Steam-assisted Gravity Drainage Performance Research Articles

Novel insights on initial water mobility: Its effects on steam-assisted gravity drainage performance

Steam-assisted gravity drainage (SAGD) is a primary commercial in-situ thermal recovery method for oil sands/bitumen in Alberta, Canada. Evidence of initial water mobility during the SAGD processes has been observed by previous studies, yet little research has been done on its effects on SAGD performance. In this study, initial water movement ahead of the steam chamber is investigated and its effects on the steam chamber development, as well as well production performance are quantified. Initial water mobility is firstly classified into two categories (low and high) based on the shapes of their steam chambers. Results show that initial water mobility can change the shape of steam chamber, pressure distribution in the reservoir and the steam condensate flow pattern along steam chamber edge. Cumulative oil production in nine years for the low initial water mobility scenario is 18.1% higher than that of the immobile initial water scenario due to the convective heat transfer induced by initial water flow ahead of the steam chamber. On the other hand, cumulative oil production in nine years of the high initial water scenario is 34.6% lower than that of immobile scenario. For the adjacent well pairs located in the same pad, compared to immobile initial water case, low initial water mobility case with the same injection pressure has the highest NPV, while high initial water mobility has a negative impact on SAGD performance. An injection pressure difference of only 200kPa for the high initial water mobility case can reduce NPV by 40%.

On the evaluation of steam assisted gravity drainage in naturally fractured oil reservoirs

Abstract Steam Assisted Gravity Drainage (SAGD) as a successful enhanced oil recovery (EOR) process has been applied to extract heavy and extra heavy oils. Huge amount of global heavy oil resources exists in carbonate reservoirs which are mostly naturally fractured reservoirs. Unlike clastic reservoirs, few studies were carried out to determine the performance of SAGD in carbonate reservoirs. Even though SAGD is a highly promising technique, several uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications especially in naturally fractured reservoirs. In this communication, the effects of some operational and reservoir parameters on SAGD processes were investigated in a naturally fractured reservoir with oil wet rock using CMG-STARS thermal simulator. The purpose of this study was to investigate the role of fracture properties including fracture orientation, fracture spacing and fracture permeability on the SAGD performance in naturally fractured reservoirs. Moreover, one operational parameter was also studied; one new well configuration, staggered well pair was evaluated. Results indicated that fracture orientation influences steam expansion and oil production from the horizontal well pairs. It was also found that horizontal fractures have unfavorable effects on oil production, while vertical fractures increase the production rate for the horizontal well. Moreover, an increase in fracture spacing results in more oil production, because in higher fracture spacing model, steam will have more time to diffuse into matrices and heat up the entire reservoir. Furthermore, an increase in fracture permeability results in process enhancement and ultimate recovery improvement. Besides, diagonal change in the location of injection wells (staggered model) increases the recovery efficiency in long-term production plan.

Prediction of steam-assisted gravity drainage steam to oil ratio from reservoir characteristics

Forecasts suggest that production of bitumen from oil sands reservoirs will increase by a factor of at least 2.5 times over roughly the next 15 years. Although a significant economic benefactor to the Canadian economy, there are challenges faced by oil sands operators with respect to greenhouse gas emissions and water consumption. For the Athabasca deposit, the current oil recovery process of choice is the SAGD (steam-assisted gravity drainage) method where high temperature and high pressure steam is injected into the oil sands formation. At present, there are more than ten SAGD operators in Alberta, Canada and results to date reveal that the geology of the reservoir impacts SAGD performance. Given the growth of the SAGD industry in Alberta, forecasting tools are required that can predict performance versus reservoir characteristics. Here, we present a neural network-based model to predict the SOR (steam-to-oil ratio) in oil sands reservoirs by using log and core data to characterize the reservoir porosity, permeability, oil saturation, depth and thickness. Our analysis confirms that the lower the porosity, permeability, and oil saturation of the reservoir, the worse the performance of the operation. In other words, the lower the quality of the reservoir, the lower the oil rate, and the higher the SOR. Our analysis also shows that well performance (i.e., SOR), is predictable with a relatively high degree of accuracy (R2∼0.80) using log and core data via a neural network model. These results imply that the depth of the reservoir, gamma ray readings, and permeability are the most important determinants of the variation in SOR.

