CA2858095A1

CA2858095A1 - System and method for producing oil

Info

Publication number: CA2858095A1
Application number: CA2858095A
Authority: CA
Inventors: Richard Bruce Taylor; Carolus Petrus Adrianus Blom; Paulus Maria Boerrigter; Ralf Hedden
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2011-12-14
Filing date: 2012-12-13
Publication date: 2013-07-18
Also published as: WO2013106156A1; CN104011329A; EA201400697A1; EP2744976A1; US20130153228A1

Abstract

The present invention is directed to a system and a method for producing oil. An ether-containing formulation comprising an ether containing from 2 to 6 carbons is injected into a formation containing oil. An oil-immiscible formulation comprising water having a salt content of less than 5 wt.% is also injected into the formation. Oil is produced from the formation.

Description

SYSTEM AND METHOD FOR PRODUCING OIL
Field of the Invention The present disclosure relates to systems and methods for producing oil Background of the Invention Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means ¨ possibly extending the life of a field and boosting the oil recovery factor.
Thermal enhanced recovery works by adding heat to the reservoir. The most widely practiced form is a steam drive, which reduces oil viscosity so that it can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil. Polymer flooding improves the sweep efficiency of injected water. Miscible injection works in a similar way to chemical flooding¨by injecting a fluid that is miscible with the oil, trapped residual oil can be recovered.
Referring to Figure 1, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation 106 through well 112, to production facility 110. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.
WO 20081 41 051 discloses a system and a method for recovering oil and/or gas from an oil-bearing subterranean formation by injecting a miscible enhanced oil recovery ("EOR") formulation, which may comprise a dimethyl ether formulation, into the formation through a well located above the formation and producing oil and/or gas from the formation through a well. In one embodiment of the disclosed method, a quantity of the miscible EOR formulation is injected into an oil-bearing formation followed by injection of another component to force the miscible EOR
formulation across the formation. The component used to force the miscible EOR formulation across the formation may be an immiscible EOR formulation, where the immiscible EOR formulation may include water in gas or liquid form, air, nitrogen, mixtures of two or more of the preceding, or other immiscible EOR agents as are known in the art.
After injecting an ether-containing EOR formulation into a formation and mobilizing oil for production from the formation with the ether-containing EOR

formulation, residual oil may be left in the formation. The residual oil retains at least a portion of the ether from the ether-containing EOR formulation since ethers are miscible in the residual oil. A portion of the ether trapped in the residual oil may be recovered by an immiscible EOR formulation used to force the ether-containing formulation across the formation if the immiscible EOR formulation contains water, however, a substantial portion of the ether may be left in the residual oil if the ether is not particularly miscible with the immiscible EOR formulation.
There is a need in the art for improved systems and methods for enhanced oil recovery utilizing an ether in an EOR formulation. In particular, there is a need in the art for improved systems and methods for enhanced oil recovery using an ether-containing solvent to improve recovery of ether trapped in residual oil in the formation after injection of an ether-containing EOR formulation into the formation.
The recovered ether may be re-utilized in an EOR formulation for further recovery of oil from the formation.
Summary of the Invention In one aspect, the present invention is directed to a system for producing oil from an underground formation comprising a first well above the formation; a mechanism to inject a formulation comprising an ether containing from 2 to 6 carbons into the formation; a mechanism to inject an oil-immiscible formulation into the formation, where the oil-immiscible formulation has a salt content of at most 5 wt.% and is comprised of water having at most 5 wt.% salt content; and a mechanism to produce oil from the formation, wherein at least one of the mechanism to inject the formulation comprising an ether containing from 2 to 6 carbons, the mechanism to inject the oil-immiscible formulation, or the mechanism to produce oil from the formation is located at the first well.
In another aspect, the present invention is directed to a method for producing oil comprising injecting a formulation comprising an ether containing from 2 to 6 carbons into a formation containing oil; injecting an oil-immiscible formulation into the formation, where the oil-immiscible formulation comprises water having a salt content of less than 5 wt.%; and producing oil, an ether containing from 2 to carbons, and water from the formation.
Brief Description of the Drawings Figure 1 illustrates an oil and/or gas production system.
Figure 2a illustrates a well pattern.
Figures 2b and 2c illustrate the well pattern of Figure 2a during enhanced oil recovery processes.
Figure 2d illustrates a well pattern.
Figures 3a-3d illustrate oil production systems.
Figure 4 is a graph of the effect of salt concentration on the solubility of DME
in the aqueous phase at 6895 KPa.
Figure 5 is a graph of the effect of salt concentration on the vapor-liquid equilibrium of DME (mol fraction (x)) with water at 50 C.
Figure 6 is a graph of the effect of pressure in the liquid-liquid region on the solubility of DME in NaCL brines at 50 C.
Figures 7a and 7b are graphs showing the CPA-SALT model prediction of the effect of salt on DME solubility (mol fraction (x)) in water (lines) compared to experimental data (symbols) at 30 C. Figure 7a shows full scale of pressure and Figure 7b emphasizes vapor-liquid equilibria.
Figures 8a and 8b are graphs showing the CPA-SALT model prediction of the effect of salt on DME solubility (mol fraction (x)) in water (lines) compared to experimental data (symbols) at 50 C. Figure 8a shows full scale of pressure and Figure 8b emphasizes vapor-liquid equilibria.
Figure 9 is a graph showing the CPA-SALT model prediction of the effect of salt on DME solubility (mol fraction (x)) in water (lines) compared to experimental data (symbols) at 80 C and 120 C for a 10 wt.% NaCI brine.
Figure 10 is a graph showing the densities of the aqueous DME-Brine phase at 30 C (symbols represent the experimental data and the lines represent CPA-SALT model predictions).
Figure 11 is a graph showing the Densities of the aqueous DME-Brine phase at 50 C (symbols represent experimental data and lines represent CPA-SALT
model predictions).

