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Collaborating Authors
Japan Canada Oil Sands Ltd.
Summary In this paper we present a large-scale experimental study of the compositional effect on produced bitumen properties in steam-assisted gravity drainage (SAGD). The SAGD experiment used a sandpack in the cylindrical pressure vessel that was 1.22โm in length and 0.425โm in internal diameter. The pore volume of the sandpack was 58โL, and the porosity and permeability were 0.33 and 5.5โdarcy, respectively. The sandpack was initially saturated with 93% bitumen and 7% deionized water. The SAGD experiment after preheating was operated mostly at a steam injection rate of 35โcm/min (cold-water equivalent) at 3,600โkPa (244ยฐC). The produced fluids (gas, oil, and water) were analyzed; for example, 10 oil samples were analyzed in terms of carbon number distribution (CND), the asphaltene content, density, and viscosity to investigate the compositional change of the produced bitumen. After the experiment, the sandpack was excavated, and samples were taken for analysis of solid, water, oil, asphaltene, and sulfur contents. Experimental data (e.g., propagation of a steam chamber and production of oil and water) were history matched using a numerical reservoir simulator. The produced bitumen was lighter and contained 1- to 5-wt% less asphaltenes than the original bitumen. Also, the remaining oil inside the steam chamber contained 6-wt% more asphaltenes. As a result, the produced bitumen was 1- to 6-kg/m less dense than the original bitumen. This is an increase in API gravity from the original 7.9ยฐ to 8.6ยฐ. In the actual operations, bitumen is diluted with condensate to decrease the oil viscosity for pipeline shipping. This decrease in bitumen density corresponds to a decrease of the diluent cost by 5 to 10%. The produced bitumen became less dense with increasing steam-chamber volume. Results were history matched with a simulation model that considers capillary pressures to properly model the mixed flow regimes of oil/water countercurrent and cocurrent flow with an expanding steam chamber. The history-matched simulation indicated that the progressively decreasing density of the produced bitumen can be attributed to the vaporization of the relatively volatile components in the remaining oil and condensation of those components near the chamber edge.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.47)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Determination of Asphaltene Precipitation Amount under the Condition of the Solvent Assisted SAGD Process by the Application of PVT Apparatus
Kaito, Yutaro (Japan Petroleum Exploration Co., Ltd.) | Kiriakehata, Shinichi (Japan Petroleum Exploration Co., Ltd.) | Nakagawa, Kazunori (Japan Petroleum Exploration Co., Ltd.) | Nakashima, Hideyuki (Japan Petroleum Exploration Co., Ltd.) | Izumi, Tanetomo (Japan Petroleum Exploration Co., Ltd.) | Yamada, Tomomi (Japan Canada Oil Sands Ltd.)
Abstract Solvent Assisted-Steam Assisted Gravity Drainage (SA-SAGD) has been studied as a more efficient process for extracting bitumen from oil sands than the SAGD process. In the SA-SAGD process, solvent is injected with steam to decrease the viscosity of bitumen by dissolution of the condensed solvent. The dissolution of solvent causes a composition change of bitumen, which can lead to asphaltene precipitation. The effects of the asphaltene precipitation have been studied as part of a solvent-based recovery process such as Vapor Extraction (VAPEX). One of the advantages of the asphaltene precipitation is in-situ upgrading of the bitumen, whereas the disadvantage is that it causes a formation damage. To evaluate the effect of the asphaltene precipitation in the SA-SAGD process, it is essential to investigate the asphaltene precipitation under the conditions expected in the SA-SAGD process. However, it takes a lot of time to obtain sufficient data with a conventional method to quantify asphaltene precipitation under high-pressure/high- temperature (HP/HT) conditions. Therefore, the aim of this study is to develop an experimental procedure to evaluate the asphaltene precipitation with pressure/volume/temperature (PVT) apparatus in a reasonable time. The complex phenomenon at the edge of the chamber in the SA-SAGD process was simplified to a model of repetitions of mixing and drainage processes, and the experiment was configured in this manner. Solvent was added to a pre-diluted bitumen sample in a PVT cell. The supernatant liquid was sampled to analyze the asphaltene weight fraction remaining in the liquid phase and evaluate the asphaltene precipitation amount in the PVT cell. This process was repeated with increase in the solvent concentration. The asphaltene precipitation amount (APA) is calculated from the sample analysis data with recurrence relations under several assumptions. This procedure enables a wide range of APAs to be obtained from a mixture of bitumen and solvent in a single experiment, which enables sensitivity analysis under various conditions. In this research, the experiment was conducted under two different temperature conditions of 120ยฐC and 150ยฐC and the pressure was fixed at 3.5 MPa. The APA curves obtained from both experiments had almost the similar trend. Another important observation is that even the multi-component solvent (as used at the operation site) can still induce asphaltene precipitation under the HP/HT conditions expected in the SA-SAGD process.
