Miscible Flooding Project Research Articles

Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Study of the impact of injection parameters on the performance of miscible sour gas injection for enhanced oil recovery

Sour gas reservoirs have faced critics for environmental concerns and hazards, necessitating a novel outlook to how the produced sour gases could be either utilized or carefully disposed. Over the years of research and practice, several methods of sour gas processing and utilization have been developed, from the solid storage of sulfur to reinjecting the sour gas into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the impact of injection parameters on the performance of sour gas injection for enhance oil recovery. In designing a miscible gas flooding project, empirical correlations are used and the key parameter which impacts the phase behavior is identified to be the minimum miscibility pressure (MMP). A compositional simulator was utilized in this research work to study the effect of injection parameters such as minimum miscibility pressure, acid gas concentration, injection pressure and injection rate on the performance of miscible sour gas injection for enhanced oil recovery. The findings showed that methane concentration had a significant impact on the MMP of the process. Additionally, an increase in acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increased overall recovery of the process.

Identification of CO2 sequestration opportunities: CO2 miscible flooding guidelines

Carbon dioxide (CO2) flooding has been demonstrated as an economically feasible technique for carbon capture and storage (CCS) via enhanced oil recovery (EOR). In the oil industry, most of the CO2-EOR projects were implemented in miscible phase (CO2 miscible flooding), and it has become the most productive EOR method in the United States since 2012. Successful implementation of CO2 miscible flooding requires comprehensive guidelines about where CO2 can be applied. With the development of new technology, the suitable conditions for CO2-EOR have changed. Therefore, updating the guidelines for CO2-EOR is necessary. In this study, we updated the guidelines for field CO2 miscible applications in the United States by collecting valuable information from about 100 publications. Significant parameters for CO2 miscible flooding such as minimum miscibility pressure (MMP) and pay zone net thickness were considered for the first time in comparison with existing research studies. After data processing/cleaning, 207 projects have remained in the dataset. Combination plots were created to explore the ranges, distributions, and cumulative frequencies of each property. Meanwhile, descriptive values were calculated based on statistical methods. The guidelines for CO2 miscible flooding were presented with important parameters, including porosity, permeability, depth, reservoir temperature, net thickness, oil saturation, oil gravity, oil viscosity, and MMP. The analyzed results show that the reservoir pressure should be greater than 1020 psi to achieve miscibility, and CO2 miscible flooding project could be successfully applied in a reservoir with an oil gravity greater than 25 °API, oil viscosity less than 4 cp, and a reservoir temperature less than 120 °F.

Experimental and simulation determination of minimum miscibility pressure for a Bakken tight oil and different injection gases

Abstract The effective development of unconventional tight oil formations, such as Bakken, could include CO 2 enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO 2 . It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil–injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO 2 , CO 2 -enriched flue gas, natural gas, nitrogen, and CO 2 -enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO 2 outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil–CO 2 MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO 2 had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil–pure CO 2 MMP and effect of impurities in the gas phase on MMP change. The Bakken oil–CO 2 had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N 2 , can increase MMP significantly.

Determining CO2 storage potential during miscible CO2 enhanced oil recovery: Noble gas and stable isotope tracers

Rising atmospheric carbon dioxide (CO2) concentrations are fueling anthropogenic climate change. Geologic sequestration of anthropogenic CO2 in depleted oil reservoirs is one option for reducing CO2 emissions to the atmosphere while enhancing oil recovery. In order to evaluate the feasibility of using enhanced oil recovery (EOR) sites in the United States for permanent CO2 storage, an active multi-stage miscible CO2 flooding project in the Permian Basin (North Ward Estes Field, near Wickett, Texas) was investigated. In addition, two major natural CO2 reservoirs in the southeastern Paradox Basin (McElmo Dome and Doe Canyon) were also investigated as they provide CO2 for EOR operations in the Permian Basin. Produced gas and water were collected from three different CO2 flooding phases (with different start dates) within the North Ward Estes Field to evaluate possible CO2 storage mechanisms and amounts of total CO2 retention. McElmo Dome and Doe Canyon were sampled for produced gas to determine the noble gas and stable isotope signature of the original injected EOR gas and to confirm the source of this naturally-occurring CO2. As expected, the natural CO2 produced from McElmo Dome and Doe Canyon is a mix of mantle and crustal sources. When comparing CO2 injection and production rates for the CO2 floods in the North Ward Estes Field, it appears that CO2 retention in the reservoir decreased over the course of the three injections, retaining 39%, 49% and 61% of the injected CO2 for the 2008, 2010, and 2013 projects, respectively, characteristic of maturing CO2 miscible flood projects. Noble gas isotopic composition of the injected and produced gas for the flood projects suggest no active fractionation, while δ13CCO2 values suggest no active CO2 dissolution into formation water, or mineralization. CO2 volumes capable of dissolving in residual formation fluids were also estimated along with the potential to store pure-phase supercritical CO2. Using a combination of dissolution trapping and residual trapping, both volumes of CO2 currently retained in the 2008 and 2013 projects could be justified, suggesting no major leakage is occurring. These subsurface reservoirs, jointly considered, have the capacity to store up to 9 years of CO2 emissions from an average US powerplant.

