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Publication numberUS3288214 A
Publication typeGrant
Publication dateNov 29, 1966
Filing dateJun 25, 1963
Priority dateJun 25, 1963
Publication numberUS 3288214 A, US 3288214A, US-A-3288214, US3288214 A, US3288214A
InventorsWinkler Adolf K
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Water/steam injection in secondary recovery
US 3288214 A
Abstract  available in
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

Nov. 29, 1966 A. K. WINKLER 3,288,214


s 0 V Q 467F f 15 o v g *20/.. :9 Q R v ix 0? ENTHALPY, BTU/LB FIG. 2

INVENTOR= HIS ATTORNEY United States Patent 3,288,214 WATER/ STEAM INJECTION IN SECONDARY RECOVERY Adolf K. Winkler, The Hague, Netherlands, assignor to Shell Oil Company, New York, N.Y., a corporation of Delaware Filed June 25, 1963, Ser. No. 290,553 3 Claims. (Cl. 166-40) This invention relates to the secondary recovery of hydrocarbons from hydrocarbon-bearing subterranean formations. More particularly, the invention is directed to a method for recovering hydrocarbons from subterranean formations wherein a hot fluid is introduced into the formation to reduce the viscosity of hydrocarbons therein. Reducing the viscosity of hydrocarbons within a formation facilitates the production of the hydrocarbons since it increases their ability to flow and, as a result, decreases the energy required to drive the hydrocarbons out of the formation and into the production well or wells, from which they are produced.

It is known in the art to use steam as a hot fluid to be introduced into a formation for the recovery of hydrocarbons present in such a formation. In this use, when passing through the pores between the grains of the formation, at least part of the steam condenses. The use of steam for this purpose is advantageous since the temperature of the injected fluid will not decrease until the total amount of the steam has condensed and, thus the temperature of the zone through which the injected fluid passes will be as high as possible. A further advantage of injecting steam into a formation is that the pore space which has been left by displaced hydrocarbons is filled to a certain extent with steam, whereby a steam cap is formed, thus providing a pre-ssurizing effect in the formation.

The injection of steam for secondary recovery purposes has the disadvantage, however, that the water used for creating the steam must be very pure in order to avoid fouling of the generator used to create steam. In addition to fouling the steam generator, impurities in the feed water may also function to foul and clog the hydrocarbon-bearing formation being treated. Although impurities may be removed from the feed water by various means, such means greatly increase the cost of a steam treating process, particularly where available water contains large amounts of impurities. The use of steam injection for secondary recovery also has the disadvantage that relatively large conduits are required to conduct the steam into the formation being treated and that heat losses from these conduits reduce the economy of the injection, unless relatively extensive insulation means are used. The use of such insulation means has the disadvantage that it increases both the size and cost of the apparatus required to support the steam injection process.

It is recognized that some of the aforementioned shortcomings of steam injections have been overcome by thermal-recovery processes utilizing hot water injection rather than steam injection. Hot water injection processes naturally avoid the necessity for large conduits as required in steam injection and as a result avoid the thermal-insulation requirement to a great extent. Furthermore, since the water in hot water injection processes is maintained so as to avoid flashing into steam, the deposit of impurities from the water presents no serious fouling problems. The injection of hot water without steam flashing has the disadvantage, however, that the formation being treated will not be as effectively heated as it would with steam injection, since the latent heat of vaporization of steam is not utilized to raise the formation to a relatively uniform high temperature. Hot water injection without steam flashing also has the disadvantage that a steam cap is not formed to provide a pressurizing effect in the formation, as it is with steam injection processes.

It is an object of the present invention to provide a thermal-secondary-recovery process wherein the advantages of each of the above described processes are maintained while their disadvantages are avoided.

With respect to the above object, it is another object of the invention to provide a thermal-secondary-recovery process wherein aqueous hot fluids are injected into at producing formation without the necessity of purifying these fluids prior to their heating in order to avoid deposits that might foul heat generating equipment and the formation.

Yet another and more specific object of the invention is to provide a thermal-secondary-recovery process wherein a hot aqueous liquid is injected into a formation under condition-s that will effect a predetermined degree of flashing of the liquid to steam.

