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Collaborating Authors
Canada
An Experimental Investigation into Sand Control Failure Due to Steam Breakthrough in SAGD Wells
Mahmoudi, M.. (RGL Reservoir Management Inc.) | Fattahpour, V.. (RGL Reservoir Management Inc.) | Roostaei, M.. (RGL Reservoir Management Inc.) | Kotb, O.. (University of Alberta) | Wang, C.. (University of Alberta) | Nouri, A.. (University of Alberta) | Sutton, C.. (RGL Reservoir Management Inc.) | Fermaniuk, B.. (RGL Reservoir Management Inc.)
Abstract In Steam Assisted Gravity Drainage (SAGD) projects, it is essential to heat the reservoir evenly to minimize the potential for the localized steam breakthrough. Steam breakthrough can cause erosive damage to the sand control liner by the flow of high-velocity wet steam, and, in extreme cases, can compromise the mechanical integrity of the liner. This research investigates the sanding mechanism during the high-quality steam injection into the SAGD production wells. A large-scale Sand Retention Test (SRT) was used to investigate the role of steam breakthrough in the sand control performance. Produced sand and pressure drops along the sand-pack were the main measurements during the tests. The test procedure and test matrix were designed to enable the examination of the impact of steam breakthrough on sand production for different steam rates. Two possible sanding mechanisms are postulated in steam breakthrough events: (1) local grain disturbance caused by the high-velocity steam near the liner, (2) effect of the complex phase behavior of the steam and the subcool level. Two different testing procedures were designed to examine these mechanisms. The local grain disturbance mechanism was investigated by injecting air at a wide range of velocities. Results indicate that this mechanism could not lead to a significant sanding when there is a bit of effective stress near the liner. Hence, it looks like that the steam velocity poses a higher risk in early stages of SAGD production when the near-liner stress is very low. The effect of high-pressure high-temperature (HPHT), low- to high-quality steam flow and the subcool level will be investigated in the next phase of the study. This work addresses the effect of high-quality steam breakthrough on the sand control performance of the liner in SAGD producer wells. The findings in this paper help the researchers to direct their research to better understand the steam breakthrough. This research will eventually help the engineers in their liner design and evaluation for the entire wellbore life cycle as the near-well stress evolves.
- North America > United States (1.00)
- North America > Canada > Alberta (0.72)
- 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 > Hangingstone Oil Sands Project (0.99)
Abstract A solvent process for heavy oil recovery is described in which an infill injection well is used to inject a cold solvent into neighboring steam chambers once they merge. Simulation results are presented summarizing acceleration in oil recovery and the beneficial impact on energy consumption. Approximately 60% of injected energy in SAGD process is retained in the reservoir. If a cold solvent is injected into a SAGD formation, it will use the stored energy to vaporize and spread within the steam chamber, while at the same time effectively cooling it. An infill injection well is drilled near the top of the rich pay zone and half way between two neighboring SAGD well pairs. Once the steam chambers merge, cold solvent is injected targeting the outer peripheries of the steam chamber. A small amount of non-condensable gas can also be added to help with pressure maintenance. Cooling of steam chamber enhances solubility of solvent in the bitumen phase and accelerates recovery. Once a secondary peak oil rate is observed due to the cold solvent, proportion of non-condensable gas to solvent in the injected fluid is steadily increased and eventually steam injection is completely ceased and the process switches to blow down phase with 100% non-condensable gas injection. Simulation results show that injection of liquid propane and traces of non-condensable gas through the infill injection well provides pressure support and immediately reduces the amount of steam injection required through the primary SAGD injection well by 40-60%. This is followed by a steady increase in oil production rate aided by the viscosity reduction due to propane solubility. A secondary oil production rate peak, comparable to the original peak observed with steam, is achieved. A variation of this process was also simulated for mature SAGD formations, where cold propane injection is accompanied by total steam injection cessation, showing advantageous results. Cold Solvent Process separates out injection of solvent from steam resulting in a much simpler facility design. No additional energy is used to vaporize the solvent at the wellhead. Unlike steam/solvent co-injection