Integrated Investigation of Enhanced Oil Recovery in South Slattery Minnelusa Reservoir, Part 2: CO2 Miscible Injection

The authors used experiment and full-field reservoir modeling to investigate and optimize the design of a CO2 miscible flooding project for the Minnelusa reservoir of the South Slattery field. Minimum miscibility pressure and core flooding tests were conducted to estimate the CO2 injection feasibility at Slattery conditions. A full-field CO2 model with finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood. Continuous CO2 miscible injection (CMI) and alternating (WAG) were simulated. WAG injections were simulated mainly to observe the improvement of low sweep efficiency caused by override and unfavorable mobility ratio. The integrated recovery efficiency comparison of CMI and WAG was used to demonstrate the mobility control of the WAG process.

Horizontal Injectors Rejuvenate Mature Miscible Flood—South Swan Hills Field

Summary The South Swan Hills pool, located in northwest Alberta, Canada, is a carbonate reef with an original oil in place (OOIP) of approximately 850 million bbl. Waterflooding began in 1963, and a staged hydrocarbon miscible flood covering most of the field began in 1973. Solvent injection in the main miscible flood was terminated in 1989, and chase gas injection ceased in 1998. In 1994, however, solvent injection was reinitiated into a single pattern in the reef margin area of the field using a horizontal injector and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. The horizontal injector was placed at the base of the reef margin to minimize the effects of gravity override and to maximize sweep efficiency. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. Both patterns are projected to recover almost 1 million bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas that were part of the original miscible-flood project. This paper covers the development of the original miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The geological and performance factors that made this redevelopment successful, and their impact on field production, are discussed. Finally, plans for future development of this mature field are presented.

Simulation of Horizontal Wells to Mitigate Miscible Solvent Gravity Override in the Virginia Hills Margin

Abstract Significant incremental recovery can be obtained when vertical sweep is improved in the mature Phase I Miscible Flood area of the Virginia Hills Field. This study advances our knowledge of the gravity override processes operating in this complex carbonate reservoir. Furthermore it shows that horizontal injection wells improve sweep efficiency thereby alleviating the impact of solvent gravity override. As a result of this simulation, a successful horizontal injection well was drilled, with an actual 18 E3m3 incremental oil recovery to date and a predicted 65 E3m3 total incremental oil. The results of this study suggest redevelopment in mature EOR areas is expected to extend the life of the miscible flood and increase overall recovery. Introduction Miscible recovery in the Virginia Hills Field Hydrocarbon Miscible Flood (HCMF) project is significantly limited by poor vertical sweep of the solvent within individual layers of the reservoir. A vertically continuous interval within the reef margin (30 m thick) was investigated and shown to have a large bypassed tertiaryoil target. This study demonstrated that recovery could be significantly increased through the use of horizontal solvent injection wells. To have confidence in the results of the study it was critical to utilize geological and production history data to address the interwell extent of significant heterogeneities. This required complete integration of geological and engineering staff in all phases of the study. Background Historical The Virginia Hills Beaverhill Lake A Pool was discovered in 1957. The field (Figure 1) produces oil from a Mid-Upper Devonian limestone, stromatoporoid build-up. The field was unitized in 1963 and a waterflood pressure maintenance scheme was implemented. In the late 1980s the patternswere normalized to inverted nine spots and in 1989 a tertiary horizontal hydrocarbon miscible flood project was initiated in the south half of the Pool. The original oil in place (OOIP) for the pool has been calculated at 59.6 E6m3 by the operator. Cumulative oil production to the end of July 1996 was 22.9 E6m3, or 38.4﹪ of the OOIP. Current oil rates of 1,000 m3/d have fallen from peak rates of 4,400 m3/d. Field average water cut is greater than 90%. Within the EOR area, well spacing is 32 ha., approximately 400 m interwell distance. Geological The internal architecture of this limestone reservoir is multilayered and compartmentalized, due to several stages of carbonate accumulation. From the base up these stages are: S1 (equivalent to the regionally extensive Slave Point platform), S2A, S2, S3L, S3U, and S4, (herein called S-units) reaching a total maximum thickness of 150 m. A high energy windward margin exists along the eastern portion of the build-up with superior reservoir quality (an average range of.09 to.12 phi, and 20 to 120 mD permeability). For this study the S3L in the margin area of the build-up was investigated (Figure 1). Solvent Gravity Override Solvent gravity override (Figure 2) occurs when there is sufficient time for injected solvent to segregate prior to its withdrawal due to gravity differences and therefore a smaller miscible oil target is swept.