Investigation of initial water mobility and its effects on SAGD performance in bitumen reservoirs and oil sands

Abstract Steam assisted gravity drainage (SAGD) has become a preferred in-situ recovery technology for oil sands and bitumen deposits in Canada. In some production history matching studies, the initial water was found to be mobile in SGAD projects, which could cause high steam loss, difficult pressure control, high steam oil ratio (SOR), etc. It is crucial to determine the initial water mobility in order to optimize SAGD performance. In this paper, a novel method is presented to effectively determine the mobility of initial water existing as the continuous wetting phase in the bitumen reservoirs. More specifically, wax was used as the oil phase, for the first time, to simulate the immobile oil phase in bitumen reservoirs and oil sands. Experimental results indicated that the interstitial water could still flow when the water saturation was as low as 5% in the simulated bitumen-water system. A triangular tube bundle model was constructed and tuned to match the experimental results. The model was used to simulate the water relative permeability curves at different initial water saturations. A correlation of the initial water mobility with the initial water saturations was developed through data analysis. The impact of initial water movement on SAGD operations was illustrated using an analytical approach, and the associated energy loss was calculated. The results showed that the initial water mobility can lead to severe energy loss.

Characterizing the Effects of Lean Zones and Shale Distribution in Steam-Assisted-Gravity-Drainage Recovery Performance

Summary Performance of steam-assisted gravity drainage (SAGD) is influenced significantly by the distributions of lean zones and shale barriers, which tend to impede the vertical growth and lateral spread of a steam chamber. Previous literature has partially addressed their effects on SAGD performance; however, a comprehensive and systematic investigation of the heterogeneous distribution (location, continuity, size, saturation, and proportions) of shale barriers and lean zones is still lacking. In this study, numerical simulations are used to model the SAGD process. Capillarity and relative permeability effects, which were ignored in many previous simulation studies, are incorporated to model bypassed oil. Numerous ranking schemes are formulated to analyze various aspects of SAGD performance. A detailed sensitivity analysis is performed by varying the location, continuity, size, proportions, and saturation of these heterogeneous features. Lean zones and shale lenses (imbedded in a region of degraded rock properties) with different sizes and degrees of continuity are placed in areas above the injector, below the producer, or in between the well pair. It is noted that among numerous parameters that influence the ultimate recovery, remaining bypassed oil, chamber advancement, and heat loss, continuity and position of these features in relation to the well pair play a particularly crucial role. Neural network modeling is subsequently used for constructing data-driven models to identify and propose a set of input variables for correlating relevant parameters or measures, which are descriptive of the heterogeneity and properties of the shale barriers and lean zones, to recovery and ranking results. This work provides a guideline for assessing the impacts of reservoir and saturation heterogeneities on SAGD performance. A set of input variables and parameters that have significant impacts on the ensuing recovery response is identified. One can define readily the proposed set of variables from well logs and apply immediately in data-driven models with field data and scaleup analysis of experimental models to assist field-operation design and evaluation. One can also extend the approach presented in this paper to analyze other solvent-assisted SAGD processes.

Fast screening of geostatistical realizations for SAGD reservoir simulation

Abstract Identifying the range of dynamic reservoir performance responses requires conducting numerical flow modeling on geostatistical realizations. The extent of steam-assisted gravity drainage (SAGD) models, multiple horizontal well-pairs, and simultaneous flow of heat and fluids make a single SAGD simulation computationally burdensome. Therefore, it is impractical to simulate all hundreds of SAGD realizations. We have introduced a static measure based on average harmonic permeability called the ( k H ) A method to help rank realizations for their SAGD performance. The high correlation between the ( k H ) A method and the thermal simulation results shows that the ( k H ) A method is a useful ranking tool and helps to select a few realizations exhibiting distinct responses for detailed flow modeling. By testing the method against several datasets, it is shown to be easy to apply, fast to run, reliable and robust compared to other methods.

