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Collaborating Authors
Improved and Enhanced Recovery
Abstract The majority of oil sands are too deep for surface mining extraction; hence, in-situ techniques such as Steam-Assisted Gravity Drainage (SAGD) must be used. However, SAGD in low-pressure, top water, reservoirs shows relatively poor performance. To improve SAGD, solvent can be co-injected with steam, as in Expanding Solvent SAGD (ES-SAGD) leading to enhanced recovery, rates, and efficiency. Like most pressurized processes, a competent caprock is needed to prevent steam losses to maintain good efficiency and rates. There exist significant oil sand resources that are considered inaccessible because they are shallow (low-pressure) with little or no caprock with top water zones. Solvent addition allows reduced operating pressure, which makes it amenable for low pressure, shallow reservoirs. This research examines ES-SAGD, with non-condensable gas co-injection, in reservoirs with top water that has the potential to quench the chamber and stagnate oil drainage. The results reveal complex dynamics between the depletion chamber and overlying water zone and operating strategies that extend the life of the chamber thus raising the recovery factor. Low-pressure ES-SAGD operating strategies can be used to efficiently recover bitumen from shallow reservoirs with top water. A key finding from this study is that addition of non-condensable gas to ES-SAGD can significantly improve recovery, rate, and efficiency. Given the volume of shallow oil sands reservoirs with top water, development of processes to unlock this type of resource is important and critical to further growth of in situ oil sands recovery in Alberta. The results provide a technical basis to construct feasible low-pressure ES-SAGD processes for this type of reservoir.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.82)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Method to Improve Thermal EOR Performance Using Intelligent Well Technology: Orion SAGD Field Trial
Clark, H. P. (Shell) | Ascanio, F. A. (Shell) | Van Kruijsdijk, C.. (Shell) | Chavarria, J. L. (Shell) | Zatka, M. J. (Shell) | Williams, W.. (Shell) | Yahyai, A.. (Shell) | Shaw, J.. (Halliburton) | Bedry, M.. (Halliburton)
Abstract A method has been developed for improving both steam injection and production conformance in a thermal EOR project by utilizing intelligent well technology incorporating interval control valves (ICV), well segmentation and associated downhole instrumentation. This provides the ability to selectively open and close segmented sections of the well bore and monitor the key parameters of temperature and pressure from surface. The initial field trial is ongoing in the injector of an Orion field SAGD well pair. Development of the completion system suitable for thermal conditions, initial field trial results and plans for further development are described. Modelling shows that, depending on the level of heterogeneity present in the reservoir, an improvement of 20 to 40% in the steam oil ratio and 5 to10 % in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost effective solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is applicable to a wide range of EOR processes such as CSS, steam drive and variations. The initial field deployment in the injector well was primarily to prove operability of the system in high temperature thermal applications, to demonstrate the feasibility of modifying steam distribution and to learn for future optimization and deployment of the system. A successful installation and commissioning has substantially validated the completion technology. Early injection test results and data provide a significant improvement in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of steam injection in the well is underway and the preliminary results are discussed. Lessons learned from the trial are highlighted. The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects to improve performance.
- North America > United States (0.89)
- North America > Canada > Alberta (0.89)
- 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 > Orion Oil Sands Project (0.99)
- North America > United States > Alaska > North Slope Basin > Orion Field > Schrader Bluff Formation (0.98)
Geostatistical Modeling and Numerical Simulation of the SAGD Process: Case Study of an Athabasca Reservoir With Top Water and Gas Thief Zones
Bao, X.. (University of Calgary) | Chen, Z. J. (University of Calgary) | Wei, Y.. (University of Calgary) | Sun, J.. (University of Calgary) | Dong, C. C. (University of Calgary) | Deng, H.. (University of Calgary) | Song, Y.. (University of Calgary)
Abstract Overlying top water and gas thief zones have a detrimental effect on the Steam-Assisted Gravity Drainage (SAGD) recovery process since steam penetrates into these zones which results in great heat loss. Due to the presence of these top thief zones, recovering bitumen by the SAGD process has become challenging in the Surmont lease of an Athabasca oil sand reservoir. Previous numerical simulations, laboratory experiments and field production data have demonstrated that oil production and steam-oil ratios tend to decrease as the depletion of top gas continues; also, heat loss to the overlying thief zone will be more significant when a top water zone is present. However, an optimal operating strategy for the full field scale SAGD process with both top gas and top water remains uncertain. The objective of this paper is to construct a 3D geostatistical model for a Surmont pilot and implement sensitivity study in SAGD simulation aiming at investigating the impact of the top thief zones on bitumen recovery. The major steps involved in the 3D geostatistical modeling process consist of structural, facies and property modeling and uncertainty analysis. Facies-based log-derived porosity, permeability and water saturation are populated into a grid block by Sequential Gaussian Simulation (SGS) in the