bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of SAGD Wind-down and Blow-down for Athabasca Oil Sands
Authors: Gu Fagang , Chan Mark , Rismyhr Oddmund , Kjosavik Arnfinn
Published: June 2013

Athabasca is the largest resource accumulation among three major Canadian oil sands reservoirs. Through more than twenty years of research and studies, Steam Assist Gravity Drainage (SAGD) has been proven as an economic viable commercial method to develop Athabasca oil sands. However, because very few of industrial SAGD projects have matured to date, Wind-Down (WD) and Blow-Down (BD) operation strategies are not well understood and more research and study efforts are needed.

In this paper the beginning time and gas injection and production rates in WD and BD with pure methane are optimized for an Athabasca oil sands reservoir with numerical simulation. A simplified economic method and assumptions for optimization are presented and applied in this study. Six type wells are selected to capture the complexity of geological architecture (including pay thickness, and permeability and porosity heterogeneities) and fluid characteristics (thief zones) of the investigated reservoir. The optimization is based on the net values of WD and BD with 2D layer cake simulation models. The sensitivity of the net values to gas and bitumen prices is also analyzed. The strategies to optimize WD and BD for compartment areas or full fields are explored in this paper. For the areas without geomodels, a weighting method is proposed and applied. For areas with geomodels single model simulation is recommended if the areas are not large while the type well/pad methodology is suggested if the compartment areas or full fields are too large to simulate with one model.

The results of this study indicate that understanding reservoir geology and optimizing WD beginning time are important and necessary to have positive WD economic values. In some cases compromise has to be made in optimization simulation due to the complexity of reservoir, availability of model and limitation of resources, and a practical optimization method with proper simplifications have to be taken. With the optimized WD and BD operation and management strategies the economy of SAGD projects can be improved significantly.
Simulation Analysis of Steam-Based EOR Using MultiObjects Grosmont Models
Authors: Ezeuko Cosmos C. , Gates Ian D.
Published: June 2013

Carbonates contain more than 50% of the world's known hydrocarbon resources. Although natural fractures are a common feature in carbonates and they can improve primary production from tight matrix carbonates, they pose a unique challenge for enhanced oil recovery (EOR) from heavy oil and bitumen (HOB) carbonates. The current focus on ‘energy mix’ to sustain the world energy demand has once again put HOB carbonates in global spotlight. Among the known HOB carbonate reservoirs globally, the Grosmont carbonate in Northern Alberta contains the largest original in-place HOB (~406.5 billion barrels). However, the Grosmont carbonate poses the greatest development challenge of all other known HOB carbonates due to its petrophysical complexity. We recently published our progress towards developing a methodology for characterizing the Grosmont carbonate that is suitable for direct reservoir simulation. The objective of the current paper is to assess the performances of different steam-based EOR recovery technologies using multiobject reservoir models of the Grosmont. Our results show that simulations on appropriate reservoir models representative of the most hydraulically active objects produce a good account of heat and fluid flow in complex carbonates. Cyclic steam stimulation (CSS) in this paper describes steam injection below fracture pressure and can therefore be related to what has recently been presented in the literature as cyclic single well steam-assisted gravity drainage.
Integrating the Key Learnings from Laboratory, Simulation, and Field Tests to Assess the Potential for Solvent Assisted - Steam Assisted Gravity Drainage
Authors: Dickson Jasper L. , Dittaro Larry M. , Boone Thomas J
Published: June 2013

ExxonMobil and its Canadian affiliate, Imperial Oil Resources, are actively developing the next generation of solvent-aided and solvent-dominated heavy oil recovery processes. While these new recovery processes possess multiple environmental and technical advantages relative to traditional heavy oil recovery processes, there are a variety of challenges that must be addressed and overcome before commercial application. One especially promising technology is the Solvent Assisted – Steam Assisted Gravity Drainage (SA-SAGD) process. In the SA-SAGD process, a light hydrocarbon solvent (diluent) is injected along with dry steam in a dual horizontal well SAGD configuration.

An integrated research program has been implemented in order to progress the SA-SAGD technology from the laboratory to the field and to better quantify the benefits of SA-SAGD over SAGD. This integrated research program includes fundamental laboratory work, advanced numerical simulation studies, scaled physical laboratory models, and a two well-pair field pilot. In this paper, we review the scope, technical challenges, and key learnings from the laboratory, numerical modeling efforts, and the field pilot. Each individual component of the research program is important and provides unique and useful information concerning the SA-SAGD process. Given the technical and economic challenges of solvent-assisted thermal heavy-oil processes, these types of fully integrated research programs are essential in order to successfully progress new technologies from the laboratory to the pilot scale and ultimately to the commercial scale. Ultimately, the program is targeted at developing reliable commercial predictive capabilities that have been validated against both laboratory and field data, for application to a wide range of heavy oil reservoirs, operating conditions, and development plans.
Key Learnings from a Simulation Study of a Solvent-Assisted SAGD Pilot at Cold Lake
Authors: Dickson Jasper L. , Subramanian Ganesan , Shah Prateek , Otahal Joan M. , Dittaro Larry M. , Jaafar Ali E. , Yerian Jeffrey A.
Published: June 2013

