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ABSTRACT One of the most common techniques used to increase oil recovery is gas injection. The gas injection can be either miscible or immiscible depending on the injection pressure. Miscibility can be reached when the pressure exceeds the minimum miscibility pressure (MMP). Temperature and pressure are important factors that usually affect the MMP. Oil properties play an important role in the success of miscible injection, with the miscible gas injection working optimally when oil is light. Here, we performed data analysis based on more than 1500 experiments, simulation and field tests from more than 170 researchers to show the conditions at which miscible injection can be applied. We investigated various gases, including carbon dioxide (CO2), nitrogen (N2), and hydrocarbon gases. Different statistical analysis tools, including histograms, boxplots, and cross-plots, are used in this study. The data demonstrate that CO2 is the most commonly used gas during miscible injection. The majority of studies performed their experiments at temperatures between 40 to 100 °C using oil with a viscosity of 0.25 to 1.5 cp, and an API gravity between 35.1 to 45 °API. Since a variety of gases have been investigated in this research, a variety of MMP has been reported. 1. INTRODUCTION Gas Enhanced Oil Recovery (GEOR) has been used widely for decades to increase the oil recovery from hydrocarbon reservoirs. Researchers have experimented with the use of different types of gases to be injected into the reservoirs, with the aim of increasing oil production. These gases include Carbon Dioxide (CO2), Nitrogen (N2), Methane (CH4), Ethane (C2H8), and Propane (C3H12). These gases have been thoroughly researched over the past decades, and many have been proven to be successful in enhancing oil recovery (Crawford, et al., 1978; Lee, and Reitzel, 1982; Hudgins, et al., 1990; Kulkarni, and Rao, 2005; Adel, et al., 2018). Gas EOR is injected into the reservoir by different methods; continuous gas injection, which involves injecting the gas continuously without any other fluid, water alternating gas, where gas and water are injected in consecutive cycles, and cyclic gas injection, which also known as ‘huff-n-puff’. The consecutive cycles method, the same well is used for injection and production by injecting the gas multiple times for soaking and production. This method has proven its success in conventional reservoirs (Issever, et al., 1993; Miller, et al., 1994; Lino, 1994; Kanfar and Clarkson, 2017).
- North America > Canada > Alberta (1.00)
- North America > United States > Texas (0.93)
- North America > United States > North Dakota (0.67)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.28)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
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- Information Technology > Data Science (0.70)
- Information Technology > Modeling & Simulation (0.68)
Abstract A new experimental technique, called PRIme, has been successfully utilized in this study to optimize solvent composition for the miscible gas injection project being considered for the Rainbow Keg River ‘F’ Pool. The PRIme technique consists of measuring the interfacial tension between the injected gas phase and the reservoir crude oil at the temperature of the particular oil containing formation and at varying pressures and/or enrichment levels of the gas phase. These interfacial tension measurements are carried out by computer digitization of the image of the profiles of the sessile and pendent drops of the crude oil enclosed in the surrounding medium of the injection gas. By fitting these experimental drop profiles with the iterative solution of the Laplace capillary equation, the value of the interfacial tension is obtained at each pressure or enrichment level. By making a plot of the interfacial tension against the independent variable (either pressure or enrichment) accurate values of the minimum miscibility pressure (MMP) and/or the minimum enrichment are obtained by extrapolation to zero interfacial tension. This paper describes the new PRime technique and provides experimental evidence for its validity by comparing the PRIme-MMP with slim-tube-MMP. Each MMP determination using the PRime technique was accomplished within 4–6 hours, while 4–6 weeks were required for the slim tube technique. The paper also describes the application of the PRIme technique to the problem of optimizing the injection gas composition at the Rainbow Keg River ‘F’ Pool miscible flood For this field application of the technique live reservoir crude oil as well as lean and rich gas mixtures, matching field gases in composition, were used in the experiments. Gas/oil interfacial tension measurements were made in ‘first contact’ as well as ‘equilibrium’ modes. The optimized solvent composition was then verified by a single slim-tube test and compared with equation of state predictions. Tt has been demonstrated through this study that the new technique is a reliable, accurate and fast technique for cost effective determination of MMP's and optimum injection gas compositions. Introduction Hydrocarbon miscible flooding is by far the most important EOR process in Canada. It accounts for 83% of the 164,600 bid of Canadian EOR oil production. Furthermore, it is worth noting that most of the 104,300 bid EOR production increase in 1992 (over that in 1990) in the US was also due to miscible projects based on both CO2 and hydrocarbon gases. Further improvements in the economics of miscible flooding could be accomplished by minimizing the cost of the solvent blends and the cost of their injection. These can be achieved by (1) optimizing the solvent composition so that minimum enrichment of the dry gas by the C2+ fraction would yield cheaper solvents for injection and enable increased sales of the natural gas liquids, (2) increasing the accuracy of determination of minimum miscibility pressures for a given solvent composition and reservoir temperature which, in turn, would enable operation at near miscible conditions resulting in considerable compression cost savings, and (3) identifying the economically optimum combination of injectant enrichment and pressure level (near miscibility).
