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Results
Summary With the current interest in exploiting thin unconsolidated heavy-oil reservoirs, cold heavy-oil production with sand (CHOPS) can be considered to be a promising primary-recovery technique. However, it offers low recovery factors (~5-15%) and creates a complex network of high-permeability channels known as workholes, while simultaneously changing formation compressibility and in-situ stress conditions. Eventually, development of such a network would lead to a softer layer within the shallow unconsolidated reservoir, which can carry less of the overburden stress. Further development of such reservoirs is usually achieved through enhanced-oil-recovery (EOR) applications in the form of cyclic solvent stimulation within an economic framework. Cyclic loading and unloading of this EOR technique make it even more difficult to predict the recovery performance. In this study, a 3D geomechanical model was used to calculate the stress distribution in a history-matched field in Alberta with 15 producers. The fractal patterns generated from the diffusion-limited-aggregation (DLA) algorithm were used to represent the wormhole network with different strength properties. Foamy behaviour of heavy oil was modelled with the help of a set of kinetic reactions. The hydro-geomechanical model was then used for field-development planning, reservoir management, and assessment of near-wellbore regions during cyclic injection and production. The fieldwide deformation and stress changes were analyzed in deep overburden, caprock, and reservoir to show the influence of local stress orientations in soft and stiff layers. Next, we considered a sector model with a single well. The model introduced was used to assess EOR processes with different solvent streams. While light hydrocarbon components help to repressurize the formation, the heavier components seem more effective in heavy-oil dilution. This occurred while stress arching redistributed the cyclic injection/production-induced stresses to flow around soft inclusions. Although it is difficult to obtain data to calibrate the 3D hydro-geomechanical model, it allows for reliable investigation of reservoir performance and provides deeper insight than does the use of flow simulation alone. The assessment of the potential of geomechanics can ascertain whether a more-detailed modelling is necessary.
- North America > United States (1.00)
- North America > Canada > Alberta (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.85)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Impact of Distance-of-Investigation Calculations on Rate-Transient Analysis of Unconventional Gas and Light-Oil Reservoirs: New Formulations for Linear Flow
Behmanesh, Hamid (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Tabatabaie, S. Hamed (University of Calgary) | Heidari Sureshjani, Mohammadhossein (IOR Research Institute)
Summary Long-term transient linear flow of hydraulically fractured vertical and horizontal wells completed in tight/shale gas wells has historically been analyzed by use of the square-root-of-time plot. Pseudovariables are typically used for compressible fluids to account for pressure-dependence of fluid properties. Recently, a corrected pseudotime has been introduced for this purpose, in which the average pressure in the distance of investigation (DOI) is calculated with an appropriate material-balance equation. The DOI calculation is therefore a key component in the determination of the linear-flow parameter (product of fracture half-length and square root of permeability, xfk) and the calculation of contacted fluid in place. Until now, the DOI for transient linear flow has been determined empirically, and may not be accurate for all combinations of fluid properties and operating conditions.ย In this work, we have derived the DOI equations analytically for transient linear flow under constant-flowing-pressure and -rate conditions. For the first time, rigorous methodologies have been used for this purpose. Two different approaches were used: the maximum rate of pressure response (impulse concept) and the transient/boundary-dominated flow intersection method. The two approaches resulted in constants in the DOI equation that are much different from previously derived versions for the constant-flowing-pressure case. The accuracy of the new equations was tested by analyzing synthetic production data from a series of fine-grid numerical simulations. Single-phase oil and gas cases were analyzed; pseudovariable alteration for pressure-dependent porosity and permeability was required in the analysis. The calculated linear-flow parameters, determined from our new DOI formulations for the constant-flowing-bottomhole-pressure (FBHP) case, and the input values to numerical simulation, are in good agreement. Of the two new DOI-calculation methods provided, the maximum rate of pressure response (unit impulse method) provides more accurate results. Finally, a field case was analyzed to determine the impact of DOI formulations on derivations of the linear-flow parameter from field data. Linear-flow analysis on the basis of the DOI calculations presented in this work is significantly improved over previous formulations for constant FBHP.
