SAGD Research Articles

A review of fines migration around Steam Assisted Gravity Drainage wellbores

This paper reviews the state-of-the-art experimental and theoretical methods on fines migration around Steam Assisted Gravity Drainage (SAGD) wellbores. The in-situ migratory particles can deposit in the pore space and result in pore throat plugging within the porous medium. This process damages the permeability around the sand control screen. This review includes field observations, experimental works, and simulations solving fines migration mathematically. Field observations indicate higher pressure differentials between the SAGD injector and producer due to the plugging of the sand control screen and surrounding formation. Coreflooding experiments confirm that the fines migration process is an essential contributing factor to the permeability damage near the SAGD wellbores. Macroscopic analytical models have also been extensively used at the lab-scale to predict the permeability variation by the fines migration. The modeling studies are focused mainly on consolidated sandstones, but the impact of sand control devices has not been incorporated. Many papers have been published to describe the influential factors controlling the fines migration process. However, the interaction between the wellbore completion and surrounding sand from the fines migration perspective has not been adequately explored. Despite numerous limitations in representing the reality near the SAGD wellbores, sand control testing procedures provide a short-term evaluation of the sand retention and flow performances of the sand control device in unconsolidated sand. However, these tests do not account for the transient behavior and long-term permeability variation caused by the fines migration process. This paper presents an integrated general-purpose procedure for the design of sand control devices in SAGD wells, addressing the gaps from this review.

Data-Driven Proxy Model for Forecasting of Cumulative Oil Production during the Steam-Assisted Gravity Drainage Process.

The purpose of this study is to develop a data-driven proxy model for forecasting of cumulative oil (Cum-oil) production during the steam-assisted gravity drainage process. During the model building process, an artificial neural network (ANN) is used to offer a complementary and computationally efficient tool for the physics-driven model, and the von Bertalanffy performance indicator is used to bridge the physics-driven model with the ANN. After that, the accuracy of the model is validated by blind-testing cases. Average absolute percentage error of related parameters of the performance indicator in the testing data set is 0.77%, and the error of Cum-oil production after 20 years is 0.52%. The results illustrate that the integration of performance indicator and ANN makes it possible to solve time series problems in an efficient way. Besides, the data-driven proxy model could be applied to fast parametric studies, quick uncertainty analysis with the Monte Carlo method, and average daily oil production prediction. The findings of this study could help for better understanding of combination of physics-driven model and data-driven model and illustrate the potential for application of the data-driven proxy model to help reservoir engineers, making better use of this significant thermal recovery technology for oil sands or heavy oil reservoirs.

Development of layer-by-layer assembled polyamide-imide membranes for oil sands produced water treatment

The sustainable expansion of steam-assisted gravity drainage, as one of the most popular enhanced oil recovery methods, strongly depends on the proper management of the produced water. The strict environmental regulations have forced the oil sands industry to treat and reuse the produced water for oil extraction. Membrane separation as a single-step water treatment technique has played an important role in removing multiple-sized contaminants from wastewater. However, fouling limits the widespread application of this technology if the membrane is not modified properly to achieve antifouling propensities. Herein, we used the layer-by-layer assembly technique to sequentially coat the hydrophilic poly(diallyl dimethylammonium chloride) and polyacrylic acid on the surface of the polyamide-imide porous membrane to improve its fouling resistance. The effect of the number of bilayers on fouling and permeation properties was examined. The membrane with the highest fouling resistance and reasonable hydrodynamic permeability of 5.2 LMH/psi was achieved by coating four bilayers. This membrane exhibited a low flux decline of 50.2% and a high flux recovery ratio of 100%, while these numbers for the pristine PAI membrane were 75.9% and 97.8% under similar test conditions. The enhanced antifouling characteristics of the modified membranes indicate the viability of these membranes for oil sands produced water treatment with an easy cleaning procedure. The key parameter that contributed to the enhanced fouling resistance of the bilayer-coated membranes was the improved surface hydrophilicity, which manifests through the reduction of water contact angle from 62° ± 3° for the pristine membrane to 52° ± 2° for surface-modified membranes.