Use of Full-Field Simulation to Design a Miscible CO2 Flood

Summary A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house four-component simulator (stock tank oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood.

Volumetric Balance Method To Monitor Field Performance Of Gas-Miscible Floods

Abstract A methodology has been developed for quantitatively evaluating (1) the flow distribution of the injected solvent toward producer wells, and (2) the solvent-swept volume between each injector producer well pair from injection-production data. At a steady-stale hydrocarbon production, the production rate reflects the solvent flow- rate to the producer. At the same time, the volumetric balance between cumulative solvent injected and cumulative hydrocarbon production from the producer reflects the volume swept by the solvent. An application of the method to the hydrocarbon miscible flood in Judy Creek ‘A’ Pool yielded data on the solvent-swept volumes which are consistent with the gravity override theory. Introduction Since the hydrocarbon miscible flood was started in Judy Creek A Pool(1) in May 1985, production performance has indicated that the gravity override by the solvent is affecting solvent conformance. This conclusion is substantiated by a comparison between injection logs and production logs; i.e. although solvent injections are reasonably uniform down to the lowest perforated zones, solvent production occurs only at the top of the uppermost geological zones. Although such qualitative evidence or gravity override abounds, no adequate technique has been available for quantitative estimation of the solvent swept volume based on field data. For the purpose of evaluating the performance of gas-miscible floods at sufficiently early stages, the "Volumetric Balance Method" was developed to determine the solvent distribution and the solvent-swept volume for each injector-producer pair from field injection-production data. This paper describes the basic principle of the "Volumetric Balance Method ", potential problems and their remedies in applying the method to field operating conditions, and actual field examples. Although Field application examples or the technique in the Judy Creek hydrocarbon miscible flood project are used, the technique is also applicable to CO2 miscible floods. Volumetric Balance Method Basic Principle Let us assume that in a reservoir (schematically shown in Fig. 1) Injector I is supplying injected fluids toward Producer P as well as toward other directions. Solvent and water injection was started at Injector I upon completion or waterflood, i,e. the reservoir was assumed to retain only the residual oil saturation after waterflood (Sorw). It is assumed that the solvent flow rate (qP toward Producer P is a fraction (f) of the total solvent injection rate (qI) at Injector I and that the solvent-swept pore volume toward Producer P is VS. The swept volumes would be determined by factors such as reservoir size, continuity and gravity override. Figure 1 depicts the case of gravity override. During the solvent flood, the swept pore volume (VS) has a non-aqueous phase saturation (Sso; solvent and oil combined) which depends on fractional flow conditions and is higher than the initial waterflood residual oil saturation (Sorw). If piston-like displacement were considered, the non-aqueous phase saturation (Sso) would reach the Producer P and production or tertiary oil would start when the volume of injected solvent toward Producer P (QP) became equivalent to VS (Sso - Sorw). In other words, the solvent-swept pore volume (VS) would become filled with the saturation Sso.