processes, solvent is delivered to the cold bitumen interface directly and extracts useful energy from the residual heat in the rock matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract SAGD is an energy and emissions intensive process for bitumen recovery. The situation is worse for reservoirs with lean zones. Industry is looking for ways to make these projects more environmentally friendly and economic by reducing energy intensity and emissions. Previously we have shown that for reservoirs with top water, SAGD is a viable option. Active de-watering of the lean zone can be accomplished using fence wells and air injection, though some water would remain. A new process is presented in which vaporized solvent is used in such a way that it helps keep water ingression into the drainage chamber at bay. The process is initiated as conventional SAGD. Once steam chamber breaches the de-watered lean zone, one of the previously drilled wells for de-watering is converted to solvent injection while steam injection is ceased. Solvent is injected as vapor at such a rate that it forms a gas blanket over the steam chamber and condenses further away due to cooler temperature in the lean zone. The combined effect of solvent injection pressure and an oil bank formedat the edges of the solvent blanket keep the water at bay. Within core of the vapor chamber, solvent vapor makes contact with cold bitumen, dissolves in the oleic phase and reduces its viscosity. The mobilized oil moves down to the producing well by gravity drainage. Simulation results show that using propane as the solvent, energy consumption of the process will be reduced by 80% as compared to SAGD (which is still being optimized via simulations), while the average production rate is doubled. Past the SAGD phase, since no steam is injected and the condensed solvent bank is effective in blocking the lean zone water, produced water to oil ratio is very low. Once economic recovery is achieved, propane retained in the reservoir can be recovered by a variety of ways that are discussed in the paper. The process described above can reduce the capital cost of a green field project by minimizing the water handling facility and significantly reduce the carbon footprint.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Telephone Lake Project (0.98)
Abstract Alberta (Canada) has the third largest proven reserves of oil in the world, mostly comprised of bitumen and heavy oil. To date, Steam Assisted Gravity Drainage (SAGD) has been the only commercially viablein-situ recovery technology for the Athabasca Oil Sands, but the current economic conditions have made the SAGD technology challenging, even for some high quality reservoirs. Moreover, from an environmental perspective, large water usage and high carbon emissions also make SAGD difficult to sustain. Due to the current low oil prices and rising penalties on carbon emissions, there is a need to develop improved recovery technologies that are more thermally efficient, with reduced environmental impact and at the same time economically feasible to develop. One of the technologies that has the potential to overcome these economic and environmental shortcomings is a hybrid steam and in-situ combustion process (ISC) called SAGDOX, as this process offers advantages over pure steam injection such as greater energy efficiency, lower water usage and reduced carbon emissions. The SAGDOX (SAGD and Oxygen Injection) process, which is proprietary to Nexen (Kerr, 2015), combines the benefits of both SAGD and ISC processes. Steam is used to preheat and pre-condition the reservoir, also aiding in carrying heat from the combustion zone towards the rich oil saturation zone. One of the main advantages of SAGDOX is the elimination of most of the nitrogen that otherwise would be injected when using air and this reduces the amount of non-condensable gas (NCG) in the reservoir substantially. Heat delivery to the formation using a combination of steam and enriched air injection is more energy efficient than pure steam injection and reduces the steam-oil ratio compared to SAGD. This also lowers the volumes of steam condensate in the produced fluids and thus reduces the produced water handling and processing requirements. The purpose of this study is to provide data to evaluate the feasibility of the SAGDOX process using a 3-D laboratory physical model. A description of the physical model is provided along with the method of operation. The results from two tests are presented and the findings from the experimental studies are also discussed.
Sand Control Testing for Steam Injection Wells
Fattahpour, V.. (RGL Reservoir Management Inc.) | Mahmoudi, M.. (RGL Reservoir Management Inc.) | Roostaei, M.. (RGL Reservoir Management Inc.) | Wang, C.. (University of Alberta) | Kotb, O.. (University of Alberta) | Nouri, A.. (University of Alberta) | Sutton, C.. (RGL Reservoir Management Inc.) | Fermaniuk, B.. (RGL Reservoir Management Inc.)