Screening High-Temperature Foams with Microfluidics for Thermal Recovery Processes

Thermal recovery processes, and in particular, Steam-assisted gravity drainage (SAGD), are the most common and practical in situ technology for bitumen extraction. While SAGD is effective, steam injection results in poor steam chamber growth and distribution with poor conformance specifically in areas with poor formation geology and bedding properties. These factors result in economic and environmental costs. Co-injecting foaming surfactants with noncondensable gases along with steam is an alternative solution to control the steam chamber behavior and its advancement throughout the formation. Selecting appropriate foaming surfactants is essential for successful implementation of a foam-steam processes. Conventional laboratory methods provide some indication of foaming surfactant performance but fail to reflect reservoir conditions and time scales. Microfluidics is well suited to assess the relevant pore-scale performance of foaming surfactants, at relevant conditions, with tight control over experimental parameters. Here, we develop a microfluidic approach to generate nitrogen-foam and assess stability and mobility control performance at relevant temperature (>150 °C) with results compared to those of traditional bulk foam analysis. The microconfinement associated with porous media creates more stable foam at reservoir-relevant temperatures and pressures. Direct visualization of the foaming dynamics, subsequent stability, and mobility testing in porous media provide a rapid assessment of foam performance as well as a diagnostic of surfactant product failures such as precipitation and phase decomposition, findings that directly informed pilot operations here. This screening also enables down-selection of the most promising agents for subsequent testing with candidate reservoir oil, in conventional cores or micromodels.

3D experimental investigation on enhanced oil recovery by flue gas assisted steam assisted gravity drainage

Flue gas assisted steam assisted gravity drainage (SAGD) is a frontier technology to enhance oil recovery for heavy oil reservoirs. The carbon dioxide generated from the thermal recovery of heavy oil can be utilized and consumed to mitigate climate warming for the world. However, most studies are limited to merely use numerical simulation or small physical simulation device and hardly focus on large scale three-dimensions experiment, which cannot fully investigate the enhanced oil recovery (EOR) mechanism of flue gas assisted SAGD, thus the effect of flue gas on SAGD production performance is still not very clear. In this paper, large-scaled and high temperature and pressure resistant 3D physical simulation experiment was conducted, where simulated the real reservoir to a maximum extent, and systematically explored the EOR mechanisms of the flue gas assisted SAGD. Furthermore, the differences between the steam huff and puff, SAGD and flue gas assisted SAGD are discussed. The experimental result showed that the production effect of SAGD was improved by injecting flue gas, with the oil recovery was increased by 5.7%. With the help of thermocouple temperature measuring sensors, changes of temperature field display that flue gas can promote lateral re-development of the steam chamber, and the degree of reservoir exploitation around the horizontal wells has been increased particularly. What’s more, the addition of flue gas further increased the content of light components and decreased the content of heavy by comparing the content of heavy oil components produced in different production times.

Technology Focus: Heavy Oil (April 2021)