Figure 12 is a graph showing the solubility of DME in Brines of Various Concentrations v. Temperature at a Fixed Pressure of 6895 KPa (1000 psi) (symbols represent experimental data and lines represent CPA-SALT model predictions).
Detailed Description of the Invention The present invention provides a system and a method for enhanced oil recovery from a formation containing oil using an ether-containing formulation comprising an ether containing from 2 to 6 carbon atoms to mobilize and produce oil from the formation, wherein the ether is recovered from residual oil not mobilized by the ether-containing formulation by injecting a low salinity oil-immiscible formulation comprising low salinity water having a salt content of at most 5 wt.% having a salt content of at most 5 wt.% into the formation, where the total salt content of the oil-immiscible formulation is at most 5 wt.%, and producing oil, an ether containing from 2 to 6 carbons, and water from the formation. The art discloses injecting an oil-immiscible formulation into a formation after the injection of a miscible formulation into the formation, where the oil-immiscible formulation may contain water and the miscible formulation may contain dimethyl ether. The salinity of the water is not limited therein, and, often, water used in an EOR waterflood has a relatively high salinity¨either because the water used is seawater or because produced water is re-injected, which has the salinity of the formation. Low molecular weight ethers such as dimethyl ether, however, partition more readily into low salinity water from the residual oil than into water having high salinity, therefore, more of a low-molecular weight ether may be recovered from residual oil using the system and method of the present invention.
The system of the present invention provides a first well located above an underground formation containing oil. The system also includes a mechanism to inject a formulation comprising an ether containing from 2 to 6 carbons into the formation, a mechanism for injecting an oil-immiscible formulation into the formation, where the oil-immiscible formulation has a total salt content of at most 5 wt.% and comprises water having a total salt content of at most 5 wt.%, and a mechanism for producing oil, an ether containing from 2 to 6 carbons, and water from the formation.
At least one of the mechanisms for injecting the ether-containing formulation into the formation, injecting the oil-immiscible formulation into the formation, and producing the oil, ether, and water from the formation is located at the first well.
In an embodiment of the system, the mechanisms for injecting the ether-containing formulation into the formation, injecting the oil-immiscible formulation into the formation, and producing the oil, ether, and water from the formation are located at the first well. In this embodiment, the ether-containing formulation may be injected into the formation for a period of time then, in a subsequent period of time, oil may be produced from the formation. Following production of oil from the formation after injection of the ether-containing formulation into the formation, the oil-immiscible formulation may be injected into the formation for a period of time, after which oil, an ether, and water may be produced from the formation.
In an embodiment of the system, the mechanism for injecting the ether-containing formulation and the mechanism for injecting the oil-immiscible formulation into the formation may be the same mechanism. The ether-containing formulation and the oil-immiscible formulation may be injected through the mechanism may be conducted sequentially or simultaneously. If the ether-containing formulation and the oil-immiscible formulation are injected simultaneously, the ether-containing formulation and the oil-immiscible formulation may be mixed together for co-injection through the mechanism for injecting the ether-containing formulation and the oil-immiscible formulation.
In another embodiment of the system, the system may include a second well.
The mechanism for injecting the ether-containing formulation into the formation, the mechanism for injecting the oil-immiscible formulation into the formation, and/or the mechanism for recovering oil, an ether, and water may be located at the second well.
In this embodiment, the ether-containing formulation may be injected into the formation at the first well for a period of time, followed by injection of the oil-immiscible formulation into the formation at the first well for a period of time. Oil, an ether, and water may be produced at the second well. Alternatively, the ether-containing formulation may be injected at the second well for a period of time followed by injection of the oil-immiscible formulation at the second well for a period of time, and oil, an ether, and water may be produced from the first well.
Alernatively, the ether-containing formulation and the oil-immiscible formulation may be injected simultaneously, preferably as a mixture, at the first or second well, and oil, an ether, and water may be produced from the first or second well, where the oil, ether, and water are produced from the first well if the ether-containing formulation and oil-immiscible formulation are injected at the second well or the oil, ether, and water may be produced from the second well if the ether-containing formulation and oil-immiscible formulation are injected at the first well. Alternatively, the ether-containing formulation may be injected into the formation at the first well, and, after a time period, the oil-immiscible formulation may be injected into the formation at the second well, and the oil, an ether, and water may be produced at the first well, or the ether-containing formulation may be injected into the formation at the second well, and, after a time period, the oil-immiscible formulation may be injected into the formation at the first well, and the oil, an ether, and water may be produced at the first well.
In another embodiment of the system, the system may include a third well.
The mechanism for injecting the ether-containing formulation into the formation may be located at the first well, the mechanism for injecting the oil-immiscible formulation may be located at the second well, and the mechanism for producing oil, an ether, and water may be located at the third well. The ether-containing formulation may be injected into the formation at the first well, the oil-immiscible formulation may be injected into the second well, and oil, an ether, and water may be recovered at the third well. The second well may be located relative to the first and third wells in a position so that at least a portion of the oil-immiscible formulation drives the ether-containing formulation towards the third well for producing and so that at least a portion of ether trapped in residual oil in the formation partitions into the oil-immiscible formulation for recovery at the third well.
Referring now to Figure 2a, in some embodiments, an array of wells 200 is illustrated. Array 200 includes a first well, included in first well group 202 (denoted by horizontal lines) and a second well, included in second well group 204 (denoted by diagonal lines).
Each well in first well group 202 may be spaced a horizontal distance and a vertical distance from adjacent wells in the first well group, where each horizontal distance between adjacent wells of the first well group 202 may be roughly equal and the vertical distance between adjacent wells of the first well group 202 may be roughly equal. Each well in first well group 202 may have a horizontal distance 230 from an adjacent well in first well group 202. Each well in first well group 202 may have a vertical distance 232 from an adjacent well in first well group 202.

Each well in the second well group 204 may be spaced a horizontal distance and a vertical distance from adjacent wells in the second well group, where each horizontal distance between adjacent wells of the second well group may be roughly equal and each vertical distance between adjacent wells of the second well group may be roughly equal. Each well in second well group 204 may have a horizontal distance 236 from an adjacent well in second well group 204. Each well in second well group 204 may have a vertical distance 238 from an adjacent well in second well group 204.
The wells of the first well group 202 have a distance from adjacent wells of the second well group 204. Each well in first well group 202 may have a distance from the adjacent wells in second well group 204. Each well in second well group 204 may have a distance 234 from the adjacent wells in first well group 202.
In some embodiments, each well in first well group 202 is surrounded by four wells in second well group 204. In some embodiments, each well in second well group 204 is surrounded by four wells in first well group 202.
In some embodiments, horizontal distance 230 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, vertical distance 232 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, horizontal distance 236 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, vertical distance 238 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, distance 234 is from about 5 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, array of wells 200 may have from about 10 to about 1000 wells, for example from about 5 to about 500 wells in first well group 202, and from about 5 to about 500 wells in second well group 204.
In some embodiments, array of wells 200 is seen as a top view with first well group 202 and second well group 204 being vertical wells spaced on a piece of land.
In some embodiments, array of wells 200 is seen as a cross-sectional side view with first well group 202 and second well group 204 being horizontal wells spaced within a formation.
Referring now to Figure 2b, in some embodiments, array of wells 200 is illustrated. Array 200 includes a first well included in a first well group 202 (denoted by horizontal lines) and a second well included in a second well group 204 (denoted by diagonal lines).
In some embodiments, an ether-containing formulation is injected into an oil-containing underground formation through mechanisms located at the second wells of the second well group 204, then, after injecting the ether-containing formulation into the formation or simultaneously with the injection of the ether-containing formulation, an oil-immiscible formulation having a salt content of at most 5 wt.% and containing water having a salt content of at most 5 wt.% is injected into the formation through mechanisms located at the second wells of the second well group 204, and oil, an ether, and water are produced from the formation through mechanisms located at the first wells of the first well group 202. The mechanisms for injecting the ether-containing formulation and the mechanisms for injecting the oil-immiscible formulation located at the second wells may be the same mechanisms. As illustrated, the ether-containing formulation and the oil-immiscible formulation have injection profile 208, and oil recovery profile 206 is being produced to first well group 202.
In some embodiments, an ether-containing formulation is injected into an oil-containing underground formation through mechanisms in the first wells of the first well group 202, then, after injecting the ether-containing formulation into the formation or simultaneously with injection of the ether-containing formulation, an oil-immiscible formulation having a salt content of at most 5 wt.% and containing water having a salt content of at most 5 wt.% is injected into the formation through mechanisms in the first wells of the first well group 202, and oil, an ether, and water are produced from the formation through mechanisms in the second wells of the second well group 204. The mechanisms for injecting the ether-containing formulation and the oil-immiscible formulation located at the first wells may be the same. As illustrated, the ether-containing formulation and the oil-immiscible formulation have injection profile 206, and oil recovery profile 208 is being produced to second well group 204.
In some embodiments, first well group 202 may be used for injecting an ether-containing formulation followed by an oil-immiscible formulation having a salt content of at most 5 wt.% and comprised of water having a salt content of at most 5 wt.%, and second well group 204 may be used for producing oil from the formation for a first time period; then second well group 204 may be used for injecting an ether-containing formulation followed by an oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.%, and first well group 202 may be used for producing oil from the formation for a second time period, where the first and second time periods comprise an injection cycle.
The ether-containing formulation may be injected for the first time period, and an oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected for the second time period .n some embodiments, the first time period may be the first 10% to about 80% of the injection cycle, or the first 20% to about 60% of the injection cycle cycle, the first 25% to about 40% of the injection cycle, and the second time period may be the remainder of the injection cycle.
Alternatively, the ether-containing formulation and the oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected into the oil-containing formation together.
The ether-containing formulation and the oil-immiscible formulation may be mixed on the surface above the oil-containing formulation and then injected together into the oil-containing formation. The ether-containing formulation and the oil-immiscible formulation may be injected separately at the surface above the oil-containing formation and mixed in the well prior to being injected into the oil-containing formation, or the ether-containing formulation and the oil-immiscible formulation may be injected separately at the surface above the oil-containing formation and mixed upon entering the formation.