- Overview > Innovation (0.62)
- Research Report (0.56)
Abstract This paper presents a complete sets ofexperimental work on finding the optimum miscibility condition for 8 Iranian oil fields. During these experimental works new miscibility criteria for slim-tube apparatus investigated. Then a comprehensive simulation procedure to model the miscibility process in slimrube apparatus is given. In order to investigate the applicability of the empirical correlations. the results of experiments and simulation runs are compared to the prediction of different correlations which show unreliable prediction of the correlations. Finally, a semi-empirical correlation is developed, which can predict the minimum miscibility pressure (MMP) with an acceptable error. Introduction In order to enhance the oil recovery from reservoirs, there are several methods. Hydrocarbon gas injection is one of the most suitable methods for some Iranian reservoirs. If the injected gas becomes miscible with the oil, the residual oil will be decreased, therefore, a high amount of oil will be recovered which is favourable. The miscible displacement of oil by injected gas is only achieved at a pressure higher than a certain minimum pressure. The determination of this minimum miscibility pressure (MMP) is vital to any gas injection process. When a study on miscibility of a crude oil and selected gas is stated, two methods are in principal to get the optimum miscibilty condition: laboratory experiments such as slim-tube dynamic tests, and modelling (theoretical and empirical). A series of experiments with slim-tube miscibility apparatus were done, then a fully compositional simulator were used to model the miscibility process in slim-tube apparatus. The results show that the available gases alone or with some enrichment can develop miscibility process with crude oils at reservoir condition. The objective of this study is to investigate different methods to obtain the optimum condition of the injected gas to get the maximum recovery. DISCUSSION In Iran, the gas injection was started for some reservoirs. Some other reservoirs are candidates for gas injection in future. However, these gas injection processes are for pressure maintenance or increasing the reservoir pressure purposes. For miscible flooding to be a competitive process in a given reservoir, several conditions must be satisfied:an adequate volume of solvent must be available at a rate and cost that will allow favourable economics, the reservoir pressure required for miscibility between the solvent and oil in question must be attainable, and incremental oil' recovery must be sufficiently large and timely for project economics to withstand the added costs. Hydrocarbon solvents in other countries such as U.S. could be too expensive. However, supply and cost in Iran as well as conservation policies could be favourable for projects with hydrocarbon solvents. Determining the MMP (item 2), is the main object of this paper, which will be discussed in next paragraphs, and economical considerations are (item 3), are vital for any industrial projects. VARIOUS METHODS FOR STUDYING MISCIBILITY PROCESS There are basically two methods to study the miscibility process.