It has been found that the above and other objects may be attained by a method wherein a hot aqueous liquid is injected into a formation at a temperature at which its vapor pressure exceeds the ambient pressure of the formation. The method includes heating an aqueous liquid to a temperature at which its vapor pressure exceeds the ambient pressure of the formation, said heating being carried out at a pressure at which substantially no vaporization of the liquid occurs. The heating is controlled so that a predetermined amount of vaporization will occur when the liquid is exposed to formation pressure, said vaporization being limited to an amount which will maintain impurities within the liquid in solution after such vaporization. After the liquid is so heated, it is introduced into a conduit leading to the formation and injected into the formation through said conduit. In its more specific embodiments, the liquid may be throttled to formation pressure either at the time it is injected int-o the formation or within the conduit prior to the time it is injected into the formation.

The enumerated and other objects and the details of the inventive method will become apparent when viewed in light of the following detailed description and accompanying illustrations, wherein:

FIGURE 1 diagrammatically illustrates a vertical section of a formation penetrated by a well facilitated to carry out the method of the invention; and

FIGURE 2 illustrates a pressure-enthalpy diagram exemplifying the invention.

Referring now to FIGURE 1, therein is illustrated a vertical section of a portion of the earth having a permeable oil-'bearing formation 10 located therein with relatively impermeable formations 11 and 12 located thereabove and therebelow, respectively. A well 13 is formed into the earth to a depth wherein it penetrates the oil-bearing formation 10 and has extending therethrough a casing string 14 provided with a perforated section adjacent to the formation 10. The perforations in the casing string 14 are designated by the numerals 15 and are typically formed through the use of perforating charges, as are well known in the well completion art.

To facilitate the method of the present invention, an injection string 16 extends through the casing string 14 to a location wherein its lower extremity is located adjacent to the perforated end of the casing string. The injection string is sealingly received within the casing string through means of a casinghead 17 at the upper extremity of the casing string and a packer 20 located in the casing string at a position slightly above the oil-bearing formation 10. Typically, the injection string will be concentric with the casing string and the packer 20 will sealingly fill the annulus between the casing and injection string.

The injection string 16 forms a part of a conduit to convey hot aqueous fluid into the formation 10. The balance of the conduit includes a pipe or conduit 21 extending between the injection string 16 and a heat exchanger 22. The conduit extending between the heat exchanger 22 and the formation includes a throttling valve 23 which is preferably adjustable. Although the throttling valve is illustrated as being interposed in the pipe 21, it is to be understood that the valve could be located anywhere in the conduit formed by the pipe 21 and injection string 16. The alternative locations for the valve 23 will be developed more completely in the subsequent description of the operation of the method of the invention.

The heat exchanger 22 is supplied with feed Water through means of a pump 24, which pump is supplied with Water through a conduit 25 communicating with a Water storage reservoir (not illustrated). The pump 24 and the heat exchanger 22 are designed to pressurize water being heated in the exchanger to an extent wherein little or no vaporization will occur within the exchanger. Through this arrangement, water being fed into and heated within the exchanger remains liquid until it expands through the throttling valve 23. Thus, any impurities in the water will remain in solution throughout the passage of the water through the heat exchanger and the conduit leading to the throttling valve. The numeral 26 in FIGURE 1 designate-s a heating conduit leading into the heat exchanger 22. The conduit 26 is merely intended to be diagrammatic and, typically, would convey gas to burners within the heat exchanger.

In operation of the system as shown in FIGURE 1, water is pumped from the reservoir by means of the pump 24 to the heat exchanger 22, in which it is heated and passed to the pipe 21. The pressure created by the pump 24 is suificient so that under conditions prevailing in the heat exchanger 22, no, or substantially no, vaporization of the water passing through the exchanger takes place. Heating in the exchanger is controlled so that a predetermined amount of vaporization will occur when the water is exposed to the pressure of the formation to he treated, said vaporization being limited to an amount which will maintain impurities within the water in solution after such vaporization. As the water passes through the throttling valve 23 in the pipe 21, the pressure is reduced to a point where the water vaporizes substantially to the predetermined degree.

After expansion through the throttling valve 23, the Water/steam mixture leaving the valve passes into the injection string 16. During the downward passage of the mixture through the injection string 16, the pressure in the mixture Will increase due to the weight of the column of fluid present in the injection string. The pressure prevailing at the bottom of the injection string is the injection pressure at which the mixture of steam and water passes into the oil bearing formation 10.

If desired, the throttling valve 23 can be arranged anywhere in the pipe 21 or injection string 16. However, if the valve is not arranged in the pipe 21, it has been found preferable to mount it at the lower extremity (i.e., outlet) of the injection string 16. With the latter arrangement, the pipe 21 as well as the injection string 16 will be filled with water under pressure during operation of the method, which water will partially vaporize sub stantially to the predetermined degree upon leaving the lower end of the injection string as a result of pressuredecrease.

