GB2142957A - Displacing hydrocarbons in subterranean reservoirs - Google Patents

Abstract

Injectivity losses in alternate displacing fluid-aqueous fluid injections into an oil-bearing reservoir can be reduced through injection of a secondary displacing fluid in conjunction with the first displacing fluid injection cycle. The secondary displacing fluids reduce residual oil saturation near the injection wells to prevent adverse effects on relative permeability to aqueous fluid flow, which can occur. Fluids useful as the secondary displacing fluid of the invention include nitrogen, methane, ethane, propane, benzene, and refined oil.

Description

SPECIFICATION Reducing injectivity losses during displacing fluid injection processes 1. Field of the invention This invention relates to the displacement of hydrocarbons through hydrocarbon-bearing subterranean reservoirs by injecting a displacing fluid such as CO2. Specifically, the invention concerns reducing losses in fluid injection rates during the alternate injection of a displacing fluid with injection of an aqueous fluid.

Background of the invention Displacing fluids such as carbon dioxide or enriched gas, which is predominantly methane with other light hydrocarbons such as ethane or propane, have been used for miscibly displacing crude oil from an oil-bearing reservoir. For example, a multiple contact process is described in Rathmell, et al., Laboratory Investigation of Miscible Displacement by Carbon Dioxide," Preprint, SPE 3483,46th SPE Fall Meeting, October 3-6, 1971, p. 1, whereby CO2 mixes with the reservoir crude oil in the reservoir and forms a fluid that is substantially miscible with oil. During this displacement process, aqueous fluid injection is alternated with CO2 injection to control the flow of injected fluid through the reservoir.

However, subsequent reductions in aqueous fluid injectivity have been experienced in alternate CO2/ aqueous fluid injections, see Shelton, et al., "Multiple Phase Behavior in Porous Media During CO2 or Rich Gas Flooding," SPE 5827, Improved Oil Recovery Symposium, March 22-24, 1976, p. 1. This problem was experienced at a 12-acre field test of CO2 displacement by Amoco Production Company in the Level land Field near Levelland, Texas, where the brine injection rate before CO2 injection was approximately 800 barrels per day. Injectivity in the first brine injection cycle after carbon dioxide injection began was only about 300 barrels per day.

The brine injectivity could not be increased above 300 barrels per day because higher rates required injection pressures which were above the parting pressure of the reservoir. If the parting pressure is exceeded, the reservoir can fracture. CO2 subsequently injected into the fractured reservoir can then flow into non-oil bearing portions of the reservoir, thereby lowering oil recovery. Thus, the brine injectivity rate must be reduced.

Such injectivity losses can have drastic adverse effects on production rates and project economics.

Techniques to alleviate this problem are thus importans to these displacement processes. Applicants are not aware, however, of any techniques for reducing or preventing anticipated injectivity losses which are implemented at the beginning of the displacement process.

Summary ofthe invention The method of the invention provides an improved method of displacing hydrocarbons from a hydrocarbon-bearing subterranean reservoirwherein fluids are injected into the reservoir by alternating injection of a displacing fluid with injection of an aqueous fluid. The method of the invention comprises reducing injectivity losses during aqueous fluid injection cycles by injecting a primary displacing fluid and a secondary displacing fluid, followed by injecting an aqueous fluid, and then alternately injecting a primary displacing fluid and an aqueous fluid. The primary and secondary fluids can also be injected simultaneously. The secondary displacing fluid lowers residual oil saturation adjacent the injection well.

The advantage of lower residual oil saturation adjacent the injection well is that subsequent aqueous fluid injections can be maintained at high rates without high injection pressures above the reservoir parting pressure. Thus loss of aqueous fluid injectivity is prevented or reduced. The secondary displacing fluid can be any fluid capable of reducing residual oil saturation near the injection well, for example, benzene, LPG, refined oil, methane, ethane, propane, nitrogen, and flue gas.

Brief description of the drawings Figure 1 displays a phase equilibrium between a crude oil and carbon dioxide.

