US3774684A - Hot fluid injection into hydrocarbon resevoirs - Google Patents

Abstract

Hot fluid may be injected into a subterranean hydrocarbon reservoir with little heat loss through the casing walls on the way down to the injection zone by placing tubing inside the casing of an injection well and injecting a hot fluid or vapor into the tubing and a cold fluid into the annulus between the tubing and casing.

Description

United States Patent 1191 Allen et al.

[ Nov. 27, 1973 HOT FLUID INJECTION INTO 1,237,139 8/1917 Yeomans 166/272 x "YDRQCARBON RESERVOIRS 3,456,730 7/1969 Lange 166/272 X 3,498,381 3 1970 13611611 1161, Jr. 166 303 [75] Inventors: Joseph C. Allen; Bellalre, Yick- 3,221,813 12/1965 CIOSIIBIIII et al..... 166/272'x Mow Shum, Houston, both of Tex. 3,386,512 6/1968 Bloom 166/303 3,380,530 4/1968 McConnell et al. 166 303 [73] Assignee: Texaco Inc., New York, NY

*Wnw Primary Examiner-Stephen .l. Novosad [22] 1972 Attomey-Thomas l-l. Whaley et al.

[21] Appl. No.: 229,927

[57] ABSTRACT [52 us. 01. 166 303 Hot fluid y be injected into a Subterranean y 51 Int. Cl E21b 43/24 carbon reservoir with little heat loss through the [58] Field 61 Search 166/303, 272, 302, s Walls on the y down to the injection zone y 166/305 R placing tubing inside the casing of an injection well and injecting a hot fluid or vapor into the tubing and a [56] a Cited cold fluid into the annulus between the tubing and UNITED STATES PATENTS 3,559,738 2 1971 Spillette 166 303 7 Claims, 3 Drawing Figures 3,186,484 6 1965 Waterman 166 272 x HOT FLU/D- "i 10 c010 FLU/D 3 I i EXTRANEOUS 1; FORMAT/0N5 3 1 8 1 i 4 i 4 f I Y L\\\ (YA/K t/2,, i #EYHYDRO- L; CARBON BEARING I V v e RESERVOIR A x/Q \r 'QQQ; [6,, l I

PATENTEB NOV 27 I975 COLD FLU/D EXTRANEOUS 4 FORMA T/ONS R S RV HYDEO v CARBON BEARING FIG 2 COMPARATIVE HEAT LOSSES k S L 0 lbboo HOT FLUID INJECTION INTO HYDROCARBON RESERVOIRS BACKGROUND OF THE INVENTION 1. Field of the Invention This invention is concerned with the field of secondary recovery of hydrocarbons from subterranean reservoirs by the injection of hot fluid into the reservoir.

2. Discussion of the Prior Art In many hydrocarbon producing areas there are reservoirs where production is no longer commercially feasible due to the fact that the original pressure in the hydrocarbon stratum has been exhausted to the extent that hydrocarbons will no longer move through the formation into production wells in sufficient quantities to permit profitable operation. Usually, however, these reservoirs in fact have more oil remaining in them than has been produced.

Also, many reservoirs contain very'viscous hydrocarbons. This high viscosity impedes flow and much of these viscous hydrocarbons are trapped in the reservoirs even while relatively high reservoir pressuresremain. Attempts to recover thesehydrocarbons have included the injection of a fluid into the reservoir to increase the pressure in the reservoir and displace the hydrocarbons to production wells where they are produced. These fluids are typically aqueous, gaseous, some hydrocarbon or a mixture of materials. It has been recognized that the temperature of the injected fluids have a great influence on the efficiency of the recovery process. The hydrocarbons in the reservoir will flow more readily if they are heated by'the injected fluid with a consequent reduction in their viscosity.

Therefore, it is often necessary and more efficient to inject a hot fluid into the-reservoir.