Upon leaving the lower end -or outlet of the injection string 16, the water/steam mixture enters the section of the casing string below the packer 20 and passes therefrom through the perforations into the oil-bearing formation 10. During passage of the Water/steam mixture into the formation, a further reduction in pressure takes place. In those :parts of the formation Where the temperature is sufliciently high, i.e., in the vicnity of the Well where the formation has already been heated, this further reduction in pressure may give rise to further evaporation of the injected hot water. Furthermore, it is possible that the pressure drops occurring in the lower end of the well and in the formation in the immediate vicinity of the well may be such that fluid injected into the formation in the form of water may partially evaporate.

Upon introduction of the steam/ water mixture into the formation 10, the mixture passes through the pores between the grains of the formation, thereby heating the hydrocarbons present in the formation and reducing their viscosity. Due to the heat transfer taking place between the mixture and the formation containing the hydrocarbons, as well as between the mixture and the formations 11 and 1 2 above and below the formation 10, conensation of a substantial part of the steam present in the mixture takes place. The condensate so formed accumulates with the hot water which forms part of the mixture. Through this condensation, the amount of steam produced with hydrocarbons produced from the formation 10 is minimized, as will be developed subsequently.

In a single hydrocarbon-bearing formation, as the formation 10, injection as illustrated with the arrangement in FIGURE 1 may take place at more than one location. The hydrocarbons which are displaced in the formation 10 by means of the water/ steam mixture may be produced through various alternative arrangements. For example, production wells may be spaced downstream from the injection well and hydrocarbons driven to these production wells by the injected water/steam mixture may be produced therefrom. In this case it is noted that the amount of steam produced from the production wells is minimized, since most, if not all, of the steam is condensed within the formation prior to the time the injected mixture reaches the production wells. In another way of producing hydrocarbons with the present invention, the steam/water mixture is injected via an injection string into the upper part of a hydrocarbon-containing formation, while at the same time hydrocarbons are produced from the lower part of I this formation through the same well used for injection passes through the packer in a fluidtight manner.

via a production string suspended in this well. In this case a packer is arranged within the casing string between the lower end of the injection string and the lower end of the production string and the production string Other production arrangements, as are known to those skilled in the art, may also be used without departing from the method of the invention.

Reference is now made to FIGURE 2, wherein a pressure enthalpy diagram exemplifies the method of the present invention. At this point it is noted that with water having a typical amount of impurities therein, vaporization within the formation would generally be limited to between 10 and 25% by weight to maintain these impurities in solution. It is to -be understood, however, that situations may arise Where a greater or lesser degree of vaporization proves practical, as can be determined experimentally. Once the pressure of the formation has been established and the desired degree of vaporization has been determined, the conditions of temperature and pressure which must be created in the heat exchanger 22 (i.e., before expansion) can be thermodynamically determined, since in the practice of the invention substantially all liquid must be present in the heat exchanger. Specifically, the temperature and pressure in the heat exchanger (i.e., before expansion) should correspond substantially to saturated liquid at an enthalpy equal to that of the desired mixture at formation pressure (i.e., pressure after expansion into the formation).

The situation exemplified in FIGURE 2 is ideal and may vary slightly from actual practice,.since it has been assumed that heat losses are negligible, which means that the enthalpy of the system is constant (i.e., an adiabatic process). Under the circumstances exemplified by FIG- URE 2, the pressure of the formation being treated was established as being 500 p.s.i.a. and the desired amount of vaporization of water injected into the formation was determined as being 20%. With this information, it was first necessary to determine the enthalpy of water which would vaporize 20% at the formation pressure of 500 p.s.i.a. To make this determination it was merely neces sary to add 20% of the difference in enthalpy between saturated vapor and saturated liquid at 500 p.s.i.a. to the enthalpy of saturated liquid at 500 p.s.i.a. From FIG- URE 2 it can be seen that figured in this manner the enthalpy of water vaporized to the desired degree at formation pressure would be 600.4 B.t.u.s per lb. With this information, and assuming that expansion takes place at constant enthalpy, it is merely necessary to determine the temperature and pressure of saturated liquid at an enthalpy of 600.4 B.t.u.s per lb. to determine the temperature and pressure conditions which must be created and maintained within the heat exchanger 22. In this case, as can be seen from FIGURE 2, the pressure and temperature requirements were determined as being 1413 p.s.i.a. and 588 F., respectively.

