil sands under low σ2 conditions and tensile fractures under high σ2 conditions, and the permeability was significantly increased after hydraulic fracturing, in which the shear fractures formed under low σ2 showed a better permeability enhancement effect than the tensile fractures formed under high σ2. The research and analysis in this study can provide reasonable suggestions and feasibility analysis for the design and construction of heavy oil extraction.

Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells

Mudstone stringers in an oil sand reservoir can significantly affect the propagation of the steam chamber in the process of steam-assisted gravity drainage (SAGD). The micro-fracturing by water injection in strongly heterogeneous oil sands can result in these problems such as hard stringer breakthrough and aggravating heterogeneity. This paper proposed a comprehensive numerical model for conventional SAGD wells and vertical well-assisted SAGD (VWA-SAGD) wells to predict the coupled thermo-hydro-mechanical responses under hot water injection in a typical Karamay oil sand reservoir with two stringers, considering skeleton shear dilation, the ''phase change'' of bitumen, formation heterogeneity, the permeability evolution induced by elastoplastic deformations, and the theory of heat and mass transfer. Major conclusions were drawn that there are three relatively narrow separate transition zones effectively heated around the SAGD wells and vertical well. The vertical well makes about 0.5 MPa increase to the pore pressure of the reservoir embedded with mudstone stringers in vertical directions and rises by about 0.6 MPa for the reservoir pore pressure above the upper stringer to reduce the pore pressure differential along the wellbore. Water injection-induced ultimate stress states can't reach the shear failure line under field operations, so the shear dilation can't be induced. The thermoporoelastic deformation determines whole reservoir deformation. The reservoir between the two stringers contributes to most of the caprock uplift. The VWA-SAGD technique can improve the porosity by about 1% in the whole vertical direction and reduce the anisotropy of porosity along the wellbore, which is beneficial to the uniform and fast propagation of the steam chamber in subsequent preheating and production stages. These findings can be employed to accurately predict the temperature, pore pressure, stress/displacement, and porosity evolutions for the field engineers to properly evaluate the uplift of reservoir and caprock, oil output changes, and heat utilization efficiency.

Simulation of SAGD with FCD (Flow Control Device) for Oil Sand Reservoirs in Canada

본 연구에서는 캐나다 오일샌드 저류층에서 SAGD(Steam Assisted Gravity Drainage) 공법 수행 시 FCD(Flow Control Device)의 작동 원리를 분석하고 저류층 생산 시뮬레이션을 통해 그 효과를 확인하였다. FCD는 유체 통과 시 추가적인 압력 강하를 유도하여 유정 전체에 걸쳐 균등한 유동을 만들어 생산 효율을 향상할 수 있다. FCD의 종류별 메커니즘과 장단점을 분석하였으며 오일샌드 저류층 모델 시뮬레이션을 통해 SAGD 공법 수행 시 FCD의 효과를 확인했다. 시뮬레이션 수행 결과, 수평 생산정에 FCD를 적용하였을 경우 누적 오일 생산량은 약 9% 증가하였으며 cSOR(cumulative Steam Oil Ratio)은 약 17% 감소하여 FCD의 SAGD 공법 효율성 증대 효과를 확인하였다. 또한, FCD 설치 구간 및 시점에 따른 영향을 분석하여 FCD의 현장 적용 가능성을 제시하였다.

Prestack Bayesian lithofacies classification technology and application in oil-sand reservoir prediction

The oil-sand reservoirs in the Athabasca region of Canada are estuarine deposits affected by tides. The strata are inclined, and the interlayers are well-developed. Accurate spatial characterization of reservoirs and interlayers is the key for efficient oil-sand development. In this paper, we have used prestack Bayesian lithofacies classification technology to predict the spatial distribution characteristics of reservoirs and interlayers of oil-sand reservoirs. We first use log lithofacies data as a label, select lithofacies sensitive elastic parameters to make a lithofacies classification probability distribution crossplot, and then project the lithofacies-sensitive elastic parameter volumes into the lithofacies classification probability distribution crossplot. Finally, we predict the spatial probability distribution of different lithofacies. Probabilistic characterization can enhance the recognition of transitional lithology and thin layers in the inversion results, reduce the uncertainty in the prediction of reservoirs and interlayers, and significantly improve the prediction accuracy of reservoirs and interlayers. The field application results in the Kinosis study area indicate that the probability volume predicted by this technology can distinguish interlayers greater than 1 m thick and identify interlayers greater than 2 m thick, which meets the technical requirements of oil-sand steam-assisted gravity drainage development.