Integrated cluster analysis and artificial neural network modeling for steam-assisted gravity drainage performance prediction in heterogeneous reservoirs

Evaluation of steam-assisted gravity drainage (SAGD) performance that involves detailed compositional simulations is usually deterministic, cumbersome, expensive (manpower and time consuming), and not quite suitable for practical decision making and forecasting, particularly when dealing with high-dimensional data space consisting of large number of operational and geological parameters. Data-driven modeling techniques, which entail comprehensive data analysis and implementation of machine learning methods for system forecast, provide an attractive alternative.In this paper, artificial neural network (ANN) is employed to predict SAGD production in heterogeneous reservoirs, an important application that is lacking in existing literature. Numerical flow simulations are performed to construct a training data set consists of various attributes describing characteristics associated with reservoir heterogeneities and other relevant operating parameters. Empirical Arps decline parameters are tested successfully for parameterization of cumulative production profile and considered as outputs of the ANN models. Sensitivity studies on network configurations are also investigated. Principal components analysis (PCA) is performed to reduce the dimensionality of the input vector, improve prediction quality, and limit over-fitting. In a case study, reservoirs with distinct heterogeneity distributions are fed to the model. It is shown that robustness and accuracy of the prediction capability are greatly enhanced when cluster analysis are performed to identify internal data structures and groupings prior to ANN modeling. Both deterministic and fuzzy-based clustering techniques are compared, and separate ANN model is constructed for each cluster. The model is then tested using a validation data set (cases that have not been used during the training stage).The proposed approach can be integrated directly into most existing reservoir management routines. In addition, incorporating techniques for dimensionality reduction and clustering with ANN demonstrates the viability of this approach for analyzing large field data set. Given that quantitative ranking of operating areas, robust forecasting, and optimization of heavy oil recovery processes are major challenges faced by the industry, the proposed research highlights the significant potential of applying effective data-driven modeling approaches in analyzing other solvent-additive steam injection projects.

A Study of Enhanced Heavy Oil Recovery by Two Well Cyclical Steam Assisted Gravity Drainage (TWC-SAGD) in Conventional and Fractured Reservoirs

Steam-assisted gravity drainage is one of the most promising strategies to develop huge heavy oil and bitumen accumulations. Like the other thermal processes, this method aims at reducing oil viscosity by increasing the temperature. But in an economical point of view, it requires a great volume of steam for injection. Moreover, early breakthrough of steam and high steam-oil ratio makes it uneconomical, especially in long production time. In this study, a new method, two wells cyclical steam-assisted gravity drainage is compared with a conventional steam-assisted gravity drainage process. Well configuration in two wells cyclical steam-assisted gravity drainage is the same as the steam-assisted gravity drainage process, but injection and production is cyclical with soaking time, like cyclical steam stimulation. Simulation results showed that two wells cyclical steam-assisted gravity drainage has a higher recovery and lower steam-oil ratio. Especially in long production times, two wells cyclical steam-assisted gravity drainage becomes more and more economical. The cyclical nature of this process gives enough time for a high temperature front to spread in the soaking time and much less steam volume is required for injection. The effect of existence of horizontal and vertical fractures, fracture spacing, and fracture density on the two wells cyclical steam-assisted gravity drainage process was investigated. It was found that vertical fractures improve two wells cyclical steam-assisted gravity drainage performance, but horizontal fractures decrease oil recovery. Furthermore, horizontal fractures between injector-producer wells had an insignificant effect on this process.