A New Method To Improve The Accuracy Of Acoustic Pressure Calculations

Abstract Acoustic pressure measurements can be an important surveillance tool in oil fields undergoing water flood and enhanced oil recovery schemes. They offer a cost-effective method for measuring subsurface pressures in pumping oil well without the expense of pulling the rods and pump. However, experience has shown that the accuracy of subsurface pressures obtained from fluid-level calculations has at times, proved questionable. Data from several well studies is presented that shows the average difference between standard acoustic pressure calculations and directly measured subsurface pressures is approximately 10%. Furthermore, a new method of calculating acoustic pressures is described. The new approach was applied to test data from nine producing oil wells in Alberta. All wells were chosen from either waterflood or miscible flood projects. For this particular set of well tests, the new procedure reduced the average difference between acoustic and directly measured pressures to within 1%. The new calculation method extends the applicability of the method described in the ERCB Guide G-5(1) to a wider range of oil compositions. The new method also addresses some of the concerns raised in the Guide G-5 and improves the accuracy of acoustic pressure calculations in water flood and miscible flood projects. Introduction In Alberta, the industry standard for the acquisition and interpretation of acoustic data is the ERCB Guide G-5 "Calculating Subsurface Pressure Via Fluid-Level Recorders ". It is an excellent technical reference that contains many specific and practical points about acoustic measurements on pumping oil wells. The Guide G-5 was developed in the early 1970s, and was based on comparative data collected from 1966 to 1968. The wells studied produced only oil and gas. No wells producing water were included. These assumptions were more than adequate for the time, and the Guide has proven to be useful for almost 20 years. The oil industry now faces different challenges in the 1990s. Waterfloods and enhanced oil recovery projects have become Commonplace. The "typical" oil well is no longer a simple gas and oil producer with easily predicted fluid gradients. Instead, it is a pumping well that produces gas, oil, water and in some cases, miscible solvent and chase gas. The Guide States, "Experience has shown that the accuracy of subsurface pressures obtained from fluid-level calculations has, at times, proved questionable. Although the producing characteristics of many wells preclude great accuracy, the lack of accuracy can be attributed in many cases to improper data-gathering procedures, interpretation, and pressure calculation techniques. " The Guide also discusses wells in water floods and states, "The producing water-cut is seldom representative of water within the fluid column in the annulus, and should not be used when making calculations." The Guide indicates instead, that the water cut in the annular column will decrease over time. Despite these guidelines and statements, it has become standard industry practice to assume that the incoming liquid water cut is constant and equal to the final producing water cut. Acoustic Verification Surveys(2,3,4) In order to investigate the accuracy of the acoustic pressure calculations, verification surveys were conducted on nine wells operated by Amoco Canada.

A simulation approach in economic assessment and risk analysis of the CO 2 miscible flooding process

Due to high cost and technical uncertainty of recovery processes, predictive models developed for CO 2 miscible flooding processes should be used to evaluate the production performance of projects. This study presents the reservoir simulation study and probabilistic cash flow analysis of CO 2 miscible flooding projects in West Virginia. An extended black oil reservoir simulator was used in this study. Historical data and information from a CO 2 injection pilot in Granny's Creek Field of Clay County in West Virginia were used. A history match was done, and then alterative matched cases were run, such as pure CO 2 injection and water-alternate-gas (WAG) injection. A PC-based probabilistic cash flow analysis (PCFA) model was developed to analze the economic evaluation of the CO 2 miscible flooding project on a popular spreadsheet. Statistical analysis of the results shows: (1) the WAG case is more profitable than the pure CO 2 injection case; (2) the pure CO 2 injection case and the WAG case are more economical than the base case. Therefore, given current oil prices, the CO 2 processes have a higher potential to succeed in tec technical aspects but not in economical aspects. This study initiates the adaptation of the model to specific parameters of West Virginia oil fields. The newly formulated microcomputer PCFA model overcomes some of the problems commonly found in the conventional Monte Carlo simulation. Thus, the simulation approach in economic assessment and risk analysis can be readily adopted in future projects.

Optimizing Electric Submersible Pump Replacement Costs

Abstract Electric submersible pumps (ESPs) have made a significant contribution to the petroleum industry as an economic means of artificial lift. As current depressed oil prices linger, it has become especially critical that casts associated with operating ESPs be kept to a minimum. One method, which has resulted in a great deal of success for Amoco Canada, has been qualifying used motors and pumps for re-use through cleaning and testing procedures. Among Amoco Canada's operations are two large fields; the South Swan Hill Unit and the Nipisi Gilwood Unit No.1. Together, a total of 235 electric submersible pumps are in service. As ESPs fail downhole, equipment is examined/or potential testing application. To the end of June 1989, 457pumps have been cleaned and tested while 221 motors have also been put through the test program. A high requalification rate and inexpensive testing cost have combined for substantial savings over traditional repair procedures, The success of the program has been further enhanced by encouraging ESP performance from equipment rerun subsequent to being cleaned and tested. Introduction Amoco Canada Petroleum Company Ltd. is the Unit Operator of two major miscible flood projects. The locations of these fields are shown in Figure 1. The South Swan Hills Unit is located 225 km northwest of Edmonton, Alberta, and comprises ISS producing wells with 70 injection wells. The 124 electric submersible pump locations account for almost 97% of the 30 000 m3 per day average fluid volume. Production is from the Swan Hills formation of the Beaverhill Lake Group, a limestone reef complex. Bottom hole temperature averages 112 °C at a depth of 2 500 m KB. The Nipisi Gilwood Unit No. 1 is located approximately 350km north of Edmonton. The average Unit fluid production is 23 500 m3 per day. Included in the 230 producing wells are 111 ESPs which are responsible for 93% of this volume. An additional 74 wells are used for injection. The producing reservoir is the Gilwood (sandstone) formation at a depth of 1 700 m and BHT of 60 °C. During the Past few years, an average of 125 ESP replacements have taken place annually in the above locations. Included in the $55,000 average replacement cost were ESP equipment expenses of $28,000 each. This resulted in an annual expenditure of approximately $3.500,000 for ESP repair and/or purchase. In April 1987, a used pump and motor testing program was initiated, similar to that described by D.L. Divine(1). In the 26 months since that time, ESP replacement expenditures have been reduced by almost $2 million. ESP Operations Amoco Canada replaces ESPs through me most economic means available. This has historically been with new equipment purchase and/or flat rate repairs. Research into the failures experienced showed that while one component failed, companion equipment was often in good condition and could be re-used. Standby inventories have been maintained separately for each Unit in order to minimize costs and eliminate deferred production due to the unavailability of equipment.