After serving two terms for a total of 6 years, my time writing this column is coming to an end. This issue of JPT marks my last opportunity to share my thoughts, recap my observations, and make note of some final touch-ups to the research conducted over this 6-year period with regard to recent heavy oil practices. Here are some highlights to keep in our minds over the coming years. Despite all the recent negative and serious changes affecting the whole world and our industry, life goes on and we will increasingly be needing energy. One should recall that statistics predict oil will continue to be the main source of energy for the next 2 decades, with heavy oil constituting a great portion of that. That means that, while the oil industry is going through unprecedented and even unpredictable economic downturns, the status of heavy oil is still unquestionable. However, we have to face the fact that this energy should be tapped in a cheap, clean, and sustainable way. The best aspect of this effort is that heavy oil technologies have been established and tested over a long period of time, unlike other unconventional resources. Lowered steam consumption, down to zero if possible, has been under consideration to minimize the emission of greenhouse gases (GHGs) while simultaneously producing heavy oil. This green effort leads us to nonsteam techniques such as the use of water with chemicals (mainly polymer) and noncondensable gases and certain unconventional methods such as solvent injection and electromagnetic heating, the latter being unavoidable especially for extraheavy oil and bitumen. These areas have been critically considered by researchers and practitioners with a considerable number of applications existing at the field scale. At the same time, the oil industry must deal with mature steam projects in the near future. We have accumulated so much heat energy over the decades, yet a substantial amount of oil remains in these reservoirs. What can be done to reuse this energy? Can we recover different forms of energies using methods with no GHG emission? The current practices encountered in field-scale operations to improve the heavy oil recovery in mature steam applications use noncondensable gases; mainly, these techniques serve to pressurize steam-assisted gravity drainage wells, improve sweep and microscopic displacement by adding chemical additives to the steam (or hot water), and re-engineer well designs (flow control for efficient heating and sweep). My final example highlighting new practices is the increasing trend of offshore heavy oil practices. Of particular interest is polymer injection through vertical and horizontal wells and pilot steam applications, methods that are effective even if they occur at the pilot stage of the process. Recommended additional reading at OnePetro: www.onepetro.org. SPE 199947 - Enhanced Oil Recovery in Post-Cold Heavy Oil Production With Sand Heavy Oil Reservoirs of Alberta and Saskatchewan Part 2: Field Piloting of Cycling Solvent Injection by Gokhan Coskuner, Consultant, et al. SPE 199925 - Scalable Steam Additives for Enhancing In-Situ Bitumen Recovery in SAGD Process by Armin Hassanzadeh, Dow, et al. SPE 199927 - The Myth of Residual Oil Saturation in SAGD - Simulations Against Reality by Subodh Gupta, Cenovus Energy, et al.

Time scales for steam injection and bitumen production in steam-assisted gravity drainage

Despite technical and economic success of Steam-assisted gravity drainage (SAGD), improvements of its thermal efficiency as reflected by the steam-to-oil ratio (SOR) present challenges. Given that the SOR is a measure of the ratio of the energy invested to the energy (chemical energy in oil) produced and emissions intensity, there is strong motivation to reduce the SOR since the lower the SOR, the lower is the energy invested and emissions produced per unit oil produced. However, there appears to be few directions for modifying SAGD to improve the SOR by adjusting the steam injection strategy or fluid production strategy alone. In this research, multiple steam components and multiple bitumen components are used in a thermal reservoir simulation model to understand the time scales of steam flow and bitumen mobilization, drainage, and production. The results reveal that immediate bitumen response is observed near the well and in the steam-trap liquid pool above the production well whereas the time scale between steam stimulation and bitumen response can be as high as hundreds of days. This brings into question the meaningfulness of the steam-to-oil ratio as a control variable for behaviours far from the well pair.

Large-scale triaxial experimental investigation of geomechanical dilation start-up for SAGD dual horizontal wells in shallow heavy oil reservoirs

There are only a few related studies focused on the steam assisted gravity drainage (SAGD) dilation start-up technology (termed as dilation start-up in this paper), especially with true triaxial stress physical modelling experiments in the laboratory. Therefore, in order to better understand the dilation start-up process, four large-scale (1050 mm × 410 mm × 410 mm) true triaxial experiments of SAGD start-up with dual horizontal wells were conducted for the first time by using the oil sands from the Xinjiang oilfield, northwest China. The dilation process characterized by temperature changes at different positions inside the experimental samples was monitored in real time. The performance differences between dilation start-up and conventional start-up were discussed in detail, and the effects of dilation pressure and dilation time on the dilation process were also studied. The experimental results indicate that dilation start-up can significantly reduce the well communication time between injector and producer, and enhance the range of dilation zone and improve the uniformity of dilation zone along the horizontal wellbores. Moreover, we find that dilation pressure is an essential factor influencing the dilation effect. The average communication parameter increases by 5% if dilation pressure increases by 10% whereas the standard deviation of communication parameter decreases. The evolution of dilation zone with time shows that long-time dilation prompts the uniform propagation of dilation zone along the horizontal wellbores. This study provides guidance for the optimization of SAGD dilation start-up in shallow heavy oil reservoirs.