Referring now to Figure 2c, in some embodiments, array of wells 200 is illustrated. Array 200 includes first wells included in a first well group 202 (denoted by horizontal lines) and second wells included in a second well group 204 (denoted by diagonal lines).
In some embodiments, an ether-containing formulation followed by or simultaneously with an oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% is injected into the formation at second wells of second well group 204, and oil, an ether, and water are produced from the formation at first wells of the first well group 202. As illustrated, the ether-containing formulation and immiscible water formulation have injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to first well group 202.
In some embodiments, an ether-containing formulation followed by or simultaneously with an oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% is injected into the formation at first wells of first well group 202, and oil, an ether, and water are produced from second wells of the second well group 204. As illustrated, the ether-containing formulation and oil-immiscible formulation have injection profile 206 with overlap 210 with oil recovery profile 208, which is being produced to second well group 204.
In some embodiments, an ether-containing formulation and an oil-immicsible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected together into the formation at first wells of the first well group 202 and oil, ether, and water may be produced from the formation at second wells of the second well group 204. Alternatively, an ether-containing formulation and an oil-immiscible formulation having a salt content of at most 5 wt.%
comprising water having a salt content of at most 5 wt.% may be injected together into an oil-bearing formation at second wells of the second well group 204 and oil,ether, and water may be produced at first wells of the first well group 202.
Referring now to Fig. 2d, in some embodiments, array of wells 200 is illustrated. Array 200 includes first wells in a first well group 202 (denoted by horizontal lines), second wells in a second well group 204 (denoted by diagonal lines), and third wells in a third well group 212 (denoted by vertical lines).

Each well in first well group 202 may be spaced a horizontal distance and a vertical distance from adjacent wells in the first well group, where each horizontal distance between adjacent wells of the first well group 202 may be roughly equal and the vertical distance between adjacent wells of the first well group 202 may be roughly equal. Each well in first well group 202 may have a horizontal distance 230 from an adjacent well in first well group 202. Each well in first well group 202 may have a vertical distance 232 from an adjacent well in first well group 202.
Each well in the second well group 204 may be spaced a horizontal distance and a vertical distance from adjacent wells in the second well group, where each horizontal distance between adjacent wells of the second well group may be roughly equal and each vertical distance between adjacent wells of the second well group may be roughly equal. Each well in second well group 204 may have a horizontal distance 236 from an adjacent well in second well group 204. Each well in second well group 204 may have a vertical distance 238 from an adjacent well in second well group 204.
Each well in the third well group 212 may be spaced a horizontal distance and a vertical distance from adjacent wells in the third well group, where each horizontal distance between adjacent wells of the third well group may be roughly equal and each vertical distance between adjacent wells of the third well group may be roughly equal. Each well in third well group 212 may have a horizontal distance 240 from an adjacent well in third well group 212. Each well in third well group 212 may have a vertical distance 242 from an adjacent well in second well group 204.
The wells of the first well group 202 may have a distance from adjacent wells of the second well group 204. Each well in first well group 202 may have a distance 234 from an adjacent well in second well group 204. Each well in second well group 204 may have a distance 234 from an adjacent well in first well group 202. The wells of the second well group 204 may have a distance from adjacent wells of the third well group 212. Each well in the second well group 204 may have a distance 244 from an adjacent well in the third well group 212. Each well in the third well group 212 may have a distance 244 from an adjacent well in the second well group 204.
The wells of the first well group 202 may have a distance from adjacent wells of the third well group. Each well in the first well group 202 may have a distance 244 from an adjacent well in the third well group 212. Each well in the third well group may have a distance 244 from an adjacent well in the first well group 202.

As shown in Fig. 2d, in some embodiments, each well in first well group 202 is surrounded by four wells in second well group 204. The four wells in the second well group may be, in turn, surrounded by eight wells of the third well group 212.
In this embodiment, mechanisms for producing oil, an ether, and water from the formation may be located at the wells of the first well group 202, mechanisms for injecting the ether-containing formulation into the formation may be located at the wells of the second well group 204, and mechanisms for injecting the oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% into the formation may be located at wells of the third well group 212.
The ether-containing formulation may be injected into the formation at the wells of the second well group 204 and the oil-immiscible formulation may be injected into the formation at the wells of the third well group 212, where the ether-containing formulation mobilizes oil for production at the wells of the first well group 202 and the oil-immiscible formulation drives the ether-containing formulation and the ether mobilized oil for production at the wells of the first well group while recovering an ether from residual oil for production at the wells of the first well group 202 along with a portion of the oil-immiscible formulation.
In some embodiments, horizontal distance 230 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, vertical distance 232 is from 5 to 1000 meters, or from to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, horizontal distance 236 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, vertical distance 238 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, horizontal distance 240 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.