- Asia > Middle East (0.68)
- North America > Canada > Alberta (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
Supported Catalyst Regeneration and Reuse for Upgrading of Athabasca Bitumen in Conjunction With In-Situ Combustion
Abu, Ibrahim I. (University of Calgary) | Moore, R. Gordon (University of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Ursenbach, Matthew G. (University of Calgary) | Mallory, Donald G. (University of Calgary) | Pereira-Almao, Pedro (University of Calgary) | Scott, Carlos E. (University of Calgary) | Carbognani Ortega, Lante (University of Calgary)
Summary A commercial supported catalyst was regenerated and reused for three combustion-tube tests to study the upgrading potential of Athabasca bitumen supplied by Japan Canada Oil Sand Ltd. (JACOS). These tests were part of a larger program of combustion-tube tests performed by the In-Situ Combustion Research Group (ISCRG) under the auspices of the Alberta Ingenuity Center for In-Situ Energy (AICISE). The tests were premixed and carried out at the same pressure of 3.45 mPa (500 psi), preheat temperature (95ยฐC), and ignition temperature (350ยฐC). Test 1 used a fresh supported catalyst. Test 2 used a regenerated catalyst retrieved from Test 1, and Test 3 used regenerated catalysts (second time regeneration of catalysts from Test 1) retrieved from Test 2. Significant hydrodenitrogenation (HDN), 52% for the fresh catalyst Test 1, 38.1% for regenerated catalyst Test 2 and 23.8% for regenerated catalyst Test 3, was obtained. The levels of hydrodesulfurisation (HDS) obtained were 18.1, 18.4, and 15.2% for Tests 1, 2, and 3, respectively. The significant HDN and HDS removal coupled with decreased viscosity, increased ยฐAPI value, and light hydrocarbons indicate upgrading of the original Athabasca bitumen for all three tests. The results showed that although the regenerated catalyst Tests 2 and 3 lost HDN activity compared to the fresh catalyst, the regenerated catalysts were still active for repeated use for in-situ upgrading.
- Personal (0.46)
- Research Report > New Finding (0.34)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Summary History matching of a steam-assisted-gravity-drainage (SAGD) reservoir requires a large ensemble size for proper uncertainty assessment, which ultimately results in high computational cost. Therefore, it is necessary to reduce the number of realizations for SAGD-reservoir simulation purposes. In this paper, a novel sampling method (based on the probability-distance-minimization method) to generate an initial ensemble of reduced size is discussed. This method considers multiple static measurements and geological properties and uses Kantorovich distance to quantify the probability distance between the original ensemble and the reduced ensemble, which is later optimized by use of the mixed-integer linear-optimization (MILP) technique. To show the effectiveness of the method, we have shown history matching of an SAGD reservoir using the smaller size initial ensemble derived from the proposed method and compared with the original ensemble. For history matching, the ensemble Kalman filter (EnKF) has been used because of its ability to assimilate data for large-scale nonlinear systems. Results are compared with several other methods, such as importance sampling, kernel K-means clustering, and sampling by use of orthogonal ensemble members. The robustness and usefulness of each method for generating an improved initial ensemble of reduced size are analyzed on the basis of two criteria: (1) Does the smaller ensemble retain the same statistical distribution characteristics as the original ensemble, and (2) does the smaller ensemble improve the performance of history matching? In general, we conclude that the improved, smaller initial ensemble created by use of the proposed method retains the best statistical characteristics of the original ensemble. Also, it provides better performance compared with other ranking methods in sampling and history matching using EnKF. Finally, the proposed method can reduce the computing cost significantly without compromising uncertainty in the forecast model, which allows for real-time updating at smaller time intervals.
- Europe (0.93)
- Asia (0.92)
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.29)
Summary Over the last 30 years, laboratory testing has been conducted to investigate the geotechnical properties of Clearwater clay shales from the Clearwater formation in northeast Alberta, Canada. These properties are important for characterization of the overburden zones above in-situ oil-sands mines and for assessment of caprock integrity in steam-assisted-gravity-drainage (SAGD) projects. In general, caprock-integrity assessments include caprock geological studies, in-situ stress determination, constitutive-property characterization, and numerical simulations, which allow operators to ensure that steam-injection pressure does not cause any risk to the confinement of steam chambers. The aim of this study is to identify and provide the representative parameters that can enhance understanding of the geotechnical behaviour of the Alberta Clearwater formation clay shale. Moreover, it illustrates how the results can be used to extract constitutive model parameters for modelling the behaviour of this class of material. The parameters are also used for complex reservoir-geomechanical simulation for caprock integrity. These parameters are also compared with other Cretaceous clay-shale counterparts in North America.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Joslyn North Mine (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.97)