Physical modeling of nitrogen slug operation in Xinjiang SAGD projects - Fundamental roles of NCG in SAGD process

Non-condensable gas (NCG) co-injection in mature Steam Assisted Gravity Drainage (SAGD) chamber had been widely implemented and significant amount of steam was saved. Encouraged by their performance, NCG SAGD was also tested in Xinjiang oilfield since 2012. Its strategy differed from others in that nitrogen slug was injected once per year since the early SAGD stage. However, its performance was quite mixed. A unique 2D model was used to mimic the field operation of SAGD and NCG SAGD. The general performance, temperature drop, pressure oscillation, gas fingering and gas coning were analyzed. It showed non-condensable feature of NCG lead to gas accumulation and pressure oscillation in NCG slug operation. Its partial pressure effect lowered down temperature, saving steam but reducing oil rate, potentially leading to gas coning issue. The main purge mechanism was gas solubility in water and oil which controlled the NCG concentration inside the steam chamber. NCG fingering was found to speed up vertical growth of steam chamber in the early SAGD stage. However, injecting NCG before chamber getting mature should be treated with caution. Lastly, NCG was recommended to inject through vertical well to the top of the formation.

A cluster-based approach for visualizing and categorizing the impacts of shale barrier configurations on SAGD production

The impact of reservoir heterogeneities in the form of shale barriers on steam-assisted-gravity-drainage (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 categorize the influences of different shale barrier configurations on SAGD production and to quantify the dissimilarities between realizations. The simulation model (both two-dimensional and three-dimensional) is based on homogeneous oil sand, with reservoir heterogeneities added to the model by superimposing sets of idealized shale barriers located within the oil sand. First, a distance function, which measures the dissimilarity in production responses between any two given shale barrier configurations, is formulated. Next, MDS is used to map the resultant distance matrix into an n-dimensional Euclidean space, where clustering analysis technique is applied to group the cases into multiple clusters. It is expected that the impact of each shale barrier configuration within the same cluster on SAGD production is similar. Specific features corresponding to the shale barriers in each cluster are analyzed, to infer any potential correlation between SAGD production and the particular shale distribution characteristics. The proposed workflow offers an efficient and systematic method for constructing representative datasets for data-driven problems that maximize the spanning of the model parameter space, without exhaustively sampling similar realizations and subjecting them to flow simulation.

Analytical modeling of the oil steam ratio during the lifetime steam-assisted gravity drainage process in extra-heavy oil reservoirs

An analytical model to predict the steam oil ratio (SOR) of the steam-assisted gravity drainage (SAGD) process, including the growing up, expanding and depletion of the steam chamber development, is proposed through the use of steam chamber development modes, energy balance, and mass balance. The calculated instantaneous steam oil ratio (ISOR) and cumulative steam oil ratio (ISOR) using the new analytical model are compared and validated with other analytical models results and numerical simulation results. The results showed that the new analytical model can predict the changing of SOR during the lifetime of the SAGD process more accurately than other analytical models. In addition, it had a high agreement with the numerical simulation results. Additionally, the new model could predict more parameters, including water cut, steam quality, heat proportion in different parts of a reservoir than previous models. This model could be a fast-effective guide for the design, prediction, and adjustment of field dual-horizontal SAGD well pairs.

Numerical simulation study of uniform steam injection method for SAGD horizontal wells

Steam assisted gravity drainage (SAGD) has a better effect on heavy oil development than other thermal recovery methods. However, during the SAGD production practice, the problem of uneven temperature distribution of long horizontal well sections has appeared. In response to this problem, the reservoir numerical simulation software CMG is used to simulate different steam injection methods for SAGD horizontal well sections. The results show that the conventional steam injection steam cavity only develops at the heel end, the development length is 1/3 of the length of the horizontal section, and the steam suction profile is uneven. The double-pipe steam injection steam cavity develops at the heel and toe ends, and the steam suction profile is uniform. Improved, multi-point steam injection steam chambers are developed along horizontal wells, and the steam suction profile is the most uniform.