A New and Practical Workflow for Large Multipad SAGD Simulation—An Oil-Sands Case Study

Summary Every simulation engineer wishes to simulate large full-field models, but historically reservoir simulation of the steam-assisted-gravity- drainage (SAGD) process has been constrained to single-well models up to a single pad. Models of these sizes provide valuable information and have helped to assess the development potential of reservoirs. These models may be used for reservoir management and to support the decision-making process for the design of the initial completion, operating strategy, and multipad wind-down evaluations, and also qualitatively assess the uncertainty in the SAGD forecast under different geological settings. However, in many cases we are left with the question of how multiwell and multipad communications ultimately affect performance at the well-pair scale. Because of technological constraints with computer hardware and simulation technology, running extremely large multipad models has been until recently largely impractical, especially when trying to run multiple scenarios to better understand the impact of geological and operational uncertainty. In this paper, we present a new and practical workflow that makes running extremely large multipad, multimillion-grid-cell SAGD models a reality. The three major steps of the workflow are (1) generating simulation-friendly geomodels, (2) use of experimental design and 3D submodels on the basis of SAGD performance index (SPI) for numerical tuning, and (3) use of 2D cross sections and SPI to develop dynamic grid-refinement-parameter values for the full 3D model. All of these steps are intended to improve the numerical stability and run time of multipad SAGD simulation models. A 24-SAGD-well-pair model with 2.52 million gridblocks was simulated for 10 years of forecast. The reservoir is geologically complex and highly heterogeneous. We discuss some of the important aspects that need to be accounted for when simulating large-scale SAGD models. Using this new workflow, the simulation run time was reduced from 42 days to 7 days on eight central processing units (CPUs)—a six-time speedup. The resulting run time is short enough to facilitate multirealization simultaneous runs using eight CPUs, hence maximizing the throughput and minimizing the simulation cycle time. This new workflow can be easily replicated and, more importantly, automated to reduce engineering time requirements. While this paper focuses on the SAGD process, this methodology is completely generic in that it can be applied to any large data set for any process. Details will differ depending on the process, but the workflow will be the same.

Connectionist Model to Estimate Performance of Steam-Assisted Gravity Drainage in Fractured and Unfractured Petroleum Reservoirs: Enhanced Oil Recovery Implications

Steam-assisted gravity drainage (SAGD) is an enhanced oil recovery technology for heavy (or viscous) oil and bitumen that involves drilling two horizontal wells in underground formations. Laboratory work, pilot-plant studies, and mathematical model development, which are generally costly, difficult, and time-consuming tasks, are taken into account as important stages in finding an effective and economical method and also predicting the performance of the SAGD technique for a certain heavy-oil reservoir. Currently, smart techniques as accurate and fairly fast tools are highly recommended for these purposes. In this work, an experimental study and an artificial neural network (ANN) linked to an optimization technique, called particle swarm optimization (PSO), were employed to obtain performance parameters such as the cumulative steam-to-oil ratio (CSOR) and recovery factor (RF) for the SAGD process. The outputs of the developed connectionist modeling (i.e., ANN–PSO) were compared with actual data, showing a...

Effect of operational parameters on SAGD performance in a dip heterogeneous fractured reservoir

Steam Assisted Gravity Drainage (SAGD) has been studied theoretically, experimentally and numerically as a promising EOR process. Most of the simulation works have been conducted microscopically in homogeneous non-dipping models. In this communication, the effect of operational parameters on SAGD performance is investigated in a dip heterogeneous naturally fractured reservoir (NFR) with oil wet rock using CMG-STARS thermal simulator. The results indicate that reservoir dip has unfavorable effects on SAGD performance due to overriding effect. Moreover, less oil saturation of matrix causes steam to penetrate into upper blocks. It has also been observed that reservoir thickness controls operational parameters. Furthermore, the results indicate that there is no need for more preheating due to desired heat communication between well pair. As it was expected, higher steam injection rate leads to more oil production. Besides, longer well pairs have no considerable effects on SAGD performance in dip reservoirs. Besides, because of quick reservoir depletion in injection at high pressure, SAGD is not recommended economically in thinner reservoirs.