- Asia (0.46)
- North America > Canada > Alberta (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
The Effect of Gas Injection On Oil Recovery During SAGD Projects
Ito, Y. (Ito Consulting Ltd.) | Ichikawa, M. (Japan Canada Oil Sands Ltd.) | Hirata, T. (Japan Canada Oil Sands Ltd.)
Abstract The effect of hydrocarbon gas injection on oil production during Steam Assisted Gravity Drainage (SAGD) projects was investigated using numerical simulation. The results indicate that oil production rates as well as total oil production are significantly reduced when gas is injected with steam from the early period of a SAGD operation. This is because most of the injected gas gathers at the upper part of the leading edge of the steam chamber and prevents the growth of steam chamber there, which results in a reduction of ultimate oil recovery. However, if the gas injection is initiated during later periods of the process, an improved steam oil ratio is obtained without significant reduction in oil production rates and the total oil production. In this case, the injected noncondensable gas migrates to the upper part of the reservoir and does not prevents the growth of steam chamber since the chamber had already grown to the desired size. Gas injection slows down the growth of steam chamber in the upper part of the reservoir and induces its growth downwards. This mode of growth of steam chamber results in an improvement in steam oil ratio as is illustrated in this paper. An understanding of this mechanism and its optimal timing are important in enhancement of the SAGD process. Introduction More than 52 billion cubic meters (330 billion barrels) of bitumen are believed to be in place in the Athabasca oil sands deposit in Canada, which are recoverable using the Steam Assisted Gravity Drainage (SAGD) in situ recovery process . SAGD process has been successfully field tested at the UTF (Underground Test Facility) project, which was initiated in 1988. The project consisted of a small scale pilot test (Phase A) with three pairs of 50 m horizontal wells, and a commercial scaled pilot test (Phase B) with three pairs of 500 m horizontal wells. The performance of these tests has been reported elsewhere . Japan Canada Oil Sands (JACOS) has participated in the UTF project since 1992 when the Phase A of project was completed. From its participation, JACOS acquired useful field data and operating experience. The data were extensively analyzed through numerical simulation. Based on this analysis, JACOS has started a demonstrative SAGD pilot operation in the Hangingstone oil sands reservoir, involving two pairs of 500 m horizontal wells and additional three pairs of 750 m horizontal well projects will start late 1999. The SAGD process is a simple process. It consists of two horizontal wells, an injector placed directly above a producer. Both wells are at first heated by steam circulation. When a communication between two wells is established, steam is continuously injected through the upper injector and oil and steam condensate are produced from the lower producer. The original recovery mechanism of the process was described by Butler who developed energy and oil flow equations associated with it. The energy flow by thermal conduction and drainage of the heated oil by gravity are the major components of his recovery concept.
Numerical Simulation of the SAGD Process In the Hangingstone Oil Sands Reservoir
Ito, Y. (Ito Consulting Limited) | Suzuki, S. (Japan Canada Oil Sands Ltd.)