Design Of Miscible Solvents For A Rich Gas Drive-Comparison Of Slim Tube And Rising Bubble Tests

Abstract This study addresses miscible solvent design for the planned hydrocarbon flood in the Virginia Hills Beaverhill Lake Unit in north central Alberta. The development a/miscibility between reservoir fluid and a series of increasingly rich solvents was studied in a rising bubble apparatus. In order to establish the validity of this relatively new technique of solvent design, the rising bubble test observations were compared to results of conventional slim tube tests previously conducted with the same soh1ents. A very good correlation was found between the minimum solvent enrichment/or miscibility determined by the two techniques. The rising bubble method is shown to be not only much faster but also superior in some respects to slim tube testing. Introduction The Virginia Hills Beaverhill Lake reservoir, a carbonate reef formation in north central Alberta, was discovered in 1957 and has been under water flood since 1963. Of the original estimated 60 × 106 m3 oil in place, about one-third has been recovered to date. Current plans are for implementation of a miscible enriched gas flood, with solvent injection targeted for 1990(1). The relatively high reservoir temperature (100 °C) and intermediate pressure (20 MPa to 27 MPa) are common to several Alberta pools where miscible gas injection is currently underway. The Virginia Hills development is a joint venture project with Shell Canada as the operator. The annual cost of the solvent (a blend of dry gas and natural gas liquids streams) required by the project is estimated to exceed $30 million. It is thus important to design the solvent containing the minimum amount of expensive natural gas liquids (NGL) yet be miscible so as to maximize the oil recovery. As the composition of the NGL stream available from the pipeline is expected to vary throughout the miscible flood project life, solvent enrichment levels have to be determined for a variety of NGL stream compositions. Given the time consuming and costly nature of the slim tube tests (and our unwillingness to rely entirely on minimum solvent enrichment predicted with the equation of state), the rising bubble apparatus (RBA) tests present an attractive alternative. However, while the slim tube test is universally accepted by the industry, the validity of this more recently emerged method of solvent design has to be established. A systematic comparison of the two techniques was therefore undertaken, the results of which are presented in this paper. Equation of state (EOS) calculations were used throughout the study to interpret, in qualitative terms, the oil-solvent phase behaviour and its trends. Background - Mass Transfer Mechanism in Virginia Hills Miscible Rich Gas Drive Table 1 shows the composition of the Virginia Hills recombined reservoir fluid (VH fluid). This is a light but somewhat waxy crude containing about 3070 (wt) asphaltenes. The compositions of typical dry gas and NGL streams available for blending the solvent are also shown in Table 1. Throughout this paper, the solvents are referred to by their NGL to dry gas molar ratio; 75/25 solvent thus contains 750/0 NGL and 250/0 dry gas.

Design Of A Field-Wide Hydrocarbon Miscible Flood For The Kaybob Beaverhill Lake" A" Pool