Figure2 displays changes in a phase equilibrium between a crude oil and a mixture of carbon dioxide and secondary displacing fluid.

Detailed description of the invention Carbon dioxide or enriched gas is used as a displacing fluid to miscibly displace hydrocarbons from a hydrocarbon-bearing reservoir, yet both are substantially immiscible with reservoir crude oil because they do not form a single-phase solution with crude oil upon a single equilibrium contact.

Instead, miscibility of crude oil with these displacing fluids is thought to be generated at reservoir pressure and temperature by an extraction process wherein lighter components, those of carbon number 2-6, of the crude oil are extracted into the displacing fluid.

Thus, generation of miscibility with CO2 (which for simplicity will be discussed exclusively hereafter, though the comments apply also to enriched gas) requires that the CO2 advance through some amount of subterranean reservoir length before a miscible displacement occurs. In the length before miscibility occurs, the displacement of oil is immiscible.

An immiscible displacement is not as efficient as a miscible displacement and thereby results in a higher residual oil saturation remaining behind the displacement front near the injection wells of a CO2 displacement project. Laboratory simulations have shown this concept. For example, CO2 displacement tests were performed in two Berea rock cores, two inches in diameter and eight feet long, mounted in pressure cells and connected together by 1/8-inch stainless steel tubing to create a 16-foot core. The cores were saturated with crude oil from the Levelland field near Levelland, Texas, and the oil was displaced with CO2. The final oil saturation in each eight foot core was then determined for each of two runs. The results showed similar overall oil recovery (90.6% and 89.0%, respectively, of original oil satura tion) in both runs.In each run the core nearest the CO2 injection face had a significantly higher residual oil saturation than its connected second core (15.5% and 9.1%; 16.2% and 11.8%; for an average higher oil saturation of 5.4%; all percents are determined on a weight basis).

The results show higher oil saturation in the first core near the injection face due to the less efficient immiscible displacement. This same phenomenon can occur near an injection well penetrating a hydrocarbon-bearing subterranean formation during a CO2 displacement process. The significance of higher oil saturation adjacent an injection well is that oil saturation affects the relative permeability of the flow of oil and water, as described in Schneider, et al., "Relative Permeability Studies of Gas-Water Flow Following Solvent Injection," SPE 5554, 50th Annual SPE Fall Meeting, September 18-October 1, 1975, which is incorporated herein by reference.

Higher oil saturation near an injection well results in a reduction in water injectivity rates because of the relative permeability change. In an alternate CO2 water injection process, production rates must be altered during water injection cycles. It thus becomes necessary to treat the reservoir or the injection well to increase water injectivity.

Applicants' invention comprises a method for preventing aqueous fluid injectivity loss. The method is implemented at the outset of injection of displacing fluids into the reservoir.

The method comprises injecting a primary displacing fluid and a secondary displacing fluid, followed by injecting an aqueous fluid. The method then continues by alternating injections of a primary displacing fluid with injection of an aqueous fluid.

The method of the invention should be understood as including different sequences of injection of the primary displacing fluid and the secondary displacing fluid. For example, the secondary displacing fluid injection can precede, can be simultaneous with, or can follow the primary displacing fluid injection. The method operates by reducing the residual oil saturation remaining near injection wells which is the cause of the injectivity loss.

One aspect of the invention is that in an alternating displacing fluid-aqueous fluid displacement process, injecting a secondary displacing fluid simultaneously with a primary displacing fluid decreases the reservoir length required for developing miscibility with reservoir hydrocarbons. This reduces oil saturation near the injection well. The result is that subsequent aqueous fluid injection rates are not as impaired, thus keeping producing rates high.

