bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Acid Gas (CO2/H2S) for the Cyclic Solvent Injection (CSI) Process for Heavy Oil Reservoirs
Authors: Huerta M. , Alvarez J. M. , Jossy E. , Forshner K.
Published: June 2012

Acid gas is a greenhouse gas (GHG) composed of (CO2/H2S). It is produced during oil, gas, and petrochemical operations. During the last several years, there has been an increasing pressure within the oil industry in Canada to further reduce GHG emissions. Another environmental problem within the oil industry comes from the elemental sulphur, which is converted from the H2S and is accumulated on the surface. Currently, there exist two technological solutions to deal with this challenge. The first one is acid gas injection into geological formations for sequestration purposes. This option has been developed in Canada over the last 22 years. The second one is the use of it for EOR operations in conventional oil reservoirs. This option has successfully been applied in Zama, a Canadian conventional oil reservoir.

There is an interest within the oil industry again to evaluate the performance of CO2/H2S to also recover heavy oil during the Cyclic Solvent Injection (CSI) process. The CSI process has already shown success in improving heavy oil recovery after primary cold production (CHOPS) using pure solvents or (CO2 /propane or CH4/propane) mixtures. Consequently, if feasible, CO2/H2S injection for CSI could also contribute to increase the heavy oil recovery factor while eliminating the accumulation of sulphur on the surface and sequestering this greenhouse gas. The results of this work indeed demonstrated that the CO2/H2S mixture tested performs better for the CSI process than some of the conventional solvents previously tested i.e. pure CO2 or methane/propane mixture. Not only the recovery factor was better but also the oil recovery declined less with subsequent cycles by using CO2/H2S mixture rather than using pure CO2. It is important to mention though that the mixture of CO2/propane still shows the best performance in the series of solvents studied so far for the Cyclic Solvent Injection at Alberta Innovates Technology Futures.
Hydroxide Alkalinity Management Using Recycled Boiler Blow Down or Caustic in SAGD
Authors: Weagle Glenn , Maltman Ron
Published: June 2012

Many SAGD facilities will boost the Boiler Feed Water (BFW) alkalinity with caustic to maintain the necessary alkalinity for corrosion protection in Once Through Steam Generators (OTSGs) and to promote rapid oxygen scavenging reactions in the boiler feed water circuit. However, some facilities can facilitate hydroxide addition with recycled boiler blow down into the BFW, thus reducing the necessity of supplemental caustic addition. This operational strategy and the issues will be discussed. This presentation outlines a case study where the management of the recycled boiler blow down resulted in reduction of caustic application, leading to operating chemical cost reductions.
A Geomechanical Methodology for Determining Maximum Operating Pressure in SAGD Reservoirs
Authors: Walters Dale , Wang Jin , Settari A.
Published: June 2012

The thermal recovery of bitumen reservoirs by steam assisted gravity drainage (SAGD) is often designed to maximize the operating pressure while maintaining a safe and economic operation. In general, higher operating pressure can reduce thermal efficiency due to heat losses to over/underburden formation, but the other benefits usually compensate. To name a few, higher steam temperatures can maximize the reduction of oil viscosity, enhance permeability associated with lower effective stress and shear dilation, and give a larger pressure window to allow flexible control of the producer. This is especially important for shallow reservoirs where the pressure window for injection and production is smaller. The limitation of the maximum operating pressure is then based on maintaining caprock integrity. Thus, shear and tensile failure mechanisms should be quantified and managed.

This paper presents a methodology to perform a geomechanical analysis of caprock integrity for SAGD operation and illustrates the available approaches. Both analytical and numerical approaches are compared demonstrating their usefulness. Main factors in the analysis are the knowledge of the initial stress state and proper representation of the complexity of the geomaterials. A typical initial stress state for a northern Alberta SAGD property, Suncor's MacKay River project, is presented showing the potential for low initial minimum total stress and elevated initial shear stress levels. The stress-strain behavior for the MacKay River sand and caprock materials is discussed focusing on the potential for shear dilation in the sand and shear strength behavior in the caprock. An elasto-plastic constitutive model is used to represent the sand and caprock materials. The increase in pressure and temperature alter the stress state and disturb the soil matrix. This disturbance results in shear dilation of the sand matrix creating regions of enhanced permeability and porosity. Also, the transfer of stress and strain to the caprock causes dynamic stress changes and, therefore, dynamic behavior of shear and tensile failure conditions. Calculations are presented showing the stress paths associated with SAGD operations, suggesting better design of lab testing programs and the implications for shear dilation in the sand and shear failure in the caprock. Finally, the results are used to demonstrate locations that are most likely at risk for potential tensile and shear failure. Stress ratios are used to summarize the analysis and quantify and monitor the failure mechanisms.

