METHOD AND SYSTEM FOR IMPOSING PRESSURE ON A WELLBORE PACKER
United States Patent 3592264
This specification discloses a method and system for increasing the hydrostatic pressure of a packer liquid on the upper side of a wellbore packer. A manometer-type fluid piston is used to increase the hydrostatic pressure by a predetermined amount.
US Patent References:
/1012777.html
Wigle - December 1911 - 1012777
Oil-well pump
McMahon - September 1927 - 1642121
Method for producing hydrocarbons in an in situ combustion operation
Ten Brink - December 1961 - 3013609
/3126950.html
Carlberg et al. - March 1964 - 3126950
Process and apparatus for producing crude oil from separate strata
Whipple - January 1968 - 3361202
/1012777.html
Wigle - December 1911 - 1012777
Oil-well pump
McMahon - September 1927 - 1642121
Method for producing hydrocarbons in an in situ combustion operation
Ten Brink - December 1961 - 3013609
/3126950.html
Carlberg et al. - March 1964 - 3126950
Process and apparatus for producing crude oil from separate strata
Whipple - January 1968 - 3361202
Application Number:
04/828914
Publication Date:
07/13/1971
Filing Date:
05/29/1969
View Patent Images:
Export Citation:
Primary Class:
Other Classes:
166/243, 166/67, 166/244.100, 417/99
International Classes:
E21B33/12; E21B33/12
Field of Search:
166/244,302,303,314,315,57,67,68,101,191,243,114--116 103/1,75,165 417/54,55,92,99
Primary Examiner:
Calvert, Jan A.
Claims:
What I claim is
1. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well, a system adapted for the application of pressure on the upper side of said packer comprising:
2. The combination of claim 1 further comprising an inlet opening into said fluidtight compartment adjacent the upper end thereof whereby liquid may be introduced into said compartment independently of said confined passageway.
3. The combination of claim 1 further comprising; a gas outlet opening from said compartment through said closure means whereby gas may be evacuated from said compartment concomitantly with the introduction of liquid thereinto.
4. A system for applying pressure on the upper side of a packer set at a first region in a wellbore to seal the annulus formed between inner and outer conduits, comprising:
5. The system of claim 4 wherein the upper portion of said first tubular member is flared to form a reservoir of increased volume.
6. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well and a closure sealing said annulus at a second region above said first region whereby a fluidtight compartment is formed within said annulus, a method for applying pressure on the upper side of said packer comprising:
7. The method of claim 6 wherein said second liquid has a specific gravity of at least twice that of said packer liquid.
8. The method of claim 6 wherein said second liquid is immiscible with said packer liquid.
9. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well, a system adapted for the application of pressure on the upper side of said packer comprising:
10. The combination of claim 9 wherein said second liquid has a specific gravity of at least twice that of said packer liquid.
1. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well, a system adapted for the application of pressure on the upper side of said packer comprising:
2. The combination of claim 1 further comprising an inlet opening into said fluidtight compartment adjacent the upper end thereof whereby liquid may be introduced into said compartment independently of said confined passageway.
3. The combination of claim 1 further comprising; a gas outlet opening from said compartment through said closure means whereby gas may be evacuated from said compartment concomitantly with the introduction of liquid thereinto.
4. A system for applying pressure on the upper side of a packer set at a first region in a wellbore to seal the annulus formed between inner and outer conduits, comprising:
5. The system of claim 4 wherein the upper portion of said first tubular member is flared to form a reservoir of increased volume.
6. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well and a closure sealing said annulus at a second region above said first region whereby a fluidtight compartment is formed within said annulus, a method for applying pressure on the upper side of said packer comprising:
7. The method of claim 6 wherein said second liquid has a specific gravity of at least twice that of said packer liquid.
8. The method of claim 6 wherein said second liquid is immiscible with said packer liquid.
9. In a well having inner and outer conduits therein defining an annulus and having a packer in said annulus at a first region of said well, a system adapted for the application of pressure on the upper side of said packer comprising:
10. The combination of claim 9 wherein said second liquid has a specific gravity of at least twice that of said packer liquid.
Description:
BACKGROUND OF THE INVENTION
This invention is directed to a method and system for increasing the hydrostatic pressures exerted by packer liquids. More specifically, this invention concerns the use of a manometer-type fluid piston in a wellbore to increase the pressure exerted by a packer liquid on a packer set in a wellbore.