ExxonMobil and Imperial Oil Resources (IOR) are conducting a Solvent Assisted - Steam Assisted Gravity Drainage (SA - SAGD) experimental pilot at Cold Lake in the Clearwater formation. In this SA-SAGD pilot, up to 20% by volume of a hydrocarbon solvent (diluent) has been injected along with dry steam in a dual horizontal well SAGD configuration. The primary objective of the pilot was to quantify the impact of solvent addition on bitumen production and steam-oil ratio (SOR). Key surveillance data collected during the pilot include production/injection rates (oil, water, and solvent), production/injection pressures, horizontal well temperatures, observation well temperatures, saturation logs, and time-lapse 3D seismic surveys.

The objective of this paper is to discuss the modeling efforts that were completed in order to interpret the initial results of the pilot. Specifically, this paper will address (1) the construction of a detailed 3D geologic model and the corresponding flow simulation model and (2) the history-matching results. The geologic model incorporates information from 3D seismic surveys as well as core and log data from the pilot observation wells. Using the geologic model and the field production data, the SA-SAGD process was modeled using a thermal simulator. An acceptable match to the total hydrocarbon production rate, injection pressure, and SOR was achieved through a minor adjustment to the model permeability.

The completed simulation studies are invaluable in increasing our understanding of the key parameters that control flow behavior in the SA-SAGD process. Ultimately, these learnings will be used by ExxonMobil and Imperial Oil Resources to optimize the process and make decisions related to full-field commercial deployment of the SA-SAGD recovery process.
A New Approach for Designing Steam Splitters and Inflow Control Devices in Steam Assisted Gravity Drainage
Authors: Kyanpour Mohammad , Chen Zhangxing
Published: June 2013

The classical SAGD involves drilling wells in parallel horizontal pairs. Steam is injected into the upper well (injector) to heat the reservoir and mobilize bitumen so that it drains to the lower well (producer) and can be lifted to the surface. In this process, steam distribution in the injector and a sustainable liquid level above the producer are key to achieve steam chamber conformance. The completion designs of these wells are critical in order to achieve optimal bitumen recovery and steam chamber development.

Two common tools in SAGD wellbore completions are Steam Splitters and Inflow Control Devices. The Steam splitters are used to customize steam distribution in the injector. The Inflow Control Devices are used in the producer to develop a uniform inflow along the horizontal wellbore.

This paper presents a method for determining the size and position of Steam Splitters and Inflow Control Devices. This method can be used for both simple and complex reservoirs containing heterogeneous geology and hydraulic barriers and baffles.
Rheological Assessment of the Elasticity of Polymers for Enhanced Heavy Oil Recovery
Authors: Wilton Ryan R. , Torabi Farshid
Published: June 2013

More recently polymer flooding recovery processes are becoming increasingly attractive due to the improvements in polymer manufacturing, hydration and implementation successes worldwide. This is especially true in the application of polymer for enhancing heavy oil recovery. It has been suggested that the elastic nature of the polymer is equally important to the viscous properties.

In the present study, a specialized rheometer was used to determine the viscoelastic properties of both hydrolyzed polyacrylamides (HPAM) and hydrophobically associating polyacrylamides (HAP) used in heavy enhanced oil recovery (EOR) processes. The rheometer has the capability to measure rheological properties in porous capillary plugs providing a more representative picture of non-Newtonian fluid flow in reservoirs. The rheological parameters were determined as influenced by polymer type, concentration, molecular weight, hydrophobicity, salinity and temperature. Increases in elastic tendencies were observed as a function of the first four; however, salinity and temperature were found to have a slightly negative effect. A medium density, hydrophobic polymer showed an earlier onset of elastic contribution at in-depth reservoir shear rates as determined by its Weissenberg number. For heavy oil reservoirs utilizing higher polymer concentrations, the viscoelastic properties of a polymer system should be evaluated in the screening process.

Recent studies suggest that viscoelastic polymers can reduce the residual oil saturation below that to waterflood with two different plausible mechanisms at play, depending whether the media is water- or oil-wet. However, in both theories, polymer elasticity is believed to be the dominant force that contributes to the additional reduction in oil saturation. Aside from measuring the elasticity directly, other parameters that quantify a polymer's elastic potential are its relaxation time and Weissenberg number; therefore, the change in these parameters with respect to dynamic shear rate or flow velocity can be further useful for screening purposes.
Use of Pressure Transient Analysis for Monitoring SAGD Steam Chamber Development
Authors: Zamani Amir , James Bruce , Hite Robert
Published: June 2013

One of the major problems faced in steam assisted gravity drainage (SAGD) development is monitoring steam chamber growth and conformance in a cost-effective way. Currently, this is primarily done using 4D seismic. However, each survey costs several million dollars, can generally be taken once a year in winter, and is limited in resolution. This paper investigates the use of pressure transient analysis (PTA) to monitor steam chamber conformance as a low-cost and on-demand alternative. While PTA has been widely and successfully used in the conventional oil and gas industry, there has been little application to SAGD.