Simulation of Flow-Control Devices With Feedback Control for Thermal Operations

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163594, ’Advanced Wellbore Simulation of Flow-Control Devices With Feedback Control for Thermal Operations,’ by Terry Stone, SPE, Schlumberger Information Solutions; Carlos Emilio Perez Damas, Schlumberger Calgary Regional Technology Centre; Glenn Woiceshyn, SPE, Absolute Completion Technologies; David Hin-Sum Law, SPE, Schlumberger Calgary Regional Technology Centre; George Brown, Schlumberger Fibre Optics Technology; and Peter Olapade and William J. Bailey, SPE, Schlumberger-Doll Research, prepared for the 2013 SPE Reservoir Simulation Symposium, The Woodlands, Texas, USA, 18-20 February. The paper has not been peer reviewed. Factors such as hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir, and well-placement issues can produce very poor steam conformance in steam-assisted gravity drainage (SAGD). Using proportional-integral- derivative (PID) feedback to control steam injection can lead to improvements in SAGD. Inflow- or injection-control devices (ICDs) can also improve SAGD performance. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control to determine the physical mechanisms and outline practical procedures to determine an improved ICD completion and feedback-control design. Introduction SAGD is the most extensively used process for development of the bitumen resources in western Canada. Fig. 1 shows the concept of this process in which two closely spaced horizontal wells are placed such that the upper well injects steam and the lower producer collects reservoir fluids that drain mostly by gravity from a constantly evolving steam chamber. Ideally, the steam chamber evolves uniformly along the entire length of the well pair. However, the actual pattern of SAGD well pairs shows very irregular steam-chamber development along the lengths of most of the pairs in the pattern. For many years, SAGD operators in this region have been evaluating methods to improve conformance along well pairs. One such method is to install dual- tubing strings in the injector and producer. Prescribed injection and production rates from each tubing string may be determined from a reservoir-engineering analysis of the formation around the pair, but such analyses are often inexact. In order to prevent the steam chamber from touching the lower producer, which would then remove hot steam instead of using it more efficiently in the upper reaches of the chamber, the injection and production rates are usually set to maintain a prescribed temperature difference between fluids exiting the upper injector and entering the lower producer. This temperature difference, also referred to as a “subcool” because it is set to be several degrees below a water saturation temperature, may be controlled at both the heel and the toe of the well pair by use of the ability to inject and produce from the two tubing strings that are landed at these points. However, setting these injection and production rates to reflect the current state of the reservoir and current subcool is difficult with conventional reservoir-engineering analysis. To improve on this, a proposal was made to use a feedback controller to monitor temperatures of produced and injected fluids automatically, with a target subcool at the heel and the toe of the well pair. By targeting the same subcool at the heel and the toe, two objectives are accomplished: (1) achieving the subcool prevents steam from entering the lower producer, and (2) both toe and heel halves are encouraged to produce uniformly because both are targeting the same subcool (i.e., if one-half temporarily operates at a lower or higher subcool than the target, steam injection is decreased or increased, respectively, in that half to compensate). Another method to improve conformance is to install carefully constructed ICDs in either the injector or the producer, or in both. When placed in the injector, these devices can equalize the outflow of steam from heel to toe better, regardless of variations in reservoir mobility properties.

Numerical Simulation of SAGD Recovery Process in Presence of Shale Barriers, Thief Zones, and Fracture System

This study presents a numerical investigation for evaluating the potential applicability of the steam-assisted gravity drainage (SAGD) recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap, and fracture systems in the McMurray and Clearwater formation. The simulation results indicated that the near-well regions were very sensitive to shale layers, and only long, continuous shale barriers (larger than 50 m or 25%) affect the SAGD performance in these well regions. In addition, the thief zones had a strongly detrimental effect on SAGD. The results also showed that the SAGD recovery process was enhanced in the presence of vertical fractures but horizontal fractures were harmful to recovery. Fracture spacing is not an important parameter in the performance of a steam process in fractured reservoirs and extending horizontal fractures will reduce ultimate oil recovery in the SAGD process. This article provides a guideline for SAGD operations in complex geological reservoirs.

