SAGD Research Articles

Drawbacks of phase change models in simulating flashing of steam with a subsaturation downstream boundary condition

AbstractThe development of phase change models applicable to a wide range of temperatures, pressures, and mass flow rates is primarily limited by the metastable or partially stable behaviour of the fluid. Due to this, the fluid does not change phase even after crossing saturation conditions. Most liquid–vapour phase change models have been developed primarily for the cavitation process where the phase change is not sustained, occurs in a very narrow region of space, or occurs under equilibrium conditions. In this paper, the mechanism of phase change is discussed along with the review of three different computational fluid dynamics (CFD)‐based phase change methods available in OpenFOAM, which are used to simulate flashing of steam, in applications related to steam assisted gravity drainage (SAGD) systems. The first method is based on barotropic compressibility (BC) used with the realizable turbulence model, the second combination is of mass transfer model (MTM) with the realizable turbulence model, and the third one is based on two fluid (TF) method along with a family of turbulence models. These methods are tested on a converging–diverging nozzle with pressure driven phase change. It is demonstrated that these methods are not able to adjust their physics to different depressurization rates, do not account for liquid to be in superheated conditions, and have significant discrepancies with experimental results. In the end, better approaches to model this category of phase change are discussed.

Removal of colloidal impurities by thermal softening-coagulation-flocculation-sedimentation in steam assisted gravity drainage (SAGD) produced water: Performance, interaction effects and mechanism study

Effective removal of colloidal impurities from steam-assisted gravity drainage (SAGD) produced water is essential for enhancing water recycling in industry. Response surface methodology (RSM) was employed to optimize the thermal softening-coagulation-flocculation-sedimentation process with softeners (Ca(OH)2, MgO and Na2CO3), poly-DADMAC as coagulant, and cationic polyacrylamide (PAM) as flocculant, and assess the interaction effects of operational variables for sludge volume index (SVI) and the removal efficiency of turbidity (TSS), particulate hardness, silica, total organic carbon (TOC) and total inorganic carbon (TIC) in synthetic SAGD produced water. The optimal conditions at 0.93 desirability were 67 mg/L poly-DADMAC dose, 14 min mixing time with softeners only, 200 rpm coagulation speed, and 16 min flocculation time. At this condition, the predicted maximum removal of turbidity, TSS, particulate hardness, silica, TOC and TIC were 99.2 %, 99.1 %, 99.4 %, 27.0 %, 69.0 %, and 30.3 %, respectively, and the value of SVI was 38.1 mL/g. Our results indicated that poly-DADMAC dose and mixing time with softeners only were the most influential factors for the treatment process. Furthermore, the temperature effect on removal mechanisms was investigated at optimal conditions under room temperature and high temperature (80 °C). The results of floc characterization and surface force measurement indicated that temperature could facilitate the removal of colloidal impurities via forming larger and denser flocs and changing their surface composition. The results also provided confirmation that adsorption and subsequent bridging are the main removal mechanisms in the coagulation-flocculation process. This study illuminates the importance of the interactions among operational variables and provides in-depth insights into the mechanism for the removal of colloidal impurities under high temperature.

Dimethyl ether-steam assisted gravity drainage: Physical 2D heavy oil simulation

Steam-assisted gravity drainage (SAGD) is a mature heavy oil thermal recovery technology but inherently limited to low recovery efficiency at mid-late stage due to the increasing heat loss in the steam chamber. Here, the dimethyl ether (DME)-assisted SAGD technology and its relevant transport and interfacial properties are specifically investigated through physical 2D heavy oil simulation. A total of four-set physical experiments, with different DME injection ratios, were conducted and compared with the traditional SAGD. The experimental results indicate DME is capable of reducing the heavy oil’s viscosity and interfacial tension at high temperatures. Three stages, rising, lateral expansion, and descending stages, are determined in the SAGD steam chamber’s development; the mid-late SAGD stage is defined when the steam chamber extends to the caprock boundary. With DME additions at the mid-late SAGD stage, higher oil recovery factor and sweep efficiency could be reached and the dew point temperature of steam chamber’s lead decreases by 0.7–1.8 °C. The optimum gas–water ratio is determined to be 3:1, with the fastest oil recovery growth and the highest final cumulative oil-vapor ratio of 0.163. This study provides reliable experimental bases and valuable analyses for the DME-SAGD technology and its application in heavy oil reservoirs.