However, in the past, cost of heating the great volumes of injection fluids has'been inflated because of the great losses of heat from 'the hot injection fluid through the sides of the well intoextraneous'formations on the way down the injection well bore to thehy'clrocarbon formation of interest. Thus, it has previously been necessary to heat the injection fluids at the surface to much higher temperaturesthan is desired at the injection point. Attempts have been made to decrease the amount of injection fluid heat loss as it travels down the injection well to the point of injection. For instance, tubing may be installed in the injection well with devices to centralize it in'the well bore andprevent its contact with the casing where rapid heat conduction would increase the flow of heat from the injection fluid.

However, much heat is still lost through the tubing walls into the annularspaces between the tubing and casing and then to extraneous formations in the earth. Other methods such as insulation have also been attempted but leave much to be desired because of the expense involved.

Also, due to depths of some hydrocarbon formations pressure limitations are placed on surface injection facilities which prevent'hot enough fluid from-being injected at the surface.

SUMMARY OF THE INVENTION Our invention is a method of injecting a'hot fluid into a subterranean hydrocarbon reservoir with a minimum of heat loss from the injected fluid to' the extraneous formations which comprisesproviding tubular means inside of well casing and injecting coldfluid into the annular space between the tubular means and the casing wall while injecting a hot fluid into the tubular means. Both fluids being injected at such a rate that the cold fluid is heated by the hot fluid in the tubular means and reaches the desired temperature of injection at approximately the same time it reaches the depth of the hydrocarbon reservoir into which injection is to take place.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 depicts an arrangement whereby an open ended string of tubing penetrates a well wherein hot fluid may be injected into the tubing and cold fluid into the annular space between the tubing and the casing.

FIG. 2 compares the heat lost to the formations above the hydrocarbon zone of interest using prior art hot water injection techniques and the method of our invention as illustrated by FIG. 1.

FIG. 3 depicts an arrangement wherein a closed tubing arrangement is provided in the well so that the hot fluid may be circulated into the well and out without contacting the cold fluid injected into the annular space between the tubing and the casing.

DESCRIPTION OF THE PREFERRED EMBODIMENTS Our invention may be more clearly understood by referring to the attached figures which illustrate typical embodiments of our invention. FIG. 1 shows an injection wellpenetrating the earth with perforations in communication with a hydrocarbon bearing reservoir.

A single string of tubing '10 penetrates the well to a depth above the perforations 11. The tubing is open at the bottomandis therefore in communication with the other materialsin the well. Steam, for example, is injected into the tubing and cold water, for example, is

injected into the annular space between the tubing and casing. The rates of injection are adjusted so that water in the annular space heats up slowly and reaches the desired temperature .for injection just as the water reaches the depth of the perforations. In this manner a minimum of heat will be lost to extraneous formations above the hydrocarbon bearing reservoir of interest. The heat of the steam is used to heatthe water, and so long as the water remains cooler than the subterranean ambient temperatures no heat will be lost. In fact, heat will be added to' the water from the surrounding formations in the earth. Only when the temperature of the water exceeds the temperature of the surrounding formations will any heat be wasted. By heat conduction calculations known to those skilled in the art it will be possible to calculate the rate of steam and water injection to allow the water to travel the maximum distance into the earth before its temperature exceeds the temperature of the surrounding formations in'the earth. In this way a minimum amount of heat will be lost to extraneous earth formations. It is clear that this method providesa great savings in heat energy and thus a corresponding economic advantage as shown by the following illustration.

The total heat delivered to the hydrocarbon formation by water-steam injection was. calculated for two theoretical situations as noted below.

CASE I (PRIOR ART) Saturated steam, at 1000 psia, 545F., 80 percent quality and 270 barrels per day (BPD), was mixed with water, at 1000 psia, F and 260 BPD, adiabatically.

The resulting mixture, approximately 3 percent quality steam at 545F., 1000 psia, was injected into 2 "/s in. tubing suspended at 4000 feet in a well with 7 inch casing.