Modeling Steam-Assisted Gravity Drainage With a Black-Oil Proxy

Summary This paper describes an alternative approach to model steam-assisted gravity drainage (SAGD) with an isothermal black-oil (BO) reservoir simulator. The oil-viscosity reduction caused by heating in the actual SAGD process is emulated by a tuned saturated pseudo-oil viscosity relation in which solution gas/oil ratio (Rs) is used as a “proxy for temperature.” In the BO formulation, fully saturated oil viscosity (μo*) at reservoir pressure equals μo that would be attained at steam-chamber temperature (T*) in the actual SAGD process; initial oil viscosity (μoi) with initial Rs = 0 represents initial oil viscosity at reservoir temperature; and BO gas properties represent steam at T*. After careful analysis of the SAGD process, one finds that oil flows only along a narrow zone along the outer edge of the steam chamber—the “edge oil-flow zone.” The temperature gradient within this narrow zone is perpendicular to the oil-flow direction and is practically impossible to model with any precision because of the large temperature variation and dynamic steam-chamber shape over time. The BO-model solubility gradient also varies, analogous to temperature in a thermal model, from zero to fully saturated (Rs*) with an associated drop in oil viscosity from μoi to μo*. SAGD design requires many hundreds of runs to find operational conditions that maximize economic value (e.g., injector and producer location, rates, pattern spacing, and steam-chamber temperature T*). The proposed BO proxy model runs several times faster than a thermal model while maintaining similar performance behavior. The proxy-model saturated pseudo-oil viscosity μo(p) relation used is found by history matching a full-physics thermal-model performance prediction of oil rate, bottomhole flowing pressure, and cumulative oil for a 2D homogeneous model. We have found a single-constant μo(p) equation that yields a good match to thermal SAGD performance. The tuned pseudo-oil viscosity relation honors the measured initial reservoir and fully heated (at T*) oil viscosities. Its dependence on Rs is not physical, but reflects the use of Rs as a transform variable for temperature, capturing the strong spatial variation of temperature and oil viscosity within the localized steam/oil boundary region in which oil has been mobilized. The pseudo-oil viscosity relation, defined by a single empirical best-fit constant n—for a given T* and a set of thermal properties—appears to be applicable for a wide range of reservoir heterogeneity, injection and production rates, and well placement. Consequently, it should be possible to use the BO proxy model for SAGD optimization of T*, control rates, and injector/producer vertical-depth difference. We also see the potential of using the BO proxy model for solvent-based SAGD, with the pseudo-oil viscosity model depending on both T* and solvent; thermal compositional modeling is yet even slower and less suitable for optimization.

A New Thermogeomechanical Theory for Gravity Drainage in Steam-Assisted Gravity Drainage

Summary Oil-sands reservoirs in western Canada hold more than 170 billion bbl of recoverable heavy oil and bitumen representing a significant source of unconventional oil. At in-situ conditions, the majority of this oil has essentially no initial mobility because of its high viscosity, which is typically in the hundreds of thousands to millions of centipoises. In steam-assisted gravity drainage (SAGD), steam injected into the formation heats oil at the edge of a depletion chamber, thus raising the mobility, ko/μo, of bitumen. Three main effects account for the increase of oil mobility. First, bitumen at steam temperature has viscosity typically less than 20 cp. Second, it is believed that shear, which is caused by thermal-expansion gradients, dilates the oil sand and causes enhanced permeability. Third, dilation at the chamber edge leads to smaller residual oil saturation (ROS). Because the production rate of SAGD is directly tied to the drainage rate of mobilized oil at the chamber edge, the thermogeomechanics of the oil sand at the chamber edge is a control on the performance of SAGD. In this study, a novel SAGD formula is derived that accounts for thermogeomechanical effects at the edge of the chamber. This paper couples dilation effects arising from thermal expansion into an analytical model for SAGD oil rate. The results reveal that volumetric expansion at the edge of the chamber plays a significant role in enabling effective drainage of bitumen to the production well.