Abstract This paper presents a simulation study of a steam assisted gravity drainage(SAGD) process applied to the Hanging stone tar sands reservoir. Two pairs of500 m long horizontal wells installed from the surface are considered. The study was conducted to forecast recovery performance and to furtherunderstand the oil production mechanism. Results predicted that more than 60%of the oil can be produced in 6 years of operation with a steam-oil ratio ofless than 3.0. The study was extended to provide a visual understanding of theflow behavior of steam, oil and water in the reservoir. The fluid flow diagramsrevealed that oil is displaced mainly by steam condensate and that convectiveenergy carried by steam condensate dominates the heat transfer mechanism. The authors applied this recovery mechanism concept to the study of sub coolingtemperature optimization for the steam trap control. The results of thisreservoir dynamics study are presented. Finally the role of this process's geomechanical effects are brieflydiscussed. INTRODUCTION The Hanging stone oil sands reservoir is located near Fort McMurray. Thereservoir is jointly owned by Petro-Canada, Imperial Oil, Canadian Occidentaland Japan Canada Oil Sands (JACOS). The bitumen viscosity at reservoircondition is over 1,000,000 m Pas and will not flow naturally. JACOS is going to use a Steam Assisted Gravity Drainage (SAGD) process toextract bitumen from the Hangingstone reservoir. A cyclic steam stimulation(CSS) process was extensively tested for the same reservoir over a decade. Through a numerical simulation study of the performance, it was found that thebitumen is difficult to produce at economically feasible rates using the CSSprocess for the subject reservoir (1). JACOS has been participating in the Underground Test Facility (UTF) projectsince 1991 when Phase A of the project was completed. From its participation, JACOS has received all of the field data plus operating and drillingexperience. UTF's field data has been extensively analyzed through numericalsimulation. Based on the analysis of the data, it was decided to drill twopairs of 500 m horizontal wells in 1997 and to start operating the SAGD processin 1998. The expected well performance calculated using a thermal simulator ispresented in the paper. Following the base case run, a series of parametricstudies were conducted. Some interesting results, such as the oil recoverymechanism obtained from the study, are also included. Although many uncertainties still exist in both the recovery concept andoperational procedure for the SAGD process, promising potential for itsapplication has been demonstrated in Phases A and B of the UTF project(2,3). One major uncertainty is whether the geomechanical change Of the formationduring the process is an important aspect or not. The role of geomechanicaleffect in the growth of the steam chamber and well performance is alsopresented. A new oil recovery mechanism is required when the geomechanicalchange of the formation occurs in the reservoir. A brief description of therecovery mechanism under the influence of the geomechanical formation change isalso discussed.
- North America > Canada > Alberta > Athabasca Oil Sands (0.43)
- North America > Canada > Alberta > Census Division No. 16 > Regional Municipality of Wood Buffalo > Fort McMurray (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.84)
Numerical Simulation Study of a Well In JACOS Hangingstone Steam Pilot Near Fort McMurray
Ito, Y. (Ito Consulting Ltd.) | Doan, Q. (Japan Canada Oil Sands Ltd.)
Abstract This paper presents a numerical simulation study of a well in a pilot project which has thirteen steam stimulation wells in an oil sand reservoir near Fort McMurray. Steam injection commenced May 1, 1990 as a joint project by Petro-Canada, 1mperial Oil, Canadian Occidental and Japan Canada Oil Sands (JACOS). A special emphasis has been made on the energy distribution around the subject well. Many thermocouples have been installed in the wellbore outside of the casing and three temperature observation wells have been drilled at 12 m distances from the well. A numerical history match was conducted when the well completed its seventh cycle of production. The bottom-hole temperature, bottom-hole pressure, fluid production of each phase and temperature profile at the observation wells were used as history match parameters. The simulation results indicate that a failure zone was mainly created in the top of the upper McMurray formation which overlies the target oil zone during the first two cycles. The location of this failure zone gradually shifted downwards as the cycles progressed The failure zone developed mainly in the lower part of the Upper McMurray formation during the third and fourth cycles, and in the top of the Lower McMurray formation, the target oil zone, during the fifth and sixth cycles. This downward change in the location of the failure zone caused a gradual improvement in oil production by cycle. To achieve a history match of all field observations, a good representation of the failure zone is an essential requirement. The Sand Deformation module interfaced with CMG's STARS model was used in this study. It was discovered that all of the field observations could not be matched simultaneously without this special version of the model. Introduction The Hangingstone Steam Pilot utilizes a cyclic steam stimulation (CSS) process to extract bitumen from the Athabasca oil sands_ The bitumen viscosity at reservoir condition is over 1,000,000 mPas and will not flow naturally. Petro-Canada initially operated the CSS Pilot project near Fort McMurray since 1985 till April 1992 as a joint venture of Petro-Canada, Canadian Occidental Petroleum Ltd., Imperial Oil Resources ltd. and Japan Canada Oil Sands Ltd. (JACOS), known as the PCEJ Group. Then JACOS subsequently took over the project. The project initially consisted of three single well steam stimulation tests. One of the interesting results of the single well tests was that oil production progressively improved with time. The mechanism of this behavior was not clearly understood at that time. A thirteen multiwell pilot test commenced on May 1990 based on the results of the single well tests. A unique feature of the multiwell project is that three temperature observation wells were drilled at a distance of 12 m from well C2 in an equilateral triangle around the well The temperature response in these wells has helped monitor heat and fluid movement in the reservoir. In addition to this, 20 thermocouples have been installed in well C2 outside of the casing at I to 2 m intervals within the target formation. These were cemented prior to the perforation of the well.
