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Results
Abstract Steam-assisted gravity drainage (SAGD) has proved to be a technically and commercially successful methodology for recovering heavy-oil in Canada. At present, there are 22 commercial SAGD projects with over 300 pads and 2,700 well pairs, contributing to nearly 1.4 million bbl/day of production. The steam growth in the steam chamber could recover up to 60% of the oil-in-place by a typical SAGD project. However, some SAGD projects are only able to present less than 20% of the recovery factor, even though they have been producing for almost decades. Currently, the steam-to-oil ratio (SOR) for most SAGD projects ranges between 2 and 4 bbl steam/bbl oil. Nevertheless, some projects are still experiencing SOR of over 4 bbl/bbl due to the aggressive steam injection. Despite the efficacious evidence and enormous contribution to oil production, many questions regarding the current SAGD project performance are still rising. The process and execution are very complex and entail great operational excellence. The thermodynamic processes (heat transfer, wettability alteration), reservoir geology (thickness, vertical conformance, steam channelling), well designs (optimal placement of the pairs, well completions), and environmental concerns (GHG emission) are also limiting factors to be detrimental to SAGD performance. Some other techniques to recuperate heavy-oil and bitumen (e.g., co-injection)—in addition to the principal SAGD—have been insinuated and employed in the projects. The efforts only presented a 5–10% of success rate. This paper focuses on extensive evaluation and analysis of the ongoing SAGD projects over the last three decades in Canada and what would be the forthcoming potential of mature SAGD. Lessons learned and limitations from historical and current SAGD applications based on the evaluation of 22 commercial SAGD projects are presented. Success and failure stories were evaluated from geological, technical, environmental, and operational points of view. The reasons behind the successful applications of existing SAGD practices were listed. In the end, suggestions were made as to the proper design of new SAGD projects and future practices in the matured fields. Some new insights for the future of mature SAGD, including "zero emission" applications using solvents and reduced emission using steam additives, are also discussed. The conclusive analyses done and the recommendations made will lead to more efficient SAGD applications (new and matured) in Canada, also providing a useful road map for the other parts of the world.
- Research Report (0.68)
- Overview (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
A Field Pilot Test on CO2 Assisted Steam-Flooding in a Steam-flooded Heavy Oil Reservoir in China
Qi, Zongyao (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Liu, Tong (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Xi, Changfeng (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Zhang, Yunjun (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Shen, Dehuang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Mu, Hertaer (Xinjiang Oilfield, PetroChina) | Dong, Hong (Xinjiang Oilfield, PetroChina) | Zheng, Aiping (Xinjiang Oilfield, PetroChina) | Yu, Kequan (Xinjiang Oilfield, PetroChina) | Li, Xiuluan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Jiang, Youwei (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Wang, Hongzhuang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Li, Huazhou (University of Alberta) | Babadagli, Tayfun (University of Alberta)
Abstract It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to the reduced residual oil saturation, the high steam-oil ratio, and the lower profitability. A field test of CO2-assisted steam flooding technology was carried out in the steam-flooded heavy oil reservoir in the J6 block of Xinjiang oil field (China). The field test showed a positive response to the CO2-assisted steam flooding treatment including a gradually increasing heavy oil production, a rise in formation pressure, a decrease in water cut, etc. The production wells in the test area mainly exhibited four types of production dynamics, while some production wells showed production dynamics that were completely different from those during steam flooding. After being flooded by CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence could yield a stable oil production. Meanwhile, emulsified oil, together with CO2-foam, was observed to be produced in the production well, which agreed well with what was observed in the lab-scale tests. The reservoir-simulation-based prediction in the test reservoir shows that the CO2-assisted steam flooding technology can reduce the steam-oil ratio from 12 m (CWE)/t to 6 m (CWE)/t and yield a final recovery factor of 70%.