Numerical Simulation Study of Field Scale SAGD and ES-SAGD Processes Investigating the Effect of Relative Permeabilities

Steam Assisted Gravity Drainage (SAGD) has been proved to be an effective method in producing from extra heavy oil or bitumen resources. The main recovery mechanism in this process is viscosity reduction by introducing heat into the reservoir. The Solvent Co-Injection processes (SCI) or Expanding Solvent SAGD (ES-SAGD) are alternative methods to the conventional SAGD. In these processes reduction in the oil viscosity is achieved by a combination of latent heat from steam and dissolution of solvents into bitumen. These alternative methods lower the steam requirements and associated costs with it, as well as the amount of carbon dioxide emission into the atmosphere caused by steam generation process.In this work some numerical simulations were conducted to examine the effect of relative permeability data on the performance of SAGD and ES-SAGD processes. Temperature dependant relative permeability data, that shows variation of end points with temperature, was tested against fixed relative permeabilities. Oil production was found to be strongly dependant on the end point relative permeability data. It is suggested to use temperature dependant relative permeabilities in numerical simulations. This must be considered as a matching criterion, when trying to history match field data.Solvent co-injection showed promising results both in terms of improved recovery factor and reduced steam oil ratio as an economical criterion. In addition, the high solvent recoveries of 97-100% in all solvent co-injection runs make the process even more economically interesting. Injecting only 2% on a molar basis of pentane, hexane or heptane as solvent, boosted the oil rates up.

Quantifying Heat Requirements for SAGD Startup Phase: Steam Injection, Electrical Heating

Summary A proper and effective startup of the steam-assisted-gravity-drainage (SAGD) well pairs, where both horizontal wells inject steam, is a key parameter to SAGD performance. In the past, a number of investigations have been conducted on the optimum startup strategy and operational procedures; however, fewer studies have modelled the heat requirements of the process. This study proposes an effective practical method that correlates the heat flux inside the horizontal wellbore with the temperature outside the wellbore wall. A transient conductive-heat-transfer equation in a cylindrical coordinate system is adopted for two different startup strategies: (a) variable heat flux (steam circulation in the well pair) to maintain a constant desired temperature at the wellbore wall and (b) constant heat flux (electrical heating of the well pair) to gradually increase temperature and finally reach a desired temperature on the wellbore wall. A novel and simple mathematical technique is presented for each startup approach to evaluate the instantaneous and cumulative heat requirements to keep the wellbore hot. Excellent agreements between the results of the proposed techniques and outputs of a commercial reservoir simulator are demonstrated. Accurate quantitative evaluation of heat requirements for the startup phase of SAGD enables optimum planning for steam requirements and practical design of any other heat sources employed in the process.

SAGD well orientation in point bar oil sand deposit affects performance

The creation and evolution of point bar reservoir systems are well understood in meandering river deposits. A large fraction of Athabasca oil sand deposits are ancient point bar systems characterized by bedded, sandstone-dominated strata with interbedded siltstone layers. The recovery process of choice for these deposits is the Steam-Assisted Gravity Drainage (SAGD) process due to the high viscosity of the oil, low solution-gas ratio, and often caps rock not sufficient to withstand injection pressures of Cyclic Steam Stimulation (CSS). However, because of the presence of siltstone interbeds, these reservoirs commonly have lateral and vertical lithological heterogeneity which interfere with the formation of uniform steam chambers along SAGD wellpairs. Other units in point bar deposits that impact SAGD chamber development within the formation include remnant channel succession and channel lag. The objective of this research is to construct a detailed three-dimensional point bar model to determine how its heterogeneity impacts SAGD performance. Here, the point bar model is based on the Lower Cretaceous Middle McMurray Formation in the Athabasca oil sand deposit in Alberta, Canada. Single SAGD wellpair submodels at different locations and orientations were extracted from the detailed point bar model. The results of the reservoir model simulation suggest that attention must be paid to SAGD wellpair placement in point bar systems.