Abstract Injector wells in thermal field developments in Western Canada are usually completed by slotted liners. The purpose of liner installation is preventing sand production after a shut-in, keeping a stable wellbore, and providing an appropriate steam distribution. The objective of this paper is to quantify the role of slot width and slot density on the sanding performance of the liner in cycles of injection and shut-in in a SAGD injection well, through a series of laboratory sand control tests. A large-scale sand retention testing facility was developed and employed to conduct a series of tests on slotted liner coupons with different slot widths and densities. These tests were tailored to simulate steam injection and backflow during the shut-in. Three representative particle size distributions for the McMurray Formation were used in this study ranging from coarse to fine sand. The experimental set-up allows to measure the amount of produced sand. Since the produced sand in steam injection wells is not usually cleaned out, the acceptable threshold for sand production in the injector should be more conservative than the same for producer wells. Testing results indicate that the sand control performance of the liner is governed by the slot width and density, and formation particle size distribution. Results indicate a negligible amount of produced sand with gas backflow for a properly designed liner even at very high gas velocities. Historically, there has been little attention to the sand control design for injector wells. This work highlights the significance of slot density and slot width in the sand control performance for steam injection wells. The paper provides the basis for the proper design of an effective sand control in SAGD injectors.
- North America > United States (1.00)
- North America > Canada > Alberta (0.51)
Abstract Steam-assisted gravity drainage (SAGD) is the method of choice to extract bitumen from Athabasca oil sand reservoirs in Western Canada. Bitumen at reservoir condition is immobile due to high viscosity and its saturation is typically large that limits the injectivity of a steam at in-situ condition. In a current industry practice, steam is circulated within injection and production wells. In theory wells, should be converted to SAGD production mode once bitumen at interval is mobile and communication is established between the injector and the producer. Operators try to use temperature fall-off data to predict successful conversion time. Although the bitumen heating sounds simple approach recently three wells fails after steam injection due to steam break-through or sand production. And they are periodically returned to circulation to ramp up production rates and heal the hot spots. Most such failures are associated with early conversion to full SAGD. This paper presents a method to describe physics based initial steam injection timing and describes different Suncor assets viscosity variation with temperature and a proper interval temperature for initiation of steam injection in SAGD process. In this study an analytical tool is developed using time-of-flight (ToF) concept to match the temperature fall-off data. The tool is used to discuss successful and failed cases in Suncor McKay River asset.
Abstract A noteworthy caprock failure occurred on the Joslyn Steam Assisted Gravity Drainage (SAGD) project in 2006 that continues to have a significant impact on the approval process for future SAGD projects. Two major reports were released by Total E&P Canada Ltd. as operator and Alberta Energy Regulatory (AER), respectively. A number of potential mechanisms were postulated within those studies, but without a definitive resolution. Inclusion of a fractured medium in the assessment of caprock integrity has not been extensively studied for detection of failure modes. The objective of this paper is to explore the effects of existence of discontinuities (e.g. fractures or fissures) in caprock, loading conditions, and steam chamber evolution, on surface heave, joint normal and shear displacements. Different modes of failure under various scenarios are presented for fissured and non-fissured caprocks. In this paper, a distinct element code was utilized to simulate the possible mechanisms of caprock failure during SAGD operation with various fracture sets in the Clearwater Formation caprock. Three-dimensional numerical models, including caprock and overburden, were simulated under different load conditions to evaluate the impact of steam injection pressure. The lower bound for maximum operating pressure (MOP) was based on the current AER formula and the upper bound was the injection pressure prior to caprock failure. Multiple realizations of fracture network in caprock were executed to reflect various geomechanical and geometrical properties of fractures. The results were compared with a previous