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.
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.
Shahid, Arshad Shehzad Ahmad (Politecnico di Torino and TNO/Geological Survey of the Netherlands) | Wassing, Brecht B. T. (TNO/Geological Survey of the Netherlands) | Fokker, Peter A. (TNO/Geological Survey of the Netherlands) | Verga, Francesca (Politecnico di Torino)
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.
Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone.
Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure.
An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process.
The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage.
In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer.
Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.
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)
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.
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.
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.
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.
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.
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 “A” 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 “immobile” 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 m3/d during the flood stage to more than 25 m3/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.