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Miscible injection is a proven, economically viable process that significantly increases oil recovery from many different types of reservoirs. Most miscible flooding projects use CO2 or nitrogen as solvents to increase oil recovery, but other injectants are sometimes used. This page provides an overview of the fundamental concepts of miscible displacement. Also provided are links to additional pages about designing a miscible flood, predicting the benefits of miscible injection, and a summary of field applications.
Fieldwide projects have been implemented in fields around the world, with most of these projects being onshore North American fields. Many of these projects are quite mature, making the recovery and production-rate benefits well established. As a result, the ability to predict recovery levels, rate improvements, costs, and resulting economics can now be considered proven and reliable.
Comparison to waterflood
To put miscible flooding into perspective, it is instructive to compare the performance of a miscible flood to that of a waterflood. Although it is impossible to define a "typical" flood, the simplistic example shown in Fig. 1 introduces the physics of the process and illustrates the level of incremental recovery and sweep often achieved with miscible flooding. This example is based on simulation results for the Means Lower San Andres reservoir in west Texas.
Fig. 1 – Example flooding performance.
The upper diagram in Fig. 1 shows a pattern element in the reservoir (with an injector on the left and a producer on the right) near the end of a waterflood. The initial average oil saturation, Soi, of 70% at the start of the waterflood was reduced to an average of 44%, Sorwf, at the end. The 44% accounts for much higher saturations near the edges of the pattern and in lower-permeability strata not contacted by water. The waterflood recovers 37% of the original oil in place (OOIP) and sweeps approximately 80% of the reservoir.
The average Sorwf in those regions swept by water is 38%. The oil that remains in the water-swept part of the reservoir is trapped as a discontinuous phase within the pore space. The primary goal of a miscible flood is to recover part of this trapped residual oil. However, solvent can sometimes also displace oil from upper regions of the reservoir not swept or poorly swept by water because of gravity-driven water "slumping."
The lower diagram in Fig. 1 shows the same reservoir element near the completion of a miscible flood started near the end of the waterflood. In practice, a solvent flood is often initiated before completing the waterflood — or, in some cases, even before starting the waterflood. The schematic shows that solvent sweeps only part of the reservoir previously swept by water, and only a portion of the residual oil in the solvent-swept regions is recovered. The average oil saturation after the miscible flood (Sorm) of 36% includes
- Higher oil saturations remaining in regions near the edge of the pattern element and in lower-permeability strata bypassed by both water and solvent
- Residual oil in that part of the reservoir swept by water but not by solvent.
The miscible flood recovered an incremental 11% OOIP over and above waterflooding results. Expressed another way, the incremental recovery was 18% of the oil remaining after waterflooding.
The solvent sweeps approximately 50% of the pattern, compared to approximately 80% for water. In regions swept by solvent, oil saturation is reduced from an average value of 38% to 24%. The average oil saturation of 24% in solvent-swept regions accounts for oil saturations lower than 24% near the injector, as well as higher saturations near the producer. At the pore level, solvent displaces some, but not all, of the waterflood residual oil.
Three solvent-injection strategies commonly used in commercial miscible-flooding applications are slug injection, water-alternating-gas (WAG) injection, and gravity-stable injection. The slug process usually involves continuous injection of approximately 0.2 to 0.4 hydrocarbon pore volumes (HCPV) of solvent that, in turn, is displaced by water or dry solvent. The WAG process involves alternately injecting small volumes (0.01–0.04 HCPV) of water and solvent. The total amount of solvent injected usually ranges from 0.2 to 0.6 HCPV. As with the slug process, the final drive fluid is usually water or dry solvent. It is commonly accepted that alternate injection of small slugs of water decreases solvent mobility and leads to increased solvent sweep efficiency. Experience with many projects has indicated that field-management processes improve with time, and additional volumes of injectant can be justified to further increase recovery.