study performed with the assumption of a continuum medium for a non-fissured caprock. For upper bound MOP conditions, the computed maximum vertical displacements at the base of caprock for models assuming 1) no fractures, 2) low fracture intensity, and 3) high fracture intensity were 79, 74 and 68 cm, respectively. It was observed that an increase in fracture intensity results in a reduction in vertical displacement at the base of caprock as well as surface heave. These variations in behavior are significant and illustrate that the assumption of a non-fractured caprock (in caprock integrity studies) may lead to conservative estimates of steam containment and ultimately, underestimation of the risk for caprock failure. At the base of caprock and under lower bound MOP conditions, a few local shear failure zones occurred above the pressurized zone, while for upper bound MOP conditions, larger zones of both shear and tensile failures were computed. It was also noted that the existence of fractures could cause local shear failure in the caprock, even below AER mandated values of MOP. Lastly, the findings of this study, including geomechanical simulations, uncertainties, and risk associated with evaluating caprock containment of SAGD operations were compared with previous studies. The results offer significant insight into our geomechanical understanding of the process in order to avoid a potential caprock failure during thermal projects, as unfortunately was experienced in the Joslyn SAGD steam release incident.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
Abstract Ever since horizontal drilling became prominent decades ago, it has been the goal of oilfield operators to find an effective mechanism for controlling the toe-to-heel flux into the production liner to delay and/or reduce the inflow of unwanted fluids such as water, gas and steam, in order to maximize sweep efficiency and oil production/recovery. Inflow Control Devices (ICDs) are basically flow restrictors installed along the completion string to alter the pressure drawdown on the reservoir by choking back the high permeability/high mobility zones while allowing more influx from the lower permeability/lower mobility zones. In steam assisted gravity drainage (SAGD) production wells the primary goal is to operate at lower subcool while minimizing live steam production. The pace of ICD technology adoption has accelerated amongst the operators since its benefit was made prominent in the Surmont field (Stalder 2012). PetroChinaCanada (formerly known as Brion Energy) recognized the technical opportunity and commenced implementation of an ICD technology trial at its MacKay River asset. The technology selection, ICDs sizing and performace prediction was conducted in 2013 (Becerra et al). In 2014 two SAGD production wells, each located on different pads, were selected to evaluate if ICDs could have a beneficial impact on performance. The purpose of this paper is to present preliminary results of the two ICD producer wells which, as of November 2017, have shown superior performance to their non-ICD neighboring wells after about 6 months of production.
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > MacKay River Oil Sands Project (0.98)
Abstract Co-injection of CO2 or light hydrocarbons with steam in the SAGD process may improve SAGD efficiency and lead to lower greenhouse gas emissions through reduced Steam Oil Ratios (SORs). Various additives are postulated to have differing effects on bitumen recovery, depending on the nature of the reservoir, the operating conditions, and the API gravity of the oil. A PVT study was conducted to investigate the phase behaviour of CO2-, C3-, and C4-bitumen systems at varying concentrations, representing the edge of a SAP steam chamber with the expected temperature range of 70ยฐC to 160ยฐC. A produced and dewatered bitumen sample was collected from the Cenovus Osprey Pilot in the Cold Lake oil sands region and characterized. Constant Composition Expansion (CCE) experiments were conducted on solvent-bitumen systems in the temperature range of 70ยฐC to 160ยฐC. Filtration tests were also conducted at high temperature and reservoir pressure to investigate the effect of solvent type and concentration on asphaltene precipitation. A Peng-Robinson Equation of State (PR-EOS) model was calibrated to measured data for CO2-, C3-, and C4-bitumen systems. Viscosity of the bitumen saturated with CO2, C3, and C4 was measured with an electromagnetic-based viscometer elevated temperatures. Phase equilibrium calculations were performed using the calibrated EOS to predict the solubility of the solvents in bitumen. A correlation was fitted to the measured viscosity data to predict the liquid phase viscosity as a function of solvent solubility and temperature for each solvent. From the CCE tests, two equilibrium phases (i.e., liquid and