The above methodology has been developed and applied in several studies of other SAGD projects and aided the operators in the optimization and permitting the operating conditions.
Impact of Adsorption on Mass Transfer in Fractured Reservoirs
Authors: Sharifi Haddad A. , Hassanzadeh H. , Abedi J. , Chen Z.
Published: June 2012

The analysis of fluid transport in fractured reservoirs is of great concern in petroleum and environmental engineering. The objective of this work is to study mass transfer between the matrix and the fracture network in such complex formations. In this study, the impact of adsorption on mass transfer in a fractured medium with variable fracture spacing is investigated. Development of a mathematical model for mass transfer in dual porosity systems enhances predictions of the rate of mass transfer between matrix and fracture. In addition, it provides a tool for an appropriate design of advanced oil and gas recovery processes. Mass transfer is modeled based on the advective-dispersive transport with adsorption in an infinite acting dual porosity reservoir under radially divergent and continuous injection. The fracture spacing has been taken into account by including the variable rock matrix block size distribution in the developed model.

By employing this model, the effects of the adsorption rate on the mass transport in a subsurface environment are analyzed. The impact of the rate of adsorption on the accumulation of the injected tracer (catalyst) in a reservoir is investigated. An understanding of the effect of adsorption on advective-dispersive mass transport with variable fracture intensity can be a key finding to develop and design advanced oil recovery processes.
An Extensive Review on the Effective Sequence of Heavy Oil Recovery
Authors: Mohammadpoor M. , Torabi F.
Published: June 2012

Different enhanced oil recovery (EOR) techniques for heavy oil reservoirs were reviewed for their ranges of applicability using available reports and publications. EOR screening criteria found in the literature are reprinted and provided. After reviewing more than 100 papers on the subject, it is apparent that there is a definitive knowledge gap on the effective sequence of EOR recovery strategies. While there are numerous studies on the application of heavy oil recovery techniques, there is a lack of comparison and categorization of the results.

For Canadian reservoirs, the first recovery method that is implemented first is either waterflooding, cold production or in some cases steamflooding. Chemical flooding and other emerging technologies are mostly coupled with these methods. In most reports, conversion of producers to injectors and introducing line drive and edge drive will improve the waterflooding performance. However, coupling waterflooding with horizontal wells, the addition of water mobility control agents and steam stimulation did not improve the waterflooding performance in some cases. In the case of fractured limestone reservoirs, it seems that immiscible gas injection is a suitable EOR method to implement, but because of the reservoir complexity, a clear understanding of the recovery mechanism and reservoir geology is needed. In-situ combustion and steamflooding are among the most efficient heavy oil recovery methods with a large range of applicability, and next to waterflooding, can become the most widely used heavy oil recovery method. Fireflooding methods can be more profitable if they are coupled with simultaneous or intermittent water injection with air.

The results obtained from this paper not only will help the petroleum industry to apply each technique to the right candidate fields, but also it will prevent researchers from duplicating unsuccessful research projects.
New Upstream and Downstream Technologies for Extra Heavy Oils
Authors: Zolotukhin Anatoly , Bokserman Arkady , Kokorev Valery , Nevedeev Andrey , Ushakova Alexandra , Shchekoldin Konstantin
Published: June 2012

Heavy oil and bitumen are found in many places worldwide, with the largest deposits in the world being in Canada (Alberta), Venezuela and the former Soviet Union.

Among huge conventional and unconventional oil resources so-called Bazhenov series represent one of the highest hydrocarbons potential in Russia. Its resources of light oil considerably exceed conventional oil resources, and extra heavy oil resources are estimated to be hundreds of billion tons (some estimates go beyond 2 trillion tons). Despite huge geological HC resources allocated in BS technology for their effective development is still a challenge.

Thermogas is one of the promising EOR technologies that are under development in Russia. First theoretical as well as experimental and pilot results indicate that this technology could be successfully deployed for the development of hydrocarbons located in Bazhenov series.

It is anticipated that the use of Thermogas technology for extraction of hydrocarbons from BS, based on successful application of similar technology for enhanced recovery of light oils from fractured dolomite formations in USA, can result in recovery of at least 35–40% of their resources. This could open up huge yet poorly estimated world unconventional oil resources that enable sustainable production of hydrocarbons at a global scale for many decades.

Technology of "cold" mechanical oil processing is another "attraction point" of intensive research in Russia. This new approach is based on extremely localized "injection" of required amount of energy in order to break intermolecular and intramolecular chemical bonds in hydrocarbon compounds and molecular conglomerates. Technological effect is gained by means of initiation of the cavitation processes in the treated medium.

Heavy organic molecules (asphaltenes, long paraffin and other complexes) and their conglomerates present in crude oil and subjected to this technology undergo breakdown of chemical bonds and, as a result, drastic changes in crude oil properties like viscosity and, to a lesser extent, density.

Although technology is at its initial, i.e. "nucleus" development phase, its applications are perceptible in many potential areas of application, from up- to mid- and to downstream petroleum sectors.