Visualization Experimental Study on Well Spacing Optimization of SAGD with a Combination of Vertical and Horizontal Wells.

For oil sand reservoirs, the steam-assisted gravity drainage (SAGD) technique is one of the most efficient thermal recovery technologies. However, the high oil viscosity and the severe heat loss seriously affect the production effect of SAGD in developing thin oil sand reservoirs by the traditional SAGD technology. Therefore, it is essential to improve the SAGD technology to enhance the recovery of the thin oil sand reservoir. In this paper, SAGD with a combination of vertical and horizontal well (VH-SAGD) technology was adopted, and the influence of different well spacings (horizontal distance between vertical steam injection wells and horizontal production wells) on the development of steam chambers was investigated. By the similarity criterion, the experimental parameters were obtained. After that, an improved 2D visualization physical model was designed with 9 × 9 high-precision thermocouples installed inside the device to monitor the real-time temperature. This experimental physical model can not only accurately capture the temperature distribution but also display the continuous change process of the chamber inside the model by the visible window. Finally, different well spacing cases (10, 15, and 20 cm) were tested to observe the development of the steam chamber and analyze the production data. Both the temperature distribution and visual window showed that the steam chamber has four obvious stages, and reasonable well spacing can promote the development of the steam chamber. When the well spacing is relatively small, the unswept area of the cold oil on both sides is large, and the area of the steam chamber overlaps more. When the well spacing is relatively moderate, the steam chamber is the most complete and the recovery factor is the highest. When the well spacing is relatively large, although the unswept area of the cold oil on both sides is small, the middle cold oil area is larger than the previous two groups. Therefore, the best well spacing for oil sand reservoirs of about 15 m thickness is 15–20 m, where the VH-SAGD method has a better displacement effect and higher oil recovery. The experimental conclusions can provide theoretical support for the production of thin oil sand reservoirs.

Quantitative Characterization of Tidal Couplets in Oil Sands Reservoir, the Upper McMurray Formation, Northeastern Alberta, Canada

AbstractThe McMurray Formation, NE Alberta, Canada, is one of the most significant bitumen bearing deposits worldwide. This formation deposited and reworked in fluvial, tidal, or estuarine environments results in a huge number of tidal couplets (TCs) which is consisted of mm-cm scale sandy and muddy interlayers. These couplets not only increase the geologic heterogeneity of the oil sand reservoir but also make it hard to predict the performance of in situ thermal processes. In this paper, based on literatures, lab analysis, core photos, logging, and drilling data, a quantitative characterization procedure for mm-cm scale tidal couplets was proposed. This procedure, which includes identification, classification, quantitative description, and spatial distribution prediction, was presented. Five parameters, thickness, mud volume, laminae frequency, spatial scale, and effective petrophysical properties, were selected to describe the TCs quantitatively. To show the procedure practically, TCs in the oil sand reservoir of McMurray Formation, Mackay River Project, and CNPC, were selected to demonstrate this procedure. The results indicate that the TCs are in mm-cm thickness, densely clustered, and in a variety of geometries. Based on geologic origins, these couplets were divided into four types: tidal bar couplets (TBCs), sand bar couplets (SBCs), mix flat couplets (MFCs), and tidal channel couplets (TCCs). The thickness, mud volume, and frequency were calculated by mathematical morphological processed core photos. The spatial scale of TCs was estimated by high-density well correlations. The effective petrophysical properties were estimated by bedding scale modeling and property modeling via REV. Finally, the spatial distribution of TCs was predicted by object-based modeling.

Experimental Comparative Investigation of Hot Solvent/Steam-Assisted Gravity Drainage in Oil Sand Reservoirs.