A range of cases were investigated using reservoir simulation including steam flooding in a vertical well, 2D homogeneous and 3D heterogeneous SAGD cases. The heterogeneous cases included variations in permeability and shale layers along the injector. Pressure responses from different pressure gauge configurations such as a single gauge and multiple gauges along the injector were analyzed.

Results indicate that PTA can estimate total chamber pore volume reasonably accurately, despite a number of non-ideal conditions such as heterogeneity in saturations and countercurrent flow. Results also indicate that PTA potentially can be used in a number of ways to monitor steam chamber growth. First, changes in total steam chamber volume potentially can be monitored by observing changes in pseudo-steady state behavior (PSS) over time. More importantly, the character of the derivative plot changes with the maturity/shape of the chamber, indicating that the derivative plot can be used as a qualitative tool for monitoring steam chamber growth. In particular, the derivative behavior at a pressure gauge is governed largely by local steam chamber conditions near the gauge so that multiple gauges down the horizontal section can be used to monitor how different parts of the steam chamber are growing. However, there are limitations on what can be discriminated; differences in chamber shape have to be major for the derivative responses to be significantly different.
Sanding Onset and Sand Rate Prediction in Heated Oil Reservoirs
Authors: Wang Yarlong , Lu Baoping
Published: June 2013

Sanding onset and sand production rate in non-isothermal conditions are of interest both for post-CHOPS and thermally EOR process for production enhancement and sand control purposes. Critical drawdowns by different criteria representing different types of formation and sanding mechanisms are presented based on a fully coupled geomechanics framework under an uniform in-situ stress and non-isothermal condition. Comparisons between a validated isothermal condition and those of heated/cooled formations are performed. Sand production rate after the onset of sand production is also calculated and two different formulations representing sanding zone and displacement changes, respectively, at the wellbore wall for an open hole case is also evaluated.
Slurrified Heavy Oil Reservoir Extraction (SHORE): A Non-Thermal, in situ Recovery Method
Authors: Yale David P , Wang Jianlin , Meier Steven W , Herbolzheimer Eric , Kushnick Arnold P , Adair Neal L , Leonardi Sergio A , Smith Richard J
Published: June 2013

The oil sands of Canada are a rich resource whose extraction faces many challenges. The most common processes for recovering in situ resources (i.e. too deep to mine) involve heating the reservoir to reduce the heavy oil or bitumen viscosity to allow it to flow to wellbores where it can be produced. This paper presents an alternate concept for recovery of these resources that does not require heat to mobilize the bitumen and that is especially well suited to reservoirs that are too thin or too geologically complex for economic thermal recovery.

The process utilizes water injection to "condition" a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. Establishing a pressure gradient between a set of injector and producer wells allows the production of a bitumen-sand-water slurry as the pressure gradient established overcomes the friction holding the reservoir sand in place. This produced slurry is then processed at the surface to extract the bitumen and the cleaned tailings are re-injected back into the reservoir to aid in the sweep of the in situ sand, support the overburden, and dispose of the tails. We have developed a first principles numerical model of the process that fully accounts for fluid flow and sand flow under reservoir conditions to simulate and understand the process. We have also developed a large scale (2 meter diameter sand pack) laboratory system to demonstrate the technical feasibility of the process under reservoir conditions.

The technology is still in the early stages of development, but the laboratory and numerical modeling efforts demonstrate promising technical potential of the process at a field-scale. The ability of the process to work in thinner and more geologically complex reservoirs than other in situ processes, and with lower CO2 and surface footprints than thermal and mining processes, could make this an attractive alternative recovery process for shallow to intermediate depth, in situ bitumen resources.
Coupled Fluid Flow-Thermoplastic Deformation of Oil Sand and Shale in SAGD Process
Authors: Gong X. , Wan R. , Mohamadi M.
Published: June 2013

Steam-Assistant-Gravity-Drainage (SAGD) has become one of the most commonly used thermal recovery processes to extract heavy oil from oil sand reservoirs, especially in Northern Alberta, Canada. However, due to geological history, interbedded shales (IBS) in the reservoir act as barriers due to their low permeability and as such hinder the progression of the steam chamber. Cap-rock integrity also needs to be ensured to prevent steam breakthrough. Therefore, a comprehensive investigation of geomechanics is required in modeling SAGD processes to properly address the above issues.