Study on thermal cracking of mudstone induced by thermal recovery of heavy oil

Steam assisted gravity drainage (SAGD) is an effective thermal recovery method for heavy oil reservoirs. Mudstone interlayers with low-permeability may block the expansion of the steam chamber and then reduce the SAGD thermal recovery. However, the mudstone may be thermally fractured by the coupling effects of thermal-hydro-mechanical (THM) in the SAGD production process. In this study, taking a heavy oil reservoir in Xinjiang as an example, we studied the thermal cracks’ initiation of mudstone interlayer by numerical simulation. Results show that: (1) Temperature changes are the main factor of affecting mudstone’s fracturing or crack propagation, and the effects of mudstone interlayer’s thickness are slightly. (2) With larger Young’s modulus, the critical fracturing temperature is lower. (3) In the peak period of gravity drainage, along the horizontal well, most of the mudstone interlayers reach the fracturing critical value and produce thermal cracks. The existence of thermal cracks will improve the SAGD productivity.

Techniques for Fast Screening of 3D Heterogeneous Shale Barrier Configurations and Their Impacts on SAGD Chamber Development

SummaryThe steam-assisted gravity drainage (SAGD) recovery process is strongly impacted by the spatial distributions of heterogeneous shale barriers. Though detailed compositional flow simulators are available for SAGD recovery performance evaluation, the simulation process is usually quite computationally demanding, rendering their use over a large number of reservoir models for assessing the impacts of heterogeneity (uncertainties) to be impractical. In recent years, data-driven proxies have been widely proposed to reduce the computational effort; nevertheless, the proxy must be trained using a large data set consisting of many flow simulation cases that are ideally spanning the model parameter spaces. The question remains: is there a more efficient way to screen a large number of heterogeneous SAGD models? Such techniques could help to construct a training data set with less redundancy; they can also be used to quickly identify a subset of heterogeneous models for detailed flow simulation. In this work, we formulated two particular distance measures, flow-based and static-based, to quantify the similarity among a set of 3D heterogeneous SAGD models.First, to formulate the flow-based distance measure, a physics-based particle-tracking model is used: Darcy’s law and energy balance are integrated to mimic the steam chamber expansion process; steam particles that are located at the edge of the chamber would release their energy to the surrounding cold bitumen, while detailed fluid displacements are not explicitly simulated. The steam chamber evolution is modeled, and a flow-based distance between two given reservoir models is defined as the difference in their chamber sizes over time. Second, to formulate the static-based distance, the Hausdorff distance (Hausdorff 1914) is used: it is often used in image processing to compare two images according to their corresponding spatial arrangement and shapes of various objects.A suite of 3D models is constructed using representative petrophysical properties and operating constraints extracted from several pads in Suncor Energy’s Firebag project. The computed distance measures are used to partition the models into different groups. To establish a baseline for comparison, flow simulations are performed on these models to predict the actual chamber evolution and production profiles. The grouping results according to the proposed flow- and static-based distance measures match reasonably well to those obtained from detailed flow simulations.Significant improvement in computational efficiency is achieved with the proposed techniques. They can be used to efficiently screen a large number of reservoir models and facilitate the clustering of these models into groups with distinct shale heterogeneity characteristics. It presents a significant potential to be integrated with other data-driven approaches for reducing the computational load typically associated with detailed flow simulations involving multiple heterogeneous reservoir realizations.

Comparison of different machine learning algorithms for predicting the SAGD production performance

Steam Assisted Gravity Drainage (SAGD) is a typical thermal recovery process consisting of an upper horizontal injector and a lower horizontal producer, which heats and removes bitumen from oil sands deposits by steam. Serious research has been conducted on data-driven models to analyze the cumulative production performance of the SAGD process, and one of the most common machine learning methods utilized is the Artificial Neural Network (ANN). It is important to test other machine learning methods like Extreme Gradient Boosting (XGBoost) and Light Gradient Boosting Machine (LightGBM) in different conditions of data samples. In this paper, a series of SAGD models based on typical oil sands reservoir properties and operational conditions were constructed. Three different data groups were simulated by the Computer Modelling Group (CMG) thermal software STARS. Three different machine learning methods, including ANN, XGBoost, and LightGBM were constructed to calibrate a relationship between the input parameters and the output parameters in the different simulated data groups. A series of final models were tested and compared. The conclusion shows that data-driven training improves as the number and randomness of the data samples increase, and the LightGBM has the best prediction performance with such data samples. The ANN model may be the best choice with data samples of the worst randomness.

