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 (
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.
… And expecting different results. Electrical heating of oil reservoirs has fascinated petroleum engineers for more than 70 years - longer, if you include the use of heaters in Siberian oilfields. The earliest laboratory study was done in Pennsylvania in 1940's. Since then, many more studies and field tests have been carried out, none of which was a commercial success. This paper takes a look at different forms of electrical heating, the supporting theoretical work, and field tests. Additionally, several examples are given illustrating the limitations of electrical heating processes. Also discussed is the logic behind the resurgence of electrical heating in recent years. Not discussed are over 200 patents on electrical heating. The major electrical heating processes are resistance heating, using direct current or low frequency alternating current, induction heating, microwave heating, and heating by means of electrical heaters. These are described briefly, and compared. In applications to oil sands, the intent is to utilize the connate water as the heating element (resistance heating) or oil sands as the dielectric (microwave heating). Induction heating is much less effective but has been tested in many field projects. Shale that has a permeability of zero to fluid flow, is electrically conductive, and thus channels much of the electric current flow in resistance heating, which also has other limitations. Microwaves suffer from low depth of penetration (of the order of 20 cm in oil sands) and low power delivery (of the order of 1 MW as a maximum). The power requirements for a typical SAGD pair, in contrast, are 15-30 MW. Electric heaters have been used in oilfields for many years for near-wellbore heating. Two large field pilots used powerful electric heaters, and were recently shut down. Although electrical heating has not had commercial success, recently there has been a resurgence in various electrical processes, as a means of reducing GHG emissions, under the flawed logic that oilfield use of electricity would displace emissions caused by steam generation.
The CHOPS process involves the growth of high permeability channels (wormholes) into the reservoir. The wormholes provide improved access to the reservoir, thereby substantially increasing oil production rates. As production from a group of CHOPS wells matures, wormhole networks that have developed from different wells often interconnect. This can have negative consequences. For example, water influx into one well will spread readily to a system of interconnected wells.
A better understanding of preferential trends in the development of wormhole networks could allow more optimal placement of CHOPS wells, in terms of their spatial distribution. There are several factors that could influence the direction of wormhole growth in a heavy oil reservoir. The direction of growth may be affected by heterogeneity in the distribution of petrophysical and fluid properties such as permeability, porosity, water saturation, and oil viscosity. The stress field could be another factor.
This paper presents the results of an experimental investigation on the influence of anisotropic (unequal) horizontal principal stresses on the direction of wormhole growth in a sand pack saturated with viscous oil. The experiments were performed in a large rectangular triaxial cell (box). Each of the two perpendicular horizontal stresses and the vertical stress applied to the sand pack could be controlled independently. Oil was injected into the sand pack through flow distributors located on adjacent vertical walls of the cell. The oil flowed through the sand toward a production well in the cell. When a critical flow rate was reached, the sand failed around one of the openings in the well. The failed sand was transported by the oil into the well, resulting in the growth of a wormhole inside the pack.
The experiments indicated that, under the conditions of stress and flow that were applied, there was a tendency for wormholes to grow in the direction of the lower horizontal stress. However, this tendency was overcome when there were significant directional differences in the oil flux (pressure gradient). Then, the wormholes tended to grow in the direction of the largest oil flux. Both behaviours are consistent with the local effective stress conditions at the tip of a wormhole that lead to continuing sand failure there.
Baek, Kwang Hoon (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Sheng, Kai (The University of Texas at Austin) | Sharma, Himanshu (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin)
Water is the most dominant component in steam-based oil recovery methods, such as steam-assisted gravity drainage (SAGD). The central question that motivated this research is whether in-situ bitumen transport in SAGD can be substantially enhanced by generating oil-in-water (o/w) emulsion, in which the water-continuous phase acts as an effective bitumen carrier. As part of the initial stage of the research project, the main objective of this paper is to present the ability of organic alkali to form oil-in-water (o/w) emulsions that are substantially less viscous than the original bitumen.
Experimental studies were conducted for emulsion phase behavior and viscosity for mixtures of Athabasca bitumen, organic alkali, and NaCl brine. Experimental variables included brine salinity, alkali concentration, water-to-oil (WOR) ratio, temperature, and sample-aging time.