Hot solvent-assisted gravity drainage (HS-AGD) is an effective way to exploit oil sands and heavy oil both economically and environmentally. The visualized microscopic seepage experiments and two-dimensional (2-D) macroscopic simulation experiments of HS-AGD are carried out, and the results are compared with that of steam-assisted gravity drainage (SAGD) in detail for the first time in order to compare their development effects of the oil sand reservoir. MacKay River oil sand bitumen is taken as an oil sample in the experiments, with n-hexane as the solvent. Micro seepage characteristics of the hot solvent and steam and the remaining oil distribution of the solvent and steam drive are investigated through microseepage experiments. The expanding process of the solvent/steam chamber and production performance of HS-SAGD and SAGD are investigated through macrosimulation experiments. The study found that the sweep efficiency of hot solvent is higher than that of steam at the same temperature due to the small interfacial tension between the condensed solvent and heated bitumen. Due to the severe gravity segregation, the steam accumulated at the top of the model during the 2-D physical simulation experiment, which results in the huge heat loss at the top of the model. The temperature of the steam chamber is significantly lower than that of the solvent chamber. The oil recovery of 200 °C hot solvent vapor is twice as much as that of 300 °C steam owing to the different drainage mechanisms of the HS-AGD and SAGD. In SAGD, only heat transfer reduces the viscosity of oil sand bitumen. The components of oil produced in SAGD have little difference compared with that of the original bitumen. In HS-AGD, both mass transfer and the sensible heat transfer reduce the viscosity of oil sand bitumen. The in situ asphaltene precipitation induced by heated-solvent extraction also upgrades the bitumen. The results of component analysis show that in HS-AGD, the content of heavy components in the oil sand bitumen is obviously reduced. This paper aims to reveal the oil drainage mechanism of HS-AGD and SAGD from the macroscopic and microscopic view and to provide theoretical guidance for the field application of this technology.

Experimental Study on Well Placement Optimization for Steam-Assisted Gravity Drainage to Enhance Recovery of Thin Layer Oil Sand Reservoirs

SAGD (steam-assisted gravity drainage) technique is one of the most efficient thermal recovery technologies for exploiting Mackay River thin layer oil sand reservoirs. However, when making use of the traditional SAGD technique (the production and injection well are located on the same axis with the horizontal well spacing of 0 m), the steam chamber development is usually insufficient because of the high longitudinal sweep rate of steam, which seriously influences the SAGD performance for developing thin layer oil sand reservoirs especially. It is extremely important to find an economical and practicable method to promote the steam chamber development in thin oil sand reservoirs in the process of SAGD production; optimizing well placement is a reliable method. In this paper, an improved well placement method is proposed to enhance production performance of traditional SAGD, which is changing the horizontal well spacing to place the production well below of the side of the injection well (two wells are not located on the same axis). Three groups of 2D visualization experiments with different horizontal distances between two wells (0 cm, 10 cm, and 20 cm) were carried out, respectively, to observe the development and change of the steam chamber development, and to explore the EOR mechanisms. On the 2D experiment basis, optimal horizontal distance was selected to perform 3D physical simulation experiment to study and verity the production mechanism systematically. The results of 2D visualization experiment showed that the final oil recoveries of experimental groups with 10 cm and 20 cm horizontal distances were 7.6% and 2.3% higher than those of traditional SGAD (horizontal distance was 0 cm), respectively. Combined with 3D experimental results, the change in the horizontal relative position of two wells makes the steam first spread laterally between injecting and producing wells; thus, the lateral development of the steam chamber was promoted, and changes of temperature field also display that the lateral sweep area of steam was increased obviously and the form of steam chamber is changed. Meanwhile, the generation of appropriate horizontal well spacing can combine the effect of steam displacement and gravity drainage better and improve the sweep efficiency of steam. Nevertheless, the overlarge horizontal well spacing will also hinder the steam chamber development because the strength of steam overlap is weakened. Furthermore, the findings of this study help for better understanding that changing the horizontal well spacing can promote the lateral development of steam chamber, which can be used to enhance the oil recovery of thin layer oil sand reservoirs especially.