petrophysical modeling process. Then a static model is further downscaled to finer simulation grids, and a submodel for each single well pair is extracted for the purpose of history match in the STARS™ simulator. Reasonable history match of oil and water rates has been achieved by calibrating this static model with field production data. The steam chamber pressure and temperature profiles from the numerical model have been conformed to the field data from the observation wells. Sensitivity analysis of the thief zones pressure, thickness and area extension has been conducted to simulate the impact of the top thief zones. Optimization of cumulative steam oil ratios (cSOR) and recovery factors by varying the steam trap control and injection pressure with the top thief zones has been investigated in great detail. Finally, integrated optimization strategies have been developed and tested on a full field-based heterogeneous simulation model.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- 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 > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)
Abstract Steam Assisted Gravity Drainage (SAGD) is a widely used enhanced oil recovery process applied in Canadian oil sands projects. Operators of SAGD projects have long been aware that many factors such as near wellbore geology, tubular sizes, lengths, and the allocation of fluid rates between tubulars in multi-string completions, can significantly impact the effectiveness of well and well- pair operations. The interaction of well components within these complex wells and the reservoir can impact the economic and technical success of the entire project either positively or negatively, suggesting that a means of optimizing this interaction that couples wellbore effects with the reservoir is required. Simulation studies were carried out to investigate the impact of wellbore design optimization on the well's performance. Reservoir simulation was used as a tool to evaluate the advantages derived from the optimization of wellbore and tubular design for thermal projects using a new fully coupled reservoir-wellbore modeling approach linked to an optimization algorithm. This paper presents results that cover important aspects such as the impact of geological heterogeneity on wellbore design; the optimization of length and positioning of multiple tubular strings within a liner for both injection and production wells; and the optimization of the allocation of injected steam between multiple tubing strings. The results indicate positioning of tubulars in a multiple tubing completion SAGD well pair have a significant impact on the steam chamber growth, productivity, SOR and ultimately on NPV. This paper presents results of two optimization cases. The base case wellbore completion had two tubing strings, the short tubing string was landed at the heel while the long tubing string was landed at the toe of the horizontal SAGD well pair. First optimization was performed by changing the length/placement of tubing strings in the injector and the producer. Optimization of tubing placement increased the NPV of the well pair from 16.3 M$ to 20.7 M$ over 8 years. The Second optimization study was performed including the tubing placement similar to the previous case along with the SAGD operating strategy in terms of steam injection rate that was allowed to change every two years. In this case the NPV was optimized from 16.3 M$ to 25.79 M$ over 8 yrs.
Abstract Enhanced oil recovery by polymer flooding and advanced (multi-lateral) wells has been applied to develop China's offshore heavy oil reservoirs. Current commercial simulators lack the ability of modeling polymer flooding processes and multi-segment wells simultaneously, thus limits their application in making reliable production predictions and the overall development plan. In this work, a black-oil simulator is extended to model polymer flooding by adding brine and polymer pseudo-components to the governing equation. The polymer solution, reservoir brine and the injected water are represented as miscible components of the aqueous phase. Necessary factors have been taken into account for the construction of mathematical model, such as inaccessible pore volume, polymer shear thinning effect, polymer adsorption, and relative permeability reduction factors, etc. These polymer-induced effects, modeled as nonlinear relationships, are based on lab experiments conducted upon core and PVT samples from China's heavy oil reservoirs in Bohai Bay. A fully implicit formulation is applied to solve the governing equations. In modeling of the multi-lateral wells which are commonly applied in Bohai Bay oil fields, the multi-segment well approach is adopted. The well index (productivity index) is calculated using a 3D projection method based on Peaceman's model. This method is extended to enable its application in both structured and unstructured grid system to fully resolve complex geometrical interaction between multi-lateral wells and the reservoir. The pressure and fluid concentration distribution along wellbores is calculated through the homogeneous model, the result of which can better describe the true physics in the wellbore. This work, for the first time, provides the development framework to model polymer flooding and advanced wells for EOR in heavy oil fields. Comparing with numerical results from commercial simulators, this model yields better accuracy and more importantly, enables the modeling of polymer flooding processes and multi-segment wells simultaneously.
- Asia > China (1.00)
- North America (0.93)
- Asia > China > Bohai Bay > Bohai Basin > Jidong Nanpu Field (0.99)
- Asia > China > Bohai Basin (0.99)
- North America > United States > Louisiana > China Field (0.96)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells. The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore. Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 10m/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.