Summary This study investigates the effect of clay type on the performance variations of steam-assisted gravity drainage (SAGD). Two SAGD experiments at identical experimental conditions were conducted. The reservoir rock for the first experiment (SAGD1) is prepared with a sand (85 wt%) and kaolinite (15 wt%) mixture, and the second experiment (SAGD2) is prepared with a sand (85 wt%), kaolinite (13.5 wt%), and illite (1.5 wt%) mixture. The effectiveness of the steam-chamber growth did not change with the clay type; however, 15-wt% reduction in oil recovery was observed for SAGD2. The possible reasons were investigated with the analyses on the produced-water, the produced-oil, and the spent-rock samples. Contact-angle, particle-size, zeta-potential, and interfacial-tension measurements were carried out on the samples. The mineralogical changes on spent-rock samples were determined by X-ray diffraction (XRD) and scanning-electron-microscope (SEM) analyses. The contact-angle measurements on the spent-rock samples displayed the higher oil-wetness for SAGD2 than SAGD1. However, the water-wetness of illite is known to be higher than that of kaolinite. This unexpected result is explained by the interaction of illite and the asphaltenes from SAGD2. The particle-size measurements, along with the SEM images, on post-mortem samples reveal that illite containing clay exhibits cementation behaviour and, hence, reduces the permeability of the rock. According to the experimental results, we developed hypotheses to understand the bitumen/illite and bitumen/kaolinite interactions for SAGD. Because of the high water-wetness of illite, illite particles first interact with water. This interaction results in cementation and forms illite lumps with sand. Then, illite lumps continue to interact more vigorously with the polar molecules (water, asphaltenes, and resins). Clay migration and production occur in both clay types; however, while kaolinite is produced in the water phase, illite-containing clay as a result of its interaction with asphaltenes is produced in the oil phase.
- Asia (1.00)
- North America > United States > Texas (0.47)
- North America > Canada > Alberta (0.47)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Summary The Pelican Lake field in northern Alberta (Canada) is home to the first successful commercial application of polymer flooding in higher-viscosity oils (i.e., greater than 1,000 cp), which has opened up new opportunities for the development of heavy-oil resources. The field produces from the Wabiskaw โAโ reservoir, which has thin pay (2 to 6 m) and exhibits a significant viscosity gradient across the field, with oil viscosities as low as 600 cp in the existing waterflood and polymer-flood areas to more than 200,000 cp in the current undeveloped โimmobileโ area. This unique geological feature limits the application of chemical injection to the less-viscous areas of the field and calls for different methods for the heavier accumulations. As a first step to develop alternative technologies capable of recovering oil from heavier areas of the field not ideal for polymer flooding, a Cenovus-designed hot-water-injection pilot began implementation in June 2011. The hot-water-injection scheme was applied to a transition area in which dead-oil viscosity ranges from 3,000 cp to approximately 15,000 cp. It consisted of one horizontal producer supported by two horizontal hot-water injectors, with an injector/producer distance of 50 m for both injectors, and three vertical observation wells equipped to monitor pressure and temperature between one injector and the producer. The pilot was operated in three phases. The first phase consisted of a 6-month primary-production period to obtain a baseline of the pilot performance before hot-water injection. The second phase consisted of hot-water injection through the edge injectors. The third phase consisted of hot-water edge injection accompanied by hot-water circulation in the production well as a means to stimulate oil production. One of the features of this stage is the use of an insulated coiled tubing (ICT), which delivers hot water continuously to the toe of the producer and allows continuous stimulation and uninterrupted oil production. This paper describes the mechanical components of the pilot and discusses the results obtained with an emphasis on the hot-water-circulation process, which has proved to be very effective. Oil production increased from approximately 6 m/d during the flood stage to more than 25 m/d during the hot-water-circulation stage and has held relatively steady for more than 2 years. The data captured have been reconciled with analytical and reservoir-simulation models, and results suggest that the technology may help unlock some of the heavier oil accumulations in the field.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabiskaw Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Morgan Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.98)
Summary Unconventional reservoirs require extensive hydraulic-fracturing treatments to produce fluids economically and efficiently. The main purpose of such treatments is to create complex fracture networks with high-conductivity paths deeper into the nonstimulated reservoir regions. Proppants play an important role in maintaining good-quality fracture conductivities, which then greatly affect long-term production performance. In addition, research on proppants has shown a reduction in conductivities under downhole stresses and multiphase-flow behaviours. Therefore, it is important to study the effect different proppants and conductivities have on production performance through actual field cases. To evaluate the production performance of wells completed with different proppants, the authors proposed an integrated work flow for characterization and simulation of unconventional reservoirs. This work flow is unique because of the stochastic fracture-network-generation algorithms and improved unstructured-grid-generation techniques. Both analysis of field-production data and numerical simulations were performed on eight wells in the CAPA field of North Dakota. For the field-data analysis, three public-data resources were reviewed to prepare a summary of reservoir properties, fracture properties, proppant properties, and production history. For the numerical simulations, all the wells were modelled and simulated with the proposed work flow. Finally, sensitivity analyses were carried out to investigate the effects of fracture conductivities and natural fractures. After completing the field-case studies and reservoir simulations, it was concluded that with the same fracture design, higher fracture conductivity improves production performance. Pumping a smaller volume of upgraded proppants with higher conductivity not only improves long-term production performance, but also justifies the additional costs and reduces the overall operation time of the entire hydraulic-fracturing job. The stimulated reservoir volume was greatly increased, as was the production performance, where natural fractures exist. In this paper, field-data analysis was applied in the Bakken to demonstrate the integrated unconventional work flow. The proposed unstructured-gridding algorithms can be incorporated into any preprocessor to handle complex networks. Reservoir, fracture, and proppant characterization and reservoir simulation of the field cases can help engineers prepare and interpret simulation input and output.