In some embodiments, vertical distance 242 is from 5 to 1000 meters, or from to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, distance 234 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to meters, or from 90 to 120 meters, or100 meters. In some embodiments, distance 244 is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or meters. In some embodiments, distance 246 is greater than distance 244 and is from 5 to 1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100 meters.
In some embodiments, array of wells 200 may have from 10 to 1500 wells, for example from 5 to 500 wells in first well group 202, and from 5 to 500 wells in second well group 204, and from 5 to 500 wells in third group 212.
In some embodiments, array of wells 200 is seen as a top view with first well group 202, second well group 204, and third well group 212 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with first well group 202, second well group 204, and third well group 212 being horizontal wells spaced within a formation.
In an embodiment, an ether-containing formulation may be injected into the formation at second wells of the second well group 204. An oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected into the formation at third wells of the third well group 212 while the ether-containing formulation is injected into the formation or after the ether-containing formulation is injected into the formation. Oil, an ether, and water may be produced from the formation at first wells of the first well group 202.
As illustrated, the oil-immiscible formulation has an injection profile 214 that may overlap with the ether-containing formulation injection profile 208, and the ether-containing formulation injection profile may overlap with the oil recovery profile 206.
Preferably, the oil-immiscible formulation injection profile 208 may overlap both the DME formulation injection profile 208 and the oil recovery profile 206.
The system of the present invention may include a mechanism for producing an ether-containing formulation. The mechanism for producing an ether-containing formulation may convert a hydrocarbon into an ether having from 2 to 6 carbons by any known method for effecting such a conversion as known in the art. For example, a dimethyl ether formulation may be produced by a mechanism for converting a hydrocarbon into DME by any known method for conversion of a hydrocarbon into DME. In an embodiment, a mechanism for producing a dimethyl ether formulation may convert natural gas separated from the formation into synthesis gas, generate methanol from the synthesis gas, and produce the dimethyl ether formulation from the methanol. U.S. Patent Nos. 7,168,265; 7,100,692; and 7,083,662 disclose suitable methods for production of dimethyl ether from natural gas that may be utilized by the mechanism for producing the dimethyl ether formulation.
The mechanism for producing the ether-containing formulation may mix an ether containing from 2 to 6 carbons with one or more oil-miscible enhanced oil recovery agents to produce the ether-containing formulation. The one or more oil-miscible enhanced oil recovery agents that may be mixed with the ether to produce an ether-containing formulation may include methanol, carbon dioxide, C1-C6 hydrocarbons, nitrogen, naphtha solvent, asphalt solvent, kerosene, xylene, trichloroethane, and mixtures thereof.
The mechanism for producing the ether-containing formulation may include a mechanism for heating the ether-containing formulation to lower the viscosity of fluids in the formation. Conventional heating mechanisms may be used to heat the ether-containing formulation prior to injecting the ether-containing formulation into the formation.
The mechanism for producing the ether-containing formulation is preferably located at the same well where a mechanism for injecting the ether-containing formulation into the formation is located. For example, if a mechanism for injecting the ether-containing formulation into the formation is located at a well of the first well group 202 the mechanism for producing the ether-containing formulation may be located at the same well of the first well group 202.
The system of the present invention may include a mechanism for separating a mixture of an ether comprising from 2 to 6 carbons and water from oil produced by the mechanism for producing oil from the formation. The mechanism for separating a mixture of the ether and water from oil is preferably located at a well of the well group where a mechanism for producing oil from the formation is located. The mechanism for producing oil from the formation may produce the ether and water in addition to oil, where the ether and water may be separated from the oil produced from the formation by the mechanism for separating the ether and water from oil.
The mechanism for separating a mixture of an ether comprising from 2 to 6 carbons and water from oil produced from the formation may include a gas liquid separator for separating a gas-ether mixture from produced oil, a liquid portion of the ether, and water, a liquid-liquid separator for separating an oil liquid phase from an ether/water phase, and/or a scrubber for separating the ether from gas by washing the gas with water.
The system of the present invention may include a mechanism for providing an oil-immiscible formulation having a salt content of at most 5 wt.% that is comprised of water having a salt content of at most 5 wt.%. The mechanism for providing the oil-immiscible formulation may be located at one or more wells where a mechanism for injecting the oil-immiscible formulation is located. The mechanism for providing an oil-immiscible formulation may comprise a water source and a mechanism for removing salts from the water source. The mechanism for removing salts from the water source may be a conventional mechanism for desalting water, for example, a nanofiltration system utilizing one or more nanofiltration membranes, a reverse osmosis system utilizing one or more reverse osmosis membranes, a combination of nanofiltration and reverse osmosis membranes, or a distillation column for distilling water.
In the method of the present invention, an ether-containing formulation comprising an ether comprised of from 2 to 6 carbon atoms is injected into a formation containing oil, for example, an underground formation containing oil. The ether-containing formulation may be contacted with the oil in the formation to mobilize oil in the formation, where the mobilized oil may be produced from the formation. Mobilizing the oil leaves an oil residuum in the formation that contains a portion of the ether of the ether-containing formulation. An oil-immiscible formulation is injected into the formation, where the oil-immiscible formulation has a salt content of at most 5 wt.% and comprises water having a salt content of at most 5 wt.%.
The oil-immiscible formulation may drive the mobilized oil and ether-containing formulation across the formation for production, and separates a portion of the ether from the oil residuum into the oil-immiscible formulation by partitioning from the oil residuum into the water. Oil, the ether, and water are produced from the formation, where the oil may include the mobilized oil and the ether may include ether separated from the oil residuum by the oil-immiscible formulation.
Injecting the ether-containing formulation into the formation containing oil may be accomplished by any known method for injecting a liquid and/or a gas into a formation, depending on the state of the ether-containing formulation. One suitable method is injecting the ether-containing formulation into the formation through a conduit in a first well, allowing the ether-containing formulation to soak in the formation to mobilize oil therein, and then producing at least a portion of the mobilized oil and at least a portion of the ether by pumping the mobilized oil and the ether out of the formation through a conduit in the first well. Another suitable method is injecting the ether-containing formulation into the formation through a conduit in a first well, allowing the ether-containing formulation to mobilize oil in the formation, and producing at least a portion of the mobilized oil and at least a portion of the ether by pumping the mobilized oil and ether out of the formation through a conduit in a second well. The selection of the method used to inject the ether-containing formulation into the formation is not critical.
The amount of the ether-containing formulation injected into the formation may be an amount sufficient to mobilize oil in the formation for production from the formation. The amount of the ether-containing formulation injected into the formation may be from 0.05 to 0.75 of the formation pore volume, or from 0.1 to 0.5, or from 0.15 to 0.3 of the formation pore volume. The amount of the ether-containing formulation injected into the formation may be selected to be an amount sufficient to increase the mobility of the oil in the formation. The amount of the ether-containing formulation injected into the formation may be an amount selected to be sufficient to reduce the viscosity of the oil in the formation relative to the viscosity of the oil in the formation prior to injection of the ether-containing formulation into the formation. The amount of the ether-containing formulation injected into the formation may be selected to be an amount effective to reduce the bubble point of the oil in the formation.
The ether-containing formulation may be injected into the formation at a pressure greater than the formation pressure as measured immediately prior to injecting the ether-containing formulation into the formation. The ether-containing formulation may be injected into a formation at a pressure up to the fracture pressure of the formation. In some embodiments, the ether-containing formulation may be injected into the formation below the fracture pressure of the formation, for example from about 40% to about 90% of the fracture pressure of the formation. The ether-containing formulation may be injected into the formation at a pressure of from above 0 to 37,000 kilopascals above the formation pressure as measured immediately prior to injecting the ether-containing formulation into the formation.
The ether-containing formulation may be heated to lower the viscosity of fluids in the formation. The ether-containing formulation may be heated to a temperature of from 40 C to 275 C, or from 50 C to 200 C, or from 75 C to 150 C. The ether-containing formulation may be heated prior to being injected into the formation to lower the viscosity of fluids in the formation, for example heavy oils, paraffins, asphaltenes, etc. The ether-containing formulation may also be heated and/or boiled while within the formation by the use of a heated fluid or a heater to lower the viscosity of fluids in the formation. In some embodiments, heated water and/or steam may be used to heat and/or vaporize the ether-containing formulation in the formation. In some embodiments, the ether-containing formulation may be heated and/or boiled while within the formation with a heater. One suitable heater is disclosed in Canadian Patent No. 2503394.
The ether-containing formulation may be mixed in with oil in the formation to form a mixture which may be produced from the formation through a well. Mixing the ether-containing formulation with the oil in the formation may mobilize previously immobilized oil, where the mobilized oil/ether-containing formulation mixture is mobile in the formation and may move through the formation to a well from which the mixture may be produced from the formation, thereby enabling the previously immobilized oil to be produced from the formation. Mobilization and movement of previously immobilized oil through the formation by mixing the ether-containing formulation and the oil may leave residual oil in the formation. A portion of the ether from the ether-containing formulation may remain with the residual oil in the formation.
Injecting the oil-immiscible formulation into the formation may be accomplished by any known method for injecting a liquid and/or a gas into a formation, depending on the state of the oil-immiscible formulation. The oil-immiscible formulation may be injected into the formation after the ether-containing formulation is injected into the formation. In one embodiment, in a first time period the ether-containing formulation may be injected into the formation at a first well and allowed to soak in the formation to mobilize oil in the formation, and subsequently oil, and ether may be produced from the first well. Then, in a second time period subsequent to the first time period, the oil-immiscible formulation may be injected into the formation at the first well and allowed to soak in the formation to recover the ether from residual oil, and subsequently oil, ether, and water may be produced from the first well. In another embodiment, in a first time period the ether-containing formulation may be injected into a formation at a first well. Subsequently, in a second time period, the oil-immiscible formulation may be injected into the formation at the first well. Oil, ether, and water may be produced from the formation at a second well over the first and second time periods. The ether-containing formulation may be injected at the first well to mobilize oil in the formation to be driven for production at the second well. The oil-immiscible formulation may be injected at the first well to drive the mixture of the ether-containing formulation and mobilized oil through the formation for production at the second well. The oil-immiscible formulation may move through the formation from the first well to the second well and recover ether from residual oil in the formation for production at the second well.
In another embodiment, the ether-containing formulation and the oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected together into the oil-bearing formation at a first well and oil, ether, and water may be produced from the formation at a second well. Alternatively, the ether-containing formulation and the oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may be injected together into the oil-bearing formation at a second well and oil, ether, and water may be produced from the formation at a first well.
In another embodiment, the ether-containing formulation may be injected into a formation at a first well. Oil, ether, and water may be produced from the formation at a second well. The oil-immiscible formulation may be injected into the formation at a third well. The first, second, and third wells may be positioned in the formation so the ether-containing formulation mobilizes oil in the formation for production at the second well and the oil-immiscible formulation drives the ether-containing formulation and the mobilized oil through the formation for production at the second well, where the oil-immiscible formulation recovers ether from residual oil in the formation and may move through the formation for production of the recovered ether and water at the second well. The ether-containing formulation and the oil-immiscible formulation may be injected over the same time period from the first and third wells, respectively, or the ether-containing formulation may be injected into the formation at the first well for a first time period and the oil-immiscible formulation may be injected into the formation at the third well for a second time period, where the start of the second time period is subsequent to the start of the first time period. The amount of the oil-immiscible formulation injected into the formation may be an amount sufficient to drive a mixture of the ether-containing formulation and mobilized oil through the formation for production from the formation and/or to recover at least a portion of the ether from residual oil in the formation for production from the formation. The amount of the ether-containing formulation injected into the formation may be from 0.05 to 0.75 of the formation pore volume, or from 0.1 to 0.5, or from 0.15 to 0.3 of the formation pore volume or the amount of the ether-containing formulation may be at least equal the formation pore volume, or may be from 1 to 2.5 times, or from 1.1 to 2.0 times, or from 1.2 to 1.5 times the formation pore volume.