Packer liquids are used to impose a hydrostatic pressure on the upper or wellhead side of a packer which has been set, for example, between production tubing and casing of a wellbore. Packer liquid use is particularly important when packers are set above high pressure formations. The hydrostatic pressure imposed by the packer liquid on the upper side of the packer opposes the formation pressure existing on the lower or formation side of the packer and thus aids in maintaining the packer in place.
Drilling mud in use in the wellbore when the packer is set is often left in the annulus above the packer to serve as a packer liquid. The properties of drilling muds are usually such that they are not completely satisfactory as packer liquids. For example, the muds may be corrosive, thus causing tubing and casing failure. Also weighting materials and other chemicals used in the drilling muds may segregate from the liquid carrier and settle to the lower portion of the well, thus interfering with the pulling of the packer and causing expensive workovers.
SUMMARY OF THE INVENTION
In accordance with the present invention, there is provided a new and improved system which is adapted for the application of pressure on a well packer. The system is employed in combination with a well which is equipped with an outer conduit, such as conventional well casing, and an inner conduit, such as a tubing string utilized for the the production of fluids from the well. The well is further equipped with a packer which is set in the annulus defined by the inner and outer conduits. The system of the present invention comprises suitable closure means which seals the annulus at a second region thereof above the location of the packer. This closure means functions with the packer to form a fluidtight compartment within the annulus between the packer and the closure means. In addition, the well is provided with means forming a confined passageway within the fluidtight compartment. This passageway extends into the compartment from the exterior thereof downwardly through the compartment to a lowermost elevation therein and thence upwardly to a level above this lowermost elevation. At this level, the confined passageway opens into fluid communication with the fluidtight compartment. With this system installed in the well, liquids of different densities can be utilized to impose a pressure on the upper side of the packer sufficient to offset the relatively high pressures which may be present in the well below the packer.
In accordance with a further aspect of the invention, there is provided a method in which the above-described system may be utilized to impose a desired pressure on the upper side of the packer. In this aspect of the invention, a liquid, commonly termed a packer liquid, is introduced into the fluidtight compartment within the annulus and a second liquid is introduced into the confined passageway contained within the fluidtight compartment. This second liquid is of a density greater than the packer liquid. By so employing these liquids of different densities, the hydrostatic pressure exerted upon the upper side of the packer is increased by a value equivalent to the differential hydrostatic head imposed by the more dense liquid contained within the confined passageway.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a vertical section of a wellbore containing an inactivated manometer-type fluid piston in the sealed annulus between a tubing and wellbore casing; and
FIG. 2 is the same vertical section as FIG. 1 with the exception that packer liquid is present in the annulus and the manometer-type fluid piston is activated to impose a predetermined pressure on the upper side of the packer.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
With reference to FIG. 1, there is illustrated a well equipped with inner and outer conduits and a packer sealing the annulus between the conduits in accordance with conventional practice. The well is further equipped with a preferred embodiment of the present invention whereby a pressure greater than that normally associated with the hydrostatic head of packer liquid within the annulus may be imposed upon the packer.
More particularly, and as shown in FIG. 1, a wellbore 1 penetrates the earth's surface 3, upper crust 5, and a subterranean formation 7. Formation 7 may be a productive formation such as an oil and/or gas reservoir in which the innate formation fluids are at a relatively high pressure. The well is provided with an outer conduit which takes the form of a casing 9 which is cemented within the well by a cement sheath 11. The well also includes a production tubing 13 which is located within the casing 9. The production tubing extends from a location adjacent the formation 7 to the surface of the earth and provides a passageway for the production of fluids from the well. The well is equipped with a packer 19 which seals off the upper portion of the well annulus from the lower portion of the well which is open to the flow of fluids from formation 7. Packer 19 typically will be set immediately above formation 7 as illustrated in the drawing.
In accordance with the present invention, there is provided a closure member 17, e.g. a casinghead, which seals the annulus between the casing 9 and the tubing 13 at an upper location. The closure member 17 and the packer 19 cooperate to form a fluidtight compartment 21 within the annulus between the closure member and the packer. The well also includes a manometer-type structure 15 which provides a confined passageway within the fluidtight compartment 21. Structure 15 is comprised of an outer tubular member 16 and an inner tubular member 14. Tubular member 14 extends to the exterior of the fluidtight compartment 21 through the closure member 17. Outer member 16 is provided with an opening 12 above the bottom thereof. As can be seen from an examination of FIG. 1, tubular members 14 and 16 provide a confined passageway 15a which extends into compartment 21 and downwardly therethrough to a lowermost elevation defined by the bottom of tubular member 16. The annulus between the inner and outer tubes 14 and 16, respectively, provides a continuation of this passageway back upwardly through compartment 21 to the opening 12. This opening provides for fluid communication between the confined passageway and the compartment 21 at a level above the bottom of the confined passageway.