The phase behavior study indicated that conditions conducive to o/w emulsions are low alkali concentrations at salinities below 1,000 ppm. At a WOR of 7:3, a single phase of o/w emulsion was observed for 0.5, 1.0, 2.0 and 5.0 wt% alkali with no NaCl, and 0.5 wt% alkali at a salinity of 1,000 ppm at 373 K. At lower temperatures, 323 K and 298 K, flocculation of emulsions in these samples resulted in separation between the bitumen-rich and water-rich o/w emulsions. However, essentially all bitumen content was measured from the bitumen-rich o/w emulsion. The oil contents in these emulsions were more than 70 vol.% at 298 K and 57 vol.% at 323 K. Viscosities of these o/w emulsions ranged between 85 cp and 115 cp at 1.0 s−1, and between 31 cp and 34 cp at 10.0 s−1 at 323 K. At 298 K, they ranged between 105 cp and 250 cp at 1.0 s−1 and between 48 cp and 74 cp at 10.0 s−1. Results in this research show that, in comparison with the original bitumen, bitumen-rich o/w emulsions were 3 to 4 orders of magnitude less viscous at 298 K, and 2 orders of magnitude less viscous at 323 K.
Wu, Yi (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Wang, Zhongyuan (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Han, Bing (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Li, Xiaoman (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Zhou, Guangxing (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Wang, Ziji (E&P Research Institute of Liaohe Oilfield Company, CNPC)
Steam Assisted Gravity Drainage (SAGD) is a widely used thermal recovery method for heavy oil and bitumen. S-13832 reservoir in Liaohe oil field in China is reaching economical limit after several cycles of cyclic steam stimulation (CSS). To improve the recovery, toe-to-heel air injection (THAI) had been field tested, however with unfavorable results. In this study, we analyze the alternative SAGD process and show it as most promising follow-up for CSS in S1-3832 reservoir.
We first conduct comprehensive summary of reasons for the previous THAI trial failure, including lack of knowledge for shale layer distributions, difficulties in control spreading of combustion front and blockage of wellbore. Then, numerical simulation has been performed to investigate the feasibility and advantage of using SAGD process in S1-3832. A fine-grid reservoir model with shale layers carefully characterized for reservoir heterogeneity and oil-water distributions modeled. Finally, history match of the field is carried out and dominant influencing factors for SAGD recovery were determined in order to establish an optimum reservoir development strategy.
Vertical injector-horizontal producer and vertical injector-vertical producer hybrid well configuration is adopted in the type pattern simulation model. Key parameters such as perforation locations, steam quality, production-injection ratio, injection rate and SAGD transition time are optimized. It is observed that steam chamber shape is irregular due to the presence of shale layers in some locations. Based on shale layer characteristics of the reservoir, perforation positions together with injection and production rates are adjusted to improve the conformance in these areas. According to these findings, a practical development strategy is designed. Ultimately, the simulation results show the production rate, accumulative oil-steam ratio and other indicators satisfy the requirement of economic development, with incremental recovery factor of 39%in the SAGD stage.
The optimum development plan has been successfully implemented for more than 1 year now, with monitored temperature showing steam chamber growth in favorable manner in the entire reservoir, even in area above shale barriers. With thermal communication achieved, production rate increases progressively, indicating a smooth transition to SAGD mode. This work has demonstrated SAGD as effective recovery process in S1-3832. It also provides technical guidance for designing follow-up processes to CSS for similar reservoirs.
The fluid flow and transport phenomena are simulated through three-dimensional consolidated and unconsolidated digital rock slabs representing the geological rock types of the McMurray formation. Finite element simulations are carried out in order to solve the mixing advection-diffusion problem, and the effluent history is processed to predict the longitudinal dispersion coefficient and evaluate the efficiency of miscible displacement processes in the presence of microheterogeneities. According to the results, consolidated samples with non-uniform cementation show a different dispersion behavior when compared to both unconsolidated and uniformly cemented rocks, suggesting that the cementation pattern remarkably influences the miscible-flood performance.