The volume ratio of the amount of the oil-immiscible formulation injected into the formation to the amount of the ether-containing formulation injected into the formation may be from 1.3 : 1.0 to 50 : 1, or from 3:1 to 15:1.
The oil-immiscible formulation may be injected into the formation at a pressure greater than the formation pressure as measured immediately prior to injecting the oil-immiscible formulation into the formation. The oil-immiscible formulation may be injected into a formation at a pressure up to the fracture pressure of the formation. The oil-immiscible formulation may be injected into the formation at a pressure of from above 0 to 37,000 kilopascals above the formation pressure as measured immediately prior to injecting the oil-immiscible formulation into the formation.
The oil-immiscible formulation may be heated . The oil-immiscible formulation may be heated to a temperature of from 40 C to 275 C, or from 50 C to 200 C, or from 75 C to 150 C. The oil-immiscible formulation may be heated prior to being injected into the formation. The oil-immiscible formulation may also be heated while within the formation by the use of a heated fluid or a heater.
Production of oil and the ether from the formation may be accomplished by any known method. Suitable methods include subsea production, surface production, secondary, or tertiary production. The selection of the method used to produce the oil and ether from the underground formation is not critical.
Referring now to Figures 3a and 3b, in some embodiments of the invention, system 300 is illustrated. System 300 includes underground formation 302, underground formation 304, underground formation 306, and underground formation 308. Facility 310 is provided at the surface. Well 312 traverses formations 302 and 304, and has openings in formation 306. Portions 314 of formation 306 may be optionally fractured and/or perforated. During primary production, oil and gas from formation 306 is produced into portions 314, into well 312, and travels up to facility 310. Facility 310 then separates gas, which is sent to gas processing 316, and liquid, which is sent to liquid storage 318. Facility 310 also includes ether-containing formulation storage 330 and oil-immiscible formulation storage 332. As shown in Figure 3a, the ether-containing formulation may be pumped down well 312 that is shown by the down arrow and pumped into formation 306. In an embodiment of the method of the present invention, the ether-containing formulation may be injected into the formation through well 312 to mobilize and drive oil in the formation to a production well for production from the formation. The oil-immiscible formulation having a salt content of at most 5 wt.% comprising water having a salt content of at most 5 wt.% may then be injected into the formation through well 312 immediately after completion of injection of the ether-containing formulation into the formation to recover ether from residual oil and to drive oil and ether in the formation to a production well for production from the formation.
Alternatively, the ether-containing formulation may be left to soak in formation 306 for a period of time from about 1 hour to about 15 days, for example from about to about 50 hours. During the soak period, the ether-containing formulation may mix with and mobilize oil in the formation 306. After the soaking period, as shown in Figure 3b, a mixture of the mobilized oil and the ether-containing formulation may then be produced back up well 312 to facility 310 as shown by the up arrow.
After producing the mixture of mobilized oil and the ether-containing formulation, as shown in Fig. 3a, the oil-immiscible formulation may be pumped down well 312 as shown by the down arrow and pumped into formation. The oil-immiscible formulation may be left to soak in formation 306 for a period of time from about 1 hour to about 15 days, for example from about 5 to about 50 hours. During the soak period the oil-immiscible formulation may contact residual oil in formation 306 and extract ether from the residual oil. After the soaking period, as shown in Fig. 3b, the oil-immiscible formulation along with any ether extracted from the residual oil is then produced back up well 312 to facility 310 as shown by the up arrow.
Alternatively, the ether-containing formulation and the oil-immiscible formulation may be injected together into the formation through well 312 to drive oil and ether to the production well for production from the formation.
Facility 310 is adapted to separate oil from the ether and water recovered from the formation. Separation may be effected by facility 310, for example, by phase separation, washing, scrubbing, or distillation. The separated ether and water may be re-injected into the formation as a portion of the ether-containing formulation by re-injection into well 312.
In some embodiments, well 312 as shown in Figure 3a injecting into formation 306 may be representative of a well in well group 202, and well 312 as shown in Figure 3b producing from formation 306 may be representative of a well in well group 204.
In some embodiments, well 312 as shown in Figure 3a injecting into formation 306 may be representative of a well in well group 204, and well 312 as shown in Figure 3b producing from formation 306 may be representative of a well in well group 202.
Referring now to Figure 3c, in some embodiments of the invention, system 400 is illustrated. System 400 includes underground formation 402, formation 404, formation 406, and formation 408. Production facility 410 is provided at the surface.
Well 412 traverses formation 402 and 404 has openings at formation 406.
Portions of formation 414 may be optionally fractured and/or perforated. As oil is produced from formation 406 it enters portions 414, and travels up well 412 to production facility 410. Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418. Production facility 410 is able to produce and/or store an ether-containing formulation, which may be produced and stored in production / storage 430. Dimethyl ether, diethyl ether, and/or other ethers from well 412 may be sent to ether-containing formulation production / storage 430.
Facility 410 also is able to produce and/or store an oil-immiscible formulation, which may be produced and/or stored in production/storage 440.
An ether-containing formulation is injected into formation 406 by pumping the ether-containing formulation down well 432 to portions 434 of formation 406.
The ether-containing formulation traverses formation 406 to aid in the production of oil by mobilizing oil in formation 406 for production at well 412, and then the ether-containing formulation and oil may be produced at well 412 to production facility 410.
The ether-containing formulation may then be recycled, for example by separating the ether-containing formulation from the oil by phase separation, or distilling or flashing the mixture of oil and ether containing formulation then re-injecting the ether-containing formulation into well 432.
After injection of the ether-containing formulation into the formation 406 down well 432, or together with the ether-containing formulation, the oil-immiscible formulation is injected into formation 406 by pumping the oil-immiscible formulation down well 432. The oil-immiscible formulation traverses formation 406 to drive the mixture of the ether-containing formulation and the mobilized oil for production at well 412. The oil-immiscible formulation extracts ether left in residual oil by the passage of the ether-containing formulation through the formation, and the mixture of the oil-immiscible formulation and ether extracted from residual oil are produced at production well 412.
In some embodiments, well 412 which is producing oil is representative of a well in well group 202, and well 432 which is being used to inject the ether-containing formulation and the oil-immiscible formulation is representative of a well in well group 204.
In some embodiments, well 412 which is producing oil is representative of a well in well group 204, and well 432 which is being used to inject the ether-containing formulation and the oil-immiscible formulation is representative of a well in well group 202.
Referring now to Figure 3d, in some embodiments of the invention, system 500 is illustrated. System 500 includes underground formation 502, formation 504, formation 506, and formation 508. Production facility 510 is provided at the surface.
Well 512 traverses formation 502 and 504 has openings at formation 506.
Portions of formation 514 may be optionally fractured and/or perforated. As oil is produced from formation 506 it enters portions 514, and travels up well 512 to production facility 510. Gas and liquid may be separated, and gas may be sent to gas storage 516, and liquid may be sent to liquid storage 518. Production facility 510 is able to produce and/or store an ether-containing formulation, which may be produced and stored in production / storage 530. Dimethyl ether, diethyl ether, and/or other ethers from well 512 may be sent to ether-containing formulation production / storage 530.
Facility 510 also is able to produce and/or store an oil-immiscible formulation, which may be produced and/or stored in production/storage 540.
An ether-containing formulation is injected into formation 506 by pumping the ether-containing formulation down well 532 to portions 534 of formation 506.
The ether-containing formulation traverses formation 506 to aid in the production of oil by mobilizing oil in formation 506 for production at well 512, and then the ether-containing formulation and oil may be produced at well 512 to production facility 510.
The ether-containing formulation may then be recycled, for example by separating the ether-containing formulation from the oil by phase separation, or distilling or flashing the mixture of oil and ether containing formulation then re-injecting the ether-containing formulation into well 532.
After intial injection of the ether-containing formulation into the formation down well 532 , the oil-immiscible formulation is injected into formation 506 by pumping the oil-immiscible formulation down well 542 to portions 544 of formation 506. The oil-immiscible formulation traverses formation 506 to drive the mixture of the ether-containing formulation and the mobilized oil for production at well 512. The oil-immiscible formulation extracts ether left in residual oil by the passage of the ether-containing formulation through the formation, and the mixture of the oil-immiscible formulation and ether extracted from residual oil are produced at production well 512.
In some embodiments, well 512 which is producing oil is representative of a well in well group 202, and well 532 which is being used to inject the ether-containing formulation is representative of a well in well group 204 and well 542 which is being used to inject the oil-immiscible formulation is representative of a well in well group 212.
In some embodiments, ether from the ether-containing formulation is produced from the formation with oil. In some embodiments, water from the oil-immiscible formulation is produced from the formation with oil and the ether from the ether-containing formulation.
In some embodiments, oil produced may be transported to a refinery and/or a treatment facility. The oil may be processed to produce commercial products such as transportation fuels including gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil to produce one or more distillate fractions. In some embodiments, the oil, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.
The ether-containing formulation utilized in the system and method of the present invention comprises an ether containing from 2 to 6 carbon atoms. The ether-containing formulation may comprise one or more ethers selected from the group consisting of dimethyl ether, diethyl ether, methyl tertiary butyl ether, ethyl tertiary butyl ether, tertiary amyl methyl ether, methyl ethyl ether, dimethoxymethane, and polydimethoxymethane. The ether-containing formulation may comprise from 5 to 100 wt.% of the one or more ethers, or may comprise from 10-95 wt.%, or from 25-90 wt.%, or from 40-85 wt.%, or at least 50 wt.%, or at least 75 wt.%, or at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt.%, or 100 wt.% of the one or more ethers. In an embodiment, the ether-containing formulation may comprise from 5 to 100 wt.%, or from 10-95 wt.%, or from 25-90 wt.%, or from wt.%, or at least 50 wt.%, or at least 75 wt.%, or at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt., or 100 wt.% dimethyl ether.
The ether-containing formulation may contain other non-ether components.
The ether containing-formulation may contain water, nitrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, and hydrocarbons other than ethers including:
glycols such as mono-ethylene glycol, di-ethylene glycol, tri-ethylene glycol, and tetra-ethylene glycol; ethanol, methanol, or other alcohols, acetals, polyols, methyl isobutyl carbinol, butyl propionate, methyl acetate, ethyl acetate, tertiary butyl acetate, or other esters, methyl ethyl ketone, methyl isobutyl ketone, acetone, or other ketones, dimethyl carbonate, diethyl carbonate, octane, pentane, LPG, C2-aliphatic hydrocarbons, diesel, mineral spirits, naphtha solvent, asphalt solvent, kerosene, xylene, and/or trichloroethane. Any water in the ether-containing formulation may have a salt content that is at least 1 wt.%, or at least 2 wt.%, or at least 5 wt.%, or at least 10 wt.% greater than the salt content of the oil-immiscible formulation.
The oil-immiscible formulation used in the system and method of the present invention has a salt content of at most 5 wt.% and is comprised of water having a salt content of at most 5 wt.%. The oil-immiscible formulation may comprise at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt.% water having a salt content of at most 5 wt.%. In an embodiment, the oil-immiscible formulation consists of water having a salt content of at most 5 wt.%. The water of the oil-immiscible formulation has a salt content of at most 5 wt.%, and may have a salt content of at most 3 wt.%, or at most 2 wt.%, or at most 1 wt.%. The water of the oil-immiscible formulation may be in gas or liquid form. The oil-immiscible formulation may include suitable oil-immiscible components mixed with the water of the oil-immiscible formulation including air and/or nitrogen.
To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.
The scope of the invention is to be defined by the claims appended hereto.
EXAMPLE
Experiments were conducted to determine the impact of salt on the solubility of DME in water. The solubility of DME in brines of 3, 10, and 20 wt% NaCI and in fresh water (0 wt.% NaCI) were measured at pressures of 3.4 MPa (500 psi), 6.9 MPa (1000 psi), and 10.3 MPa (1500 psi) along 20 C and 50 C isotherms. The solubility of DME in 10 wt.% NaCI was measured at pressures of 3447 KPa (500 psia), 6895 KPa (1000 psia), and 10342 KPa (1500 psia) for use as a basis for validation of extrapolation to higher temperatures. The experimental protocol is summarized in Table 1.