To summarize, the present invention is directed to an improved thermal-recovery process of the steam-type wherein the expenses of pure water generally necessitated by steam injection are alleviated. Specifically, by heating the injected fluid in liquid form and maintaining the fluid in largely liquid form after injection, impurities within the fluid remain in solution and do not deposit out to foul either the heat exchanger utilized to 'heat the fluid or the formation into which the fluid is injected. In addition to alleviate the necessity for high purity water, the present invention also avoids the large conduits and heat losses encountered in conventional steam injection process.

In conclusion, it is noted that the present invention is not intended to be limited to the specific apparatus described with reference to FIGURE 1 or the specific example set forth in FIGURE 2. For example, the tube type heat exchanger illustrated is not intended to be limiting, but rather any heat exchanger capable of withstanding the pressure requirements of the method could be used. Furthermore, various casing string and tubing string arrangements, as are Well known to those skilled in the well completion art, could he used Without materially departing from the invention. The exact conditions represented in FIGURE 2 are merely intended to illustrate those that might exist during a particular appli- 6 cation of the invention. It is believed apparent that the steps used to arrive at the conditions of pressure and temperature in the heat exchanger of the example could equally well be applied to situations wherein conditions within the formation being treated vary considerably from those of the example. Therefore, various changes in the details of the described method may be made, within the scope of the appended claims, without departing from the spirit of the invention.

I claim as my invention:

1. A method of reducing the viscosity of hydrocarbons Within a hydrocarbon-bearing earth formation, comprismg:

(a) heating an aqueous liquid containing impurities at a pressure at which substantially no vaporization of the liquid occurs to a temperature which will cause it to vaporize at formation pressure to a predetermined degree selected so that the impurities within the liquid will remain in solution therewith after vaporizing to said predetermined degree, said temperature and pressure corresponding substantially to saturated liquid at an enthalpy equal to that of the desired mixture at formation pressure;

(b) introducing said liquid into a conduit leading to the formation; and

(c) injecting said liquid into the formation through said conduit.

2. A method according to claim 1 wherein the liquid is throttled to formation pressure at the time it is injected into the formation.

3. A method according to claim 1 wherein the liquid is throttled substantially to formation pressure within the conduit prior to the time it is injected into the formation.

References Cited by the Examiner UNITED STATES PATENTS 1,237,139 8/1917 Yeomans 16611 1,491,138 4/1924 Hixon l66-ll 3,186,484 6/1965 Waterman 166-11 X CHARLES E. OCONNELL, Primary Examiner. S. I. NOVOSAD, Assistant Examiner.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3,288,214 November 29,-, 1966 Adolf K. Winkler It is hereby certified that error appears in the above numbered patent requiring correction and that the said Letters Patent should read as corrected below.

In the heading to the printed specification, after line 7, insert Claims priority, Great Britain, July 26,

Signed and sealed this 12th day of September 1967.

( AL) Attest:

ERNEST W. SWIDER Attesting Officer EDWARD J. BRENNER Commissioner of Patents

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US1237139 *Jan 13, 1917Aug 14, 1917 Method of and apparatus for extracting oil from subterranean strata
US1491138 *Apr 18, 1921Apr 22, 1924Hixon Hiram WMethod of stripping oil sands
US3186484 *Mar 16, 1962Jun 1, 1965Beehler Vernon DHot water flood system for oil wells
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3385359 *Sep 29, 1966May 28, 1968Shell Oil CoMethod of producing hydrocarbons from a subsurface formation by thermal treatment
US3465826 *Oct 19, 1967Sep 9, 1969Gulf Research Development CoHigh-temperature water injection
US3499488 *Nov 30, 1967Mar 10, 1970Texaco IncSecondary oil recovery process using steam
US5979549 *Oct 29, 1997Nov 9, 1999Meeks; ThomasMethod and apparatus for viscosity reduction of clogging hydrocarbons in oil well
US6129148 *Sep 21, 1999Oct 10, 2000Meeks; ThomasMethod for viscosity reduction of clogging hydrocarbons in oil well
WO1999022115A1Aug 20, 1998May 6, 1999Thomas MeeksMethod and apparatus for viscosity reduction of clogging hydrocarbons in oil well
U.S. Classification166/303
International ClassificationE21B43/16, E21B43/24
Cooperative ClassificationE21B43/24
European ClassificationE21B43/24