Recent developments in Thermogas EOR as well as in cold mechanical oil processing are described in this paper.
Laboratory Evaluation of Thermoreversible Gel for In-Depth Conformance Control in Steam-Stimulated Wells
Authors: He Hong , Wang Yefei , Zhao Mengyun , Cheng Limin , Liu Peng
Published: June 2012

Cyclic steam stimulation(CSS) is one of the most common methods used to improve oil recovery in heavy oil reservoirs. However, due to reservoir heterogeneity, unfavorable mobility ratio and gravity segregation, steam channeling through high permeability zones occurs, resulting in poor sweep efficiency and a reduction in ultimate oil recovery. To settle the steam channeling problem, this paper presents the laboratory evaluation of a thermoreversible gel formed from hydroxypropyl methylcellulose (HPMC) for in-depth conformance control in steam-stimulated well. The effects of concentration of HPMC, sodium chloride and urea on the gelation temperature, gel strength and degree of syneresis observed in gel samples were studied. The long-term thermal stability of the thermoreversible gel was evaluated. Sandpack flow experiments were conducted to evaluate the reversibility of plugging and selective plugging ability.

The experimental results showed that as the concentration of HPMC increased, the gelation temperature, degree of syneresis decreased and gel strength increased. Based on proper gelation temperature, good gel strength, degree of syneresis and economical cost, the proper concentration of HPMC should range from 2.0wt% to 2.5wt%. The gelation temperature and gel strength increased with increasing sodium chloride concentration. While as urea concentration increased, the gelation temperature increased and gel strength decreased. After aging for 60days at 110°C, about 3.5% syneresis was observed in gel samples, which indicated that the gel had good long-term thermal stability. The singular and parallel sandpack flow results showed that the thermoreversible gel had good reversibility of plugging and selective plugging ability.

Therefore, these results indicate that the thermoreverible gel studied here are good candidates for in-depth conformance control in steam-stimulated wells, which can provide a basis for field application.
Full Field Applicability of MWAGD Process Coupled With Horizontal Well Pair Model to Recover Extra Heavy Oil and Bitumen
Authors: Bansal Gopal , Jha Ashutosh Kumar , Chauhan Nitesh , Sharma Tushar
Published: June 2012

Applicability, assessment and work-how of Micro-Wave Assisted Gravity Drainage (MWAGD) process in Mehsana (India) heavy oil field along with added advantages over SAGD were presented in the previous part of this paper [1]. Various studies have been done during last 10 years illustrating wider applications of micro-wave heating of heavy oil reservoirs through quantitative and qualitative exercises. But the main problem that arises in micro-wave heating is very low penetration depth of micro-wave radiations which limits the application of this unconventional thermal EOR method on full field scale.

The scope of this paper is to eliminate this problem by using horizontal well pair combination which enhances the drainage area within the heating radius of micro-wave radiations.The phenomenon of conversion of Micro-wave energy to heat energy is described and finally, a mathematical model based on energy balance principle is developed.

Two parallel and vertically aligned horizontal wells are drilled. The upper well is production well and lower well is micro-wave source well with their length and vertical separation on the order of 500 meters and 15 meters respectively. In the lower well micro-wave sources are installed at various positions along the length with longitudinal spacing on the order of 20 meters. Advantages of heating of oil from the lower well are explained in lucid manner. This type of installation model confirms the coverage of larger reservoir volume in spite of short penetration depth of micro-wave radiations. Along with volumetric and selective heating in this process heat is developed within the formation fluid rather than being brought to it from the outside, and hence the fluid is heated more uniformly throughout the medium. Also, above proposed model can be applied effectively in case of carbonate formations where uneven sweeping occurs along steam assisted gravity drainage (SAGD) well pairs due to vuggs and fractures.
Electron-Induced Chain Reactions of Heavy Petroleum Fluids—Dominant Process Variables
Authors: Alfi Masoud , Da Silva Paulo F. , Barrufet Maria A. , Moreira Rosana G.
Published: June 2012

Ionizing electron particles were used as an efficient means of delivering energy to heavy hydrocarbon molecules. Although heavy oil reserves are known as rich sources of energy, their contribution to the energy market has been impacted by the fact that the conventional thermal or catalytic upgrading and visbreaking methods always demand a considerable energy and money investment. Therefore, application of potential alternatives with lower operating costs and higher process throughput appears to be extremely crucial in such a competitive market. In this research, high-energy electron processing technology was offered as a remedy to reduce the viscosity of heavy petroleum samples. Irradiated fluids exhibited lower viscosities than thermally cracked samples. Moreover, reaction temperature was observed to have a substantial influence on radiolysis process. At relatively low temperatures, radiation-induced upgrading stays inactive without any contribution to the viscosity reduction process. However, as the temperature exceeds a specific threshold, radiation-induced chain reactions become activated, decreasing the viscosity of irradiated samples. At the end, we have investigated the effect of different additives upon radiolysis of hydrocarbon molecules. Interestingly, radiolytic reactions were completely suppressed by some of these additives.
Sub-Cool, Fluid Productivity, and Liquid Level above a SAGD Producer
Authors: Yuan Jian-Yang , Nugent Daniel
Published: June 2012

Thermodynamic steam trap, or sub-cool control, in a typical SAGD production is essential to the stability and longevity of the operation. It is commonly achieved through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing bypassing of steam from the injector to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule of thumb sub-cool estimation of 10°C/m of liquid level is popularized in the industry, however, does not prove to hold in many situations.