T[t]
P [psia] 30 50 80 120 1000 11=111111111111=1111111ilililililililil LLE, Subsurface PVT

Vr.:c4Rt$ItOtWggPIRMIOildiriEffina VLE and VLLE, Surface facilities Vapor-liquid equilibrium (VLE) data were measured as a first step of the liquid-liquid equilibrium measurements. A weighed brine solution was added to an autoclave and warmed to the selected temperature with stirring. After the brine solution reached thermal equilibrium, vapor was withdrawn from the autoclave into a weighed trap to remove light gases such as nitrogen or carbon dioxide. After the solution returned to temperature, the pressure was measured by a pressure transducer. The temperature and pressure were logged at ten second intervals by computer.
Aliquots of a measured volume of degassed dimethyl ether (DME) were then added to the autoclave from the pump. After the pressure and temperature stabilized, the pressure was measured. Aliquots of DME were then added to the brine mixture until a second liquid phase formed (the pressure no longer changes upon addition of DME). The pressure at this condition was also measured.
The data to this point consisted of masses of brine and DME (calculated from the volume) added to the autoclave and the resulting equilibrium pressure.
These values, along with the cell volume, temperature, and critical properties of water and DME, were used to derive equilibrium liquid and vapor compositions by using a flash algorithm and an activity coefficient equation. A non-random two liquid equation was selected to model the liquid phase non-idealities. Liquid densities required by the flash routine were measured or taken from published brine densities, and vapor densities were calculated from the Peng-Robinson equation of state.
Once a second liquid phase rich in DME was present, the stirrer was turned off and the contents of the autoclave were allowed to settle. Then aliquots of the lower liquid phase were slowly drawn into a weighed sample receiver. This sample receiver was connected to an empty, weighed gas bag. During sampling, most of the DME in the sample flashed out of the brine sample and flowed into the gas bag.
The brine mixture in the sample receiver was stirred by an explosion-proof magnetic stirrer to help the DME flash out. The receiver was also thermostatted at 30 C
to provide a consistent condition for the final state of the samples.
After the sample was taken, the receiver and gas bag were allowed to equilibrate for ten to twenty minutes. Then the sample receiver and gas bag were both weighed. The buoyant effect of the atmosphere on the gas bag was included to determine the actual mass of DME collected in the bag.