The In Situ Formation Of Bitumen-Water Stable Emulsions In Porous Media During Thermal Stimulation
Bennion, D. Brant (Hycal Energy Research Laboratories Ltd.) | Chan, Mark (Petro Canada Inc.) | Sarioglu, Gurk (Petro Canada Inc.) | Courtnage, Dave (Imperial Oil Ltd.) | Wansleeben, John (Canadian Occidental Petroleum Ltd.) | Hirata, Toshiyuki (Japan Canada Oil Sands Ltd.)
Abstract The formation, production and handling of highly viscous bitumen-water emulsions Is a significant problem in the operation of many heavy oil thermal stimulation projects. This paper documents an extensive study examining the in-situ emulsification of bitumen and water under conditions of simultaneous flow in an unconsolidated preserved state porous media at full reservoir pressure conditions and at a temperature of 200 ยฐ C. Various co-injection ratios from 100% bitumen - 0% water to 100% water and 0% bitumen were examined in both water saturation Increasing and decreasing directions (drainage and imbibition). The test results Indicate that in-situ emulsification does occur, that certain simultaneous flow ratios cause a localized increase in the severity of emulsification, and that the degree of emulsification appears to be related to the relative flowing proportion of fluids inside the porous media. Some evidence of directional hysteresis effects on emulsion quality were also observed. Introduction Evaluations have indicated that as much as 65% of the oil produced in the world today Is In the form of emulsions. Emulsions can exhibit complex phase behavior and viscosity effects, and their presence can greatly impact the economics and efficiency of hydrocarbon recovery. Hence a proper understanding of emulsion formation and how it can Impact flow In porous media Is essential. Emulsion formation Emulsions can potentially occur whenever two immiscible fluids come into contact with one another. Emulsions consist of a continuous external phase and an encapsulated, discontinuous Internal phase. In typical oilfield operations water and oil are the primary two fluids of concern when discussing emulsions (although recent studies have also Investigated the existence and effect of gas in oil type emulsions). The two common types of oilfield emulsions are described as water in oil emulsions, where the oil is the continuous external phase and the water is encapsulated as droplets within the oil phase; and oil In water emulsions, where the water Is the continuous external phase and the oil phase Is encapsulated as discontinuous droplets. Water in oil, or water Internal emulsions, are characterized by viscosities greater (sometimes substantially greater) than the actual clean crude oil. In comparison, oil in water, or water external emulsions, are characterized by viscosities much lower than the oil phase. Unfortunately, about 95% of the produced oilfield emulsions are of the high viscosity water in oil (water internal) type. Water internal emulsions can be typified by the size of the droplets of encapsulated water into microemulslons (Dw < 0.1 microns) or macroemulslons (Dw> 0.1 microns). Almost all naturally occurring oilfield emulsions are of the macroemulsion type with encapsulated water droplet volumes varying between 0.1 to 10 microns in diameter, Water internal emulsions can be stable at relatively high concentrations of bound water (up to 70%). The bound water content is usually referred to as emulsion quality. When quality in the emulsion becomes too high, the emulsion passes through what is known as the "inversion point".
Steady State Bitumen-Water Relative Permeability Measurements At Elevated Temperatures In Unconsolidated Porous Media
Bennion, D. Brant (Hycal Energy Research Laboratories Ltd.) | Sarioglu, Gurk (Petro Canada Inc.) | Chan, Mark (Petro Canada Inc.) | Hirata, Toshiyuki (Japan Canada Oil Sands Ltd.) | Courtnage, Dave (Imperial Oil Ltd.) | Wansleeben, John (Canadian Occidental Petroleum Ltd.)