The impact of permeability barriers on steam-solvent coinjection – A mechanistic study using a physical model

Coinjection of steam and condensate has been studied for improving the energy efficiency of steam-assisted gravity drainage (SAGD) as solvent-assisted SAGD or SA-SAGD. However, it is not well understood how tortuous hydraulic paths under heterogeneous permeability can influence the compositional and thermal flow characteristics in SA-SAGD. We addressed this question by performing an experiment of the coinjection of steam and condensate for bitumen recovery. This paper discusses the experimental results and gives our mechanistic analysis of how the tortuous hydraulic paths affected the thermal and compositional flow and the properties of the produced bitumen in the experiment.The physical model was a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.2 m, which was filled with unconsolidated sands. Two shale plates were horizontally installed above the well pair at different elevations so that they could represent permeability barriers to cause tortuous flow paths during the SA-SAGD experiment. The porosity and permeability of the sandpack was 0.34 and 5.6 D, respectively. Initially, the oil and water saturations were 95% and 5%, respectively.After preheating for 1 day, a mixture of 98.2 mol% steam and 2.8 mol% condensate was injected at 3500 kPa for 4 days (35 cm3/min of steam, cold water equivalent). The injection and production histories along with the real-time temperature distribution were recorded during the experiment. Produced oil samples were frequently taken and analyzed for density and asphaltene content. After the experiment, the sandpack was excavated and sampled from different locations to analyze the saturation and asphaltene content of the remaining oil. The experimental results in this paper were compared with the previous SAGD and SA-SAGD experiments that used the same experimental set up with a homogeneous sandpack.Results showed that, in comparison to the homogeneous SAGD case, SA-SAGD was able to lower the cumulative steam-oil ratio (SOR) by a factor of two to three even in the presence of shale plates. Analysis of the temperature profiles indicated that the steam chamber vertically expanded from the lower part to the upper part through tortuous paths at lower temperatures. An emerging steam chamber above the shale plates occurred by convective heat from the injection well through lower-temperature flow paths between shale plates, involving light to intermediate solvent components that enabled the steam chamber to expand away from the injection well. This highlights the important role of volatile solvent components in the growth of a steam chamber in SA-SAGD under heterogeneity. The produced bitumen density in this research was closer to the original bitumen than in the homogeneous SA-SAGD case because the bitumen dilution and the solvent retention increased by the tortuous flow regime resulted in efficient drainage of oil at lower temperature.

Introduce dimethyl ether (DME) as a solvent for steam-assisted gravity drainage (SAGD) co-injection: An effective and environmental application

Conventional heavy oil and bitumen thermal recovery is currently facing increasing energy demands and climate-related challenges. Dimethyl ether (DME) as a renewable and sustainable solvent was recently proposed as a possible solution for a carbon transition to hydrogen economics. However, only limited studies with unclear mass transfer mechanisms have been conducted on DME and its co-injected on steam-assisted gravity drainage (SAGD) optimization. In this study, a numerical model was developed to investigate the DME-based expanding-solvent SAGD (ES-SAGD) process to capture the complex mechanisms involved. The impact of temperature on relative permeability curves and coupled heat/mass transfer were further discussed in detail. The results of DME-based ES-SAGD and conventional SAGD were compared in terms of process performance and energy efficiency as well as carbon intensity. The optimal range of DME concentration was investigated to achieve the highest recovery factor, and with the assistance of DME carbon intensity can be reduced to one quarter to half of that in conventional SAGD. The study confirmed DME is a novel solvent that leads to the viable performance of ES-SAGD to meet carbon emission reduction objectives.