- North America (0.88)
- Asia > China (0.85)
- Europe > United Kingdom > North Sea > Central North Sea (0.40)
Abstract Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks. A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples. Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
- North America > United States > West Virginia (0.67)
- North America > United States > Pennsylvania (0.67)
- North America > United States > Ohio (0.67)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Gansu > Ordos Basin (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.87)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.67)
Summary Foamy-oil flow is encountered not only during the primary stage of the cold-heavy-oil-production (CHOP) process through evolving methane originally in the oil but also in the post-CHOP enhanced-oil-recovery (EOR) applications in which different gases are injected and dissolved in heavy oil. Despite remarkable efforts on the physics of foamy oil flow, the mechanics of its flow through porous media is not properly understood yet. This is mainly because of lack of detailed experimental studies at the core scale to clarify the physics of the process and to support numerical-modeling studies. One also should test foamy-oil flow for different types of EOR gases dissolved and evolved at different conditions under pressure depletion. The objective of the present work is to perform detailed laboratory experiments on foamy-oil flow through porous media. Pressure/volume/temperature (PVT) studies were conducted to determine the actual pressure ranges in the coreflooding experiments in the beginning. After dissolving different gases in dead oil at 400 psi for methane (CH4) and carbon dioxide (CO2) and 112 psi for propane, the oil was injected into a sandpack to saturate it. The solution-gas-drive test was started by opening the outlet valve of the coreholder after reaching equilibrium. To mimic typical post-CHOP EOR conditions with methane, propane, or CO2 injection, the pressure was kept high (400 psi for CO2 and CH4 and 112 psi for propane). The produced oil by solution-gas drive and the gas evolved were monitored by collecting them in a graduated cylinder and a gas cylinder, respectively, while the pressure was recorded by an automatic data-acquisition system. The experimental data provided information about the effect of initial pressure of the depletion test in the amount of oil and gas measured as well as the visual observations of bubble characteristics of the foamy oil. Results showed that, among the three gases, CO2 is a good candidate for foamy oil. Maximum oil recovery [more than 50% of original oil in place (OIP) (OOIP)] was obtained in case of CO2.
- North America > Canada > Alberta (0.94)
- Asia > Middle East (0.93)
Summary Estimation of effective fracture-network permeability (EFNP) is an essential part of modeling transport processes in naturally fractured reservoirs. A practical way of doing this is to use correlations that consider the statistical and physical characteristics of the networks. Thus, selection of the proper parameters to be characterized and/or measured that are highly correlative to the network permeability is critical. In this study, we analyzed fractal-based correlations previously developed by Jafari and Babadagli (2011a, 2011b) to clarify the physical relationship among network properties and the correlation parameters. It was shown that the connectivity index is a more-powerful parameter to rely on in permeability estimation, especially at percolation ranges far from the threshold. Also, it was of high interest to inspect the effect of physical parameters of a fracture network on different fractal dimensions as well as their positive/negative correlation with permeability to make a distinction between the mathematical and physical contributions of variables. We explained the earlier observation of Jafari and Babadagli (2009) regarding the method to determine fractal dimensions and their observed differences, which were found to be related to the computational scheme. That is why the box-counting fractal dimension gives the highest correlation compared with other fractal dimensions, especially the sandbox fractal dimension. The conditions of a strong correlation among different fractal dimensions and the scale-dependency of correlations in natural and synthetic patterns were also addressed.
- Asia > Middle East (0.93)
- North America > United States > Nevada (0.28)
- North America > United States > California (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Abstract Proppants are one of the essential parameters in fracking design. They not only provide fracture permeability but do prevent “healing” of fractures. Hence, the quantification of proppant transport characteristics is highly critical in a sustainable production from hydraulically fractured wells. Previous attempts were limited to smooth (parallel) fracture surfaces, to a great extent. The consensus reached in the literature, however, is that the roughness of fractures may play a crucial role on proppant transport affecting the permeability of hydraulic fractures. In this paper, an experimental scheme to visually and quantitatively investigate the hydraulic characteristics of rough fractures in the presence of proppants is presented. Seven rock samples of different kinds (i.e., granite, marble, and limestone) were fractured under the Brazilian test and molded to manufacture 20x20 cm transparent replicas. Propping agents were injected at a constant rate into perfectly mating (joint) and sheared fractures in water and polymeric solutions representing typical rheological properties of hydraulic fracturing fluids. During these 2-D experiments, the inlet pressure was continuously monitored to quantify the permeability changes due to proppant distribution caused by the roughness of fracture surfaces. Simultaneously, corresponding images were collected to trace the transport of proppants and their behavior was correlated to the measured permeability change. For a better visualization of proppants, the injected fluid was dyed with a fluorescent material. The proppant behavior in joint and shear type fractures were different. In both cases, fracture closure areas existed, which controlled the proppant movement and permeability change significantly. The injection rate, proppant size, and fracture roughness controlled by lithological properties of the rocks were the other critical factors affecting the permeability and proppant transport. After quantifying the roughness characteristics through different fractal methods (e.g., variogram analysis, power spectral density, etc.), correlations between fracture permeability in the presence of proppant and rock types were presented. The quantitative and visual data collected for a wide range of rock types with original roughness characteristics are expected to be useful in fracking design and selection of proper proppants for different reservoirs. Key words: Proppant transport, fracture roughness, joint and shear fractures, fracture permeability, fractal fracture surfaces. Introduction The main goal of hydraulic fracturing is to provide permeable flow path for hydrocarbons in tight formations. The stability of this permeable flow path can be achieved by propping agents that are injected with treated water. Design of fracturing fluid treatment together with selecting proper proppant type critically impacts the hydrocarbon recovery from the formation (Coulter et. al.2004; Terracina et al. 2010; Kassis et al. 2010; Ribeiro and Sharma 2012, 2013). The mechanism of proppant transport in rough-walled fractures and its effect on permeability should be understood clearly in the assessment of recovery performance, as well. Proppant transport depends on the distribution of asperities, surface roughness, and contact area, which are all controlled by lithological properties of the rocks (Fredd et al. 2000). In addition, rough surface coupled with shear displacement causes closures of the fracture at some points and this eventually affects the proppant transport (van Dam and de Pater 1999).