Abstract Accurate drainage and imbibition relative permeability data are essential for the accurate prediction of the performance of heavy oil reservoirs undergoing cyclic steam stimulation or steam drives. There is very little published data regarding steady state relative permeability measurements at elevated temperatures. This paper documents two complete water-bitumen steady state drainage and imbibition tests conducted at a temperature of 200 ยฐC at full reservoir pressure and overburden conditions utilizing composite core stacks of actual, preserved reservoir core material. The test results indicate substantial hysteresis effects in the non-wetting (bitumen) phase and provide insight into the wettabillty, displacement efficiency, residual saturations and endpoint permeabilities and relative permeabilities for an unconsolidated heavy oil sandstone reservoir. Introduction Relative permeability Is an empirical parameter used to modify Darcy's single phase flow equation to account for the numerous complex effects associated with the flow of multiple immiscible phases within porous media. Relative permeability measurements are utilized extensively in many areas of reservoir engineering, and more particularly in recent years In the area of matching, predicting and optimizing reservoir performance and depletion strategies through the use of detailed numerical simulation models. Those Involved In numerical simulation realize the importance of good relative permeability data on the performance of reservoir simulation models. This paper discusses the generation of two complete sets of high temperature drainage and hysteresis relative permeability data. Factors affecting relative permeabiuty Relative permeability can be affected by many physical parameters including fluid saturations. physical rock properties, weltability, saturation history (hysteresis effects, overburden stress, clay and fines content, temperature, interfacial tension, viscosity magnitude of Initial phase saturations, Immobile or trapped phases, and displacement rates and capillary outlet phenomena.. A detailed discussion of the many factors affecting relative permeability is beyond the scope of this paper, but the general consensus of researchers is that In order to obtain the most representative relative permeability data that reservoir conditions during the tests be duplicated as closely as possible. This involves the use of well preserved or restored state reservoir core material, the use of uncontaminated actual reservoir fluids in the tests, and operation at full reservoir conditions of temperature, pressure and confining overburden stress. Effect of temperature on relative permeability Various authors have investigated the effect of temperature on absolute fluid permeability. Gobran investigated the effects of temperature on the permeability of both consolidated and unconsolidated sands and found only moderate differences in permeability in the 38 to 149 ยฐC temperature range. Udell et al investigated high temperature absolute permeabilities in glass bead and Silicon sand packs and found substantial permeability reductions (up to 40%) at temperatures exceeding 150 ยฐC. They concluded that these permeability reductions could be attributed to stress and temperature Induced Silica dissolution at the grain contacts and used effluent analyses which contained large amounts of dissolved silica to support these findi
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
Steady-State Bitumen-Water Relative Permeability Measurements at Elevated Temperatures in Unconsolidated Porous Media
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Sarioglu, Gurk (Petro Canada Inc.) | Chan, M.Y.S. (Petro Canada Inc.) | Hirata, Toshiyuki (Japan Canada Oil Sands Ltd.) | Courtnage, Dave (Imperial Oil Ltd.) | Wansleeben, John (Canadian Occidental Petroleum Ltd.)
Bennion, D.B. Hycal Energy Research Laboratories Ltd. Sarioglu, Gurk Chan, M.Y.S. Petro Canada Inc. Hirata, Toshiyuki Japan Canada Oil Sands Ltd. Courtnage, Dave Imperial Oil Ltd. Wansleeben, John Canadian Occidental Petroleum Ltd. SPE Members Abstract Accurate drainage and imbibition relative permeability data are essential for the accurate prediction of the performance of heavy oil reservoirs undergoing cyclic steam stimulation or steam drives. There is very little published data regarding steady state relative permeability measurements at elevated temperatures. This paper documents two complete water-bitumen steady state drainage and imbibition tests conducted at a temperature of 200C at full reservoir pressure and overburden conditions utilizing composite core stacks of actual, preserved reservoir core material. The test results indicate substantial hysteresis effects in the non-wetting (bitumen) phase and provide insight into the wettability, displacement efficiency, residual saturations and endpoint permeabilities and relative permeabilities for an unconsolidated heavy oil sandstone reservoir. Introduction Relative permeability is an empirical parameter used to modify Darcy's single phase flow equation to account for the numerous complex effects associated with the flow of multiple immiscible phases within porous media. Relative permeability