Experimental and numerical investigation of mining assisted heavy oil production for the Bati Raman field, Turkey

This research aims to investigate possible ultimate recovery from the largest oil reserve (Bati Raman) in Turkey using a new method called mining-assisted heavy oil production (MAHOP) where declines (tunnels) are excavated from the surface to the reservoir. A series of excavations (galleries) continue along the bottom of the reservoir and proceed along the reservoir's bottom. Fan-shaped steam injection holes that are drilled in the reservoir from the top and sides of the galleries are then used to inject steam similar to conventional steam-assisted gravity drainage (SAGD). A scaled experimental model and a numerical model have been designed and developed to assess the advantages and disadvantages of the proposed method. MAHOP experiments conducted at different wettability conditions showed that ultimate oil recovery varies between 49.56% and 71.73%. These promising results are then verified using a numerical model. It is argued that the temperature increase may alter the wettability of oil-wet rock to more water-wet, which contributes to incremental oil recovery. The conceptual economic study of the MAHOP recovery results show that the process can be economical in terms of both initial investment and operating costs. Thus, MAHOP is strongly recommended for the exploitation of the Bati Raman field.

Molecular Dynamics Investigation of Wettability Alteration of Quartz Surface under Thermal Recovery Processes.

One of the primary methods for bitumen and heavy oil recovery is a steam-assisted gravity drainage (SAGD) process. However, the mechanisms related to wettability alteration under the SAGD process still need to be fully understood. In this study, we used MD simulation to evaluate the wettability alteration under a steam injection process for bitumen and heavy oil recovery. Various oil droplets with different asphaltene contents were considered to determine the effect of an asphaltene content on the adsorption of the oil droplets onto quartz surfaces and wettability alteration. Based on the MD simulation outputs, the higher the asphaltene content, the higher the adsorption energy between the bitumen/heavy oil and quartz surfaces due to coulombic interactions. Additionally, the quartz surfaces became more oil-wet at temperatures well beyond the water boiling temperature; however, they were extremely water-wet at ambient conditions. The results of this work provide in-depth information regarding wettability alteration during in situ thermal processes for bitumen and heavy oil recovery. Furthermore, they provide helpful information for optimizing the in situ thermal processes for successful operations.

Feasibility of implementation of solar thermal energy in steam-assisted gravity drainage (SAGD) in extra-heavy oil field in Colombia

The feasibility of implementing solar thermal energy in enhanced oil recovery (EOR) projects in Colombia has been practically avoided mainly owing to its high operating cost. However, Solar thermal energy can enable generating steam to be used for the EOR process with SAGD. Based on the amount of steam needed for an extra-heavy oil project, a solar thermal parabolic trough heat plant of 76.6 MWt for field application was designed to produce up to 261 MMBTU/h from computer simulated studies. This plant can generate injection steam during day hours and can be complemented with a steam conventional generation system for operating during night hours and on highly cloudy days. The obtained results showed the generated solar steam can contribute an average of 37.5% total daily steam requirement. By applying System Advisor Model (SAM), the produced solar steam can generate a saving of US$ 27602/day, which is signification saving of US$ 10.07 MM in one year. Therefore, the solar thermal parabolic trough heat technology can be a suitable option to implement in the Colombian Eastern Llanos Basin for thermal EOR.

Analyzing Gradual Vegetation Changes in the Athabasca Oil Sands Region Using Landsat Data

Oil sand mining in northern Alberta/Canada in the Athabasca region is a major intrusion into the otherwise pristine natural environment. The various types of oil sands mining, transport, and processing are causing large-scale discharge of pollutants. Accordingly, this study examined the gradual changes in the physically undisturbed vegetation, that occurred from 1984 to 2021 in the Athabasca oil sands monitoring region. First, the abrupt changes were masked out with the help of auxiliary and Landsat data. Subsequently, a normalized burn ratio Landsat time-series was applied to the LandTrendr algorithm on the Google Earth Engine. In order to interpret gradual changes, measurement criteria were used to describe vegetation development, vulnerability, and variability. In addition, the spatial and temporal relationship of these to oil sand opencast mines, processing facilities, and steam assisted gravity drainage (SAGD) mines was examined. The results showed that a major part of the vegetation in the Athabasca oil sand monitoring region underwent a positive development (65.9%). However, around the opencast mines a negative vegetation development and stability within a radius of 10 km could be observed. In the surroundings of processing facilities, the development and stability of vegetation was disturbed within a radius of 2 km. Thereby the analysis of land cover classes showed that deciduous, coniferous, and mixed forest are disproportionately affected. Conversely, no negative influences on neighboring vegetation could be detected around SAGD mines. The temporal analysis showed that vegetation disturbance was most pronounced between 1990 and 2000, but recovered in recent years.