The numerical simulation of SAGD typically solves classic multiphase fluid flow equations, but with seemingly less detailed reservoir thermo-hydro-mechanical (THM) deformation calculations. However, the latter play a major role in SAGD responses in that the injection of steam significantly alters both the pore fluid pressure and temperature fields in the reservoir, which in turn impact on effective (skeleton) stresses. The latter inevitably leads to plastic deformations which eventually cause geomechanical failure inside and above the reservoir. Relevant to this issue is the dilatancy of geomaterials under shearing that increases the pore volume, and thus permeability. Hence, a proper treatment of such effects requires the coupling of multiphase flow with geomechanics.

In this paper, the THM behavior of the reservoir was studied through a proper constitutive modeling of the porous media. Specifically, a generalized density-stress-fabric dependent elasto-plastic model with stress-dilatancy and plastic damage as main ingredients was implemented into COMSOL (2012), a commercial finite element programming environment, to model geomechanical behavior during SAGD process. The strength and deformation of oil sand and IBS were evaluated through the respective stress-strain relationships, including stress path analysis. As such, geomechnical effects would be highlighted in view of the global operation and performance of the SAGD process.
Influence of Clay Minerals and Water Film Properties on In-Situ Adsorption of Asphaltene
Authors: Hematfar V. , Maini B. B. , Chen Z.
Published: June 2013

Asphaltene is the heaviest and most polar fraction of crude oil that creates many problems in various sections of petroleum industry including reservoir development, well tubing, surface facilities and pipelines. There have been many investigations of the consequences of asphaltene precipitation but the adsorption of asphaltene on rock surfaces and its impact on multiphase flow are not yet well understood.

In this work, the effects of asphaltene adsorption on wettability, relative permeability, and displacement efficiency in porous media were evaluated using flow experiments in sand-packs. Clay content and water film residing between pore surface and the hydrocarbon phase are recognized as the governing factors on the level of adsorption. These experiments involved pre- and post-adsorption measurements of relative permeability and recovery in sand packs. Adsorption on sand particles was induced and measured by extended injection of asphaltene solution with known concentration into the sand pack and collection of effluent samples for analysis. A spectrophotometer was employed to measure the asphaltene concentration of each sample and the dynamic adsorption curves were obtained by the subsequent material balance calculations. Adsorption reversibility was examined by analyzing the sand samples at different sections of sand-pack and the wettability alternation was inferred from the displacement behavior. Observed improvement in the displacement behavior is explained by the combined effects of desorption due to brine injection in the post adsorption waterflood and by reduction of interfacial tension due to surface active properties of asphaltene particles.

The experimental results show the importance of the existence and properties of water film on the extent of asphaltene adsorption. Presence of clay intensifies the adsorption phenomenon but its impact on two phase flow behavior and recovery depends on the brine salinity. Maximum adsorption occurred under direct contact of sand surface and asphaltene solution when no water film was present, which resulted in more oil-wet conditions, thereby reducing the relative permeability to asphaltene solution and recovery.
Mechanism of Heavy Oil Recovery Driven by Electromagnetic Inductive Heating
Authors: Mustafina Daria , Koch Andreas , Danov Vladimir , Sotskiy Sergey
Published: June 2013

Electromagnetically driven heavy oil recovery is considered as an alternative or as a complementary technique to steam injection methods. Inductive electromagnetic heating (IH) of heavy oil reservoir represents a complicated multi-physics process affected by operating conditions, reservoir and fluid properties. The IH takes place at frequencies of 10-3 - 1 MHz and the principle is based on the eddy currents generation in the mineralized connate water and its Joule heating.

This work presents a numerical simulation study of IH assisted heavy oil recovery. Previously developed coupled electromagnetic and reservoir simulation workflow is applied for this analysis. The workflow incorporates coupling between ANSYS Emag and CMG STARS. The study is focused on the recovery drive mechanism and influence of the reservoir and operating parameters on the production.

The IH is realized via closed inductor loop through which alternating current is passed. In our current study we consider two-dimensional pay zone completely surrounded by impermeable barriers and two horizontal "SAGD – like" well pairs, a pair of producer (lower well) and inductor (upper one). Different well constraint cases and the sensitivity to fluid and reservoir properties (pay zone thickness, depth of a reservoir, distance between wells and electrical conductivity contrast between pay zone and under-, overburden) are evaluated.

Operating pressure plays a significant role for the production. It defines the water boiling temperature and controls underground steam generation and consequently the drive mechanism. The sensitivity to fluid and reservoir properties is estimated in terms of production efficiency and recovery factor.