A secondary displacing fluid injected simultaneously with CO2 reduces the reservoir length the CO2 must advance before a miscible displacement occurs. This is due to change in the phase equilibrium of a mixture of reservoir oil and CO2 caused by the secondary displacing fluid. The phase equilibrium effects of a secondary displacing fluid are illustrated by the Figures. Figure 1 displays the phase equilibrium at constant temperature of crude oil from the Level land field in Texas with CO2. The equilibrium shows a liquid region 1, a liquid-liquid region 2, and a multiphase or multiple phase region 3. The multiphase region includes a vapor phase, a CO2-rich liquid phase, an oil-rich liquid phase, and can also contain a solid asphaltene phase.

Miscibility of crude oils with CO2 occurs only above a minimum pressure, known as the minimum miscibility pressure. Displacements performed at pressures above the minimum miscibility pressure in the liquid-liquid region 2 of Figure 1 are referred to as liquid-liquid displacements. Displacements performed at pressures in the multiphase pressure region 3 are referred to as multiphase pressure region displacements. Displacements at pressures above the MMP in the multiphase pressure region result in more efficient utilization of the injected displacing fluid, even though both displacements are miscible displacements. However, in contrast to the liquid-liquid pressure region, as is seen in Figure 1, the multiphase pressure region exists only over a defined pressure range indicated by lines 4 and 5.

The multiphase pressure region thus does not have to include a particular reservoir pressure, and a multiphase pressure region displacement is not possible in such reservoirs.

Figure 1 is considered representative of multiple phase equilibria between a crude oil and CO2. This type of equilibria exists for many oils. However, a different oil may display a phase equilibrium without the formation of multiple phases. Each reservoir crude oil thus has its own unique phase equilibrium with CO2 which should be determined because the phase equilibrium can determine the length required to develop miscibility. For example, the reservoir length required for a miscible displacement at pressures in the multiphase region 3 of Figure 1 is not as great as that for one performed in the liquid-liquid region 2 in Figure 1.

A secondary displacing fluid affects the phase equilibrium and reduces the length required to achieve multiphase miscibility. Applicants' copending application, "Miscible Flooding with Displacing Fluid Containing Additive Compositions," U.K. Patent Application No.8417051 incorporated by reference, describes alterations in the phase equilibrium of a mixture of a displacing fluid and crude oil resulting from the addition of an additive, such as the secondary displacing fluid of this invention, to the primary displacing fluid. The alterations in the phase equilibrium induced by the secondary displacing fluid are seen in Figure 2 which shows the phase equilibrium at constant temperature of a mixture of CO2 and a secondary displacing fluid with Levelland crude. Here, the secondary fluid is present as an additive to CO2, the primary fluid, and its presence results in the formation of multiphase region 7, which is much larger than the original multiphase region 3. Hereafter this type of secondary displacing fluid is referred to as an additive-type secondary displacing fluid, or as an additive. Use of the additive expands the multiphase region to exist over a larger pressure range shown by lines 8 and 9. Hence, the multiphase region now exists at constant temperature over a broader pressure range, indicated by dotted lines 8 and 9, than the range for multiphase region 3 of a mixture of only CO2 with oil.Although Figure 2 shows an expansion of the multiphase region which is mainly upwards in pressure, it is also possible that a particular additive will alter the equilibrium so that the multiphase region 7 is mainly adjusted to exist at lower pressure levels than the original multiphase region 3. Thus an additive-type secondary displacing fluid can adjust the phase equilibrium so that the multiphase region pressure range encompasses the reservoir pressure. This permits miscibility to be achieved in a shorter length to reduce residual oil saturation.

When using an additive-type secondary displacing fluid, the phase equilibrium of a mixture of a displacing fluid which contains an additive-type secondary fluid with a particular reservoir crude oil should be determined. This is necessary because the desired concentration of additive in the displacing fluid is that concentration sufficient to adjust the multiphase region of the phase equilibrium at reservoir temperature to include a particular reservoir's pressure. The phase equilibrium is then analyzed to determine whether a sufficient adjustment is achieved. For each additive-type secondary displacing fluid a range of additive concentrations sufficient to adjust the phase equilibrium can be present.This concentration range can be determined by noting first that a particular reservoir's temperature is constant, and second that only over a limited pressure range do multiple fluid phases exist at that temperature. Thus, all additive concentrations which, in a mixture of a displacing fluid with reservoir crude oil at a particular reservoir's temperature, can produce multiple phases at a pressure corresponding to the given reservoir's pressure are included in the concentration range. The concentration range can differ with each reservoir.