Optimization of Steam Assisted Gravity Drainage in Verified Integral Simulator

Optimization of Steam Assisted Gravity Drainage in Verified Integral Simulator

Modelling temperature dynamics of the SAGD process in an oil reservoir by the discovery of parametric partial differential equations

AbstractMany chemical and industrial processes are complex, and the dynamics of such processes cannot be explained using a partial differential equation (PDE) or a system of PDEs with constant coefficients. Parametric PDEs, that is, PDEs with their coefficients varying across time or space, are utilized for this purpose. The non‐availability of data at all spatial locations and partially available process knowledge add to the complexity of modelling such processes. This paper proposes a framework to discover parametric PDEs using data‐driven and hybrid modelling approaches with the temperature dynamics of steam‐assisted gravity drainage (SAGD) process in an oil reservoir as the system under study. We utilize an ensemble of 200 realizations of the temperature dynamics generated using the variogram for the PDE discovery. Permeability, which is one of the oil reservoir's petrophysical properties, is used to develop the hybrid models. We infer that utilizing partial process knowledge aids in improving the model's accuracy.

Numerical Investigation of a Novel Bottom-Up Assisted Pressure Drive Process in Oil Sands Reservoirs with Shale Barriers

Steam-assisted gravity drainage (SAGD) is widely applied to recover bitumen and heavy oil resources. Reservoir heterogeneity, especially the presence of shale barriers, continues to challenge the performance of SAGD. A novel enhanced oil recovery process, bottom-up assisted pressure drive, is proposed to improve the oil production in the reservoirs with shale barriers. In this work, numerical simulation is applied to investigate the feasibility of a bottom-up assisted pressure drive process. A reservoir model with typical oil sand reservoir properties is developed considering shale barriers. The performance of bottom-up assisted pressure drive and SAGD is compared under the same reservoir conditions, including steam chamber development, oil production rate, cumulative oil production, and the pressure difference between injector and production. The inherent mechanisms associated with the bottom-up assisted pressure drive are also well understood and confirmed. In the bottom-up assisted pressure drive, a flat steam chamber is developed from the bottom of the reservoir in the early stage of the process and grows upward with the injection of steam. The large volume of the steam chamber and the huge contact area between steam and bitumen contribute to a high oil production rate. The peak oil production rate in the bottom-up assisted pressure drive is approximately three times that in the SAGD process. The cumulative oil production in the bottom-up assisted pressure drive is 20% higher than that in the SAGD process. The effect of shale barriers on bottom-up assisted pressure drive is less, indicating one advantage of this novel process over SAGD in oil sands reservoirs with shale barriers. The pressure difference in the bottom-up assisted pressure drive is greater than that in the SAGD process. The pressure drive is another mechanism for improving oil production. The calculated net present value (NPV) in the bottom-up assisted pressure drive process is 27% higher than that in the SAGD process. This is mainly attributed to the high oil production rate in the early stage of the process and high cumulative oil production. The simulation study in this work provides technical support for the future field applications of this novel recovery process.