Previous works on this topic did not consider particularly IH in much detail. The results obtained in this work provide a comprehensive understanding on IH assisted heavy oil or bitumen production process, drive mechanism behind it and the ways of improvement of this technology.
Revitalizing Indonesia's Potential for Oil Production: The Study of Electromagnetically Heated Gravel Packs for Steam-produced Heavy Oil Reservoirs
Authors: Gunadi Trianto A. , Bae Wisup , Suranto Suranto , Lee Jaehoon , Hidayat Fiki , Netzhanova Akmaral
Published: June 2013

Indonesia, like many other countries, is also a producer of heavy oil. An example is from Duri Field which has begun producing oil successfully by steam-injection since 1985. However, the relatively shallow and unconsolidated formations have been causing noticeable and sometimes significant sand problems (up to 500 cubic meters per day) resulting in excessive workover operations and loss in production. Delaying production due to workover in a steam-assisted production method is costly, because over time the viscosity of the movable oil will increase again due to the temperature drop. This condition will make the oil even harder to produce when the well is reopened. Thus, an inexpensive but effective solution is needed to remedy this problem.

This paper proposes a new and cost-effective method for improving the efficiency of the steam injection methods for fields similar to Duri by using EM-heated proppant as gravel pack/frac-pack material in the production well. Installing an EM field generator in the wellbore and using EM-heated proppant will have a dual advantage over the conventional method by being more resistant to flow and being able to heat the near-wellbore region of the production well. By heating the near-wellbore region of the production well, the lowered-viscosity of the steam-contacted oil will be maintained as it enters the wellbore.

From results of simple calculations, backed up with laboratory observation, heated-proppant is intended to transfer and sustain heat as well as other thermal stimulation methods. Production increment is predicted to be small due to smaller heated radius; however the increased well longevity before a workover schedule and hands-free operation should provide a more cost-efficient well for producing heavy oils, in-time covering the installation cost of the EM Generator.
Experimental investigation of heavy oil recovery from fractured-porous carbonate core samples by secondary surfactant-added injection
Authors: Roschin P. V. , Vasquez Cardenas L. C. , Petukhov A. V. , Mikheyev A. I.
Published: June 2013

In this study, the description of Enhance Oil Recovery effectivity (EOR) of surfactant denominated reagent A, at the secondary waterflooding process for heavy oil recovery from fractured-porous carbonate core samples were investigated experimentally. For this experiment have been selected two cores, 14,75 cm long and 3 cm diameter were stacked in a long 3D confining core holder. In the first step, cores have been saturated by brine. In the second step, cores have been saturated of heavy oil through the water-saturated core sample for two-phase saturation. In the third step, we provided the injecting of water through the core sample for measuring oil recovery factor (by cold water 20ºC) simulating the primary recovery at these conditions. In the fourth step, was injected of 2 pore volumes of Reagent A through the core sample for measuring oil recovery factor (by reagent A) and simulating the slug. In the fifth step and final, was injected water through the core sample for measuring full oil recovery factor (by cold water) after slug of Reagent A. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored and regulated carefully.
In Situ Bitumen Viscosity and Saturation Estimation From Core Log Integration for Canadian Oil Sands
Authors: Chen Jiansheng (Jason) , Bryan Jonathan
Published: June 2013

Canadian oil sands contain bitumen with viscosity above 100,000 cP at in-situ conditions. Thermal recovery of this oil requires knowledge of both the oil and water saturation profile, and also the oil viscosity profile in the reservoir. A core-log integration program was conducted for in-situ viscosity and saturation estimation. Two wells were logged with NMR and other special petrophysical logs. Core samples on these wells were taken for lab NMR and other special core analyses, with the goal of calibrating the logging tool outputs against the laboratory core data.

Lab NMR measurements were conducted on both core and extracted bitumen samples at different temperatures (12, 20, 50, and 80 °C). Viscosities were also measured for the bitumen samples at these same temperatures. Results show that when viscosity is higher than 100,000 cP, oil viscosity is no longer sensitive to T2 geometric mean, but it still strongly correlates to a parameter defined as the relative hydrogen index (RHI) of the oil (Bryan et al., 2003). RHI is a convenient way of expressing how much of the signal is lost due to the rapidly relaxing components that are not fully captured by NMR equipment. This is also consistent with LaTorraca's (1999) findings, but in the Canadian oil sands the bitumen samples have viscosity values much higher than the heavy oil samples studied by LaTorraca. These results demonstrate that, while in heavy oils the oil mean relaxation time is a valuable parameter for predicting in-situ viscosity, in bitumen formations the RHI term will be the primary NMR parameter for predicting oil viscosity.