The concentration range can be determined by means of a slim-tube displacement test or a windowed cell apparatus, described in detail in "Multiple Phase Generation During CO2 Flooding," R.L.

Henry, R. S. Metcalfe, SPE/DOE Symposium on EOR, April 20-23, 1980, herein incorporated by reference.

For example, in a slim-tube test, the displacing fluid is injected into a sand-packed and oil-filled tube and the produced fluid phases are monitored.

One complication of a hydrocarbon displacement process is that the process cannot be observed in situ, and must be studied through simulation in the laboratory. Thus, the multiple-phase behavior observed in laboratory tests and described above is belived to occur in a reservoir undergoing flooding by the method of the invention. However, for purposes of the invention it is immaterial whether multiple phases do in fact form in the reservoir when primary and secondary displacing fluids according to the invention are injected. One aspect of the invention is to reduce injectivity losses by injecting a displacing fluid containing an additive-type secondary displacing fluid being in a sufficient concentration to form multiple phases at reservoir conditions according to phase behavior observed on the surface under simulated conditions.

For each reservoir more than one additive-type fluid can produce multiple phases at reservoir conditions. Each particular additive fluid has its own concentration range, because each additivecontaining displacing fluid has its own unique phase equilibria with reservoir oil. Thus, for a particular reservoir, the multiphase pressure range is not the same for different additive-containing displacing fluids. It accordingly follows that a choice of additives for adjusting the multiphase region is usually available.

The selection of a particular additive for use in a chosen reservoir depends on otherfactors. The additive selected first depends on whether the pressure range over which multiple phases occur exists at pressures above or below the reservoir pressure. For example, where the multiphase region exists below the reservoir pressure and must be adjusted upward, those additives more volatile than CO2 are employed to adjust the region to encompass the reservoir pressure. Additives more volatile than CO2 include, for example, methane, nitrogen, argon, and helium. If the multiphase region must be adjusted downward in pressure, an additive less volatile than CO2, such as, for example, LPG or propane, is used. Other factors include availability, cost, separation procedures for a given additive from the produced crude, and other economic considerations.

Because a range of additive concentrations sufficlient to adjust the phase equilibrium exists, more than one additive concentration can be used. This is an advantage of the invention since upsets within the reservoir and in the displacing fluid injection can occur with regularity. The displacement thus continues to be more efficient despite, for example, slight changes in the displacing fluid composition.

As a range of concentrations is available, the choice of the actual additive concentration to be used in the displacing fluid is based on considerations well-known to those skilled in the art. These considerations are the same as those referred to above for choosing the additive to be used.

Fluids useful as an additive-type secondary displacing fluid of the invention include, for example, hydrocarbons such as ethane, propane, LPG, butane and mixtures thereof; gases such as methane, nitrogen, flue gas, air, argon, helium and mixtures thereof; and other gases such as hydrogen sulfide and carbon monoxide. These fluids, or their components in the case of flue gas, are often found in petroleum reservoirs. Thus they do not have the disadvantage of a possible deleterious effect on the reservoir. In general, any additive which can adjust the multiphase region of the phase equilibrium can be used.

In another aspect of the invention, the secondary displacing fluid is of a different type since it does not reduce the reservoir length required for miscibility.

This type of secondary displacing fluid is contact miscible with oil and substantially displaces oil away from the injection well so that the area of higher oil saturation occurring after the initial immiscible displacement is farther from the injection well. This lessens subsequent water injection losses by effectively increasing the area of the face of the reservoir portion which contains higher oil saturation. Thus, more fluid can flow into the area of the reservoir having lower permeability.