The concentric arrangement of tubular members illustrated is the preferred structure for forming the confined passageway within compartment 21. This arrangement can be easily installed and withdrawn from the well and fits readily within the annular space between the casing 9 and tubing 13. However, it will be recognized that the confined passageway may be formed by other suitable structures. For example, the confined passageway may be formed by a U-shaped tubular member which extends downwardly through compartment 21 and then upwardly a relatively short distance from the bottom thereof.
In utilizing the system shown in FIG. 1 to impose a desired pressure on the upper surface of packer 19, a packer liquid 22 is introduced into compartment 21 and a second liquid, of a density greater than that of the packer liquid, is introduced into the confined passageway 15a. Preferably this second liquid has a density of at least twice that of the packer liquid. The greater the density of this second liquid, the smaller the amount needed to increase the pressure on the wellhead side of packer 19 by a given value. The two liquids preferably are immiscible with one another to restrict mixing. Bromoform, other halogenated hydrocarbons, and mercury are examples of dense liquids which may be used as the second liquid in the fluid piston. Compartment 21 is filled with a corrosion inhibited packer liquid via inlet opening 23a located adjacent the upper end thereof. As shown in FIG. 1, opening 23a is provided with a conduit 23, valve 25, and pump 27. During the filling process, air is evacuated from compartment 21 via a gas outlet 29a through closure means 17. Gas outlet 29a is provided with a valve 31 and conduit 29. Valve 31 is normally opened to remove all air and gas from compartment 21. This allows compartment 21 to be completely filled with packer liquid. A sufficient amount of a second liquid having a density greater than the packer liquid is injected into fluid piston 15 via tubular member 14 to increase the pressure on the upper side of packer 19 to an amount which approximately equals the pressure on the formation side of packer 19. The second liquid injected into the fluid piston settles to the bottom thereof. In FIG. 1, compartment 21 is completely filled with a corrosion inhibited packer liquid and fluid piston 15 has a dense liquid filling the bottom thereof. In this state, the pressure exerted on the upper side of packer 19 is imposed solely by the hydrostatic pressure of the packer liquid filling compartment 21.
As additional second liquid is put into fluid piston 15 via tubular member 14, the pressure exerted on the upper side of packer 19 is increased and the configuration approaches that of FIG. 2. As illustrated by FIG. 2, the packer liquid completely fills compartment 21 including tubular member 16 above interface 18 between the relatively dense liquid 20 and packer liquid 22. As further second liquid is put into tubular member 14 of fluid piston 15, the difference in height between the second liquid in tubular member 14 and tubular member 16 is increased since the packer liquid and second liquid are immiscible one with the other and both are essentially incompressible. The pressure on the upper side of packer 19 is thus increased by an amount corresponding to the difference in hydrostatic pressure produced by the second liquid in tubular members 14 and 16.
In a further preferred structure of this invention, the inner tubular member 14 is flared to form a reservoir 14a of increased volume. The purpose of flaring this inner tubular member is best understood by the following description in reference to FIG. 2. Under the conditions of FIG. 2, the packer liquid in the fluidtight compartment is pressurized by the manometer-type fluid piston. Since both the packer liquid and the fluid piston liquid are essentially incompressible, any small leak of liquid from the fluidtight compartment would produce a large decrease in pressure. However, the flared portion of the inner tube of the manometer-type fluid piston serves as a reservoir of fluid piston liquid. Thus, in the case of a small leak there is less of a decrease in the height of the dense liquid in the inner tube and less pressure decrease than there would be if it were not for the flared portion which serves as a reservoir.