The results from the lab NMR have been integrated with NMR and other petrophysical logs for viscosity and saturation estimation. A workflow is developed for core-log integration. First, oil/water T2cutoff values were calibrated using Dean-Stark core saturation and lab NMR measurements to establish the separation between oil and water signals in the spectra. Then the water amplitude and oil apparent amplitude were calculated from the NMR log using the calibrated T2cutoff. Finally, water saturation and RHI were computed from the amplitude; while oil viscosity was computed from the RHI using the correlations developed from core-log integration. The output from this study is a combined calculation of fluid saturations, oil viscosity and an indication of variability in pore size distribution within the formation. This allows for an improved understanding of optimal locations for well placement and the expected growth of the steam chamber within the reservoir during thermal operations.
Prediction of Effective Diffusion and Dispersion Coefficients, Considering Different Flow and Heterogeneity Properties of Porous Media
Authors: Taheri S. , Abedi J. , Kantzas A.
Published: June 2013

Heavy oil and bitumen are important hydrocarbon resources that are destined to play an increasingly significant role in the oil supply of the world. The total heavy oil resources are estimated to be about 10 trillion barrels, nearly three times the conventional oil in place in the world. The efficient and economic recovery of heavy oil and bitumen reserves is a crucial technical challenge. Most of these reserves lie deep inside the earth's crust and are not easily recoverable owing to their very high viscosity. Hydrocarbon solvent-based processes are thought to be effective EOR technologies for heavy oil and bitumen production.

An important feature of the miscible fluid displacement is the mixing of the solvent and oil. This mixing occurs on the microscopic scale and result from the diffusion and dispersion process. Mixing effect has positive and negative effects on the miscible process. It could exerts a considerable damping effect on the growth of viscous and gravity fingers as an advantage of the dispersion and diffusion and on the other hand mixing of the solvent with oil in a reservoir decreases the effective strength of the solvent, which can have annoying effect on the miscibility and recovery efficiency. So, correct treatment of this mixing effect within the simulation of the miscible recovery process is very important.

Mixing of the solvent and oil is governed by the diffusion and dispersion coefficients. For measuring these coefficients, we must depend largely on experimental measurements of them, because no universal theory permits their accurate a priori calculation. There are many influencing parameters on the mixing process during solvent injection into porous media. Designing an experiment to investigate all the effective parameters is extremely difficult (if not impossible) and time consuming. So, based on the sub-pore scale modeling method, a special program has been developed to investigate the mass transfer process in any porous medium, considering all medium properties. A realistic image of the porous medium without any simplification is directly used in the program.

Developed program used the porous medium image directly, so, heterogeneity effect could be investigated. Pore and throat size distributions, as an important heterogeneous parameter, has a unique effect on the diffusion and dispersion coefficients. A comprehensive study of the pore and throat size distribution effect on the mixing coefficients will be presented in this paper.
Advanced Numerical Simulation of Solvent Vapour Extraction (SVX) Processes
Authors: Imran Muhammad , Knorr Kelvin(Kelly) D , Jia Peng
Published: June 2013

This work presents advanced numerical simulation techniques that were developed to improve the history matching and predictive capability of both laboratory and field scale SVX processes. An algorithm was developed to incorporate the time dependence of SVX processes in the CMG STARS software; it incorporated a non-equilibrium solvent solubility method. A new methodology was developed to correct for excessive numerical dispersion effects at field scale gridblock sizes. Thermal effects due to solvent dissolution in heavy oil were also studied.

The advanced numerical simulation technique was constrained by PVT mixing experiments designed to generate mass transfer and non-equilibrium solvent solubility datasets for the solvent–oil system. The numerical models were tuned from the datasets obtained from three lab scale 3D SVX physical model experiments and by the use of a unique set of gas-liquid relative permeability curves (applicable to all three experiments) that employed the solvent mass transfer rate as the history matching parameter. The three physical model experiments varied in only model geometry and horizontal well placement. A relationship between reaction frequency factor (ra) and gridblock size was developed to correct for excessive numerical dispersion effects at field scale gridblock sizes. Thermal effects were incorporated in the numerical model by properly assigning the thermal parameters describing the fluid and porous media heat capacities and vaporization enthalpy coefficients.

The studies found that simulations conducted using a non-equilibrium solvent solubility method yielded more realistic relative permeability (kr) curves. The dissolved solvent concentrations and diluted oil viscosity profiles were also more realistic. The viscosity-reducing potential of the thermal effects of solvent dissolution were found to be negligible when compared with the viscosity-reducing effects of solvent dilution.
An Experimental Study of the Post-CHOPS Cyclic Solvent Injection Process
Authors: Du Zhongwei , Zeng Fanhua , Chan Christine
Published: June 2013

Cold heavy oil production with sand (CHOPS) has been applied successfully in many oil fields in Canada. However, only 5% - 15% of the original oil in place (OOIP) is recovered during cold production typically. Therefore, effective follow-up techniques are of great importance. Cyclic solvent injection (CSI), as a post-CHOPS process, has greater potential than continuous solvent injection to enhance heavy oil recovery. Continuous solvent injection results in early breakthrough due to the existence of wormholes; while in CSI process, the existence of wormholes can increase the contact area of solvent and heavy oil and the wormholes also provide channels that allow diluted oil to flow back to the wellbore.