Liu, Hao (China University of Petroleum) | Cheng, Linsong (China University of Petroleum) | Huang, Shijun (China University of Petroleum) | Chen, Xiao (China University of Petroleum) | Huang, Qian (China University of Petroleum)
Co-injection of solvent and steam in Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) increases the mobility of highly viscous oil relative to conventional SAGD wherein only steam is injected. This consequently results in higher oil production rates and lower energy consumption relative to SAGD due to the combined benefits of heating and dilution. Current efforts have been made to study mass transfer from a single-component-solvent/steam mixture into the heavy oil at the steam front, while the low-cost multicomponent solvent is actually co-injected with steam on the field, which presents a much more complicated interfacial condition.
In this paper, a generalized methodology has been developed to couple heat and mass transfer of this solvents–steam–heavy oil system at the interface. In the model, the equation of state and fugacity equation are integrated to calculate and analysis the equilibrium state of transition interface. Then, the transition interface model is established based on heat transfer formulations and gaseous phase convective equations. Finally, under the temperature and velocity boundaries, the model is solved by applying implicit Runge-Kutta method and the results are used to analysis the heat and mass transfer characteristics.
The predicted results show that increasing the fraction of lighter solvent can enhance mass transfer, while the heat transferred is seriously deteriorated. Besides, the closer the bubble point temperature and dew point temperature of the stream is, the smaller the elevation of mass transfer will be, but the heat transfer is almost unaffected. Therefore, to realize the best effects of heat and mass transfer, solvents with larger saturation temperature difference should be applied, and the composition of the solvents should be carefully determined according to the formation properties and solvent components.
Conducting an ES-SAGD project on a field has many challenges, especially considering its main economic factors: production increase and solvent cost. With the new methodology, an optimum multicomponent solvent can be screened from the ocean of solvent candidates for a best heat and mass transfer performance in an ES-SAGD process and hence the oil flux at the chamber edge can be maximized with a minimized solvent cost. Therefore, it is of fundamental and practical importance to study the coupled heat and mass transfer of multicomponent solvents–steam–heavy oil system at the interface.
The CHOPS process involves the growth of high permeability channels (wormholes) into the reservoir. The wormholes provide improved access to the reservoir, thereby substantially increasing oil production rates. Field evidence and laboratory experiments indicate that wormholes tend to persist as stable high-permeability flow channels throughout the duration of the CHOPS process.
The existence of wormholes in the reservoir needs to be taken into consideration in the design of post CHOPS recovery processes. One of the key issues is the stability of wormholes during the re-pressurization phase of any follow up process to CHOPS. For example, wormholes could remain as stable high permeability flow channels to deliver injected fluids into a reservoir or they could collapse to improve conformance for fluid injection.
This paper presents the results of experiments testing the stability of wormholes under conditions that could be destabilizing such as cold and hot water circulation, heating, and pressurization with hydrocarbon gases (e.g., methane, ethane). The experiments were performed in a triaxial cell, approximately 19 cm in diameter and 18 cm long, packed with water-wet sand and saturated with heavy oil. Wormholes were generated in the pack by injecting heavy (dead) oil into the cell at a sufficiently high rate to produce sand from the pack. Then, conditions that could be destabilizing to wormholes were applied to test their outcome.
Cold water flowing through the wormhole eroded its walls, eventually causing the pack to collapse after more than a week. The injection of hot water accelerated the process of erosion considerably. Heating the pack did not cause it to collapse, but the wall of the wormhole was destabilized to a limited extent in that the diameter of the wormhole increased by more than a factor of two. The heating reduced the viscosity of the heavy oil in the pack, causing the apparent strength of the sand to decrease. Pressurizing the sand pack with methane and then slowly depressurizing it did not destabilize the wormhole. However, pressurizing the pack with ethane caused the sand matrix surrounding the wormhole to collapse over a period of two weeks. As in the case of heating, dissolution of ethane into the heavy oil caused the apparent strength of the sand to decrease by reducing the viscosity of the heavy oil in the pack.
Although the confining pressure in these experiments was relatively low, the experimental cell did not allow for stress redistribution due to the deformation of the sand matrix, as would occur in the field. For this reason, the wormholes generated in the experiments were less stable than ones in the field. Consequently, the laboratory conditions that resulted in wormhole collapse should be regarded as a guide to the behaviour that would be expected in the field.