It is desirable to impose a pressure on the upper side of packer 19 which is essentially equal in value to the pressure existing on the lower side of packer 19, imposed by formation 7. The pressure imposed on the upper side of packer 19 is made up of two components, (1) the hydrostatic pressure of the packer liquid in compartment 21, and (2) hydrostatic pressure imposed at the casinghead by manometer-type fluid piston 15. This relationship where the pressure on the upper side of packer 19 is equal to the pressure on the lower side of packer 19 is represented by the following equation:
P P + P C = P F (1) where:
P P = hydrostatic pressure imposed by the column of packer liquid filling compartment 21,
P C = hydrostatic pressure at the casinghead imposed by the manometer-type fluid piston, and
P F = pressure imposed on the lower side of packer 19 by formation 7.
Thus, P C = P F - P P . (2)P F is determined by measuring with conventional means the pressure on the lower side of packer 19. P P is determined by multiplying the height of the column of packer liquid in compartment 21 by the pressure gradient (related to density) of the packer liquid filling compartment 21. Thus P C to be imposed by the fluid piston 15 is determined by subtracting P P from P F . A sufficient amount of second liquid is then added to tubular member 14 of fluid piston 15 to impose an added pressure of P C at the casinghead 17.
Remembering that P C = P F - P P and that P F is known and P P can be determined, the desired P C can be obtained. For example, where P F = 7,650 p.s.i. and P P = 10,000 (0.45 p.s.i./ft.= 4,500 p.s.i., then P C desired = P F - P P = 7,650 - 4,500 = 3,150 p.s.i. Thus, dense liquid is added into tubular member 14 until a P C at the casinghead of 3,150 p.s.i. is measured. This results in a configuration such as seen in FIG. 2 where the length of the column of dense liquid in the first passageway comprising tubular member 14 is 9,000 feet and the length of the column of the dense liquid in the second passageway comprising tubular member 16 is 1,000 feet and the location of interface 18 is 1,000 feet above the top of packer 19. The specific gravity of the corrosion inhibited packer liquid is slightly greater than 1, giving a pressure gradient of 0.45 p.s.i. per foot. The specific gravity of the dense liquid in the manometer-type fluid piston is exactly twice that of the packer liquid, giving a pressure gradient of 0.90 p.s.i. per foot. Thus the pressure exerted at interface 18 is equal to (9,000 feet - 1,000 feet) times 0.90 p.s.i./ft. or 7,200 p.s.i. The pressure at the casinghead is equal to 7,200 p.s.i. minus the hydrostatic pressure exerted by the packer fluid in compartment 21 above interface 18 or 7,200 - (9,000 × 0.45)= 3,150 p.s.i. the desired P C . Therefore, a condition of pressure balance across packer 19 is obtained.
This invention is directed to a method and system for increasing the hydrostatic pressures exerted by packer liquids. More specifically, this invention concerns the use of a manometer-type fluid piston in a wellbore to increase the pressure exerted by a packer liquid on a packer set in a wellbore.
Packer liquids are used to impose a hydrostatic pressure on the upper or wellhead side of a packer which has been set, for example, between production tubing and casing of a wellbore. Packer liquid use is particularly important when packers are set above high pressure formations. The hydrostatic pressure imposed by the packer liquid on the upper side of the packer opposes the formation pressure existing on the lower or formation side of the packer and thus aids in maintaining the packer in place.
Drilling mud in use in the wellbore when the packer is set is often left in the annulus above the packer to serve as a packer liquid. The properties of drilling muds are usually such that they are not completely satisfactory as packer liquids. For example, the muds may be corrosive, thus causing tubing and casing failure. Also weighting materials and other chemicals used in the drilling muds may segregate from the liquid carrier and settle to the lower portion of the well, thus interfering with the pulling of the packer and causing expensive workovers.
SUMMARY OF THE INVENTION
In accordance with the present invention, there is provided a new and improved system which is adapted for the application of pressure on a well packer. The system is employed in combination with a well which is equipped with an outer conduit, such as conventional well casing, and an inner conduit, such as a tubing string utilized for the the production of fluids from the well. The well is further equipped with a packer which is set in the annulus defined by the inner and outer conduits. The system of the present invention comprises suitable closure means which seals the annulus at a second region thereof above the location of the packer. This closure means functions with the packer to form a fluidtight compartment within the annulus between the packer and the closure means. In addition, the well is provided with means forming a confined passageway within the fluidtight compartment. This passageway extends into the compartment from the exterior thereof downwardly through the compartment to a lowermost elevation therein and thence upwardly to a level above this lowermost elevation. At this level, the confined passageway opens into fluid communication with the fluidtight compartment. With this system installed in the well, liquids of different densities can be utilized to impose a pressure on the upper side of the packer sufficient to offset the relatively high pressures which may be present in the well below the packer.