Abstract There are currently 56 hydrocarbon miscible flood projects operating In Alberta of which 12 are horizontal water alternating gas (WAG) processed. Seven of the 12 horizontal schemes are in the Upper Swan Hills formation of the Beaverhill Lake group. In most cases the miscible floods were introduced after years of waterflooding. In general, a solvent is injected into the previously water flooded zone to displace residual oil. The methods used to estimate this tertiary oil recovery are unique to each project and operator. This paper presents a cost-effective method off forecasting ultimate oil recovery from a planned hydrocarbon miscible flood in a Beaverhill Lake reservoir. Introduction The Kaybob Beaverhill Lake (BHL) "A" Pool is located 240 km (150 miles) north and west of Edmonton, Alberta (Fig. 1). Plans are to convert from a horizontal patterned waterflood to a horizontal water alternating gas patterned hydrocarbon miscible flood in 1988. This paper describes the proposed Kaybob miscible flood project with emphasis on miscible flood pattern selection, miscible solvent design and forecasting remaining secondary and tertiary oil recovery. Previous attempts to model and history match the waterflood performance in the Kaybob field have been unsuccessful. The miscible flood forecast is therefore, a combination of expected secondary recovery under the current waterflood and tertiary recovery under miscible flood. In this paper, miscible flood patterns and infill locations are defined first, followed by the waterflood and tertiary forecasts for each pattern and infill well. The design of the miscible solvent is also given. Background The Kaybob BHL "A" Pool is a multi-layered carbonate reef discovered in 1957 with the drilling of the well Phillips Kaybob "A-1" at 7–22–64–19 W5M. The field covers an area of 7067 ha (17 462 acres) and has been drilled up to an average spacing of 64 ha (160 acres) with a total of 93 wells. The original oil-in-place (OOIP) is estimated at 44.3 ×106 m3. Oil is produced from the Upper Swan Hills Formation of the Beaverhill Lake Group which is middle to early Devonian. Typical facies distribution in the pool are shown in Figure 2, with the cross section of each reefal stage (platform, Stage II to VI) given in Figure 3. Schultheis(2) found the best reservoir characteristics exist in the reef margin. The less permeable and less porous reservoiroccurs in the back reef. A line drive water flood in the south end of the pool was initiated in 1964 to maintain reservoir pressure. In 1978 the line drive was replaced by inverted nine spot patterns on 64 ha spacing (Fig. 4). Recovery to July 1987 was 15.68 ×106 m3 or 35.3% of the OOIP. Pattern Selection Patterns for the miscible flood were selected on the basis of preferentially using existing water injection wells as solvent injectors. In order to optimize miscible displacement, patterns were designed to follow permeability trends observed from the progress of the waterflood (Fig. 5). The number of patterns chosen represents the maximum number of inverted nine spots on 64 ha well spacing (Fig. 6).

Monitoring The Mitsue Hydrocarbon Miscible Flood-Program Design, Implementation And Preliminary Results

Abstract The first two of three stages of a horizontal hydrocarbon miscible flood (HCMF) project have been implemented at the Mitsue Gilwood Sand Unit No.1, in Slave Lake, Alberta. Stage I was started up in May 1985 while the second stage commenced in May 1986. Stages 1 and 2 cover an area of 12500 ha with an original-oil-in-place of 57.2 × 106 m3. A project of this magnitude requires careful monitoring if the unit's technical and economic goals are to be achieved. A comprehensive monitoring program was developed to provide the data needed to evaluate and optimize flood performance. The program includes fluid sampling and analysis, tracer injection and analysis, pressure and profile surveys, numerical simulation, a data management system, and an observation well. This paper describes the monitoring program and the rationale for its different facets. The program for the surface sampling a produced well effluent is presented. Details are provided on the selection of five radioactive and two chemical tracers and the procedures used for their injection. In this tertiary project, produced fluid compositional changes are shown to be more reliable for estimating solvent breakthrough dates than GOR. Based on solvent breakthrough data to date, a correlation of solvent-oil ratio (SOR) to GOR was developed. The tracer breakthrough data are presented and analyzed. The tracer breakthrough data confirm that gravity override is taking place in the reservoir and, also suggest that the solvent is sweeping more than one sand layer. The implications of the tracer analysis results on reservoir continuity within the project area, areal sweep efficiency and on flood performance are discussed. Introduction The Mitsue Gilwood ‘A’ Pool was discovered in 1964. It is a sandstone reservoir, located 200 km northwest of the City of Edmonton, Alberta, near the town of Slave Lake (Fig. 1). It is a large pool, extending over an area of 48 000 ha or 475 km2 with an original oil-in-place of approximately 160 × 106 m3. The Mitsue Gilwood Sand Unit No. 1 commenced an HCMF in most of the waterflood swept areas of the unit in May 1985. Reservoir Geology The Gilwood sandstones are part of the Middle Devonian Watt Mountain Formation(l). The sands were deposited in a fluvial environment. This shallow dipping pool was formed by a stratigraphic trap (Fig. 2) with an extensive aquifer system located on the downdip, western edge. From depositional studies, the sands are divided into three groups-lower, middle and upper sands. The lower sands (layer 3) contribute less than 5% of the pool's reserves. They are made up of fine-grained, primarily non-channel, lower-meander reach and strand plain deposits. The lower sands are considered nonfloodable by the HCMF. The middle and upper sands (layers 1 and 2) are primarily channel deposits. The middle sands were deposited in the braided to coarse-grained meander reach of a fluvial system while the upper sands were deposited in the fine-grained braided to lower-meander reach regions of another fluvial system.