CASE II (IVIETHOD OF THE INVENTION) Using the same tubing and casing diameters, the heat delivered to the formation was calculated using the same steam and water properties given in Case I. However, in this case only steam was injected into the tubing and the water was injected into the tubing-casing annulus.

Results for each case are represented in FIG. 2 by plotting the heat lost to the overburden formation as a function of time. The heat loss from the well bore to the overburden formation was determined by standard mathematical techniques using a computer program. Theory and development of the calculation procedure is based on a quasi-steady-state method. Case II results were developed by standard mathematical techniques using a computer program. The energy is transferred from the hot fluid to the cold water in the annulus, and, subsequently to the overburden formations above the formation which accepts the injected fluid. FIG. 2 shows that the heat loss to the extraneous formations would be cut approximately in half using the method of our invention. Due to the transient nature of the problem, the principle of superposition was used to determine the thermal energy transferred from the water in the annulus to the overburden formations. Solutions were obtained using established energy balance equations with numerical iteration. Briefly the solution procedure was as follows:

1. Assume a T the outlet temperature of the injected steam at a rate of S (lb/hr).

Due to the large values of the convective heat transfer coefflcient and well depth, I-I (ft), the outlet temperature of the injected water, T would be equal to T 2. Thermal energy transfer calculation:

Thermal energy given up by the steam is Q, (T,, T,.,) S SH X (BTU/hr) 1 where H is the latent heat of the injected steam. (BTU/lb),

and X is the inlet steam quality.

Thermal energy gained by the injected water in the annulus is Qu: wo m) W where W is the water injection rate (lb/hr).

3. Thermal energy transfer from the water in annulus to the surrounding formation by conduction, is calculated as follows:

IOg A a0 a log oB azlog o B (1310810 8 a. log B 3 where A R F/KT, dimensionless heat flux.

B aJ/R dimensionless time,

a,,, 11,, a a a and a are constants,

R is the casing radius, ft.

K and a are the thermal conductivity (BTU/hr-ftF.) and diffusivity (ft /hr), respectively.

I is time, hr.

T is the temperature difference between the casing surface and the formation, F.

F is the heat flux, BTU/hr-ft. Then Q (4 where A is the casing surface area, ft. Due to the transient nature of this problem, the method of superposition must be employed as illustrated as follows:

a. At the end of the 1st time step, say t,,

wo ami. wm,l wi wo, 1) T is the average water temperature. 1 n fo) where T, is the ground surface temperature and T is the sand face formation temperature, F. F is calculated from equation (3) with T= T 1 T, and t= t, b. At the end of the 2nd time step, i.e., t= t t, t

wo wo. 2 wm. 2 wi wo. 2) The method of superposition says where F, is calculated with T= T 1 T,, and t F is calculated with T= T 2 T and t z, t and so on 4. An energy balance required If equation (5) can not be satisfied within a preset tolerance, a new value of T is selected and calculations from steps 1 to 4 are repeated. Otherwise, solution is advanced one time step by starting the calculation from step 1.