A New Analytical Model for Predicting Steam-Assisted Gravity-Drainage Performance in the Plateau and Decline Stages

Summary Analytical models have been widely used to study the steam-assisted gravity-drainage (SAGD) process. Existing analytical models for this process either underperform or are limited in their applicability. In this paper, a new analytical model is developed to address these shortcomings. The new model consists of three major components. First, an equation for predicting oil production rate during the plateau stage was developed. This equation allows for permeability anisotropy in the reservoir, which is neglected in the majority of existing analytical models. Second, a novel and concise equation for calculating oil production rate during the decline stage was derived. This equation for the first time provides a general relationship between oil production rate during the decline stage and the properties of the reservoir together with key operating conditions and simultaneously mitigates the shortcomings of the majority of existing models (e.g., inapplicable in the decline stage of the SAGD process). Third, new correlations representing heat loss from the steam chamber to the overburden and heat transfer to oil-undepleted zone ahead of the chamber interface were derived; new predictive equations for estimating steam/oil ratio (SOR) in the plateau and decline stages of SAGD were obtained. The new model has been validated against a 2D scaled laboratory experiment and a set of field data. The results of this validation show that the new model predicts the oil production rate and SOR over the lifetime of an SAGD operation (excluding the short steam rise period) reasonably well. Predictions from the new model were also compared with several existing analytical models: The new model provided a closer match to actual measurements than other models. This robust model is grounded in more physics and incorporates reservoir geology and well operating conditions. It enables better understanding of the SAGD process and significantly improves the prediction of SAGD performance. Hence, it can be used to design new SAGD projects, predict existing projects, and optimize existing projects.

Permeability decline by fines migration near sand control screens in steam assisted gravity drainage: A numerical assessment

The near-wellbore permeability loss caused by the release and migration of naturally fine particles impairs the well productivity in oil reservoirs. The damage would be intensified in the presence of restrictions such as sand control screens due to retardation and accumulation of fine particles resulting from flow convergence and high volumetric flux.This study focuses on the experimental investigation and mathematical modeling of the permeability impairment near the sand control screens under a representative fines migration process for the SAGD well conditions. For this purpose, the single-phase flow experiments were conducted on unconsolidated sand packs in a sand retention testing (SRT) setup. The testing used different sand screens and considered the chemical effect of the fines migration process and different salinity for the saturating brine and flowing fluid. A 3D numerical model incorporating governing fluid and particle transport equations in porous media and an empirical permeability loss equation was established to simulate the fines migration process.The results show that the sand screens with a low open flow area and narrow aperture size cause higher permeability loss under the same flow conditions. Higher salinity reduction yields higher mobilized fines concentration, causing high near-screen permeability loss. For the salinities above 800 ppm, no significant pressure drops were observed. Furthermore, changing salinity to deionized water (DI) caused almost complete plugging of the sand pack, masking the flow performance of the sand control screen. A good match was obtained between the measured and calculated dimensionless pressure drops from the experimental and numerical models. The calibrated model could accurately enough predict the dimensionless pressure drops for the near-screen interval. It was confirmed that the porous medium's model parameters were nearly independent of the sand screen. However, different results were obtained for different salinities, confirming the 'parameters' dependency on not just porous medium but also fluid properties.

A semi-compositional approach to model asphaltene precipitation and deposition in solvent-based bitumen recovery processes

Steam assisted gravity drainage (SAGD), as a commercially proven high ultimate recovery process for heavy oil and bitumen is energy intensive and may be limited by high usage of water. In the recent years, numerous methods to combine solvent and heat have been proposed for the in-situ recovery of bitumen. Among these methods, N-Solv (heated solvent vapor injection) and EBRT (enhanced bitumen recovery technology) utilize heated solvent vapor to extract heavy crudes under in situ conditions. These methods take the advantage of partial in situ upgrading of oil with much lower consumptions of water and natural gas and have the potential to reduce greenhouse gas (GHG) emissions. However, with the current knowledge relevant to solvent/heat-assisted recovery processes, it still remained uncertain how the in-situ upgrading could impact ultimate recovery and the efficiency of these processes. This study, thus, aims at providing insights about these processes with a numerical model. The study develops a simulation model that captures important mechanisms involved in the processes such as diffusion/dispersion, solvent dissolution, asphaltene precipitation and potential deposition. The complexity of modelling such processes is due to interrelation of oil–gas phase behavior and fluid transport mechanisms combined with in situ upgrading of oil. The intention is not to only identify factors important to the modeling of these processes, but also find how robust simulation models can be developed to replicate observed field behavior. A semi-compositional approach, based on liquid–liquid equilibrium, is proposed to properly capture the asphaltene precipitation in thermal numerical simulators using direct lab measured data. Our analysis will be presented regarding upgrading mechanisms that should be implemented, their effect on the oil production rate, and techniques to model them.