The significance of operating parameters on electromagnetic-solvent bitumen recovery process

Current thermal bitumen recovery processes are highly vulnerable to the low oil price environments. Solvents-aided processes could be a promising option over Steam Assisted Gravity Drainage (SAGD), with the potential for lowered initial capital investment and reduced operating costs. Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH®) technology is a novel process where electromagnetic waves and hydrocarbon solvents are employed for bitumen recovery.This study examines the significance of operating parameters on the electromagnetic-solvent process when the injected solvent is either pure propane or pure butane. The effect of several parameters, including operating pressure and applied power on various response surface models, were examined using Design of Experiment and multivariate regression analysis. Results show that the operating pressure is the main governing factor for the selection of the solvent type, while other parameters such as applied power are less significant. Generally, it is recommended to operate the process at native reservoir pressure to minimize the risk of loss of expensive solvents into the thief zones.Lack of reservoir containment (leakiness) is another important factor in the process design, especially when prescribing an operating pressure regime considerably different than that of the surrounding impairments. Due to a wide variation of the in-situ bitumen viscosity in different oil sands reservoirs, each bitumen type requires a different solvent mole fraction to mobilize the bitumen. For the type of bitumen used in this study, the optimum pressure range for butane was found to be around 800–1000 kPa, and for propane injection, around 2400–2600 kPa.

Subsurface Migration of Methane From Oil Sands Thermal Recovery Operations

AbstractSteam injection into oil sands reservoirs for bitumen extraction leads to the in situ generation of gases (mainly methane). Many oil sands formations have permeable cap rocks that may allow these gases to migrate to the overlying formations and pose environmental challenges to the groundwater. We present a detailed analysis of the long‐term fate of the in situ generated gases over the course of thermal oil recovery operations. The impacts of capillary barriers on upward migration of the in situ generated gases are quantified. Our findings reveal that the upward migration of gases over a 100‐year period in formations with continuous flow barriers with a permeability of less than ∼1 × 10−18 m2 is negligible. However, for formations with discontinuous flow barriers, the migrated gas can potentially leak to the surface depending on the capillary entry pressure of the preferential pathways (e.g., sand layers). In this case, the upward migration is primarily controlled by high permeability pathways. It was found that the migrated gas is effectively trapped by the residual and dissolution trapping mechanisms, and the gas migration to the overlying formations is prevented or significantly reduced by capillary pressure of sand layers. The results indicate that the migrated gas to the shallow groundwater is primarily comprised of methane and is free of CO2 and H2S. These results provide valuable insights into the long‐term fate of these gases in thermal oil recovery operations. They also offer potential opportunities for the development of regulatory frameworks and screening considerations for caprock/seal integrity/risk assessments.

Temperature-Dependent Irreducible Water Trapping in Heavy-Oil Reservoirs

SummaryTemperature-dependent irreducible water saturation has great implications for heavy-oil production. Especially in processes using thermal methods, the irreducible water saturation varies significantly when temperature rises from the initial reservoir condition to the temperature of injected hot fluids. In this work, the irreducible water saturation retained in a heavy-oil/oil-sands reservoir has been theoretically analyzed as a function of temperature in the view of thermodynamics. This analysis involves oil/water interactions, thermodynamic stability, pendular rings between particles, and a dense random-packing theory. The temperature-dependent irreducible water saturation in two heavy-oil reservoir samples (Coalinga and Huntington Beach) and two oil-sands reservoir samples (Cat Canyon and Peace River) have been analyzed using an oil/water/silica system. The computed results have been compared with published experimental data. The good agreements of the comparison demonstrate the feasibility of the proposed analysis to describe the irreducible water saturation in a heavy-oil/oil-sands reservoir up to 300°C. Through these analyses, the theoretical understandings of temperature-dependent irreducible water in a heavy-oil/oil-sands reservoir have been provided. As temperature increases, the mutual water/oil solubilities are increased by enhanced molecular interactions, as well as the surface energy at an oil/water connecting interface. As a result, the oil/water interfacial tension (IFT) decreases, which diminishes the contact angle and enlarges a water-filled pendular ring between particles at elevated temperatures. Thus, the irreducible water saturation is increased by the enlarged pendular rings in a dense packing porous medium. In addition, this study demonstrates the possibilities to alter the irreducible water saturation appropriately in a heavy-oil/oil-sands reservoir to enhance oil recovery, decrease water cut, save costs of surface oil/water separation, and reduce heat consumption.