This paper presents a study of the dynamics of SAGD production control with a resulting algebraic equation that relates sub-cool, fluid productivity and wellbore draw down to the liquid level above a producer. The main conclusions of this study include: There is no minimum sub-cool value for a pure gravity drainage scenario; however, as the wellbore draw down is considered there is minimum sub-cool value in order to maintain the stability of fluid flow.For a given productivity, the liquid level increases as sub-cool increases or as wellbore draw down decreases.For each set of parameters, there exists a minimum productivity below which SAGD operation would halt.Before the steam chamber reaches the top of the reservoir, the production rate is limited by the vertical distance between the injector and the producer, the larger the distance the higher the production rate can be.

A verification of this analysis was conducted via a series of numerical reservoir simulations. Although limited to 2D, we believe this analysis captures the main physics amid the dynamic complexity of SAGD production control. The resulting algebraic equation can be used for better understanding the dynamics of sub-cool control and determining operation strategies.
Foamy Oil Behaviour in Solvent Based Production Processes
Authors: Bjorndalen N. , Jossy W. E. , Alvarez J. M.
Published: June 2012

Foamy oils, generated during cold production, have also been detected in solvent based recovery processes. Understanding the foamy oil mechanism is key to determining how oil is produced in processes such as Cyclic Solvent Injection (CSI). Visual observations of solvent exsolving from solution during depressurization were performed to gain a better understanding of these processes.

Heavy oil saturated with CO2, CH4, C3H8 and a combination of CO2 and C3H8 are examined in an etched glass micromodel. Three different expansion rates are examined. The results indicate that CO2 and CH4 show an extreme supersaturation. CO2 saturated oil produces more nucleation sites than CH4, C3H8 and a mixture of CO2 and C3H8. Approximately 8 times more nucleation sites were produced with CO2 than with CH4. With more nucleation sites, there is a greater potential for oil recovery with solution gas drive.

The experiments conducted here provide a qualitative understanding of the foamy oil process and aid in the understanding of solvent based enhanced oil recovery mechanisms such as Cyclic Solvent Injection (CSI).
A Non-thermal Surfactant-Polymer Based Technology for Enhanced Heavy Oil Recovery in Oil Sand and Ultra Shallow Reservoirs
Authors: Wu Yongfu , Mahmoudkhani Amir , Watson Philip , Fenderson Thomas , Kolla Harsha , Nair Mohan
Published: June 2012

Current technologies for in-situ heavy oil recovery involve either heating the reservoirs to liquefy the hydrocarbons or attacking the deposits with solvents. This is usually accomplished by providing a source of external energy such as using natural gas to heat the oil or subjecting it to mechanical stimulation. However, a challenging case is in ultra-shallow reservoirs where the recovery is limited only to matrix oil drainage by gravity. In these cases, many heavy oil reservoirs are too thin to use thermal processes for enhanced heavy oil recovery due to the heat losses to overburden and underburden. In this paper, a study to develop a new technology to increase heavy oil recovery using alkali, surfactant and polymer is presented. It has been found that novel surfactants can create a stable emulsion for heavy oil and formation brine, by which viscosity of heavy oil can be reduced significantly. At 25 °C, the viscosity of heavy oil is 15,785 cP. But when the heavy oil and synthetic brine are emulsified with some new surfactants, the viscosity reduces about 2.88 to 3.46 cP. Therefore, the mobility of heavy oil is improved significantly.

In order to analyze the contribution of the various components to viscosity, a heavy oil sample was separated with a silica gel column. It was found that asphaltenes and resins, the two heaviest and most polar components in the heavy oil, exert the largest influence on the viscosity of heavy oils. Viscosity decreases as temperature increases, which is leveraged by thermal technology for heavy oil recovery. The decrease in viscosity is most pronounced, however, at temperatures below 60 °C. The high viscosity of heavy oil can be dramatically reduced further by emulsification with proper surfactants and alkali, which is the principle behind non-thermal technology for heavy oil recovery.