Some conditions may exist, however, which would prevent the convenient operation of the procedure illustrated by FIG. 1 above. FIG. 3 illustrates a procedure which is another typical embodiment of our invention. FIG. 3 is a closed tubing arrangement wherein all the benefits embodied in the open tubing arrangement of FIG. 1 are provided with the added feature of segregation between the hot fluid in the tubing and the cold fluid to be heated in the annular space between the tubing and casing. A large string of closed end tubing 10 penetrates a well 11 and a smaller string of open end tubing 12 penetrates the closed end string of tubing. A hot fluid, steam, for instance, is circulated down through the annular space 13 between the tubing strings and up through the small inside tubing string. A cold fluid, water, for instance, is injected down the annular space 14 between the large tubing strings and the well casing. This water is heated on the way down the well bore in the manner described in FIG. 1 by contacting the heated tubing string 10 and is injected into a hydrocarbon reservoir. Once again injection rates may be adjusted so that the water heats as slowly as possible and attains its desired temperature at the depth of the hydrocarbon formation in which it is to be injected. The method of FIG. 3 may be used in shallow formations where the temperature of the injected steam is limited to the injection pressure which is in turn limited by the shallow depth. Since injecting steam at an excess pressure to provide high temperature might lift the overburden thus rupturing the earth formations with harmful consequences known to those in the art of oil production, the open tubing arrangement of FIG. 1 cannot be desirable since the pressure of the steam is communicated to the earth formations. Also, where it is desired to inject superheated steam into a shallow formation the method of FIG. 3 would provide superheated steam at the hydrocarbon reservoir depth while injecting only saturated steam at the surface. For examnle mt dst 1 a 3 Pounds Pe 339%.? n is injected into the annulus 14. Saturated steam at 600 pounds per square inch is injected into the annulus 13 and circulates out through the small string of tubing 12. The 300 psi steam is superheated by the 600 psi steam without the high 600 psi pressure affecting the hydrocarbon reservoir. Thus, in the shallow formations high pressure which may rupture the formations will not have to be used in order to attain high fluid injection temperatures since the high pressure fluid in the closed circulating tubing arrangement is isolated from the formation. Another example with the open tubing embodiment of FIG. 1 would be inapplicable is where the hydrocarbon reservoir is very deep. Here the steam would be condensed to water for a considerable depth in the well. Thus, very high steam pressure would be necessary in order to maintain the desired rate of steam injection.

Also, the method of our invention allows a hotter fluid to enter the shallow formation than would be possible by injecting hot fluid from the surface. For example, consider a reservoir 600 feet below the surface. By a typical standard practice the overburden at 600 feet ssa a e t e 99 P nd EQS HQUQLQL pound per square inch per foot of depth. Above this pressure the formation is likely to fracture or rupture. At 600 feet the hydrostatic heat is 260 pounds per square inch. Thus, the maximum surface injection pressure is 600 minus 260 340 pounds per square inch. At this surface pressure the maximum temperature of water is 430F. and the heat content of the water is 408 BTU per pound. Heat losses on the way down would cause the water to enter the formation at an even lower temperature. However, using the method of our invention as depicted in FIG. 3 steam may be injected into the tubing strings as shown and water into the annulus between the large tubing and the casing. The water is injected into the formation at 486F. at 600 pounds per square inch since it picked up its heat on the way down and was not limited in temperature by the surface injection temperature and pressure. At 486F. the water enters the formation with a heat content of 471 BTU per pound. Two distinct advantages are apparent, the heat flow rate is increased by 15.4 percent and the material flow rate into the formation is increased by 14.5 percent over the surface heating of the water.

Heat flow rate increase:

4sa 4ao 471 408 Also, the basic advantage of our invention, the conservation of heat energy is also gained. The above example assumes for illustration purposes no heat loss of the water injected at 430F. at the surface when in fact there would be heat loss on the way to the formation. When this is taken into account an even greater advantage would be realized by using the method of our invention.

The method of our invention may be applied to any fluid or mixture of fluids such as hot solvents, hot gases, steam and hot water to name just a few. In each case the advantages are similar. Other mechanical arrangements are those shown in FIGS. 1 and 3 may be envisioned and still be within the scope of our invention. The types of reservoirs and hydrocarbons to which our invention is best suited are those in which hot fluids are more efficient than cold fluids for the recovery of hy drocarbons. Prior-art is replete with information concerning hot fluid injection and its advantages.

We claim:

1. A method for injecting a first fluid into a subterranean hydrocarbon reservoir via a cased well penetrating and in fluid communication with the reservoir wherein there exists tubular means inside and open at some point to the annular space between the tubular means and the casing wall and said first fluid is a mix ture of a second fluid injected down the tubular means and a liquid injected down the annulus comprising injecting said liquid into the annulus which liquid is initially at a temperature below the reservoir temperature,

injecting said second fluid into the tubular means at a temperature above the temperature of the reservoir before injection began in such a way that the cooler liquid in the annulus is heated by the fluid in the tubular means to a temperature in excess of the reservoir temperature at about the same time said liquid in the annulus reaches the depth of the hydrocarbon reservoir and injecting said first fluid into the hydrocarbon reservoir.