Integration of data-driven models for dynamic prediction of the SAGD production performance with field data

Steam-assisted gravity drainage (SAGD) is a successful thermal recovery process and has been widely applied to oil sands production. The prediction of oil production of the SAGD process plays a significant role in decision-making, where numerical simulation is one of the tools which support engineers. However, the traditional numerical simulation process for the SAGD production prediction, such as history matching, sensitivity analysis, and predictive runs, is a time-consuming process that is always associated with heavy computational costs. Engineers require reliable alternative modeling tools for the management of SAGD production. In this study, a data-driven model-based workflow is formulated and tested for the prediction of the SAGD production performance. After a series of data processing and integration of real field data, the machine learning algorithms are successfully utilized to predict future production performance based on past production information and operational conditions. A comparison of different machine learning algorithms shows that a Gated Recurrent Unit (GRU) based model has the best predictive ability.

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Steam huff and puff has become one of the most widely used technologies to enhance oil recovery during the early phase in heavy oil reservoirs. However, when the development entered in the later phase gradually, the production performance had characteristics with low oil-to-steam ratio and the oil recovery is generally 20–30%. Predecessors usually study a certain follow-up method for a block, and the well pattern is very regular. For the oilfield in the later phase of steam huff and puff, there was a lack of systematic comparison and evaluation with different follow-up methods under irregular well patterns. In this paper, the heavy oil reservoir in block G of Liaohe oilfield was taken as an example. In view of the complex geological conditions and irregular well pattern, the follow-up developing strategies, steam flooding (SF), steam assisted gravity drainage (SAGD) and fire flooding (FF) were compared and evaluated by numerical simulation. A model with seven components and four reactions (used in FF) was established by using STARS module of CMG software. A variety of combined well patterns with vertical and horizontal wells were designed for comparing the production performance. In total, two cases of SF, three cases of SAGD, and two cases of FF were simulated and the oil recovery were studied. The results indicated that these follow-up development methods can enhance oil recovery in different degrees. The combined well pattern with vertical and horizontal wells had a better production performance than that of only vertical wells. In the study, the performance of FF with the horizontal well was the best (oil recovery was 31.7% in the 20th year; cumulative air oil ratio was 3973 m3/m3; final oil recovery was 54.6%), while the SAGD with one horizontal well was the worst (oil recovery was 15.3% in the 20th year; cumulative steam oil ratio was 17.7 t/m3; final oil recovery was 32.6%). Compared with SAGD and FF, the performance of SF was not the best and far from the worst (oil recovery was 40.3% in the 20th year; cumulative steam oil ratio was 12.7 t/m3; final oil recovery was 40.3%). The results show that when the well pattern conditions are complex, the number of wells is large, and the formation is heterogeneous, the SAGD of the vertical and horizontal well combination is obviously affected by the inter well interference. Meanwhile, SAGD production has certain delay and high water cut. It seems that the production performance of SF is not affected by horizontal wells, and the water cut is high. FF with horizontal wells has obvious production performance and can find more uniform formation temperature rise and stable water cut between 0.5 and 0.7.