- Research Report > New Finding (0.35)
- Research Report > Experimental Study (0.35)
Asgarpour, S., SPE, Gulf Canada Corp. Singhal, A.K., SPE, Premier Reservoir Engineering Services Ltd. Premier Reservoir Engineering Services Ltd. Card, C.C., Gulf Canada Corp. Wong, T.W.,* SPE, Gulf Canada Corp. Springer, S., SPE, Gulf Canada Corp. Summary. The required slug size for a patterned hydrocarbon miscible flood in the Upper Devonian reef at Fenn-Big Valley, central Alberta, was computed on the basis of dispersion/diffusion calculations at the leading and trailing edges of the solvent slug. This slug size included consideration of microscopic heterogeneities and a safety factor so that sufficient slug remained to ensure miscibility. This calculated slug size formed the design basis for a pilot experiment in part of the pool. After 3 years of pilot operation, sufficient performance and tracer results were available to enable a re-evaluation of the design basis. The motivation behind re-evaluation was to extend the recovery process to a much larger part of the pool. part of the pool. Whereas local heterogeneities and transport considerations indicated that a moderate slug size (6% HCPV) was required, regional and interwell heterogeneities, flooding patterns, and geometry of flood propagation indicated that about twice this slug size was needed. Because of this, it was concluded that the realistic design basis for a field-scale project must fully consider regional and interwell heterogeneities. This paper deals with the supporting data and procedures used in developing the revised design basis for the project. Introduction In a miscible flood where the water-alternating-gas (WAG) process is used, the total amount of solvent used should be enough to process is used, the total amount of solvent used should be enough to maintain miscibility conditions at the displacement front in the bulk of the reservoir. Whereas heterogeneities and stratifications have a net effect of increasing the solvent losses and consequently the solvent requirements, economic considerations dictate optimizing these amounts. The principal parameters determining solvent losses are the dispersion and mixing coefficients (defined later). Unfortunately, no simple methods for determining these coefficients are available. The complexity of the flooding process makes the interpretation of data from any of the available methods extremely difficult. These complexities, besides heterogeneities, and stratification could be a result of the shape of the displacement front, the geometry of the swept area, dead-end pores, the nature of the miscible flood, the presence of mobile water or trapped gas, or wettability. Furthermore, the dispersion observed in a single core sample is different from that observed a few meters around a wellbore. These, in turn, could be different from those observed over interwell distances in the reservoir, as pointed out by Warren and Skiba. The realistic numerical modeling of a hydrocarbon miscible flood requires a detailed reservoir description, but such details are seldom available. Furthermore, the extent of numerical dispersion involved tends to mask the effects of physical dispersion. In view of resource and process uncertainties, more sophisticated numerical approaches are rarely considered cost effective. Obviously, if the physical dispersion parameters could be measured easily and physical dispersion parameters could be measured easily and cost-effectively, this method would be preferable to other methods. Usually, however, a number of economic and operational difficulties render most numerical dispersion parameter measurements too difficult to interpret. In this study, data obtained from a hydrocarbon miscible flood in the South Lobe of Fenn-Big Valley D-2 pool (Devonian reef) were used to determine dispersion coefficients from core studies, single-well tracer tests, and interwell radioactive tracers injected to trace the solvent slugs. From various analyses of data obtained, efforts were made to determine solvent requirements for a field-wide expansion of the project. Fenn-Big Valley, D-2A, South Lobe Project The Fenn-Big Valley D-2A pool, located in Alberta (Fig. 1), was discovered in 1950 and was developed on a 16-ha [40-acre] spacing with an average well depth of 1600 m [5,250 ft]. The reservoir consists of stratified porous dolomite ranging in thickness from 8 to 40 m [26 to 131 ft]. It is fairly heterogeneous, with significant variations in both porosity and permeability. Primary production has been under a natural waterdrive with excellent support from the underlying aquifer. To date, much of the pool, especially the south lobe, has effectively been swept by the encroaching aquifer. The relevant properties of this reservoir are presented in Table 1. The EOR scheme is a hydrocarbon miscible flood, WAG injection process designed to operate with a WAG ratio of 1 in each of the seven pattern areas. Injection of solvent began in April 1983. Solvent and water will be injected over a period of 12 cycles (about 4 years), followed by chase-gas/water injection for another 12 cycles. The project area will then be subjected to a scavenging waterflood. Dispersion and Solvent Slug Requirements As mentioned earlier, in miscible displacement of oil by solvent, adequate solvent volumes should be injected to account for the solvent losses resulting from diffusion and dispersion in the reservoir. The overall transport and mixing of solvent in an idealized displacement can be expressed by the following convection-diffusion equation. ,.................................