In this study, the effects of wormhole and sandpack model properties on the performance of the CSI process are experimentally investigated using three different cylindrical sandpack models. The length and diameter of the base model are 30.48 cm and 3.81 cm, respectively. The other two models, one with a larger length (i.e. 60.96 cm) and the other with a larger diameter (i.e. 15.24 cm), are used for up-scaling study in the directions parallel and perpendicular to the wormhole, respectively. The porosity and permeability of these models are about 35% and 5.5 Darcy typically. A typical western Canadian oil sample with a viscosity of 4330 mPa · s at 15 °C is used. And pure propane is selected as the solvent. The experimental results suggest that (1) the existence of wormhole can significantly increase the oil production rate. The larger the wormhole coverage is, the better the CSI performance is; (2) a reservoir or well with wormholes developed at bottom is more favorable for Post-CHOPS CSI process; (3) the oil recovery factor is almost independent on the model diameter during the chamber rising phase; and the oil relative production rates in two different diameter models are close during the chamber spreading phase due to similar solvent dispersion rate; (4) the model length hardly affected the oil production rate comparing with the wormhole length; (5) the well with a horizontal wormhole is inclined to get a good CSI performance; (6) a relationship of oil production rate to drainage height is obtained and verified; (7) the mass transfer rate decreases verse time during the soaking period.
Kinetic Models for Low Temperature Oxidation Subranges based on Reaction Products
Authors: Khansari Zeinab , Kapadia Punitkumar , Mahinpey Nader , Gates Ian D.
Published: June 2013

In situ combustion (ISC) based enhanced heavy oil recovery is complex because there are numerous chemical reactions taking place simultaneously, in addition to mass transport and flow mechanisms, within the context where oil mobility is controlled largely by its temperature which in turn is controlled by heat transfer all occurring in a reservoir typically several hundred meters deep where geological heterogeneity is uncertain. From a reaction point of view, the complexity arises due to the immense number of components reacting through many different reaction paths in an underground system where the geology and heavy oil saturation vary spatially within the reservoir. It is known that there are four major classes of reactions taking place within an ISC process: low temperature oxidation (LTO), high temperature oxidation (HTO), thermal cracking (TC), and aquathermolysis. Within the reservoir, during ISC, LTO and TC reactions play a major role by providing fuel for HTO. In many documented reaction schemes in the literature, the LTO interval is considered as a single reactive zone spanning a single temperature range. In this work, a new reaction scheme is proposed based on analysis of thermogravimetric data where the LTO reaction temperature range has been separated into three temperature subranges each with their own dominant set of reaction products. The results demonstrate that models of LTO with a single range are inadequate for LTO modeling whereas multiple subranges were capable of representing the behavior of LTO effectively.
Closure Modeling Of Sub-grid-scale Effects For Well-drainage-scale Prediction Of CHOPS
Authors: VanderHeyden Brian , Ma Xia , Zhang Duan
Published: June 2013

A tractable, predictive modeling approach for Cold Heavy Oil Production with Sand (CHOPS) remains a significant practical challenge. In CHOPS, instabilities of oil-sand interactions lead to formation of meso-scale structures, such as wormholes or other defects. The sand stress concentration around these structures often leads to sand failure, and production of sand in the process. The failure and motion of sand alter the permeability, and hence affect the oil production. Because these structures result from the instability of the oil-sand interactions, sizes, shapes and locations of these structures are unpredictable. One can only describe them using the statistical methods. Furthermore, in typical well-drainage scale or multi-well-scale numerical simulations these mesoscale structures are typically below the level of resolution and must be modeled as sub-grid-scale effects. Rigorous well-drainage-scale averaged governing equations can be easily derived, but closure models for the sand stress and sand production cannot be adequately developed without proper description of the sub-grid effects.

The sub-grid momentum balance equation for sand demands that the divergence of the sand stress balances the gravity, pressure gradient and oil drag. Since gravity is a constant, and for a given mesoscale structure, the oil flow rate and hence the drag is determined by the imposed macroscopic pressure gradient, without information from sub-grid-scale pressure variation, we assert that the pressure gradient is the only independent variable affecting the stress and failure in sand. This leads to the proposition of closing the well-drainage-scale averaged governing equations in terms of the pressure gradient without explicitly involving the sand stress. Based on this proposition we derive a well-drainage-scale pressure diffusion equation without explicit representation of the sand stress.