In this research, emulsions created by the surfactants B and E are stable at 25 °C, and their performance in non-thermal heavy oil recovery was evaluated using sand pack flooding test. 23% of heavy oil recovery was achieved by injection of surfactant B and polymer Superfloc® A-110 HMW. It has also been found that injection of 1.0 PV of surfactant solution followed by injection of 1.0 PV of polymer solution to be the optimum methods for both surfactants B and E. In most cases, Superfloc® A-110 HMW polymer seems to be slightly better than Superfloc® A-120 V for enhanced heavy oil recovery.
Caprock Integrity Case Study for Non-thermal Polymer Flooding Project Using 4D Reservoir Coupled Geomechanical Simulation
Authors: Ansari S. , Haigh R. , Khosravi N. , Khan S. , Han H. , Vishteh M.
Published: June 2012

Maintaining an effective caprock seal is of prime importance in any enhanced oil recovery (EOR) stimulation involving subsurface injection of fluid. Hydraulic or mechanical breaching of the caprock may entail leakage of injected fluids and/or hydrocarbons into shallower formations, or even to the surface, with the potential for adverse environmental impact. Determining a safe optimal injection pressure which minimizes the likelihood of such an occurrence is a challenging problem. For example, assessing caprock integrity with the static stress measurement alone at the virgin state of reservoir without considering dynamic stress changes is likely to be both unreliable and inadequate.

In this paper, we present a case study of hydraulic and mechanical integrity of Wabiskaw caprock at multiple injection scenarios under dynamic conditions. In this study a multi-disciplinary approach was used which integrates geology, petrophysics, reservoir engineering and geomechanics followed by a finite element coupled reservoir-geomechanics simulation. A 3-D mechanical earth model (MEM) was constructed utilizing advanced azimuthal shear anisotropic sonic log and core based mechanical properties. All the available LOT mini-frac as well as MDT micro-frac tests data were assessed and used to calibrate the anisotropic stresses at initialization step in addition to assessing the lateral variability of the vertical stress. Several tight streaks expected to provide additional abutment to the primary caprock were honored in the model. The 3-D MEM was extended to the surface and embedded with the sideburden and underburden layers incorporating adjacent injectors and producers to minimize the boundary effects.

This study evaluated tensile and shear failures within the reservoir and the caprock at several injection scenarios for a period of 30yrs with injection bottomhole pressures of 116 and 155bar at the rate of 150 m3/day. No shear failure or tensile failures were predicted by the coupled geomechanical simulator in the caprock for all the injection scenarios. This model also predicted the vertical displacement within the reservoir, caprock and at the surface. The amount of heave at the ground surface was negligible.
Associative Polymers Outperform Regular Polymers Displacing Heavy Oil in Heterogeneous Systems
Authors: Wassmuth Fred , Green Ken , Bai Jen
Published: June 2012

The use of polymer floods to efficiently displace heavy oils with viscosities up to 10,000 mPa.s has be tested successfully in laboratory scale evaluations; commercial success on the field scale has been achieved with oil viscosities up to 2000 mPa.s in Western Canada1 and other parts of the world1. Since it has been established that the polymer flood technology can be successful at displacing heavy oils on a field scale, it is timely to improve the efficiency of this technology. Researchers have shown that heterogeneities are more detrimental when waterflooding heavy oils than experience obtained from conventional waterfloods3, 4. Hence, it is essential to understand the polymer flood displacement of heavy oil in the presence of heterogeneities. In addition, it was beneficial to conform the impact of large scale heterogeneities with judicious use of associative polymers.

Building a high and low permeability layer into a cylindrical sandpack allowed for demonstrating the impact of heterogeneities on a waterflood and polymer flood displacing heavy oils; the high permeability layer had a permeability 10 times greater than the low permeability layer. The reduced oil recovery in the heterogeneous, dual permeability core can be modeled correctly using a reservoir simulator if a capillary pressure difference curve is introduced during the simulations. The capillary pressure difference curve controls the degree of cross-flow from the high permeability layer to the low permeability layer and corrects the sweep efficiency.

Salinity and hardness tolerant associative polymers suitable for injection into reservoir core have been screened and developed for heavy oil displacement processes. These specialty polymers generate a higher in situ apparent viscosity by forming large hydrodynamic radii through association between polymer molecules. In reservoir applications, these associative polymers may generate tremendous resistance factors in high permeability streaks. The dual permeability corefloods demonstrated that associative polymers outperformed the regular partially hydrolyzed polyacrylamides in two aspects: (1) the associating polymer generated incremental oil recovery after HPAM recovery and (2) the mobility reduction (or resistance factor) of the associative polymers was significantly higher than HPAM. Hence associative polymers can be used for blocking and diverting purposes in high permeability layers where regular polymers may not be as effective.
Challenges While Performing Infill Cementing Amongst Existing SAGD Wells
Authors: Schneider Jason , Sylvestre Chuck
Published: June 2012

The drilling and completing of Infill wells (wells drilled amongst existing SAGD wells) is becoming common practice with many operators in North Eastern Alberta. These Infill wells pose numerous challenges that may not exist in the drilling and completing of a conventional SAGD well. In addition to conventional challenges such as lost circulation that need to be safely managed to have a successful completion strategy, the Infill wellbore has elevated temperatures and heat transfer rates due to contact with or close proximity to a steam chamber. There is no single, universal strategy used by operators to address and control these challenges, which require robust cementing solutions.