For some pinnacle reefs and steeply dipping reservoirs with high vertical communication, it is advantageous to inject less-dense solvent at the top of the reservoir in a gravity-stable displacement process. Solvent sweep efficiency and oil recovery are quite high, provided that there is sufficient vertical continuity.
Factors affecting recovery
The two major factors that affect the performance of a miscible flood are oil-displacement efficiency at the pore level and sweep efficiency on the field scale. Oil displacement can be explained using the schematic on the left side of Fig. 2, which shows solvent flowing from left to right through a pore space. The displacement process involves several mechanisms. One is direct miscible displacement of oil by solvent along higher-permeability pore paths. Additionally, part of the oil initially bypassed (on the pore level) by solvent can later be recovered through oil swelling that occurs as solvent dissolves in the oil, or by extraction of oil into solvent. Swelling and extraction take place as solvent continues to flow past the initially bypassed oil. These can be significant mechanisms in field processes and together may account for as much as 20 to 30% of the total incremental recovery. Oil-displacement efficiency is affected by solvent composition and pressure. Solvents can be designed that give very high displacement efficiencies at the pore level.
Fig. 2 – Factors affecting miscible recovery.
The right side of Fig. 2 shows that, on a field scale, sweep efficiency is affected by viscous fingering and solvent channeling through high-permeability streaks. Gravity override can sometimes occur because solvent is usually less dense than the oil it is displacing. When vertical communication is high, solvent tends to gravity segregate to the top of a reservoir unit and sweep only the upper part of that zone. Although gravity override can be a problem in reservoirs having good vertical communication (such as Judy Creek and Prudhoe Bay), it is not usually a serious problem for west Texas carbonates, which tend to be more stratified and have poor vertical communication.
Sweep efficiency on the field scale is usually the single most important factor affecting performance of a miscible flood. Sweep efficiency can be increased to some extent by reducing well spacing, increasing injection rate, reconfiguring well patterns, increasing solvent-bank sizes, and modifying the ratio of injected water to injected solvent (WAG ratio).
Fig. 3 presents part of a considerable body of laboratory evidence that solvent effectively displaces oil from contacted regions of the reservoir. The graph of oil recovery as a function of total pore volumes of fluid injected shows the results of a laboratory coreflood conducted at conditions corresponding to the Sharon Ridge reservoir in west Texas. The waterflood recovered approximately 40% OOIP. A CO2 flood that followed increased oil recovery to approximately 80% OOIP, demonstrating that CO2 can displace a large portion of the residual oil remaining after a waterflood. Sorm was 10%; the WAG ratio for the miscible flood was 1.
Fig. 3 – Laboratory coreflooding studies.
The schematics at the bottom of Fig. 3 illustrate the pore-level recovery mechanisms discussed earlier (Fig. 2). At the end of the waterflood, residual oil is a discontinuous phase that occupies approximately 40% of the pore space. Early in the miscible flood [3.0 to 3.5 total pore volumes (PV) injected], some of this oil has been miscibly displaced by solvent from the higher-permeability flow path (on the pore scale). However, some oil also has been initially bypassed by solvent. Note that this bypassing at the pore level is much different from solvent bypassing, which can occur at the field scale because of larger-scale reservoir heterogeneities. As depicted in the schematic corresponding to late in the flood (to 7.0 total PV injected), part of this locally bypassed oil is subsequently recovered by extraction and swelling that takes place as solvent continues to flow past the bypassed oil. In this case, approximately 30% of the total amount of oil recovered by the CO2 flood was recovered by extraction and swelling.
True miscible displacement implies that injected and displaced phases mix in all proportions without forming interfaces or two phases. The single-phase condition also implies that the solvent eventually displaces all resident oil from the pore space that it invades. Although some fluids, such as propane, fulfill this definition, most solvents available for oilfield use form two distinct phases over a broad range of mixtures and pressures when combined with reservoir oils. However, when the same solvent displaces oil at reservoir temperature and above a suitably high pressure in a long, small-diameter (slim) sandpacked tube, a miscible-like displacement occurs. Slimtube experiments are designed to make the displacement essentially 1D with 100% volumetric sweep by the solvent front.