Approach Uses Intentional Deadheading of ESPs To Improve Run Life

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204521, “Intentionally Deadheading SAGD ESPs: An Unconventional Approach To Improve Run Life,” by J. Daine Studer, Jesus E. Chacin, SPE, and Roger Walters, SPE, ConocoPhillips, et al. The paper has not been peer reviewed. _ Electrical submersible pumps (ESPs) used in steam-assisted gravity-drainage (SAGD) applications run at the highest motor temperatures possible. However, they cool very rapidly when shut down. High cooling rates promote motor oil volumetric contraction, eventually leading to wellbore fluid ingress and short-circuited motors. The complete paper discusses successful field tests designed to decrease ESP cooling rates by inducing controlled deadheads rather than shutting down ESPs. Various extended-deadhead field trials (of up to 70 or more days in duration) validated the approach while confirming that no deadhead-related ESP damage was induced. Introduction In conventional operations, when ESPs operate in deadhead mode (i.e., no flow into the production line), all useful lifting work turns into heat and the ESP can overheat rapidly. The tendency to overheat increases as the gas/oil ratio of the lifted fluid increases. This type of overheating failure usually manifests as burnt stage components and cable burns close to the pump. At the Surmont SAGD plant, however, anecdotal evidence when ESPs inadvertently ran for a few hours in deadhead mode showed that SAGD ESPs cooled during deadhead events. This was the genesis of the project presented in the paper, which is to intentionally deadhead, rather than shut down, SAGD ESPs to offset or partially offset naturally occurring rapid cooling. Application Background A typical Surmont ESP producer completion features wells that are surface-cased with 13⅜-in. casing to approximately 120 m, and 9⅝-in. to approximately 350–450 m true vertical depth. Horizontal sections range from 600 to 800 m in length and are terminated with 7-in. slotted liners or flow-control-device strings. ESPs produce through 3½-in. tubing and are set at an inclination angle of 75° to 82° in specially drilled tangent sections. A 21/16-in. guide string is used to protect and land as deep as possible an optical fiber string inside a protective coiled string (1¼ in.). This optical fiber is used to obtain distributed temperature measurements. A bubble tube is bundled inside the ESP power cable to provide single-point downhole pressure measurements at pump-setting depth (PSD) in the annular space. Most ESPs used at Surmont feature power ranging from 60 to 180 hp to lift total gross production rates to the 1,000–6,500 B/D range. Water cuts average from 70 to 73%. The most-common failure modes experienced at Surmont caused by temperature cycling include worn mechanical shaft seals, metal bellows overextension, and thrust bearing wear (Fig. 1).

Investigation on Swelling Performance of Oil Sands and Its Impact on Oil Production during SAGD Processes

SAGD (Steam Assisted Gravity Drainage) is used in Canadian fields where there are interlayers that impede steam chamber development and thus impede production. Many experiments have been conducted on the effect of interlayers on oil recovery. However, the swelling characteristics of interlayers under different conditions, as well as the possible clay mineral transformation and particle migration of clay particles at high temperatures, are rarely studied. In this paper, the swelling characteristics of natural oil sands and artificial clay samples were studied by high temperature hydration swelling experiments to obtain a better comparison. The effects of temperature, pressure and solution type on the swelling rate of oil sand were studied. The uniaxial compressive strength of the core in the presence of clay was studied by the scribe test. In addition, before and after the aging test at 220 °C and 2.5 MPa, the clay mineral composition was studied by the X-ray diffraction method, and the mineral transformation was proved. Finally, the impact of clay swelling on oil production is investigated by simulating the particle migration effect while considering the swelling effect. The results show that the swelling rate of oil sand increases with the increment of temperature and the decrement of pressure. The swelling rate of an artificial clay sample in distilled water is the highest, while a 1% KCl + 1% CaCl2 solution has the best swelling inhibition effect. This study aims to provide new insights into reservoir damage research during SAGD development.

Monitoring CO2 injection and retention in steam-assisted gravity drainage (SAGD) operations

CO2 co-injection can be used to lower the energy requirements for heavy oil recovery in thermal oil operations. Technologies, including steam-assisted gravity drainage (SAGD) for the extraction of bitumen from oil sands, have the potential to improve the energy efficiency and economics of heavy oil production as well as provide an opportunity for carbon retention in the reservoir to offset CO2 return to the atmosphere and reduce greenhouse gas (GHG) emissions. Here, we report a geochemical approach that was developed to monitor the fate and transport of CO2 in the subsurface for a SAGD CO2 co-injection pilot program. Using δ13C–CO2 values from the injection well and other monitoring wells, a Bayesian state space model was used to evaluate the dynamic relationship between co-injection and reservoir CO2 rebound to baseline. The model provides simultaneous estimates of the isotopic changes in CO2 during co-injection, between injections, as well as between sampling events. The results suggest CO2 co-injection could be a viable step towards GHG reduction on a path to net zero emissions.