Design of a Tertiary Hydrocarbon Miscible Flood for the Mitsue Reservoir

A large-scale hydrocarbon miscible flood has been designed and is being conducted in the Mitsue Gilwood Sand Unit No. 1 in Alberta, Canada. The horizontal miscible flood occurs mostly in previously waterflooded zones and is a true test of the tertiary displacement mechanism. An area of 17,900 acres (7250 ha) is being flooded with a first-contact-miscible (FCM) hydrocarbon solvent followed by a lean chase, gas, both alternated with equal volumes of water. Inverted five-spot injection patterns are used. This paper reviews the evaluation and design process by use of recently developed methodologies, involving innovative laboratory techniques and simulation processes used in planning the miscible flood. Laboratory work was used to develop correlations for determining the hydrocarbon solvent enrichment required for both FCM and multiple-contact miscibility (MCM) as a function of solvent C/sub 2+/ fraction and molecular weight at the reservoir pressure of 2,500 psia (17.2 MPa). Simulation studies indicate that optimum solvent and chase-gas slug sizes of 15 and 25%, respectively, will yield an incremental 12.2% of original oil in place (OOIP), or 21.3 MMSTB (3.4 x 10/sup 6/ stock-tank m/sup 3/). Solvent and chase-gas recoveries were estimated to be 73 and 44%, respectively. Early performance of the miscible floodmore » indicates that the solvent is successfully mobilizing tertiary oil. Wells previously shut in because of high water production have experienced an increase in oil rates and a decrease in WOR's.« less

Performance Of South Swan Hills Tertiary Miscible Flood

Abstract A review of the performance of the tertiary hydrocarbon miscible flood which has been operating in the West Waterflood area of the South Swan Hills Unit since September 1982 is presented. The production trend clearly indicates that the tertiary flood has reversed the steady decline experienced under waterflood to the extent that the oil production has increased from 450 m3/day to as high as 1200 m3/day in 1986. The ultimate recovery factors for the project area are estimated at 38% original oil-in-place (OOIP) by waterflood and 59% OOIP by miscible flood. The projected 20% incremental recovery is based on a black oil model simulation and is in line with the incremental recovery predicted for the secondary miscible flood in the South Swan Hills Unit(1). The early performance of the tertiary flood is consistent with model simulation work and indicates that the projection in incremental recovery is achievable. Introduction The South Swan Hills Unit is located 190 km northwest of Edmonton, Alberta (Fig. I). Production is from the Swan Hills member of the Beaverhill Lake Formation which is a reef of Upper Devonian age. The unit is subdivided into three project areas (Fig. 2). The tertiary hydrocarbon miscible flood was installed in what was originally the West Waterflood Project area in September 1982. The project area encompasses approximately 4450 ha and contains 83 wells drilled on 64-ha spacing. Current plans are to inject a total hydrocarbon slug of 47.2% HCPV. This slug will comprise 15% HCPV solvent slug followed by a 32.2% HCPV dry gas slug. Both slugs are to be injected at an injection ratio with water conducive to optimum flood performance. Following hydrocarbon injection, the flood will revert to straight water injection. Geological Description The South Swan Hills reservoir is a Beaverhill Lake carbonate reef which comprises four oil-bearing geologic zones (Fig. 3). In the Tertiary Project area, only Zones 1 and 2 are of concern because, excluding the northern portion of the project area, Zone 3 (table reef zone) is predominately water-bearing. Zone 1 is a porous calcarenite which is characteristically of good porosity and high permeability. Zone 2 varies from a continuous reef front facies in the western part of the project area to a lagoonal facies in the eastern portion. Except for intermittent porous stringers, the lagoonal facies is characteristically poorer in quality. The reservoir rock averages 25 m in thickness and 8% in porosity. Waterflood Performance Waterflood operations began in 1963 at which time a semi-peripheral line drive was installed along the southwestern edge of the unit (Fig. 4). Additional voidage replacement capability was added as unit allowable were increased. Prior to start-up of the secondary miscible flood in the central portion of the unit in 1973, an estimated 5.0 × 106 m3 of oil migrated from the West Waterflood Project area into the Secondary Miscible Flood Project area due to a high pressure gradient which existed easterly across the unit(1). Waterflood operations continued in the West Waterflood area until September 1982. Figure 5 shows the production performance of the West Waterflood area since 1963.