Fig. 4 shows a series of hypothetical slimtube experiments. In these experiments, the solvent displaces oil from the fully oil-saturated slimtube at several pressures. Oil recovery is shown after 1.2 pore volume (PV) of injection for each pressure. Oil recovery increases with pressure up to approximately 95 to 98% and then increases very little thereafter. The pressure at which the break in the recovery curve occurs is said to be the minimum miscibility pressure (MMP). If the displacements had been conducted at constant pressure and with increasing enrichment by components such as ethane, propane, and butane, the break over would have been at the minimum miscibility enrichment (MME). Above the MMP or MME, the displacement is said to be "multiple-contact" or "dynamically" miscible. The increasing recovery with pressure or solvent enrichment results from in-situ mass transfer of components between solvent and resident oil. Each pressure increase produces an equilibrium mixture that becomes compositionally similar at the MMP or MME. Methane, methane enriched with C2 –C4 hydrocarbons, CO2, N2, and flue solvent will all give compositionally enhanced displacements under the right conditions of pressure, temperature, and oil composition. The MMP or MME can be significantly different for each of these solvents.
A slimtube is not representative of the performance in reservoir rock because it does not account for the effects of factors such as gravity segregation and reservoir heterogeneity on volumetric sweep. Fig. 5 shows how ethane enrichment of methane affected oil recovery in an experiment conducted by Chang et al. with live reservoir fluid in a 34.6-in.-long, relatively homogeneous Bentheimer sandstone core. The experimental conditions resulted in a single, gravity-overriding tongue of solvent in the core. Oil recovery continued to increase from enrichment levels well below to well above the MME determined from slimtube displacements without evidencing a pronounced break over. In other words, compositional enhancement continued to increase recovery well above the slimtube MME for this gravity-dominated displacement.
Fig. 5 – Enriched gasflood with gravity tongue in outcrop core(after Chang, et al.).
Jerauld reported a similar finding by use of a compositional reservoir simulation of a one-fourth nine-spot pattern element (Fig. 6). Recovery continued to increase from well below to well above the simulator-predicted MME of 0.65.
Fig. 6 – Effect of enrichment on recovery in a reservoir study. After Jerauld (solid lines are the reference model, and dashed lines are the scaleup model).
Overall industry experience
Fig. 7 shows how incremental ultimate recovery increased with total solvent slug size for a few projects for which these data were available in the literature. The interpretations given in this figure are the author’s and are not necessarily those of the project operators. Many of the projects represented in this figure are ongoing, and the ultimate incremental recovery is an estimate.
The contribution of incremental oil production from gas-injection projects (mostly miscible) has continued to grow since 1984, as reported biennially by the Oil & Gas Journal. Fig. 8 shows the volumes reported in this reference. In 2002, total incremental production was nearly 550,000 BOPD. Approximately 60% of the total comes from hydrocarbon miscible projects, and most of the remainder comes from CO2 miscible projects in the US. The advent of the significant contributions from the projects (hydrocarbon miscible) in Venezuela beginning in 2000 indicates an ongoing effort to identify and implement miscible projects around the world.
Miscible injection has been applied successfully in many reservoirs. Field examples are presented to illustrate how CO2, enriched hydrocarbons, and N2 solvents have been used to increase oil recoveries significantly. The resulting experience with miscible projects has made it possible to reliably predict the economic viability of new projects in other reservoirs. Advances incompositional simulation enhance the ability to assess miscible flooding and improve its effectiveness.
- Healy, R.N., Holstein, E.D., and Batycky, J.P. 1994. Status of Miscible Flooding Technology. Proc., 14th World Petroleum Congress, Stavanger, 29 May–1 June. 407–416.
↑ 2.0 2.1 2.2 2.3 2.4 2.5 Hadlow, R.E. 1992. Update of Industry Cite error: Invalid
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