- North America > United States > Texas (0.69)
- North America > Canada > Alberta (0.47)
- Geology > Geological Subdiscipline > Geomechanics (0.89)
- Geology > Rock Type > Sedimentary Rock (0.69)
Summary Although proved beneficial and economic for thin reservoirs, the cold heavy-oil production with sand (CHOPS) method has several limitations. The sand produced during CHOPS changes the geomechanical and petrophysical properties continuously and results in open channels in the reservoir known as wormholes. Also, the CHOPS method results in a low oil recovery (8–10% original oil in place). This entails a follow-up enhanced-oil-recovery (EOR) process, which is always an option for further exploitation, referred to as post-CHOPS. Assessment of such a process through numerical simulation, as the most inexpensive yet most powerful tool, necessitates a comprehensive modelling approach to capture its dynamic physical nature. Only through such a realistic model can one obtain reasonably reliable reservoir characteristics after CHOPS that are critically important to assess post-CHOPS applications. To this end, we implemented a fractal pattern of different kinds by use of a diffusion-limited aggregation (DLA) algorithm as wormhole domain with a partial dual-porosity approach and a step-by-step simulation technique, taking advantage of a simple mathematical model to integrate the sand-production data with fractal patterns. The wormhole network is assumed to grow with more sand production, respecting geological conditions and well perforation. Moreover, its effective properties and the contained fluid can be controlled along its length and pattern at different steps. Such an option is of great assistance in the history-matching process. The model was validated successfully with available Alberta field data. As a preliminary step to post-CHOPS, several thermal, solvent, and hybrid combinations of both scenarios were considered. The proposed method for CHOPS modelling is a useful approach to initiate a quick post-CHOPS study in practice if sand production history is provided. One may also take advantage of its compatibility with any black-oil, compositional, or thermal simulators.
- North America > United States (1.00)
- Asia (0.93)
- North America > Canada > Alberta (0.90)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.64)
- North America > United States > Oklahoma > Anadarko Basin > Pauls Valley Field (0.99)
- North America > United States > Louisiana > Frog Lake Field (0.99)
Summary Recently, the steam-over-solvent injection in fractured reservoirs (SOS-FR) method was proposed as a potential solution for efficient heavy-oil/bitumen recovery in oil-wet naturally fractured reservoirs. The method is based on initial injection steam (Phase 1), followed by solvent (Phase 2). In the third cycle (Phase 3), steam is injected again to recover more oil and retrieve the solvent. Solvent retrieval during the third cycle was observed to be fast if the temperature is at approximately the boiling point of the solvent. This process is controlled by efficient matrix recovery and the mechanics of the process need to be clarified to further determine the efficient application conditions for the given matrix and oil characteristics. Single-matrix behaviour during the process was numerically modelled for static conditions and the results were matched with the experimental observations. The physics of the recovery mechanism was analyzed through visual inspection of saturation and concentration profiles in each cycle. The major observation was the substantial effect of gravity in oil recovery when the matrix were exposed to solvent. Special attention was given to the solvent retrieval rate and amount in Phase 3 and the permeability reduction caused by asphaltene precipitation in Phase 2. This phenomenon was modelled using a permeability function changing with spatial coordinates and time (i.e., k =f (x ,y ,z ,t ). It was observed that permeability reduction caused by asphaltene precipitation is significant and needs to be taken into account in the modelling process. After showing the effect of the matrix size on the oil recovery and solvent retrieval, an upscaling analysis was performed. The log-log relationship between the time value to reach ultimate recovery and the matrix size yielded a straight-line relationship with a noninteger exponent less than two for all three phases of the process. The observed straight-line relationship (and the exponent values obtained) is highly encouraging to extend the study to obtain a universal scaling relationship.