Many clients are completing Infill cementing with expected bottom hole circulating temperatures (BHCT) ranging from 35°C to 100°C. This variation in clients’ BHCT results is due in part to the drilling, and more specifically, the circulation strategy used. Static periods of only a few hours can bring the effective temperature to that of the reservoir. As a conventional SADG strategy cannot be used for all wells, a specific blend design utilizing different technologies must be investigated. The large variations in bottom hole static temperature (BHST) and BHCT require complete understanding of the cement blend performance and its specific application. Cement blend designs that are applicable and can perform over a range of temperatures reduce the impact of these challenges.

With the frequency of Infill cementing expected to increase, a greater understanding of the effective wellbore temperatures and the subsequent effective applicable temperature range of cement blends is needed.
Real Time Optimization of SAGD Wells
Authors: Gonzalez Luis E. , Ficocelli Peter , Bostick Tad
Published: June 2012

The SAGD process has been utilized for the past 15 years and an efficient steam utilization process provides the best solution to reducing the variable production costs and to increasing the recovery rate. The use of real time downhole monitoring is an effective approach to achieve this optimization. The main objective of steam injection is to decrease the oil viscosity, so it can flow through the horizontal and the vertical sections.

The emergence of downhole distributed sensing (DTS) and array temperature sensing with fiber optics technology has led to instrumented wells allowing operators to access data on a real time basis leading to a better control of the operations and the ability to optimize the steam process. Additionally, fiber optics technology allows for the measurement of pressure and temperature on same fiber and in close proximity along the wellbore. In the ultra-high temperature environment the amount of pressure monitoring points are limited and many SAGD operators are asking for at least 3 pressure in-conjunction with the distributed temperature points.

The SAGD process has a number of different variables that are dynamic and complex and changing with time. The most important variables of the process include the steam injection rates, subcool and downhole pressure and temperature. One of the key objectives when using the SAGD process is to reduce the SOR to lower the high cost of steam generation. The optimization of the SOR is a process of reducing the steam injection rate and/or increasing the oil production. Since SAGD is a dynamic process this can only be achieved through the use of Real Time Optimization.

Once the steam reduces the viscosity and mobility of the oil is achieved, the SAGD well production can be optimize using the nodal analysis technique meaning that an Inflow (very dependent with temperature & viscosity) will be calculated and optimized but it is also necessary at same time to calculate the outflow which is dependent on the type and optimization of artificial lift system that is used. The integration of different measured points of pressure and temperature (40 points of temperature and 2 pressure points) using fiber optic technology along the horizontal section of the producer well with other parameters like wellhead pressures, temperatures and mainly production rates will allow for the optimization of the SAGD Process and better management of the well.

This paper will describe in detail the processes that are required to be controlled and the main variables that are needed to be measured and calculate to optimize the oil production on a SAGD well.
Numerical Simulation Studies on Development of an Offshore Heavy Oil Field by Early-stage Chemical Flooding
Authors: Sun F. , Zhang X. , Kang X. , Gong B. , Liu W. , Qin G. , Xu J.
Published: June 2012

As one of the major enhanced oil recovery mechanisms, chemical flooding procedure has been widely and successfully used in matured fields and the overall sweep efficiency has been improved between 5–12% due to various chemical flooding treatments. China National Offshore Oil Company (Cnooc) started its pilot offshore chemical flooding projects to evaluate the chemical flooding opportunities at early development phase. In this paper, we present numerical simulation studies on overall evaluation of a Cnooc’s offshore heavy oil chemical flooding project using chemical flooding simulator.

In the numerical simulation studies, we have developed a numerical model with the focus on various complex chemical flooding procedures. Moreover, we have also developed a dynamic well model that is capable of modeling multi-phase flow inside complex multi-lateral wellbores. An algebraic multi-grid linear solver has been developed and implemented into the simulator. As the simulator has been developed following the advanced software architecture design and it can be easily expanded other field applications.

The targeted field in this paper is an offshore heavy-oil field with hundreds of wells and a complex fault system. The production started in 1999, and waterflooding in 2000. In 2007, all water injectors have been switched to polymer injection for better conformance control. In this field-scale reservoir simulation study, the polymer solution, reservoir brine and the injected water are represented as miscible components of the aqueous phase. Key factors such as inaccessible pore volume, polymer shear thinning effect, polymer adsorption, and relative permeability reduction factors have been taken into account for the construction of the mathematical model. Simulations have been run for evaluation on optimal polymer injection timing, amount and pattern.
Prediction of Bitumen and Solvent Mixture Viscosity Using Cubic-Plus-Association Equation of State
Authors: Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal
Published: June 2012

Viscosity is an important transport property for engineering design and simulation of bitumen production and transportation. During the production of bitumen with solvent injection, steam-assisted gravity drainage (SAGD) or expanding solvent steam-assisted gravity drainage (ES-SAGD), the produced fluid is faced with various temperature, pressure and composition conditions. Therefore, a model is necessary to predict the viscosity of the mixture of bitumen and solvent in wide ranges of temperatures, pressures and compositions (T-P-x).

