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Designing a miscible flood
Miscible flooding is presently the most-commonly used approach in enhanced oil recovery. Miscible flooding is a general term for injection processes that introduce miscible gases into the reservoir. A miscible displacement process maintains reservoir pressure and improves oil displacement because the interfacial tension between oil and water is reduced.
Choosing a candidate
A decision to implement a miscible flood in a particular field will usually consist of a sequential approach.
First is the screening stage. Data will allow a reasonable estimate of:
- Minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME) (See Miscible flooding for information about calculating MMP and MME)
- Miscible flood residual oil saturation (Sorm)
- Amount of solvent required
- Operating costs
This information is adequate to determine if a reservoir is a candidate.
MMP and MME guidelines and correlations
MMPs with different solvents gives some rough guidelines for achieving MMP or MME. For hydrocarbon solvent enriched with the C2 –C4 hydrocarbons, MMP in the range 1,500 to 3,000 psi might be expected for mid-API-gravity oils, depending on oil and solvent compositions and reservoir temperature.
The vaporizing-solvent process is applicable to high-gravity oils. MMP typically is greater than 3,500 psi and is usually greater than 4,500 psi (and can be much greater).
CO2 flooding is applicable with medium-gravity oils. At temperatures less than approximately 125°F, MMP can be as low as 1,200 psi. MMP increases with temperature.
Fig. 1 shows an approximate correlation for CO2 flooding MMP. Fig. 2 shows one graph for a similar correlation that was developed for condensing-solvent-drive MMP. It also appears to be useful for condensing/vaporizing drives. Other graphs are given in Benham, Dowden, and Kunzman.
Fig. 2 – Correlation for enriched-gas-drive MMP (after Benham, Dowden, and Kunzman).
In field projects in which the displacement was above either the MMP or the MME, residual oil saturation determined by coring behind the solvent front varied from approximately 3 to 10% PV.
Second, a more thorough assessment may require acquiring laboratory data on Sorwf , Sorm, and MMP or MME.
Analog data from nearby fields may be adequate for these values and may indeed be adequate for evaluating a project without additional work. Occasionally, some type of field pilot may be thought necessary to address such questions as displacement and sweep efficiencies (most small pilots do not produce results to reliably predict these factors), injectivity of miscible fluids, and existence of fractures or very-high-permeability layers that would prevent the miscible fluids from contacting a significant volume of the reservoir.
Third, some type of simulation will normally be done to incorporate reservoir and fluid characteristics unique to the field in question. The type of simulator used will depend on the amount and quality of the characterization data available and the perceived risks of the project that justify the costs of the various types of simulation that can be done.
MMP can also be calculated accurately if a reliable fluid characterization with an equation-of-state is available. The calculation can be made using analytical methods, compositional simulation, and/or multiple mixing cell models. Analytical methods use the method of characteristics to solve the hyperbolic equations of flow and phase behavior. Compositional simulation is used to simulate a slim-tube displacement, where the number of grid blocks are varied. Mixing cell models rely on moving various fluids ahead and behind in contacts that mimic how fluids move in a formation.
The best method for MMP determination is slim-tube experiments, followed by calculated MMPs with the analytical or mixing-cell methods. Ideally, these methods should agree before doing compositional simulation. The advantage of the calculated MMPs is that they can predict the MMP for compositions or conditions not measured in the slim-tube experiment(s). The multiple mixing cell method is especially robust. The advantage of slim-tube experiments is that they use the actual crude (hopefully uncontaminated), but very few of these measurements can be done owing to time and cost. Other methods such as the rising bubble or vanishing interfacial tension experiments for MMP determination should not be used as they are unproven to mimic the proper interaction of phase behavior with flow.
Factors to be considered
Several factors should be considered in assessing the economic viability of a miscible project:
- What miscible fluids are available, and what is the corresponding MMP or MME?
- Miscible fluids commonly considered are hydrocarbon solvents such as enriched methane, CO2, N2, and, less often, exhaust or flue gases. Assessments of hydrocarbon solvents should include near-term lost revenue because of delays in sales (if any) and the ultimate amount of solvent that will remain in the reservoir at abandonment. MMP and MME will also narrow the number of solvents that may be applicable to a specific field.
- Is the MMP sufficiently below overburden pressure, or are adequate enrichment fluids available for the field in question?
- In many instances, the MMP for a given solvent may exceed the overburden pressure of a formation. Where MMP is less than overburden, the question becomes whether a high-enough injection rate can be achieved to satisfy a reasonable project life.
- Are near-miscible recoveries high enough to support a project?
- As discussed earlier, significant additional recovery may be possible without reaching the slimtube MMP.
- What is the incremental recovery vs. the solvent slug size (Fig. 3)
- Numerical simulations can provide sufficient insight to evaluate the economics of a project. For most projects, slug size can be refined further during the actual flood (usually increased) when actual performance can be used to modify initial projections.
- Which WAG ratio will be most effective?
- Simulations can give a good initial estimate and will be good enough for defining the costs of a WAG project.
- Several different Water Alternating Gas (WAG) schemes have been used in practice. These include:
- An initial slug of miscible solvent followed by a low WAG ratio tapering to a high ratio.
- A constant WAG ratio that tapers to a high ratio near the end of the project.