Experimental study and numerical simulation of urea-assisted SAGD in developing exra-heavy oil reservoirs

Laboratory experiments and pilot applications have proved that urea is an efficient agent to enhance heavy oil recovery. Numerous studies have been conducted to investigate the mechanisms of urea co-injection process in steam flooding or cyclic steam stimulation. However, investigations of applying urea in steam assisted gravity drainage (SAGD) process are rarely published. The mechanism of enhanced oil recovery in the urea assisted SAGD process has not been fully understood. Laboratory experiments and numerical simulations were conducted to study the decomposition rate of urea, the effect of urea decomposition products on reservoirs and pipelines, and the distribution of effective decomposition products of urea in the steam chamber at conditions of different concentrations, temperatures, and injection rates. The results show that the solubility of the effective urea decomposition products affects their distribution in the formation because of the huge difference between the solubility in oil and water. In SAGD process, urea cannot be completely decomposed and will produce solid decomposition products, which could block the reservoir pores and production pipelines in certain conditions. Moreover, numerical simulation indicates that the use of low-concentration urea injection in SAGD can effectively enhance oil recovery and oil production rate, while high-concentration urea can reduce the oil recovery and oil production rate. In addition, it was proved that CO2 mainly exists at the edge of the steam chamber and NH3 is distributed in the irreducible water near the well-bore. CO2 is more effective than NH3 for enhancing oil recovery in urea assisted SAGD. Studies indicate that urea co-injection is a feasible method for enhancing oil recovery in the SAGD process.

Discovering Energy Consumption Patterns with Unsupervised Machine Learning for Canadian In Situ Oil Sands Operations

Canada’s in situ oil sands can help meet the global oil demand. Because of the energy-intensive extraction processes, in situ oil sands operations also play a critical role in meeting the global carbon budget. The steam oil ratio (SOR) is an indicator used to measure energy efficiency and assess greenhouse gas (GHG) emissions in the in situ oil sands industry. A low SOR indicates an extraction process that is more energy efficient and less carbon intensive. In this study, we applied machine learning methods for data-driven discovery to a public database, Petrinex, containing operating data from 2015 to 2019 extracted from over 35 million records for 20 in situ oil sands extraction operations. Two unsupervised machine learning methods, including clustering and association rules, showed that the cyclic steam stimulation (CSS) recovery method was less efficient than the steam-assisted gravity drainage (SAGD) recovery method. Chi-square tests showed a statistically significant association between the CSS recovery method and high SOR (p < 0.005). Two association rules suggested that the occurrence of non-condensable gas (NCG) co-injection produced a low SOR. Chi-square tests on the two rules identified a statistically significant relationship between gas co-injection and low SOR (p < 0.005). Association rules also indicated that there was no association between the production regions and SORs. For future in situ oil sands development, decision-makers should consider SAGD as the preferred method because it is less carbon intensive. Existing in situ oil sands projects and future development should explore the possibility of NCG co-injection with steam to reduce steam consumption and consequently reduce GHG emissions from the extraction processes.

Vertical-well-assisted SAGD dilation process in heterogeneous super-heavy oil reservoirs: Numerical simulations

PetroChina’s Karamay heavy oil reservoirs mostly comprise Jurassic deposits of braided fluvial facies that have a low porosity, extremely high bitumen viscosity, and strong heterogeneities within the reservoir. Steam-assisted gravity drainage (SAGD) dilation start-up has been proven an efficient reservoir geomechanical stimulation method as it shortens the steam circulation time, reduces steam usage, and increases the oil production rates. This method worked well on relatively good-quality oil sand reservoirs. However, for reservoirs with heterogeneous reservoir properties along the SAGD well, field well production data indicated the presence of non-uniform steam chambers in post-dilation SAGD wells. Enhanced dilation methods, such as vertical-well-assisted SAGD dilation (VW-SAGD-Dilation) are have been used, and field pilot tests have yielded promising results. This reservoir stimulation process utilizes one or more vertical wells beside the SAGD well to initiate the formation of dilation zones that connect to the dilation zone formed during the conventional SAGD dilation start-up. Compared with the normal SAGD dilation start-up, this composite dilation process creates a uniform dilation zone along the SAGD well, thus improving the thermal conformance and well productivity. The vertical well and SAGD well are connected by this composite dilation zone, which enables the combined use of the SAGD process and cyclic steam stimulation process. This paper presents our understanding and numerical case studies of this enhanced dilation strategy. The well production data from the post-dilation wells were positive (uniform steam chamber growth and higher oil rate), which highlights the promising potential of using geomechanical dilation as a reservoir stimulation method to create a large stimulated reservoir volume in heterogeneous super-heavy oil reservoirs.