Enhanced Recovery Of Light And Medium Crude Oil In Canada

Abstract In Canada, the major enhanced oil recovery (EOR) technique for light and medium erode oils is Hydrocarbon Miscible Flooding (HCMF). A solvent (rich hydrocarbon gas) that is or will become miscible with the oil is injected to mobilize the oil down to a lower residual oil saturation than can be achieved under water-flood. A variety of reservoir conditions need to be considered in designing an HCMF. Monitoring the HCMF progress is necessary to optimize oil recovery. Many HCM floods, which are either vertical (gravity stable) or horizontal, have been implemented and accepted as being technically successful. These schemes have already produced a significant amount of incremental reserves and are expected to be a major contributor to Canadian oil production in the future. Introduction Enhanced oil recovery (EOR), as discussed here, is a means to increase light and medium oil recovery to a higher level than achievable by waterflooding. In Canada, as in other parts of the world, there are a variety of techniques being used or considered. The major ones are miscible flooding, immiscible CO2, flooding, polymer flooding, and chemical flooding. The following is a brief description of the different processes. Miscible (Hydrocarbon, CO2) Miscibility is defined as the physical condition where two or more fluids will form a single homogeneous phase when mixed in all proportions, that is, they mix without forming an interface. This results in a dramatic improvement in the displacement efficiency over that of a waterflood. The potential for hydrocarbon and CO2 miscible floods is well known as demonstrated by the number of projects in operation. The choice of solvent (miscible displacing fluid) to be used in a potential EOR scheme is primarily controlled by solvent availability. There are more developed sources of CO2 in the United States than in Canada and, as a result, there are more CO2 miscible flood projects in the U.S. High productivity natural gas wells (with associated natural gas liquids [NGL]) that would otherwise be shut in due to reduced market demand, serve as sources of solvent for HCMF projects in Canada. There now are 56 HCMF and 5 CO2 projects known to be operating in Canada. Immiscible (CO2) This process improves recovery because the CO2 mobilizes the oil by causing oil swelling and reducing oil viscosity. Currently, there are no known active projects in Canada. Polymer A high viscosity fluid (water with dissolved polymer) is injected into the reservoir to improve the mobility ratio between the displacing fluid and the oil. This technique has potential in specific situations (i.e. good reservoir quality with some higher permeability streaks and a viscous oil). There are five known projects now operating in Canada. Chemical Flooding This process usually involves the injection of surface active chemicals which are used to reduce the mobility ratio or mobilize trapped oil. The technique currently has limited economic potential because of the high cost of chemicals in comparison to the incremental recovery. At the present time, there are four known projects operating in Canada.

Reservoir Model Studies For Miscible Flood Projects

Abstract Predictions/rom a compositional numerical model/or first contact horizontal miscible flooding (5-spot pattern) by solvent injection show recoveries ranging from 81.5% to 52.2% DOIP depending on the type of miscible flood project, permeability heterogeneities and solvent-oil mobility ratio. Incremental recoveries over waterflooding range from 40.9% to 13% GOIP in a reservoir where a water zone was present. Model results show that ultimate recoveries with continuous solvent injection are insensitive to the time of implementation of a miscible flood project during waterflooding. Predictions also show that water-alternating solvent injection is effective only in reservoirs with high permeability contrast. Infill drilling (9-spot pattern) resulted in accelerated production with negligible incremental recoveries. Introduction The model predictions reported in this study form part of a joint project designed to develop an integrated engineering-economic model which could be used to examine secondary or tertiary recovery potential under miscible flooding. Selection of the reservoir that has considerable enhanced oil recovery (EOR) potential was accomplished by detailed survey of several reservoirs in Canada(1). Ultimate recoveries and production/injection rate forecasts for horizontal miscible flooding were obtained using a miscible flood reservoir simulator(2). The sensitivity analysis developed in this study will be used as first step guide lines for the development of an engineering economic model which will determine the economic feasibility of EOR projects. Modelling Development The development of the model was based on the options currently available in CMG's miscible flood reservoir simulator (MISIM3). The model assumptions are summarized below:First contact miscibility is taking place at all times.A physical dispersion of 0.2 m2/d is present in the horizontal direction and 0.002 m2/d in the vertical direction.Mixing by diffusion is insignificant compared to physical or convective dispersion. (Only one set of dispersion coefficients was applied in this study for the two types of reservoir description.)Hysteresis effect and viscous fingering are not incorporated in the model.The reservoir fluid is characterized by three components: oil, solvent and chase gas. Initially the reservoir fluid composition is 1, 0, 0, i.e. only the oil component.During solvent injection the calculated relative permeability of the hydrocarbon phase (solvent plus oil) is modified as a function of solvent concentration. The higher the solvent concentration, the higher the solvent mobility.Model production/injection rates for the wells represent 1/8 of the full well rates for primary and 5-spot pattern cases. For the 9-spot pattern the model production rates for the infill well represent 1/4 of the full well and for the original wells the rates represent 1/8 of the full well.The model inherently assumes that each producer in the pattern will exhibit the same performance. Producers are completed in the top three layers and injectors in the top four layers. The 3-D Reservoir Model The 3-D reservoir model, shown in Figure 1, represents Ys of a 5-spot and 1/8 of a 9-spot pattern. The model shows areas of no vertical communication between layers in the reservoir (thick lines).