- North America > Canada > Alberta (0.29)
- North America > United States > California (0.28)
- Asia > Middle East > Turkey (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
Summary We used an integrated solution by combining "direct" and "inverse" approaches to fracture network characterization in a stochastic numerical model. Static geological data obtained from cores and well logs were used together with dynamic data such as well-test responses to build 3D discrete fracture-network models. We used the data obtained from the fractured carbonate Midale field in Canada. The fractured-reservoir model was constructed from static and dynamic (drawdown and pulse-interference tests) data. Matrix and several fracture parameters including fracture length, density/spacing, aperture, connectivity, and orientation were evaluated in a quantitative sensitivity study to determine which characteristics have a higher influence on the accurate match to well-test response. We used experimental design to optimize the number of simulations needed for a sensitivity study and history match. The sensitivity analysis revealed a strong influence of matrix quality on the pressure response, suggesting that the history match can be specific to the simulated process and not necessarily unique. The results emphasize the contribution of matrix in the Midale reservoir and the need to simulate a broader range of processes for an accurate description of the fracture/matrix system dynamics. In a general sense, the approach used in this study proved to be useful in integrating fracture data from different sources and assessing its reliability and relative importance. Introduction In this study, we apply a widely accepted integrated approach to characterize the matrix/fracture system of the Midale field in southeastern Saskatchewan, Canada. Often serving as an example for classical NFR in literature, Midale is a perfect case study for several reasons. The field produces light oil from a mature carbonate reservoir. Currently Midale is undergoing a full-field CO2 flooding, which became possible largely thanks to the success of the pilot CO2 flood project in the late 1980s. Massive amounts of data and experience were accumulated throughout the years. Moreover, considerable research was conducted into matrix and fracture characterization and production mechanisms (Payne 1988; Beliveau 1989; Beliveau et al. 1993; Malik et al. 2006; McKishnie et al. 2005). Nevertheless, the success of enhanced recovery still depends on further research into the matrix heterogeneity, NFN geometry, and fracture/matrix interaction. Developments in computational and analytical methods have provided us with some useful tools, which facilitate the method described below. This paper describes how integrated fracture and matrix characterization using static and dynamic data helped us to construct and validate a discrete 3D fracture network embedded into reservoir matrix. Furthermore, we present the statistical analysis of designed flow simulations used to clarify the role of NFN properties in the reservoir performance.
- Research Report > New Finding (0.74)
- Research Report > Experimental Study (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Communications > Networks (0.66)
Summary Fracture-network mapping and estimation of its permeability constitute two major steps in static-model preparation of naturally fractured reservoirs. Although several different analytical methods were proposed in the past for calculating fracture-network permeability (FNP), different approaches are still needed for practical use. We propose a new and practical approach to estimate FNP using statistical and fractal characteristics of fracture networks. We also provide a detailed sensitivity analysis to determine the relative importance of fracture-network parameters on the FNP in comparison to single-fracture conductivity using an experimental-design approach. The FNP is controlled by many different fracture-network parameters such as fracture length, density, orientation, aperture, and single-fracture connectivity. Five different 2D fracture data sets were generated for random and systematic orientations. In each data set, 20 different combinations of fracture density and length for different orientations were tested. For each combination, 10 different realizations were generated. The length was considered as constant and variable. This yielded a total of 1,000 trials. The FNPs were computed through a commercial discrete-fracture-network (DFN) modeling simulator for all cases. Then, we correlated different statistical and fractal characteristics of the networks to the measured FNPs using multivariable-regression analysis. Twelve fractal (sandbox, box counting, and scanline fractal dimensions) and statistical (average length, density, orientation, and connectivity index) parameters were tested against the measured FNP for synthetically generated fracture networks for a wide range of fracture properties. All cases were above the percolation threshold to obtain a percolating network, and the matrix effect was neglected. The correlation obtained through this analysis using four data sets was tested on the fifth one with known permeability for verification. High-quality match was obtained. Finally, we adopted an experimental-design approach to identify the most-critical parameters on the FNP for different fracture-network types. The results are presented as Pareto charts. It is believed that the new method and results presented in this paper will be useful for practitioners in static-model development of naturally fractured reservoirs and will shed light on further studies on modeling and understanding the transmissibility characteristics of fracture networks. It should be emphasized that this study was conducted on 2D fracture networks and could be extended to 3D models. This, however, requires further algorithm development to use 2D fractal characteristics for 3D systems and/or development of fractal measurement techniques for a 3D system. This study will provide a guideline for this type of research.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- Asia > Middle East > Iran (0.28)
- North America > United States > California (0.28)
- North America > United States > Wyoming > Bighorn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Big Horn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (23 more...)