The amount of DME still dissolved in the brine sample at 30 C and atmospheric pressure was determined from the measured vapor-liquid equilibrium data. A small correction was also made for the amount of water vapor that left the sample receiver and was collected in the gas bag. Normally, four samples were taken at a given condition, with the first being a purge and not included in the average reported in the tables in this report. The standard deviation of the other three samples was usually less than one percent of the average DME
concentration.
Rarely, the DME concentration in one of the samples would differ from the other two measurement by more than 2%. In this case, an additional sample was withdrawn and processed.
After the measurement of the concentration of DME in the lower liquid phase at the vapor-liquid-liquid equilibrium pressure was completed, additional DME
was added until the autoclave became liquid full. The pressure was then raised in the autoclave to 3437 KPa (500 psia) by adding additional DME to the vessel. At this point, a constant pressure was maintained as the contents of the autoclave were stirred. After stirring vigorously for twenty to thirty minutes, the stirrer was turned off and the aqueous and DME-rich phases in the autoclave were allowed to separate.

Then aliquots of the lower liquid (aqueous) phase were removed and analyzed as described above. Solubility data were also measured in the same manner at 6895 KPa (1000 psia) and 10342 KPa (1500 psia).
After the liquid phase analyses were completed, the density of the lower liquid phase was measured in a densimeter. The densimeter was calibrated using nitrogen and boiled, deionized water. The nitrogen calibrations were performed at the selected temperature and atmospheric pressure. A hand pump was used to calibrate with water over the full range of pressure encountered during the measurements. The density of water was taken from the equation of state and database maintained by the National institute for Standards and Technology (NIST).
The calibration constants were developed from the measured frequency data as a function of temperature and pressure.
A set of samples was taken to determine the amounts of salt in the lower liquid phase at 50 C, 17% brine, and the vapor-liquid-liquid equilibrium (VLLE) composition. These samples were taken into weighed vials and then evaporated to dryness. The two lower liquid samples averaged 17.0 0.1 wt% salt.

A second set of samples were taken of the upper liquid phase at 30 C, 20%
brine, and 10342 KPa (1500 psia) to determine if a measureable amount of salt was in the upper liquid phase. These samples were also taken into vials and evaporated to dryness. No measureable salt was found in the upper liquid phase.
The experimental technique was validated by comparing the measured DME
solubility in fresh water at 50 C to published experimental data. Comparison for vapor-liquid and vapor-liquid-liquid equilibria indicated that the results of the experimental technique correlated well with published experimental data. There was no published data available for DME solubility in water at 50 C in the liquid-liquid region although the experimental liquid-liquid equilibrium data correlated with published liquid-liquid equilibrium data at higher temperatures (100 and 121 C). The impact of pressure on the solubility of DME in water does not vary significantly in this temperature range (50 to 121 C): the solubility of DME increases from 15.4mol%

(interpolated value) to 16.7mol% between 5000 and 10000 KPa at 50 C, it increases between 12.3mol% and 13.7mol% at 100 C in the same interval of pressure.
The DME solubility data measured experimentally is summarized in Figures 4-6, where the salt concentration is reported on a gas-free basis. Dimethyl ether was strongly salted out by sodium chloride. At 30 C the solubility of DME in the aqueous phase decreases from 17.4 mol% in fresh water to 3.71 mol% in a 20 wt.% brine.