The Effect of Geometrical Properties of Reservoir Shale Barriers on the Performance of Steam-assisted Gravity Drainage (SAGD)

Many bitumen reservoirs contain shale layers of varying thickness, lateral extent, and frequency. These shale layers, depending on their size, vertical and horizontal locations, and continuity throughout the reservoir, may act as a flow barrier and severely reduce vertical permeability of the pay zone and slow down the steam-assisted gravity drainage steam chamber development. Therefore, to improve productivity in these reservoirs, understanding of the effects of reservoir heterogeneities has become necessary. This work presents numerical investigation of the effects of shale barriers on steam-assisted gravity drainage performance when applied to produce mobile heavy oil. The most concern of the work is upon how different geometrical properties of these shale barriers, such as vertical and horizontal position, density, discontinuity, and dispersion through the reservoir, affect the steam-assisted gravity drainage performance and steam chamber development in above wells region. Simulation results showed that the performance of steam-assisted gravity drainage is lower in the case of presence of continued shale layers, their longer extension, and their higher density (number of shale layers per unit volume). As the vertical distance between the continued shale layer and injector decreases, the recovery factor will be less. Distribution scheme of the layers also affected the recovery performance and production rates, since higher was the produced oil in the case of scattered layers as compared to the case of stacked shale layers on top of each other. It was found that the effect of the aforementioned parameters on the ultimate oil recovery factor and production rates was less in the case of presence of discontinuities in the shale barriers.

Analysis of Heavy Oil Recovery by Thermal EOR in a Meander Belt: From Geological to Reservoir Modeling

The objectives of this work is to assess the impact of reservoir heterogeneities on heavy oil recovery of a reservoir analogue of meander belt through the Steam Assisted Gravity Drainage (SAGD) process by using numerical models. These models are obtained with different scales of upscaling of the geological model. Meander belts consist of point bar deposits, characterized by a 3D complex internal architecture, with different scales of heterogeneities, which distribution is associated with the depositional processes. Based on a 3D outcrop description of a meander belt analogue to the Canadian heavy-oil fields, the approach includes three steps: 1) the construction of a reference static reservoir model based on a very fine description of the outcrops in terms of architecture and geological heterogeneities, 2) upscaling of the grid at different scales using different upscaling factors in order to evaluate their impact on the heterogeneity distribution in the reservoir, 3) reservoir SAGD simulations using horizontal well doublet (steam injector and producer) across the meander belt, so as to assess the impact of upscaling of heterogeneities on heavy oil production. The impact of heterogeneities on simulation results are evaluated for several upscaling stages. Results show that heterogeneity distribution has an impact on fluid flow at different stages of production. On the fine gridded model, small scale heterogeneities impact the steam chamber development and fluid flow in the wellbore vicinity at the beginning of the steam injection, whereas large scale heterogeneities strongly influence oil recovery during the whole recovery process and lower the efficiency of the reservoir drainage. On coarser grids, the effect of small-scale heterogeneities can be diminished, depending on the upscaling stage. The geomechanical effect is not taken into account in this work, the objective being to assess the impact of heterogeneities on oil recovery. The performance of SAGD is clearly linked to the steam chamber development, which depends on the degree of heterogeneities present in the reservoir. The simulation workflow and the sensitivity study on the upscaling method contribute to a better restoration of the heterogeneity distribution in the reservoir. The negative effect of these heterogeneities during the oil recovery must thus be quantified in order to monitor the thermal production at crucial periods of the production process.