Impact of carbon capture technologies on GHG emissions from oil sands in-situ facilities: A system prospective

The Canadian in-situ bitumen extraction is one of the most energy-intensive processes and a large GHG producer. In an increasingly carbon-constrained environment, industry and technology developers aim towards decarbonization of their operations by considering several design strategies. Post-combustion carbon capture (PCC) and heat integration are available solutions that can significantly reduce GHG emissions produced by in-situ extraction plants such as steam-assisted gravity drainage (SAGD) facilities. An important challenge that currently limits the use of carbon capture in SAGD facilities, apart from the capital cost, is the large quantity of energy needed and the associated GHG emissions. In this work, the energy performance of two typical SAGD configurations was optimized with and without PCC technologies. Aspen HYSYS® was used to model each configuration for a standard capacity and CanmetENERGY’s INTEGRATION software was used to optimize heat recovery. First, it was shown that SAGD facilities’ energy consumption and GHG emissions could be reduced by up to 8% through optimized heat recovery leading to a significant increase in the boiler feedwater and combustion air temperatures. Then, two PCC technologies were integrated into the SAGD configurations. Several energy integration strategies were considered to provide part of the regeneration energy required in the PCC units by using the excess heat in the SAGD and PCC plants. The analysis revealed that, depending on the SAGD process configuration, the PCC technology considered and the level of heat integration within the SAGD plant, 13–47% of the regeneration energy could be provided by heat recovery. Additionally, the techno-economic analysis results showed a capture cost of US$34.6–55.3/t-CO2 for different studied scenarios.

Condensing Solvent Processes: In Search of the Production Function

Summary The heavy-oil- and bitumen-recovery process by injection of a pure condensing solvent in a solvent vapor chamber provides an alternative to steam-based recovery techniques such as steam-assisted gravity drainage (SAGD). Because of the lower operating temperature between 40 and 80°C, the process uses a much lower energy budget than a steam process and thus results in significantly reduced greenhouse-gas emissions. This paper describes the route to a successful production function with the physical processes at play and using analytical tools. Physical relationships are derived for the solvent/bitumen (S/B) ratio, the bitumen drainage from the roof of the solvent vapor chamber, and for bitumen extraction from both sides of the solvent chamber by the draining condensed solvent. The fast diffusion of bitumen into this narrow liquid solvent zone is likely subtly enhanced by transverse dispersion. The speed of bitumen extraction from the roof of the solvent vapor chamber is constrained by the gas/oil capillary pressure. Extraction from the side of the chamber is approximately three times faster by the action of the thin gravity-draining liquid solvent film. Several equations are provided to enable creation of a heat balance for this condensing solvent process. Laboratory and field observations are matched, including the rates, the heat balance, and the S/B ratio. The model can explain constrained production performance by identifying the rate-limiting steps (e.g., when insufficient solvent condenses). The model predicts high solvent holdup during the rise of the solvent chamber. A method to estimate this solvent liquid saturation is provided. The S/B ratio depends on injector-wellbore heat losses, the (high) liquid saturation in the rising solvent chamber, and the process properties (operating temperature), reservoir properties (heat capacity, porosity, and oil saturation), and solvent properties (density and latent heat). In the existing body of literature, no satisfactory analytical model was available; this new approach helps to constrain production performance and to estimate solvent and heat requirements. The methods in this paper can be used in the future for subsurface project design and performance predictions.