vapour) were observed for the C3- and CO2-bitumen systems. Three equilibrium phases were observed for the C4-bitumen system at high C4 concentrations. These three phases include a bitumen-rich heavy oil phase, a solvent-rich lighter oil phase, and a vapour phase. Due to the extracting/condensing mechanism and asphaltene precipitation, the bitumen-rich phase formed in C3-bitumen system was lighter than the one in C4-bitumen system. Filtration tests showed more asphaltene precipitation by C3 and C4 dissolution than CO2. Moreover, C3 has more potential for asphaltene precipitation than C4. Viscosity measurements showed that dissolution of C3 and C4 in bitumen resulted in greater viscosity reduction than CO2 dissolution. This difference was more pronounced at lower temperatures. The highest C4 solubility in bitumen and C4 potential for forming a C4-rich liquid phase showed stronger condensing and extracting effect of C4 than C3 and CO2 in solvent-bitumen interactions. Moreover, C4 lead to more bitumen swelling than C3 and CO2. EOS predictions and viscosity measurements indicated that increasing the solvent concentration in a solvent-bitumen system beyond a defined Threshold Solvent Concentration (TSC) has an insignificant effect on solvent solubility and bitumen viscosity reduction.
- North America > United States (1.00)
- North America > Canada > Alberta (0.67)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Turkey > Bati Raman Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
A Cluster-Based Approach for Visualizing and Quantifying the Uncertainty in the Impacts of Uncertain Shale Barrier Configurations on SAGD Production
Zheng, Jingwen (University of Alberta) | Leung, Juliana Y. (University of Alberta) | Sawatzky, Ronald P. (InnoTech Alberta) | Alvarez, Jose M. (InnoTech Alberta)
Abstract Impacts of reservoir heterogeneities in the form of shale barriers on SAGD production can be analyzed by generating a large number of realizations of shale barrier configurations and subjecting them to flow simulation. However, visualizing and quantifying the (dis)similarities among these realizations is often challenging. A workflow that applies multidimensional scaling (MDS) and cluster analysis techniques is developed to represent the uncertain influences of different shale barrier configurations on SAGD production and to quantify the dissimilarities between realizations. A two-dimensional homogeneous simulation model is employed, and reservoir heterogeneities are simulated by superimposing sets of idealized shale barriers on the homogeneous model. The petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. One thousand models with various shale barrier configurations are then subjected to flow simulation to estimate SAGD production in each case. First, a distance function, which measures the dissimilarity in production responses between any two given shale barrier configurations, is formulated. Next, MDS maps the resultant distance matrix into an n-dimensional Euclidean space, where k-means clustering technique is applied to group the models into multiple clusters. Although the precise distribution of shale barriers would vary among models within the same cluster, it is expected that their impacts on SAGD production are similar. Specific features corresponding to the shale barriers in each cluster are analyzed, and they are studied to infer any potential correlation between SAGD production and the particular shale distribution characteristics. The results are employed to revise the original set of realizations by adding new models to clusters with fewer members and removing models from clusters with redundant members. The new models are subjected to flow simulation to verify their membership to the assigned clusters, and good agreement in the results has been observed. Data-driven or AI-based modeling approaches for production analysis have gained much attention over recent years. In most cases, a training data set consisting of many different realizations of reservoir heterogeneity is needed. A key question remains: "how many realizations are needed to span the model parameter space?" The proposed workflow offers an efficient and systematic method for constructing data sets that maximize the spanning of the model parameter space, without exhaustively sampling similar realizations and subjecting them to flow simulation. This is a particularly important consideration when 3D models are utilized. Furthermore, the ability to visualize and select representative models or scenarios from individual clusters has important potential for facilitating improvements in operations design in the presence of reservoir heterogeneities.
- North America > Canada > Alberta > Athabasca Oil Sands (0.34)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.15)
- Research Report > Experimental Study (0.68)
- Overview > Innovation (0.55)