- North America > United States (0.93)
- Asia > Middle East (0.68)
- Europe (0.67)
- North America > Canada > Alberta (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Performance Analysis and Field Application Result of Polymer Flooding in Low-Permeability Reservoirs in Daqing Oilfield
Fenglan, W.. (Daqing Oilfield) | Xia, L (Daqing Oilfield) | Siyuan, L.. (China University of Geosciences) | Peihui, H.. (Daqing Oilfield) | Wenting, G.. (Daqing Oilfield) | Yonghui, Y.. (Daqing Oilfield Design Institute)
Abstract The polymer flooding technology in high and medium permeability reservoirs has been applied commercially in Daqing Olifield since 1996. It has become an important supporting technology for both the stable output of Daqing Oilfield and the development improvement of the mature oilfields. In order to study EOR method in low permeability(less than 100mD) reservoirs, pilot tests of polymer flooding were performed in Daqing oilfield. According to the research results, the low-molecular weight polymer (400800 Dalton) can be continuously injected into low permeability reservoirs under the specified well spacing. Pilot tests of polymer flooding show that oil production was increased from 1.06 tons/d to 3.04 tons/d and water cut was decreased from 96.0% to 89.8% in low permeability reservoirs. Formations with extra-low permeability(less than 10mD) are not flooded effectively in the process of polymer flooding. Production performance of polymer flooding in low permeability reservoirs can be improved by measures of fracturing or separate zone injection with different molecular weight polymers. Comparison and analysis on injection profiles and productivity profiles at different injection polymer parameters showed that the polymer solution with low-molecular weight and relative high concentration was suitable for polymer flooding in low permeability reservoirs. Numerical simulation and pilot results both showed that more than 5% OOIP were obtained by polymer flooding over that of water flooding in low permeability reservoirs in Daqing oilfield.
- Asia > China > Heilongjiang > Songliao Basin > Saertu Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract This paper is the report for the second stage research of nano-particle and surfactant-stabilized solvent-based emulsion experimental study for the heavy oil in Alaska North Slope Area. The core flooding studies under laboratory conditions were implemented after the bench tests, which is including the phase behavior test, rheology studies and interfacial tension measurement. And these studies provide the optimum selecting method for the nano-emulsion which could be used in the core flooding. The experiment results suggest this kind of emulsion flooding is a good optional EOR (enhanced oil recovery) process for heavy oil reservoirs in Alaska, Canada after primary production, where heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems. Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nanoemulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation. In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat. In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.90)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Experimental Characterization of Production Behavior Accompanying the Hydrate Reformation in Methane Hydrate Bearing Sediments
Ahn, T.. (Seoul National University) | Park, C.. (Kangwon National University) | Lee, J.. (Korea Institute of Geoscience and Mineral Resources) | Kang, J. M. (Seoul National University) | Nguyen, H. T. (Seoul National University)
Abstract The paper analyzed experimentally the production characteristics of hot-brine stimulation accompanying the hydrate reformation in the presence of methane hydrate. Many attempts have been to recover commercially the methane hydrate such as depressurization, thermal stimulation, and inhibitor injection. Hot-brine injection coupling thermal recovery with inhibitor injection has been investigated as one efficient production scheme but the hydrate reformation during the dissociation is problematic, that influences negatively the recovery rate. An experimental apparatus divided the steel body into 12 blocks not only to describe one-dimensional dissociation effectively but to control the temperature accurately. The specified amount of methane hydrate were formed artificially in unconsolidated and packed sediments where average particle size, absolute permeability, and porosity were 260 μm, 4.4 D, and 42 %, respectively. The production trends were observed in the temperature range, 283.85 ~ 303.15 K and in the injection rate, 10 cc/min and 15 cc/min, respectively. Methane hydrate reformed in all tests, of which reason can be the recombination of water and dissociated methane at downstream zones. In early time, the production rate was low but it increased significantly in late time. The former was why most gas dissociated in upstream were consumed to reform hydrate in downstream while the latter was to combine both dissociation amount of initial and reformed hydrate. The dissociation front moved fast at the higher temperature and injection rate. The production efficiency of 15 cc/min and 294.55 K was similar to that of 10 cc/min and 303.15 K. The results confirmed the production behavior of methane hydrate under the reformation phenomenon and could provide with the fundamentals to develop the efficient production scheme based on hot-brine stimulation.
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract Foamy oil viscosity is a controversial topic among researchers as to what happens to the apparent oil viscosity when the dispersed gas bubbles start migrating with the oil. For conventional oils, below the true bubble point pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent viscosity of gas-in-oil dispersion remains relatively constant, or perhaps declines slightly between the true bubble point and a characteristic lower pressure, called pseudo bubble point, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead oil value at atmospheric pressure. However, it is a well known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy oil viscosity being lower than the oil viscosity is counterintuitive. The major difference here is the extreme viscosity of the base liquid phase for foamy oil and how this interacts with the gas phase in a porous medium. The reported results appear to be very oil specific in this area, and are also a very strong function of how rapidly pressure is depleted in a given system. It is also likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity due to the size of dispersed bubbles being comparable to the pore sizes. This study aims to investigate this issue by measuring the foamy oil viscosity under varied conditions. The effect of several parameters, such as shear/flow rate, and gas volume fraction and type of viscometer employed, on foamy oil viscosity was experimentally evaluated. Three different viscosity measurement techniques, including Cambridge viscometer, capillary tube as well as a slim tube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling needle viscometer correlate better with the observed behavior in the slim tube than the capillary viscometer results. Also, unlike live oils, the apparent viscosity of foamy oils was flow rate dependent. Overall, the viscosity of foamy oil was found to be similar to live oil viscosity for a large range of gas volume fraction.
- North America > United States (0.94)
- North America > Canada > Alberta (0.48)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)