An Integrated Analysis for Post Hydraulic Fracturing Production Forecast in Conventional Oil Sand Reservoir

Hydraulic fracturing is one of the stimulation treatment in oil and gas well by creating a fractured through a proppant injection to the formation. A most critical problem in the actual oil and gas industry is that the fracturing engineers could not forecast approximately post-production performance after fracturing the job, which is a severe problem. This problem phenomenon has occurred in some cases and significantly impacts production such as oversizing or lower sizing of pumping rate setting. Integrated analysis for post job hydraulic fracturing production based on the geometry model iteration and Productivity Index (PI) comparison in the conventional oil sand reservoir is simply a method to analyze and forecast approximately incremental production performance. The fractured software generates a fractured geometry model that considers half-length of fractured parameters, width in front of perforation, average width, fractured height, and pressure net. Then we compare the Productivity Index's prediction value through the method of Cinco-Ley, Samaniego and Dominguez. A case study in the well of TM#2 (conventional oil sand reservoir) was conducted as the comprehensive study to provide the data and proceed analysis for production forecast. We found that the geometry model and iteration of PKN 2D method generated a small fractured geometry model compare to fracCADE software. The cooperation between PKN 2D method and Cinco-Ley, Samaniego, and Dominguez concept successfully predict post-production forecast. This concept could be proposed as a quick look measurement for production scenarios to overcome pump sizing.

Comparison of different machine learning algorithms for predicting the SAGD production performance

Steam Assisted Gravity Drainage (SAGD) is a typical thermal recovery process consisting of an upper horizontal injector and a lower horizontal producer, which heats and removes bitumen from oil sands deposits by steam. Serious research has been conducted on data-driven models to analyze the cumulative production performance of the SAGD process, and one of the most common machine learning methods utilized is the Artificial Neural Network (ANN). It is important to test other machine learning methods like Extreme Gradient Boosting (XGBoost) and Light Gradient Boosting Machine (LightGBM) in different conditions of data samples. In this paper, a series of SAGD models based on typical oil sands reservoir properties and operational conditions were constructed. Three different data groups were simulated by the Computer Modelling Group (CMG) thermal software STARS. Three different machine learning methods, including ANN, XGBoost, and LightGBM were constructed to calibrate a relationship between the input parameters and the output parameters in the different simulated data groups. A series of final models were tested and compared. The conclusion shows that data-driven training improves as the number and randomness of the data samples increase, and the LightGBM has the best prediction performance with such data samples. The ANN model may be the best choice with data samples of the worst randomness.

Vertical-well-assisted SAGD dilation process in heterogeneous super-heavy oil reservoirs: Numerical simulations

PetroChina’s Karamay heavy oil reservoirs mostly comprise Jurassic deposits of braided fluvial facies that have a low porosity, extremely high bitumen viscosity, and strong heterogeneities within the reservoir. Steam-assisted gravity drainage (SAGD) dilation start-up has been proven an efficient reservoir geomechanical stimulation method as it shortens the steam circulation time, reduces steam usage, and increases the oil production rates. This method worked well on relatively good-quality oil sand reservoirs. However, for reservoirs with heterogeneous reservoir properties along the SAGD well, field well production data indicated the presence of non-uniform steam chambers in post-dilation SAGD wells. Enhanced dilation methods, such as vertical-well-assisted SAGD dilation (VW-SAGD-Dilation) are have been used, and field pilot tests have yielded promising results. This reservoir stimulation process utilizes one or more vertical wells beside the SAGD well to initiate the formation of dilation zones that connect to the dilation zone formed during the conventional SAGD dilation start-up. Compared with the normal SAGD dilation start-up, this composite dilation process creates a uniform dilation zone along the SAGD well, thus improving the thermal conformance and well productivity. The vertical well and SAGD well are connected by this composite dilation zone, which enables the combined use of the SAGD process and cyclic steam stimulation process. This paper presents our understanding and numerical case studies of this enhanced dilation strategy. The well production data from the post-dilation wells were positive (uniform steam chamber growth and higher oil rate), which highlights the promising potential of using geomechanical dilation as a reservoir stimulation method to create a large stimulated reservoir volume in heterogeneous super-heavy oil reservoirs.

