Journal of Canadian Petroleum Technology

Journal Information
ISSN : 0021-9487
Published by: Society of Petroleum Engineers (SPE) (10.2118)
Total articles ≅ 2,937
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Rajan G. Patel, , Shahed Rahim, Zukui Li
Journal of Canadian Petroleum Technology, Volume 54, pp 424-441;

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.
Taniya Kar, Albina Mukhametshina, Yasin Unal, Berna Hascakir
Journal of Canadian Petroleum Technology, Volume 54, pp 412-423;

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.
Hamid Behmanesh, Christopher R. Clarkson, S. Hamed Tabatabaie, Mohammadhossein Heidari Sureshjani
Journal of Canadian Petroleum Technology, Volume 54, pp 509-519;

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. 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.
Siavash Taghipoor, Alireza Nouri, Dave Chan
Journal of Canadian Petroleum Technology, Volume 54, pp 460-474;

Summary In this paper, a new hydraulic-fracturing model is introduced for cohesionless sand, which is also applicable to weak sandstone formations with high permeability and low shear strength. Phenomena such as shear-band development and shear-enhanced permeability are of paramount importance during hydraulic fracturing of cohesionless sand or weak sandstones, which make the fracturing response quite different from what it is conventionally believed to be in competent rocks. The smeared approach in simulating hydraulic fracturing has been implemented in the proposed model within the continuum mechanics framework. Both matrix and fracture flow have been considered in this model. Tensile- and shear-fracture development and their fluid flow were simulated. The cubic law and Touhidi-Baghini’s shear-permeability model (Touhidi-Baghini 1998) were used to capture the permeability evolution and to model flow in tensile and shear fractures, respectively. Shear fracturing of geomaterials involves intense localization of deformation and strain softening, which is a discontinuous phenomenon, resulting in mesh dependency of the results in the continuum model. The fracture-energy-regularization method was used in this model to reduce the mesh-size dependency of the energy dissipated during fracture propagation. The smeared-fracture approach has been validated against laboratory hydraulic-fracturing experiments with reasonable agreement. Consistent with the experiments, the results of the numerical model indicate that tensile fractures are formed in a very small area around the injection point despite the application of high injection pressure compared with the minimum boundary stress. It is found that shear fracturing and shear-permeability evolution are the most important mechanisms that influence and control the fracturing response. The dominant fracturing mechanism is found to be governed by the high permeability and low shear strength of the material.
Arshad Shehzad Ahmad Shahid, Brecht B. T. Wassing, , Francesca Verga
Journal of Canadian Petroleum Technology, Volume 54, pp 450-459;

Summary A geomechanical and fluid-flow coupled model was developed to simulate natural-fracture-network reactivation during hydraulic-fracturing treatments in shale gas reservoirs. The fractures were modelled using the continuum approach in a commercial finite-difference code, labeled the “softening ubiquitous joints” model, with randomly distributed strength parameters to describe heterogeneity along the fracture plane. The models allow for intersecting fractures to represent realistic scenarios. The permeability values in the fractures are dynamically updated during the simulations together with the reversible tensile opening because of elastic response and irreversible shear opening caused by plastic deformations. The reactivation of the fracture network resulted in high permeability along these fracture planes. The developed model can predict microseismic events caused by slip on the fracture planes. The magnitude levels of these microseismic events are comparable with the levels observed in events monitored by use of geophone arrays during hydraulic-fracturing treatments for different shale gas reservoirs.
Ibrahim I. Abu, R. Gordon Moore, Sudarshan A. Mehta, Matthew G. Ursenbach, Donald G. Mallory, Pedro Pereira-Almao, , Lante Carbognani Ortega
Journal of Canadian Petroleum Technology, Volume 54, pp 372-386;

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 (95°C), and ignition temperature (350°C). 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 °API 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.
Patrick Kam, Muhammad Nadeem, Alex Novlesky, Anjani Kumar, Ese N. Omatsone
Journal of Canadian Petroleum Technology, Volume 54, pp 475-488;

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.
Nadia Shafie Zadeh, Rick Chalaturnyk
Journal of Canadian Petroleum Technology, Volume 54, pp 394-411;

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.
Christopher R. Clarkson, Farhad Qanbari
Journal of Canadian Petroleum Technology, Volume 54, pp 489-508;

Summary There is now an array of analytical, semianalytical, and empirical forecasting methods that can be used to history match and forecast multifractured horizontal wells (MFHWs) completed in low-permeability (tight) reservoirs. Recent developments in analytical modelling have extended model application to cases in which the fracture geometry associated with MFHWs is complex. However, analytical modelling is still primarily limited to single-phase-flow problems, which is very restrictive, and potentially inaccurate, for tight oil and liquid-rich gas reservoirs flowing at less than saturation pressure. In this work, a semianalytical method is presented for history matching and forecasting MFHWs with simple and complex fracture geometry completed in tight, black-oil reservoirs and flowing at less than the bubblepoint pressure. The linear-to-boundary (LTB) model, commonly used to model flow in the inner (stimulated) region of an MFHW, is altered to account for two-phase flow of oil and gas. The enhanced-fracture-region (EFR) case, in which both stimulated and nonstimulated regions contribute to flow, is approximated (empirically) by superposition of two modified LTB models (one representing the inner fractured region and the other the outer, nonstimulated region), and similarly altered to account for two-phase flow. An important observation is that, for MFHWs flowing at less than bubblepoint at constant flowing bottomhole pressure during transient linear flow, the slope of the square-root-of-time plot for both oil and gas phases is constant [i.e., gas/oil ratio (GOR) is constant]. The slope and intercept of the square-root-of-time plot for the primary phase (e.g., oil in the cases studied) can therefore be used to generate a forecast during the transient linear-flow period for oil and for gas (by assuming constant GOR). For boundary-dominated flow, a robust method for forecasting gas and oil was developed using material balance for both phases combined with a modified productivity-index equation that accounts for multiphase flow. A fully implicit approach has been used to solve the flow equations for oil and gas. The new modified LTB and EFR models simplify forecasting considerably for low-permeability black-oil reservoirs exhibiting multiphase flow behaviour, relative to numerical simulation, although they are not as rigorous. The new models can, however, be tied directly to the results of rate-transient analysis and are flexible enough to be applied to common conceptual models used in the literature for forecasting MFHWs under certain conditions. The new modified LTB model has been compared with both simulated and field examples. The initial results demonstrate that transient- and boundary-dominated-flow periods for oil and gas are reasonably matched with the new approach, although slight mismatches may occur, particularly during early boundary-dominated flow. The limits of the new forecasting method will continue to be explored in future work.
Karim Ghesmat, Litong Zhao
Journal of Canadian Petroleum Technology, Volume 54, pp 387-393;

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.
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