In accordance with a further aspect of the invention, there is provided a method in which the above-described system may be utilized to impose a desired pressure on the upper side of the packer. In this aspect of the invention, a liquid, commonly termed a packer liquid, is introduced into the fluidtight compartment within the annulus and a second liquid is introduced into the confined passageway contained within the fluidtight compartment. This second liquid is of a density greater than the packer liquid. By so employing these liquids of different densities, the hydrostatic pressure exerted upon the upper side of the packer is increased by a value equivalent to the differential hydrostatic head imposed by the more dense liquid contained within the confined passageway.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a vertical section of a wellbore containing an inactivated manometer-type fluid piston in the sealed annulus between a tubing and wellbore casing; and
FIG. 2 is the same vertical section as FIG. 1 with the exception that packer liquid is present in the annulus and the manometer-type fluid piston is activated to impose a predetermined pressure on the upper side of the packer.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
With reference to FIG. 1, there is illustrated a well equipped with inner and outer conduits and a packer sealing the annulus between the conduits in accordance with conventional practice. The well is further equipped with a preferred embodiment of the present invention whereby a pressure greater than that normally associated with the hydrostatic head of packer liquid within the annulus may be imposed upon the packer.
More particularly, and as shown in FIG. 1, a wellbore 1 penetrates the earth's surface 3, upper crust 5, and a subterranean formation 7. Formation 7 may be a productive formation such as an oil and/or gas reservoir in which the innate formation fluids are at a relatively high pressure. The well is provided with an outer conduit which takes the form of a casing 9 which is cemented within the well by a cement sheath 11. The well also includes a production tubing 13 which is located within the casing 9. The production tubing extends from a location adjacent the formation 7 to the surface of the earth and provides a passageway for the production of fluids from the well. The well is equipped with a packer 19 which seals off the upper portion of the well annulus from the lower portion of the well which is open to the flow of fluids from formation 7. Packer 19 typically will be set immediately above formation 7 as illustrated in the drawing.
In accordance with the present invention, there is provided a closure member 17, e.g. a casinghead, which seals the annulus between the casing 9 and the tubing 13 at an upper location. The closure member 17 and the packer 19 cooperate to form a fluidtight compartment 21 within the annulus between the closure member and the packer. The well also includes a manometer-type structure 15 which provides a confined passageway within the fluidtight compartment 21. Structure 15 is comprised of an outer tubular member 16 and an inner tubular member 14. Tubular member 14 extends to the exterior of the fluidtight compartment 21 through the closure member 17. Outer member 16 is provided with an opening 12 above the bottom thereof. As can be seen from an examination of FIG. 1, tubular members 14 and 16 provide a confined passageway 15a which extends into compartment 21 and downwardly therethrough to a lowermost elevation defined by the bottom of tubular member 16. The annulus between the inner and outer tubes 14 and 16, respectively, provides a continuation of this passageway back upwardly through compartment 21 to the opening 12. This opening provides for fluid communication between the confined passageway and the compartment 21 at a level above the bottom of the confined passageway.
The concentric arrangement of tubular members illustrated is the preferred structure for forming the confined passageway within compartment 21. This arrangement can be easily installed and withdrawn from the well and fits readily within the annular space between the casing 9 and tubing 13. However, it will be recognized that the confined passageway may be formed by other suitable structures. For example, the confined passageway may be formed by a U-shaped tubular member which extends downwardly through compartment 21 and then upwardly a relatively short distance from the bottom thereof.