(1) where C = concentration of solvent, v = interstitial velocity, and K = tensor formulation of the dispersion coefficient. For layer thickness larger than 330 cm [greater than 11 ft], Wheat and Dawe suggested that fluid mixing caused by transverse dispersion is negligible. In this case, when the only nonzero component of the velocity is constant and in the × direction, Eq. 1 reduces to .................................(2) SPERE p. 227
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.44)
- Geology > Rock Type > Sedimentary Rock (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
An Application of Chemical Tracers In Monitoring Injection In Vertical Hydrocarbon Miscible Floods
Carr, L. (Husky Oil Operations Ltd.) | Wong, F. (Husky Oil Operations Ltd.) | Nagel, R. (Husky Oil Operations Ltd.) | McIntyre, R. (Husky Oil Operations Ltd.) | Rosenegger, L. (Teknica Petroleum Services Ltd.)
Abstract Chemical tracers have been utilized to effectively monitor injected fluid movement in two vertical hydrocarbon miscible floods in the Rainbow Field, Alberta. By placing small slugs of chemical tracers, consisting of sulphur hexafluoride (SF6) and chlorinated fluorocarbons (CFC) or halocarbons within the injectants, the spreading and development of chase gas and solvent banks were monitored, and in some cases, reservoir flow channels identified. In addition, geological units were confirmed and well workover planning improved, resulting in increased cost effectiveness in operating the miscible floods. The chemical tracer program commenced with the first field application conducted in the Rainbow Keg River "A" (R.K.R.A.) Pool secondary miscible flood on January 31, 1991, where chase gas injection into two wells was traced. Subsequently a program of tracing chase gas and solvent was initiated at one well location in November, 1991 in the Rainbow 1 Keg River "B" (R.K.R.B.) Pool tertiary miscible flood, and later at six additional chase gas and solvent co-injection wells. This paper presents the design of the tracer programs, the significance to the operation of the miscible oil recovery schemes and alternative tracers considered for the future. Introduction Husky Oil operates seven mature secondary and three tertiary miscible flood enhanced oil recovery projects in the Rainbow Field of northwest Alberta (Figure 1). Cost effective operation of these floods requires that solvent and chase gas sweep a significant extent of the reservoir without being produced at high rates. If miscible solvent bypasses large portions of the reservoir due to channeling, recovery efficiency will be lower than expected. Maintaining cost effective operation of hydrocarbon miscible flooding has required the development of extensive tracer programs designed to track and optimize solvent distribution in the reservoir as well as detect breakthrough at the very early stages. Previously, Husky had used radioactive tracers to monitor solvent bank placement in the R.K.R.B. Pool(1). Following the successful conclusion of this program and others in Rainbow Lake, other tracers were researched with the expectation that more of the analysis could be conducted on site and with reduced cost. More recently, Husky has used several Freon" haIocarbons and SF6 as chemical tracers to monitor chase gas and solvent injection in both the R.K.R.A and B Pools. FIGURE 1: Field location map. Illustrations available in full paper. Tracing injected chase gas and miscible solvent is used to identify the distribution of these fluids, both regionally and vertically, in the miscible floods. This enabled identification of the source of early solvent and chase gas breakthrough due to reservoir channeling, and allowed for early remedial action. Tracers less expensive than radioactive tracers, both from an initial cost and a per sample analysis cost basis were sought. They had to be detectable and accurately measurable at extremely low concentrations in the field lab and be readily handled by the field operations group. Finally, they could not be native to the oil reservoirs or have adverse rock or fluid adsorption or partitioning characteristics.
- North America > United States (1.00)
- North America > Canada > Alberta (0.96)