- North America > United States > North Dakota (1.00)
- North America > United States > Texas > Dawson County (0.50)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Summary The steam-assisted-gravity-drainage (SAGD) process has been widely used commercially in western Canada for bitumen production. Improving the oil-production rate and reducing the steam/oil ratio (SOR) have been the focus of the industry. In heterogeneous reservoirs, oil production could be impeded by steam breakthrough at one location of the producer and higher liquid level above the other sections of the producer. Various completion methods have been proposed to improve production efficiency. Outflow-control devices (OCDs), such as steam splitters, are used to match steam delivery to reservoir requirements, and inflow-control devices (ICDs) may be used in producers to maximize oil production. Scab liners are the most widely used type of ICD. In general, oil drainage into producers may need to be slowed at some locations and sped up at other locations of the well. In this study, we address how to design SAGD injector and producer completions using steam splitters and scab liners. Results from reservoir simulation with coupled wellbore hydraulics will be presented to show how a well pair could be optimized by attaining favorite pressure profiles inside the injector and producer liners. This investigation will also address sensitivities on steam-splitter location, size, and number of holes, as well as size and length of scab liners.
Reservoir Characterization and History Matching of the Horn River Shale: An Integrated Geoscience and Reservoir-Simulation Approach
Kam, Patrick (Encana Services Company and Penn West Petroleum) | Nadeem, Muhammad (Encana Services Company) | Novlesky, Alex (Computer Modelling Group) | Kumar, Anjani (Computer Modelling Group) | Omatsone, Ese N. (Encana Services Company and DeGolyer and MacNaughton Canada)
Summary We present a systematic approach to integrate geoscience and dynamic reservoir modeling for two multiwell pads in the Horn River basin, Canada. The Horn River shale-gas play is a world-class unconventional gas resource and is being exploited by use of multistage hydraulic fracturing along horizontal wells. The two well pads, Pad-1 and Pad-2, selected for this study comprise eight and seven horizontal wells, respectively, with 1 to 7 years of production history. Numerical modelling of shale reservoirs has historically been a problematic low-confidence exercise because of the difficulties associated with inadequate characterization of the geologic framework of shale plays; the problems of estimating the properties of induced-fracture networks; and the complexities of capturing multiphase flow in fracture networks and wellbores during production, especially in the face of offset-well activity. This paper provides insights into these issues. The geoscience modelling activity begins with integrating information from cores, well logs, petrophysical analyses, and seismic data into a 3D geocellular model. At first, the model is built upon a simple lithostratigraphic concept, which is the basis of the numerical-flow-modelling exercise of Pad-1. The 3D geocellular model is thereafter thoroughly reworked to incorporate a sequence-stratigraphic perspective to the Horn River shale. This reworked geocellular model has a profound impact on the dynamic modelling of Pad-2. Also, hydraulic conductivity of induced and natural fractures is measured on Horn River core plugs at reservoir conditions to constrain conductivity values assigned to primary, secondary, and tertiary flow paths into dynamic reservoir modelling. As a result of the integrated work flow, we have achieved a history match allowing us to further understand the hydraulic-fracturing behaviour and its impact on producing shale reservoirs of the Horn River formation. On the basis of the findings, we recommend targeting the Evie and Otter Park shale reservoirs for landing horizontal wells and multistage fracturing when the Carbonate Fan is thin; this approach can produce all three compartmentalized shale reservoirs of the Horn River formation. Ultimately, the objective of any reservoir modelling project is to provide a range of reliable forecast of future performance that is grounded in representative geoscience interpretations and that takes operational constraints into account. The technical learnings described in this work will be helpful to further understand hydraulic-fracturing behaviour and its impact on producing shale reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)