Application of back-propagation neural networks in the distribution of oil sand reservoirs\u2014a case study from the western slope of the Songliao Basin, China

High-quality hydrocarbon source rocks are present in the upper Cretaceous layer in the western slope of the Songliao Basin. Oil and gas have accumulated in these rocks at the shallow edge of the basin, which has led to the formation of oil sand resources. This study uses the back-propagation (BP) neural network method to predict the distribution of oil sand reservoirs and is the first study of its kind in China. First, based on the basic data collected by core sample, well log and geochemical analyses, and the reasonable selection of samples, the cores are divided into mudstone, siltstone, fine sandstone, medium sandstone, and sand, according to lithology. Second, a three-layer BP neural network model is constructed with two hidden S-type layers and one linear output layer. Third, through a comparison of the effect of different numbers of training sessions of the sample data, we demonstrate that the accuracy of the model can be increased to 90% after training the network 100,000 times. Then, the log-derived data of rocks with unknown lithologies are input into the neural network to predict whether they contain oil sands. We show that the BP neural network method can predict the distribution of oil sand reservoirs in the target horizon of the study area, and the results are consistent with research results on the corresponding sand reservoirs and sedimentary facies. Thus, we conclude that it is feasible to use the BP neural network method to predict the distribution of oil sand reservoirs.

Identifying Reservoir Features via iSOR Response Behaviour

To extract viscous bitumen from oil sands reservoirs, steam is injected into the formation to lower the bitumen’s viscosity enabling sufficient mobility for its production to the surface. Steam-assisted gravity drainage (SAGD) is the preferred process for Athabasca oil sands reservoirs but its performance suffers in heterogeneous reservoirs leading to an elevated steam-to-oil ratio (SOR) above that which would be observed in a clean oil sands reservoir. This implies that the SOR could be used as a signature to understand the nature of heterogeneities or other features in reservoirs. In the research reported here, the use of the SOR as a signal to provide information on the heterogeneity of the reservoir is explored. The analysis conducted on prototypical reservoirs reveals that the instantaneous SOR (iSOR) can be used to identify reservoir features. The results show that the iSOR profile exhibits specific signatures that can be used to identify when the steam chamber reaches the top of the formation, a lean zone, a top gas zone, and shale layers.

Influence of temperature-viscosity behaviors of Karamay oil sand bitumen on the geomechanics in the SAGD process

Viscosity-temperature behavior is important for the thermal recovery of bitumen: firstly, it is a criterion for evaluating the evolution of mobility with temperature, which affects oil production; and secondly, it determines the role of bitumen in the geomechanics in oil sand reservoir. To quantitatively evaluate the effect of temperature on dynamic viscosity, some experimental and modeling investigations were conducted. The viscosity of Karamay oil sand bitumen over a temperature range of 20 ~ 350 °C was measured, and the viscosity-temperature behavior was simulated by a modified three-parameter model using the least square method. It was found that the viscosity of Karamay bitumen drops sharply with the temperature increase. The effect of bitumen viscosity on the geomechanics in the SAGD process was discussed in terms of reservoir deformation, fluid flow, and heat transfer behaviors. The reservoir deformation, fluid flow, and heat transfer behaviors at varying bitumen viscosity show significant differences in the drained, partially drained, and undrained geomechanical zones. The structure’s bulk modulus, effective stress, and volumetric strain in the drained zone are lower than those in the undrained zone; while the oil mobility and Peclet number show the opposite tendency. The changes in the structure’s bulk modulus, effective stress, volumetric strain, oil mobility, and Peclet number due to the phase change of bitumen increase with the increase of oil saturation. This study can provide the field engineers with guidance for the design of a proper oil recovery scheme before its implementation, and with a useful relation for the coupled thermal-flow-structure analyses.

Sodium nanofluid for efficient oil recovery in heavy oil and oil sand reservoirs

Sodium nanofluid for efficient oil recovery in heavy oil and oil sand reservoirs