measurements are utilized extensively in many areas of reservoir engineering, and more particularly in recent years in the area of matching, predicting and optimizing reservoir performance and depletion strategies through the use of detailed numerical simulation models. Those involved in numerical simulation realize the importance of good relative permeability data on the performance of reservoir simulation models. This paper discusses the generation of two complete sets of high temperature drainage and hysteresis relative permeability data. Factors Affecting Relative Permeability Relative permeability can be affected by many physical parameters including fluid saturations, physical rock properties, wettability, saturation history (hysteresis effects), overburden stress, clay and fines content, temperatures interfacial tensional viscosity, magnitude of initial phase saturations, immobile or trapped phases, and displacement rates and capillary outlet phenomena. A detailed discussion of the many factors affecting relative permeability is beyond the scope of this paper, but the general consensus of researchers is that in order to obtain the most representative relative permeability data that reservoir conditions during the tests be duplicated as closely as possible. This involves the use of well preserved or restored state reservoir core material, the use of uncontaminated actual reservoir fluids in the tests, and operation at full reservoir conditions of temperature, pressure and confining overburden stress. P. 255^
- North America > Canada (0.68)
- North America > United States (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
The In-Situ Formation of Bitumen-Water-Stable Emulsions in Porous Media During Thermal Stimulation
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Chan, M.Y.S. (Petro Canada Inc.) | Sarioglu, Gurk (Petro Canada Inc.) | Courtnage, Dave (Imperial Oil Ltd.) | Wansleeben, John (Canadian Occidental Petroleum Ltd.) | Hirata, Toshiyuki (Japan Canada Oil Sands Ltd.)
Bennion, D.B. Hycal Energy Research Laboratories Ltd. Chan, M.Y.S. Sarioglu, Gurk Petro Canada Inc. Courtnage, Dave Imperial Oil Ltd. Wansleeben, John Canadian Occidental Petroleum Ltd. Hirata, Toshiyuki Japan Canada Oil Sands Ltd. SPE Members Abstract The formation, production and handling of highly viscous bitumen-water emulsions is a significant problem in the operation of many heavy oil thermal stimulation projects. This paper documents an extensive study examining the insitu emulsification of bitumen and water under conditions of simultaneous flow in an unconsolidated preserved state porous media at full reservoir pressure conditions and at a temperature of 200 C. Various co-injection ratios from 1 00% bitumen - 0% water to 100% water and 0% bitumen were examined in both water saturation increasing and decreasing directions (drainage and imbibition). The test results indicate that in-situ emulsification does occur, that certain simultaneous flow ratios cause a localized increase in the severity of emulsification, and that the degree of emulsification appears to be related to the relative flowing proportion of fluids inside the porous media. Some evidence of directional hysteresis effects on emulsion quality were also observed. Introduction Evaluations have indicated that as much as 65% of the oil produced in the world today is in the form of emulsions. Emulsions can exhibit complex phase behavior and viscosity effects, and their presence can greatly impact the economics and efficiency of hydrocarbon recovery. Hence a proper understanding of emulsion formation and how it can impact flow in porous media is essential. Emulsion Formation Emulsions can potentially occur whenever two immiscible fluids come into contact with one another. Emulsions consist of a continuous external phase and an encapsulated, discontinuous internal phase. In typical oilfield operations, water and oil are the primary two fluids of concern when discussing emulsions (although recent studies have also investigated the existence and effect of gas in oil type emulsions). The two common types of oilfield emulsions are described as water in oil emulsions, where the oil is the continuous external phase and the water is encapsulated as droplets within the oil phase; and oil in water emulsions, where the water is the continuous external phase and the oil phase is encapsulated as discontinuous droplets. Water in oil, or water internal emulsions, are characterized by viscosities greater (sometimes substantially greater) than the actual clean crude oil. In comparison, oil in water, or water external emulsions, are characterized by viscosities much lower than the oil phase. Unfortunately, about 95% of the produced oilfield emulsions are of the high viscosity water in oil (water internal) type. Water internal emulsions can be typified by the size of the droplets of encapsulated water into microemulsions (Dw < 0.1 microns) or macroemulsions (Dw >0.1 microns). Almost all naturally occurring oilfield emulsions are of the macroemulsion type with encapsulated water droplet volumes varying between 0.1 to 10 microns in diameter. P. 239^
- North America > Canada (0.68)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)