- Monthly adjustments in individual-pattern WAG ratios based on the observed performance of offset producers.
- In all cases, surveillance practices after the start of a project include periodic (monthly to quarterly) studies of the gas/oil-ratio (GOR) and water/oil-ratio (WOR) trends in producing wells and the indicated adjustments needed in WAG ratios in offsetting injectors to achieve desired performance.
- Will water- and solvent-injection rates change?
- Several projects have experienced reduced water injectivity (20% or more) after the WAG process was started.
- Some projects have experienced solvent injectivity higher than water, while others have seen significant decreases.
- Such decreases in injectivity may significantly affect project economics.
- Will separation of the solvent from produced fluids be necessary?
- This is a problem usually associated with CO2 and N2 projects. Breakthrough of solvents (which occurs early and grows with time) will contaminate produced hydrocarbon gases. Separation is required to remove contaminants before sale. The investment and operating cost of separation facilities and compression for reinjecting the recovered miscible materials should be included in the economic assessment of the project.
- In some instances, the amount of hydrocarbon gases produced may not justify its recovery, and reinjection of the total solvent stream may be a more practical solution.
- How much solvent must be purchased, and how much should be recycled?
- Simulation results should provide sufficient insight on the rates of solvent breakthrough to answer this question. Predicted purchased volumes are generally in the 40 to 50% range of the total injection required, with the remainder being recycled solvent.
- Initial estimates of solvent needs are usually in the 40 to 60% range of HCPV. This figure tends to increase over the project life as reservoir management practices improve sweep and reduce costs, thus sustaining the economic viability of the project longer than originally forecast.
- What is the time from first expenditure to first incremental production? (Fig. 4)
- Capital outlays for equipment, drilling, and modifications to existing facilities will be made before the project start.
- In addition, experience shows that there is a delay from the time solvent injection starts to the first significant production response. This delay roughly corresponds to injection of 0.05 to 0.1 hydrocarbon pore volume (HCPV) of solvent. In most cases, most of the purchased solvent is injected before significant recovery of incremental oil. Such a delay, of course, is inevitable because waterflood residual oil that is displaced by the solvent front has to travel from injector to producer. Often, there is no delay because incremental increases in oil production result from immediate improvements made to operations. There also can be a substantial delay before the peak incremental oil rate is attained, amounting very roughly to 0.1 to 0.2 HCPV of solvent injected. Project economics should include the impact of this timing.
- Another important feature of field tests that is consistent with mechanistic concepts and simulations is that solvent breakthrough usually occurs concurrently with the first production of the incremental-process oil or shortly thereafter. This signifies only a small, clean oil bank ahead of the advancing solvent front because of solvent fingering caused by adverse mobility ratios, gravity override, or permeability stratification. Much of the banked-up oil is located around the sides of these fingers and will be recovered with additional solvent injection.
- Are additional wells needed?
- Many projects have included the drilling of infill wells to provide more effective injectors, better volumetric sweep, and the productivity needed for good project economics. This applies to relatively low-cost environments in mature operating areas and has not been necessary or practical when wellbores are in good condition; in other, higher-cost operating areas; or where the reservoir characteristics did not require additional development.
- Mungan, N. 1981. Carbon Dioxide Flooding-fundamentals. J Can Pet Technol 20 (1). PETSOC-81-01-03. http://dx.doi.org/10.2118/81-01-03
- Benham, A.L., Dowden, W.E., and Kunzman, W.J. 1960. Miscible Fluid Displacement—Prediction of Miscibility. Trans., AIME 219: 229.
- Stalkup, F.I. 1983. Miscible Displacement, Vol. 8. Dallas, Texas: Monograph Series, SPE.
- Rogers, J.D. and Grigg, R.B. 2001. A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process. SPE Res Eval & Eng 4 (5): 375-386. SPE-73830-PA. http://dx.doi.org/10.2118/73830-PA
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
Ahmadi, K., & Johns, R. T. (2011, December 1). Multiple-Mixing-Cell Method for MMP Calculations. Society of Petroleum Engineers. doi:10.2118/116823-PA
Christensen, J. R., Stenby, E. H., & Skauge, A. (2001, April 1). Review of WAG Field Experience. Society of Petroleum Engineers. doi:10.2118/71203-PA
Jarrell, P.M, Fox, C.E., Stein, M.H., Webb, S.L., Practical Aspects of CO2 Flooding, Editor: R. T. Johns, SPE Monograph Series, Volume 22, ISBN 1-55563-096-0, Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers Inc., Richardson, Texas, 2002.
Johns, R. T., & Orr, F. M. (1996, March 1). Miscible Gas Displacement of Multicomponent Oils. Society of Petroleum Engineers. doi:10.2118/30798-PA
Johns, R. T., Yuan, H., & Dindoruk, B. (2004, September 1). Quantification of Displacement Mechanisms in Multicomponent Gasfloods. Society of Petroleum Engineers. doi:10.2118/88999-PA
Panda, M., Ambrose, J. G., Beuhler, G., & McGguire, P. L. (2009, February 1). Optimized EOR Design for the Eileen West End Area, Greater Prudhoe Bay. Society of Petroleum Engineers. doi:10.2118/123030-PA
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