Nguyen, Ngoc T. B. (University of Calgary) | Dang, Cuong T. Q. (Computer Modeling Group Ltd.) | Yang, Chaodong (Computer Modeling Group Ltd.) | Nghiem, Long X. (Computer Modeling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Steam Assisted Gravity Drainage (SAGD) has been widely applied to unlock hydrocarbon resources in oil sands reservoirs. This method uses steam, which is generated at the surface, to heat a formation and create a steam chamber around an injector. Past studies have indicated that reservoir heterogeneity is one of the crucial factors that directly affectthe performance of the SAGD process. This paper presents an innovative integrated modeling approach for evaluating, assisted history matching, and production forecasting of the SAGD process with the presence of a complex shale barrier system in oil sands reservoirs.
As SAGD is a strongly geological dependent recovery process and, unfortunately, there are many uncertainties associated with reservoir geology in reality. Therefore, it requires generating a large number of geological realizations to capture the critical effects of geology, especially with the presence of shale barriers, in history matching and field development planning of the SAGD process. To quantify the impact and improve the quality of history matching compared with the traditional method, an efficient integrated workflow has been developed in which geological information generated from a geological modeling package is automatically updated for a reservoir simulator and controlled by an intelligent optimizer in a big-loop modeling approach.
A detailed workflow on the integrated modeling approach that includes shale barriers for a typical oil sands reservoir is described in the first section of this paper. Shale bodies are geostatistically distributed in the geological models. A comprehensive parametric study was conducted with numerous geological realizations to identify the critical role of shale barriers in SAGD performance including shale geometry, shale length and thickness, shale distribution and proportions. Then the Bayesian algorithm with a Proxy-based Acceptance-Rejection sampling method is employed for assisted history matching of SAGD production profiles. With the presence of complex shale barriers, it requires simultaneous updating of both geological and reservoir engineering parameters. Using the proposed approach, the global history matching errors were drastically reduced in all production wells. Validation results indicate that the integrated modeling approach effectively helps to update the properties and distribution of shale barriers to find the closest geological distribution compared to the true solution. Finally, an ensemble of the best-matched simulation models is used to perform a probabilistic forecasting to capture the uncertainties in future production profiles.
Not limited to history matching ofthe SAGD process, the proposed approach can be also applied to different complex problems such as robust optimization for various recovery methods from conventional to unconventional reservoirs.
Shale barriers may act as flow barriers with adverse impacts on the steam chamber development, as observed in numerous field-scale SAGD projects. Efficient parameterization and inference of such heterogeneities in 3D models from production data remain challenging. A novel workflow for SAGD heterogeneity inference by integrating data-driven modeling and production time-series data analysis is presented.
Variation of shale barriers along the directions between the cross-well pair, as well as of the horizontal wellbore, is considered. Based on a dataset gathered from the public domain, a set of reservoir and operational parameters that represent the typical Athabasca oil sands conditions are extracted to build a 3D homogeneous (base) model. The heterogeneous models are constructed by superimposing shale barriers with varying volume, geometry and locations onto the base model. Production data is recorded by subjecting the generated models to numerical simulation. Input features are extracted from the production time-series data, while output parameters are formulated based on the distribution of shale barriers in the generated models. Data-driven models, such as artificial neural network (ANN), are applied to approximate the non-linear relationships between input and output variables, facilitating the inference of shale characteristics. The final outcome is an ensemble of 3D models of heterogeneity that honor the actual SAGD production histories.
A decline in oil production is observed when the steam chamber encounters a shale barrier. The proposed workflow can capture the observed production patterns effectively. The proposed methodology is demonstrated to be useful for characterizing shale heterogeneities. A testing dataset is used to assess the consistency between model predictions and the target values. In addition, the production responses corresponding to the characterized heterogeneous models are in agreement with the actual responses.
Previous data-driven modeling studies involving 3D heterogeneity inference and SAGD production analysis are limited. The issue of parameterizing a large number of possible heterogeneity descriptions is still challenging. This work presents a preliminary effort to explore this issue. It offers a significant potential to extend most widely-adopted data-driven modeling approaches for practical SAGD production data analysis. The outcomes serve to support the use of data-driven models as complementary and computationally-efficient tools for inference of shale barriers.