Fluids useful as miscible-type secondary displacing fluids include, for example, benzene or refined oil. It should be noted that some fluids, such as ethane and other light hydrocarbons, can operate as either a miscible-type secondary displacing fluid or as an additive-type fluid.

However, any fluid capable of reducing residual oil saturation near the injection well, either through its effect on length requirements or through direct displacement of oil, or through other mechanisms, is within the scope of the invention.

The secondary displacing fluid can be injected either simultaneously with or before injecting the primary displacing fluid. Whether the secondary displacing fluid is injected with or prior to the primary displacing fluid depends on the type of secondary displacing fluid injected. For example, a miscible-type fluid such as benzene, which reduces residual oil saturation near the injection well by displacing oil, should be injected prior to the primary displacing fluids. An additive-type fluid such as methane or propane, for example, which reduces residual oil saturation by decreasing miscibility length requirements is injected simultaneously with the primary displacing fluid.

In carrying out the invention, it is believed only necessary to inject the secondary displacing fluid in conjunction with the first primary displacing fluid injection cycle and not during subsequent displacing fluid cycles. But it may be desirable to inject the secondary displacing fluid in later displacing fluid cycles.

The method of the invention is performed by injecting the secondary displacing fluid either prior to, simultaneously with, or after injection of the first displacing fluid injection of an alternate displacing fluid-water displacement process. The amount of secondary fluid injected varies according to the type of secondary displacing fluid used. The amount of miscible-type secondary displacing fluid required is less than the amount of additive type fluid. The amount of additive-type secondary displacing fluid is a sufficient amount of the secondary fluid to adjust the multiphase region of the phase equilibrium to encompass reservoir pressure at reservoir temperature.

However, a preferable amount of either type of secondary displacing fluid injected is about 1 to about 15% by volume, and more preferably about 10% by volume, of the amount of primary displacing fluid injected during the first displacing fluid injection cycle. The amount of primary displacing fluid injected in each injection cycle of an alternate displacing fluid-water injection is generally about 1 to about 5 percent of the reservoir pore volume (PV), and often about 1 to about 2 percent PV. Thus, the amount of secondary fluid injected will preferably be from about 0.1 to about 0.5 percent PV, and more preferably about 0.1 to about 0.2 percent PV. Smaller or larger amounts of secondary fluid may be also used, and the exact amount should be engineered for each reservoir application.

It is emphasized that it is not believed necessary to reinject the secondary displacing fluid during subsequent injection cycles. Rather, once miscibility has been generated and residual oil saturation is reduced near the wellbore, it is unnecessary to repeat the process. This offers a distinct advantage over techniques to reduce injectivity loss which require continuous treatment.

The following examples are presented to show the phase equilibrium effect of an additive-type secondary displacing fluid which results in the development of miscibility in a shorter reservoir length.

Example 1 Oil from the Levelland Field in West Texas is subjected to slim-tube displacement tests at a press ure of 1900 psig and a temperature of 106"F by injection of(1) CO2 and (2) a CO2-nitrogen mixture.

The minimum pressure required for miscible displacement (MMP) of the Levelland oil by pure CO2 at 106"F is determined to be 1175 psig. The maximum pressure at which multiple phases are observed with C 2 is 1600 psig. The Levelland reservoir pressure is 1900 psi, however, so the multiple phase region of the phase equilibrium does not exist at reservoir conditions.

When CO2 is diluted with 10 mole percent nitrogen to produce a 90 mole percent CO2, 10 mole percent N2 mixture, and the mixture is injected, the MMP is 1600 psig, and the maximum pressure at which multiple phases are observed is 3400 psig. The multiphase pressure range thus shifts upward in pressure and also increases from a spread of 425 psi to 1800 psi. The expansion of the multiphase region encompasses the reservoir pressure condition.

Example 2 A displacement test is performed in an eight-foot Berea core saturated with Level land crude oil at 1900 psi and 160 F. A displacement test is first performed with CO2. Oil recovery is determined to be 67 percent. This displacement is also determined to be immiscible through observation of produced fluids through a sight glass.