2. The method of claim 1 wherein said first fluid enters the reservoir as a liquid.

3. The method of claim 1 wherein said first fluid enters the reservoir partially or completely vaporized.

4. A method for injecting a first fluid into a subterranean hydrocarbon reservoir via a cased well penetrating the reservoir wherein there exists tubular means inside the well arranged to prevent fluid communication between the inside of the tubular means and the annular space between the tubular means and the casing wall and wherein said annular space is in fluid communication with the reservoir comprising injecting said first fluid as a liquid into the annular space between the tubular means and the casing wall which liquid is initially below reservoir temperature, I injecting a second fluid into the tubular means at a temperature above the reservoir temperature before injection began in such a way that said cooler first fluid in the annulus is heated by said second fluid in the tubular means to a temperature in excess of the reservoir temperature at about the same time said first fluid in the annulus reaches-the depth of the hydrocarbon reservoir and injecting said first fluid into the hydrocarbon reservoir. 5. The method of claim 4 wherein said first fluid enters the reservoir as a liquid.

contacting said liquid in the well bore with a fluid en-- cased in said tubular means wherein said fluid is at a temperature greater than the temperature of the hydrocarbon reservoir and said liquid is initially at a temperature less than the temperature of the hydrocarbon reservoir and wherein the liquid exceeds the reservoir temperature at about the time the liquid reaches the depth of the hydrocarbon reservoir.

Claims (7)

1. A method for injecting a first fluid into a subterranean hydrocarbon reservoir via a cased well penetrating and in fluid communication with the reservoir wherein there exists tubular means inside and open at some point to the annular space between the tubular means and the casing wall and said first fluid is a mixture of a second fluid injected down the tubular means and a liquid injected down the annulus comprising injecting said liquid into the annulus which liquid is initially at a temperature below the reservoir temperature, injecting said second fluid into the tubular means at a temperature above the temperature of the reservoir before injection began in such a way that the cooler liquid in the annulus is heated by the fluid in the tubular means to a temperature in excess of the reservoir temperature at about the same time said liquid in the annulus reaches the depth of the hydrocarbon reservoir and injecting said first fluid into the hydrocarbon reservoir.

2. The method of claim 1 wherein said first fluid enters the reservoir as a liquid.

3. The method of claim 1 wherein said first fluid enters the reservoir partially or completely vaporized.

4. A method for injecting a first fluid into a subterranean hydrocarbon reservoir via a cased well penetrating the reservoir wherein there exists tubular means inside the well arranged to prevent fluid communication between the inside of the tubular means and the annular space between the tubular means and the casing wall and wherein said annular space is in fluid communication with the reservoir comprising injecting said first fluid as a liquid into the annular space between the tubular means and the casing wall which liquid is initially below reservoir temperature, injecting a second fluid into the tubular means at a temperature above the reservoir temperature before injection began in such a way that said cooler first fluid in the annulus is heated by said second fluid in the tubular means to a temperature in excess of the reservoir temperature at about the same time said first fluid in the annulus reaches the depth of the hydrocarbon reservoir and injecting said first fluid into the hydrocarbon reservoir.

5. The method of claim 4 wherein said first fluid enters the reservoir as a liquid.

6. The method of claim 5 wherein said first fluid enters the reservoir partially or completely vaporized.

7. A method for heating a liquid injected into the most external annular space in an injection well bore containing tubular means wherein said annular space is in communication with a subterranean hydrocarbon bearing reservoir which comprises contacting said liquid in the well bore with a fluid encased in said tubular means wherein said fluid is at a temperature greater than the temperature of the hydrocarbon reservoir and said liquid is initially at a temperature less than the temperature of the hydrocarbon reservoir and wherein the liquid exceeds the reservoir temperature at about the time the liquid reaches the depth of the hydrocarbon reservoir.

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