In this work, we propose a semi-theoretical viscosity model based on the Arrhenius mixing rule and considering the effect of association between the molecules of the solvent and the bitumen. To achieve this purpose, thermodynamic perturbation theory (TPT) is used. The association part of the cubic-plus-association (CPA) equation of state (EoS) is applied to calculate the fraction of bonding solvent molecules. We calculate the viscosity of the solvent in wide temperature and pressure ranges using the modified Enskog theory (MET).

Results show an acceptable agreement between the results of this model and experimental viscosity data of saturated bitumen with different solvents (CH4, N2, CO2, and C2H) at various T-P-x ranges. These experimental data cover the typical T-P-x ranges of oil recovery methods.
Forecasting SAGD Process under Geological Uncertainties Using Data-Driven Proxy Model
Authors: Fedutenko E. , Yang C. , Card C. , Nghiem L.
Published: June 2012

Resevoir simulations are routinely employed in the prediction of the performance of SAGD (Steam Assisted Gravity Drainage) process under different operating scenarios. They have been shown to have a significant potential to predict the future performance of SAGD operations. Due to the inherent uncertainty of petroleum reservoir data, the prediction needs to take into account the geological uncertainties associated with a particular reservoir. Usually, this is achieved by obtaining a history-matched model, conditioned to production field data. The model is then used to forecast future production profiles. Since the history match is time restricted to the previous production period, this is essentially an extrapolation problem with respect to time. Hence, such forecasts may not be very accurate. In addition, the simulation time is quite substantial for field studies with a large number of gridblocks. Therefore, forecasting workflows that reduce the number of necessary simulations while providing an accurate prediction are highly beneficial.

This paper presents a new approach for predicting production performance during SAGD process based on the results of SAGD simulations for a case with 3 well pairs. The approach utilizes the following workflow. Firstly, the field data were obtained, which consist of production outputs (particularly - cumulative Oil and cumulative SOR) for a typical time horizon of 5 years and the corresponding operating conditions. Secondly, a number of equiprobable geological realizations was generated using geostatistical methods to describe the permeability and porosity uncertainties of the reservoirs. Thirdly, direct numerical simulations of all realizations were conducted under a production operating scenario for a 10-year period. Then the data-driven proxy model is built that fits the actual field data to a linear, non-local function of the simulation data. The non-locality means that all the 10-year simulation results are considered in the match of the 5-year production data. After that the proxy is used to predict the production field data for the next five years. In this work, since the actual full 10 years of data are known, the predicted data are compared with the actual production data for the same period to evaluate the prediction quality.

This workflow is applied to a synthetic 3-Well-Pair SAGD model. It is shown that the proposed approach provides a highly reliable forecasting procedure for the reservoir considered. The difference between the predicted and actual field data lies within few percents, while the computational cost remains quite low. The use of the proposed approach in the prediction of uncertain reservoir performance under different operating scenarios during the SAGD process is also discussed.
Experimental Study of In-Situ Upgrading for Heavy Oil Using Hydrogen Donors and Catalyst under Steam Injection Condition
Authors: Zhang Zhiyong , Barrufet Maria , Lane Robert , Mamora Daulat
Published: June 2012

This research is a study of the in-situ upgrading of Jobo crude oil using steam, tetralin or decalin, and catalyst (Fe(acac)3) at temperatures of 250 °C, 275 °C and 300 °C for 24 hours, 48 hours and 72 hours using an autoclave. Viscosity and API gravity changes were investigated. We found that tetralin and decalin alone were good solvents for heavy oil recovery. Tetralin or decalin at concentrations of 9% (weight basis) could reduce the Jobo crude oil viscosity measured at 50 °C by 44% and 39%. Steam alone had some upgrading effects. It could reduce the oil viscosity by 10% after 48 hours of contact at 300°C. Tetralin, decalin or catalyst showed some upgrading effects when used together with steam and caused 5.4%, 4% and 19% viscosity reduction compared with corresponding pre-upgrading mixture after 48 hours of reaction at 300°C. The combination of hydrogen donor tetralin or decalin and catalyst reduced the viscosity of the mixture the most, by 56% and 72% compared with pre-upgrading mixture. It meant that hydrogen donors and catalyst had strong synergetic effects on heavy oil upgrading. We also found that 300 °C was an effective temperature for heavy oil upgrading with obvious viscosity reduction in the presence of steam, hydrogen donors and catalyst. Reaction can be considered to have reached almost equilibrium condition after 48 hours. The study has demonstrated that in-situ heavy oil upgrading has great potential applications in heavy and extra heavy oil recovery.
Modelling of Gas Exsolution and Transport in a Live Heavy Oil Reservoir
Authors: Uddin M.
Published: June 2012