To develop the closure models, we can extract information from both explicit full-physics simulations of the sub-grid-scale effects with resolved sand stress and from pilot scale production data. Full physics simulations using the multiphase material point method are shown to adequately model lab-scale wormhole experiments. History matched simulations at the well-drainage scale are shown to track transients in pilot data and are a measure of the success of the modeling approach.
Integrated Study of Foamy Oil Flow and Wormhole Structure in CHOPS through Transient Pressure Analysis
Authors: Xiao Lei , Zhao Gang
Published: June 2013

In this paper, a radial-composite CHOPS well model, integrating foamy oil flow and complex wormhole configurations, tends to investigate how wormholes and foamy oil can affect pressure responses of CHOPS wells simultaneously. Heavy oil starts containing dispersed gas and forming relatively continuous foamy oil when pressure drops below certain point. Such foamy oil with high compressibility and pressure-dependent properties makes the partial differential equations highly nonlinear and existence of wormholes makes them more difficult. Pseudo variables of pressure and time, introduced in this paper, aim at solving such nonlinear problems. Unsteady state problems of this model were solved semi-analytically using source and sink function methods. Generated type curves provide new transient pressure behaviours of mature CHOPS wells with wormholes and foamy oil flow. They show that effects of wormholes mainly dominate the early time flow period, while distinct fluid properties between foamy oil and original heavy oil zones start affecting late time flow period when pressure disturbance has reached the interface. Foamy oil compressibility can affect pressure responses significantly during late time flow period because it is very different from original heavy oil. With known foamy oil properties, this model provides new perspectives of transient pressure analysis of field pressure data to estimate wormhole coverages and drainage areas of foamy oil zones, which are very important in post-CHOPS development such as infill well drilling and EOR planning.
Stochastic Optimization of Hot Water Flooding Strategy in Thin Heavy Oil Reservoirs
Authors: Zhao David W. , Gates Ian D.
Published: June 2013

Stochastic optimization, based on a simulated annealing method, was done to determine the optimum hot water-flooding strategy for recovery of oil from thin (<6 m) heavy oil reservoirs. The results reveal that high injection pressures are critical to a successful hot water flooding strategy. For water temperature during injection, the results show from a thermal efficienty point of view that that it is most efficient to adopt a temperature profile where the injection temperature starts high and ends at low water temperature. Multiple cycles of this profile might be beneficial depending on the reservoir conditions. The lower temperature injection at later stages of the recovery process partially recovers the heat stored in the reservoir matrix and therefore increases the overall heat utilization efficiency. A sensitivity analysis shows that the permeability distribution affects the performance of the hot water flooding process most significantly. The existence of a higher permeability zone in the lower part of the reservoir leads to earlier oil production and water breakthrough. The absolute permeability value has the largest effect on process performance. High permeability was found to lead to more oil and water production in the early stage of operation and achieved the best economic performance. The low permeability case was found to show a slow oil production. Although it has the lowest cumulative injected energy to oil produced ratio, poor oil production made the operation process uneconomic.

Keywords: thin heavy oil reservoirs, hot water-flooding, energy to oil ratio, stochastic optimization, simulated annealing
Understanding the Thermo-Hydro-Mechanical Pressurization in Two-Phase (Steam/Water) Flow and its Application in Low-Perm Caprock Formations in SAGD Projects
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick
Published: June 2013

Steam-assisted gravity drainage (SAGD) is one successful thermal recovery technique applied in the Albertan oil sand reservoirs. When considering in situ production from bitumen reservoirs, bitumen viscosity must be reduced to achieve the mobility required to flow toward the production well. Steam injection is currently the most promising thermal recovery method. While steam flooding techniques have proved to be commercially viable methods to extract bitumen from bitumen reservoirs, caprock integrity and the risk of losing steam containment can be a challenging operational problem. Since permeability is low in Albertan thermal project caprock formations the water trapped in pores undergo large pressure increases during heating. In addition, water undergoes a large volume increase as it flashes to steam and the resultant pore pressure causing profound effective stress reduction. Once this condition is established, pore pressure increases can lead to shear failure of the caprock, and to subsequent caprock integrity failure or casing failure. It is typically believed that low permeability caprocks impede the transmission of pore pressure from the reservoir, making them more resistant to shear failure (Collins, 2005, 2007). In cases of "thermo-hydro-mechanical pressurization", low permeability caprocks are not always more resistant. As the steam chamber rises into the caprock, the heated pore fluids may flash to steam. Consequently, there is a vapour region between the steam chamber interface penetrated into the caprock and water region within the caprock which is still at subcritical state.

This study develops the fluid mass and thermal energy conservation equations and presents analytical solution to evaluate the thermo-hydro-mechanical pressurization in low permeability caprocks and flow of steam and water after initiation of steam injection in SAGD process. Both short-term and long-term response are calculated. The evaluated thermal pressurization is compared for shallow and deep oil sand reservoirs, for similar transport properties. These results showed that the thermo-hydro-mechanical pressurization is larger in deep reservoirs; SAGD application can cause high pore-pressure and potential shear with the caprock resulting steam releases to surface and casing failures.