A second test using a 10 mole percent nitrogen and 90 mole percent CO2 injected fluid mixture shows 74 percent oil recovery in the same eight-foot core. Sight glass observations indicate that miscibility is generated. Residual oil saturation is also lower after this flood. The second run shows use of an additive-type fluid as the secondary displacing fluid of the invention. If water were subsequently injected, the reduction in water injectivity rates would be lessened due to the less adverse relative permeability effects of lower oil saturation.

It should also be noted that no attempt was made to minimize the length requirements for generation of miscibility. For example, it is possible that smaller or lesser amounts of nitrogen can achieve higher displacement efficiencies, and lesser lengths required to develop miscibility than 10 percent nitrogen.

The scope of the invention should not be determined from what has been described herein which is meant to be merely illustrative. Rather, the scope of the invention is given by the appended claims.

Claims (16)

1. A method for displacement of hydrocarbons through a hydrocarbon-bearing reservoir wherein displacing fluid is injected into the reservoir through an injection well penetrating the reservoir by a fluid injection sequence comprising: injecting into the reservoir a primary displacing fluid and a secondary displacing fluid, followed by injecting an aqueous fluid; and then alternately injecting a primary displacing fluid and an aqueous fluid.

2. A method according to Claim 1 further comprising injecting the secondary displacing fluid prior to injecting the primary displacing fluid.

3. A method according to Claim 1 wherein the secondary displacing fluid is injected simultaneously with the primary displacing fluid.

4. A method according to any preceding claim wherein the amount of secondary displacing fluid is about 0.1% to about 0.2% of the reservoir pore volume.

5. A method according to any preceding claim wherein the amount of secondary displacing fluid injected is about 10% of the amount of the primary displacing fluid injected in the first injection cycle.

6. A method according to any preceding claim wherein the primary displacing fluid is CO2.

7. A method according to any preceding claim wherein the secondary displacing fluid is selected from methane, ethane, propane, butane, LPG, nit rogen, flue gas, air, helium, hydrogen sulfide, carbon monoxide and mixtures thereof.

8. A method according to Claim 7 wherein the secondary displacing fluid is nitrogen.

9. A method according to any of Claims 1 to 6 wherein the secondary displacing fluid is contact miscible with reservoir hydrocarbons.

10. A method according to Claim 9 wherein the secondary displacing fluid is selected from benzene and refined oil.

11. A method for displacing hydrocarbons from a hydrocarbon-bearing subterranean reservoir which comprises injecting into the reservoir through an injection well penetrating the reservoir a fluid injection sequence comprising: (a) injecting a secondary displacing fluid in a volume corresponding to up to about 10 percent by volume of the volume amount of a subsequent primary displacing fluid injection; (b) injecting a primary displacing fluid; (c) injecting an aqueous fluid; and (d) repeating steps (b) and (c).

12. A method according to Claim 11 wherein the primary displacing fluid is carbon dioxide.

13. A method according to Claim 12 wherein the secondary displacing fluid concentration is about 10% by volume of the volume amount of CO2 injected.

14. A method according to any of Claims 11 to 13 wherein the secondary displacing fluid is selected from benzene or refined oil.

15. A method for preventing subsequent aqueous fluid injectivity losses in an alternating CO2-aqueous fluid injection into a hydrocarbonbearing reservoir comprising: (a) injecting into the reservoir through an injection well penetrating the reservoir a mixture of CO2 and a secondary displacing fluid, wherein the mixture comprising a sufficient amount of the secondary displacing fluid such that a multiple phase pressure region of a phase equilibrium of a mixture of the CO2 and the secondary displacing fluid with reservoir hydrocarbons encompasses reservoir pressure at a reservoir temperature; (b) injecting an aqueous fluid; (c) injecting CO2, and (d) repeating steps (b) and (c).

16. A method according to Claim 15 wherein the secondary displacing fluid is selected from nitrogen, methane, ethane, propane, and flue gas.