Depressurization causes the exsolution of dissolved gases as bubbles within the live heavy oil reservoirs. The exsolution of bubbles increases the fluid volume within the reservoir, forcing both oil and bubbles to the well. Subsequently, growth and coalescence lead different sizes of gas bubbles accumulation in the producing zone which mainly controlled by viscous and capillary forces. Laboratory data show a significant amount of gas bubbles become trapped in the flow system. This entrapment of the gas phase results in higher critical gas saturation. Modelling of gas bubble exsolution and transport is vitally important in designing production technology for improving oil recovery. This project was devoted to develop a mechanistic foamy oil model for quantifying gas exsolution and transport which can operate within the commercial reservoir simulator.

The foamy oil model has been completed in two parts: In Part 1, a kinetic model with five components and four reactions was developed to simulate gas exsolution in a live heavy oil reservoir. The kinetic model coupled with the commercial simulator (CMG STARS) was applied to history matching of several laboratory gas exsolution experimental data. Performance of the model in special form under different flow regimes has been presented at the 2005 SPE/PS-CDVI/CHOA Symposium. In Part 2, we developed a set of analytical functions to quantify gas bubbles partition and gas-oil relative mobility in reservoir porous media as function of capillary number.

In this paper, the foamy oil model in generalized form is systematically presented: (1) history matches of mercury withdrawal experiments – studying the gas exsolution parameters with capillary number, (2) analysis of micro-model tests – developing a gas bubbles partition function depending on capillary number, and (3) history matches of radial drainage pressure depletion experiments – developing a set of relative permeability alteration functions depending on grid block capillary number for field scale modeling.
Experimental Investigation of the Effect of Hexane on SAGD Performance at Different Operating Pressures
Authors: Mohebati Moslem Hosseininejad , Maini Brij B. , Harding Thomas G.
Published: June 2012

Solvent SAGD hybrid processes have attracted considerable attention in recent years. The perceived benefits of solvent addition to steam in SAGD are higher oil rate, lower energy and water consumption, higher recovery by lowering residual oil saturation (Sor) and higher return on investment. Despite numerous investigations that have been published regarding different aspects of solvent SAGD processes, this hybrid process is poorly understood and the solvent effects are difficult to predict. In fact, there is no available theory to model to the transport phenomena and the role of solvent within the steam chamber. Numerical simulation studies typically model the viscosity reduction of bitumen by solvent dissolution but do not capture other plausible mechanisms that yield higher oil rate and recovery, for example, lowering of Sor or partial in-situ upgrading. Laboratory experiments at realistic reservoir conditions are needed to gain more insight into these hybrid processes.

This paper presents the results of a series of laboratory experiments for evaluation of solvent addition to SAGD. These experiments were conducted at different representative reservoir pressure in a 3-D scaled physical model. Hexane, which has shown the best performance in many studies, was co-injected as solvent with steam in these experiments. Oil rate, recovery, and steam oil ratio were compared and the hybrid solvent/SAGD process performance was evaluated at different operating conditions. Additionally post-test sand samples were extracted from the model to examine residual oil saturation in different parts of the model after each experiment.

Experimental results showed improved performance of SAGD with addition of hexane, both at high and low operating pressure. However, the impact of hexane on the shape of the steam chamber and distribution of residual oil was significantly affected by operating pressure. This behavior of hexane, which appears to be related to its phase behavior, shows that solvent SAGD processes are considerably more complex than first thought.
The Evaluation of Open-hole Completions for Steam-Assisted Gravity Drainage Wells In a Heavily Karsted and Fractured Carbonate Formation
Authors: Arseniuk Stephen E. , Peterson Jeff , Barrett Kent , Chou Queena
Published: June 2012

The Upper Devonian Grosmont Formation, located in the West Athabasca Oil Sands Deposit, contains an estimated 406 billion barrels of bitumen. The reservoir is a heavily karsted and fractured, bitumen-saturated carbonate. Initial thermal horizontal well development is currently underway in this resource. These horizontal wells have similar logistics, well construction and materials challenges to those in the McMurray Formation.

Laricina has been actively developing the Grosmont Formation. Production from the pilot began in 2011 and many lessons have been learned. The next phase of development is a 10,700 bbl/day commercial project scheduled for first steam in 2014. The Grosmont, despite many drilling challenges such as severe lost circulation, also provides many opportunities not typically achievable in clastic oil sands developments. Carbonate rock is typically a good candidate for open-hole completions due to its geomechanical properties. This paper will discuss the geomechanical investigation evaluating borehole stability during drilling and completion, steam injection and production operations.