This effect is shown in Figure 4 at 6895 KPa (1000 psia) in the liquid-liquid region for different temperatures. In the low pressure vapor-liquid region the presence of salt enhances the volatility of DME as shown in Figure 5.
Increasing pressure increases the solubility of DME in fresh water from 14.6 mol% to 16.8 mol% at 50 C (between 3347 KPa and 10342 KPa (150 and 1500 psia)). As brine concentration increases, the pressure effect on solubility becomes less pronounced as shown in Figure 6. This is due to the increasing density of the brine with salt concentration.
The Cubic-Plus-Association (CPA) equation of state model was extended to account for the effect of salt on the solubility of DME in the aqueous phase, and ultimately on its partitioning between brine and oil at reservoir conditions.
CPA is available in Unisim Design through SPPTS 3.0 and subsequent versions. A
hypothetical component, SALT, was introduced into the model system to account for the effect of salt concentration on DME solubility. Parameters describing water-SALT interactions and thus characterizing the brine, were adjusted to the boiling point elevation, freezing point depression, and hydrate point depression data for NaCI brines. The parameters describing the interactions of SALT with DME were adjusted to the experimental data provided above. The quality of the predictions are shown in Figures 7a, 7b, 8a, 8b, and 9 over the whole range of conditions (vapor-liquid and liquid-liquid) and pressures (up to 10000 KPa).
Temperature-dependent interaction parameters (ko and k1) for use in the CPA-SALT model were regressed from data at temperatures ranging from 30 C to 120 C. The ko and k1 parameters correspond to CPA binary interaction parameters BCPAO and BCPAOT.
The CPA-SALT model also predicts the densities of the DME-brine phase with reasonable accuracy as shown in Figures 10 and 11. The average deviation for all measured data points was 2.5%.
The solubility of DME in brines was plotted versus temperature at various brine concentrations in Figure 12. The CPA-SALT model was used to predict the solubility of DME in the remaining brines at high temperatures. The agreement between model predictions and experimental data at lOwt.% salt is excellent.
The effect of salt on the partitioning of DME between oil and aqueous phases was predicted based on the CPA-SALT model, a key input to estimating DME
efficiency as an EOR solvent. The model predicted that the partition coefficient of DME would increase by a factor 4 between fresh water and a 20wt. /0 NaCI
brine.
The prediction indicated that less DME can be injected in a single phase slug with highly concentrated brines since the efficiency of DME should increase due to the preferential partitioning into the oil enhanced by the presence of salt.
The CPA-SALT model was used to predict the impact of the presence of salt on the partitioning of of DME between oil and aqueous phases. Predicted partitioning was found to increase by a factor 4 between the limiting case of fresh water and a 20wt. /0 NaCI Brine at 50 C (oil was modeled as nC16). Due to its reduced solubility in brine, less DME can be injected in a one-phase slug, but the higher partitioning allows for better miscibility of the DME in oil. The predicted partitioning also indicates that DME may be recovered from residual oil using water having a low salt content to recover DME from the residual oil, particularly in formations containing water having a relatively high salt content.
The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. While compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of" or "consist of" the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, "from a to b,"
or, equivalently, "from a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value "about" the specified lower limit and/or the specified upper limit.
Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles "a" or "an", as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

Claims

1. A system for producing oil from an underground formation comprising:
a first well above the formation;
a mechanism to inject an ether-containing formulation comprising into the formation,where the ether-containing formulation comprises an ether containing from 2 to 6 carbon atoms;
a mechanism to inject an oil-immiscible formulation into the formation where the oil-immiscible formulation has a salt content of at most 5 wt.% and is comprised of water having at most 5 wt.% salt content; and a mechanism to produce oil from the formation, wherein at least one of the mechanism to inject the ether-containing formulation into the formation, the mechanism to inject an oil-immiscible formulation into the formation, or the mechanism to produce oil from the formation is located at the first well.

2. The system of claim 1 wherein the ether-containing formulation comprises from 5-100 wt.%, or from 10-95 wt.% , or from 25-90 wt.%, or from 40-85 wt.%, or at least 50 wt.%, of at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt.%, or 100 wt.% dimethyl ether.

3. The system of claim 1 or claim 2 wherein the oil-immiscible formulation comprises at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt.%, or is 100 wt.% water having a salt content of at most 5 wt.%.

4. The system of claim 1 or any of claims 2-3 wherein the oil-immiscible formulation is comprised of water having a salt content of at most 3 wt.%, or at most 2 wt.%, or at most 1 wt.%.

5. The system of claim 1 or any of claims 2-4, further comprising a second well at a distance from the first well, wherein the mechanism to inject the ether-containing formulation into the formation is located at the first well and the mechanism to produce oil from the formation is located at the second well.

6. The method of claim 5 wherein the mechanism to inject the oil-immiscible formulation into the formation is located at the first well.

7. The system of claim 5, further comprising a third well at a distance from the first well and at a distance from the second well wherein the mechanism to inject the ether-containing formulation into the formation is located at the first well and the mechanism to inject the oil-immiscible formulation into the formation is located at the third well.

8. The system of claim 1 or any of claims 2-7 wherein the mechanism for injecting the oil-immiscible formulation into the formation is configured to inject the oil-immiscible formulation into the formation after the ether-containing formulation is initially injected into the formation by the mechanism for injecting the ether-containing formulation into the formation.

9. A method for producing oil, comprising:
injecting an ether-containing formulation into a formation containing oil, where the ether-containing formulation comprises an ether containing from 2 to 6 carbons;
injecting an oil-immiscible formulation into the formation, where the oil-immiscible formulation comprises water having a salt content of less than 5 wt.%; and producing oil from the formation.

10. The method of claim 9 further comprising the steps of:
contacting the ether-containing formulation with oil in the formation to mobilize oil in the formation wherein mobilizing the oil leaves an oil residuum containing an ether in the formation; and contacting the oil-immiscible formulation with the oil residuum and separating a portion of the ether from the oil residuum into the oil-immiscible formulation.

11. The method of claim 9 or claim 10 wherein the ether-containing formulation comprises from 5-100 wt.%, or from 10-95 wt.%, or from 25-90 wt.%, or from 30-85 wt.%, or from 40-80 or at least 80 wt.%, or at least 85 wt.%, or at least 90 wt.%, or at least 95 wt.%, or 100 wt.% dimethyl ether.

12. The method of claim 9 or any of claims 10-11 wherein the oil-immiscible formulation comprises at least 80 wt.%, or at least 90 wt.%, or at least 95 wt.%, or at least 97 wt.%, or is 100 wt.% water having a salt content of at most 5 wt.%.

13. The method of claim 9 or any of claims 10-12 wherein the oil-immiscible formulation is comprised of water having a salt content of at most 3 wt.%, or at most 2 wt.%, or at most 1 wt.%.

14. The method of claim 9 or any of claims 10-13 wherein the ether-containing formulation comprises one or more hydrocarbons other than the ether, carbon dioxide, carbon monoxide, nitrogen, or mixtures thereof.

15. The method of claim 9 or any of claims 10-14 wherein the ether-containing formulation comprises the ether and water, where the water in the ether-containing formulation has a salt content at least 1 wt.% greater than the salt content of the oil-immiscible formulation.

16. The method of claim 9 or any of claims 10-15 wherein the oil-immiscible formulation is injected into the formation after initially injecting the ether-containing formulation into the formation.