In utilizing the system shown in FIG. 1 to impose a desired pressure on the upper surface of packer 19, a packer liquid 22 is introduced into compartment 21 and a second liquid, of a density greater than that of the packer liquid, is introduced into the confined passageway 15a. Preferably this second liquid has a density of at least twice that of the packer liquid. The greater the density of this second liquid, the smaller the amount needed to increase the pressure on the wellhead side of packer 19 by a given value. The two liquids preferably are immiscible with one another to restrict mixing. Bromoform, other halogenated hydrocarbons, and mercury are examples of dense liquids which may be used as the second liquid in the fluid piston. Compartment 21 is filled with a corrosion inhibited packer liquid via inlet opening 23a located adjacent the upper end thereof. As shown in FIG. 1, opening 23a is provided with a conduit 23, valve 25, and pump 27. During the filling process, air is evacuated from compartment 21 via a gas outlet 29a through closure means 17. Gas outlet 29a is provided with a valve 31 and conduit 29. Valve 31 is normally opened to remove all air and gas from compartment 21. This allows compartment 21 to be completely filled with packer liquid. A sufficient amount of a second liquid having a density greater than the packer liquid is injected into fluid piston 15 via tubular member 14 to increase the pressure on the upper side of packer 19 to an amount which approximately equals the pressure on the formation side of packer 19. The second liquid injected into the fluid piston settles to the bottom thereof. In FIG. 1, compartment 21 is completely filled with a corrosion inhibited packer liquid and fluid piston 15 has a dense liquid filling the bottom thereof. In this state, the pressure exerted on the upper side of packer 19 is imposed solely by the hydrostatic pressure of the packer liquid filling compartment 21.
As additional second liquid is put into fluid piston 15 via tubular member 14, the pressure exerted on the upper side of packer 19 is increased and the configuration approaches that of FIG. 2. As illustrated by FIG. 2, the packer liquid completely fills compartment 21 including tubular member 16 above interface 18 between the relatively dense liquid 20 and packer liquid 22. As further second liquid is put into tubular member 14 of fluid piston 15, the difference in height between the second liquid in tubular member 14 and tubular member 16 is increased since the packer liquid and second liquid are immiscible one with the other and both are essentially incompressible. The pressure on the upper side of packer 19 is thus increased by an amount corresponding to the difference in hydrostatic pressure produced by the second liquid in tubular members 14 and 16.
In a further preferred structure of this invention, the inner tubular member 14 is flared to form a reservoir 14a of increased volume. The purpose of flaring this inner tubular member is best understood by the following description in reference to FIG. 2. Under the conditions of FIG. 2, the packer liquid in the fluidtight compartment is pressurized by the manometer-type fluid piston. Since both the packer liquid and the fluid piston liquid are essentially incompressible, any small leak of liquid from the fluidtight compartment would produce a large decrease in pressure. However, the flared portion of the inner tube of the manometer-type fluid piston serves as a reservoir of fluid piston liquid. Thus, in the case of a small leak there is less of a decrease in the height of the dense liquid in the inner tube and less pressure decrease than there would be if it were not for the flared portion which serves as a reservoir.
It is desirable to impose a pressure on the upper side of packer 19 which is essentially equal in value to the pressure existing on the lower side of packer 19, imposed by formation 7. The pressure imposed on the upper side of packer 19 is made up of two components, (1) the hydrostatic pressure of the packer liquid in compartment 21, and (2) hydrostatic pressure imposed at the casinghead by manometer-type fluid piston 15. This relationship where the pressure on the upper side of packer 19 is equal to the pressure on the lower side of packer 19 is represented by the following equation:
P P + P C = P F (1) where:
P P = hydrostatic pressure imposed by the column of packer liquid filling compartment 21,
P C = hydrostatic pressure at the casinghead imposed by the manometer-type fluid piston, and
P F = pressure imposed on the lower side of packer 19 by formation 7.
Thus, P C = P F - P P . (2)P F is determined by measuring with conventional means the pressure on the lower side of packer 19. P P is determined by multiplying the height of the column of packer liquid in compartment 21 by the pressure gradient (related to density) of the packer liquid filling compartment 21. Thus P C to be imposed by the fluid piston 15 is determined by subtracting P P from P F . A sufficient amount of second liquid is then added to tubular member 14 of fluid piston 15 to impose an added pressure of P C at the casinghead 17.
Remembering that P C = P F - P P and that P F is known and P P can be determined, the desired P C can be obtained. For example, where P F = 7,650 p.s.i. and P P = 10,000 (0.45 p.s.i./ft.= 4,500 p.s.i., then P C desired = P F - P P = 7,650 - 4,500 = 3,150 p.s.i. Thus, dense liquid is added into tubular member 14 until a P C at the casinghead of 3,150 p.s.i. is measured. This results in a configuration such as seen in FIG. 2 where the length of the column of dense liquid in the first passageway comprising tubular member 14 is 9,000 feet and the length of the column of the dense liquid in the second passageway comprising tubular member 16 is 1,000 feet and the location of interface 18 is 1,000 feet above the top of packer 19. The specific gravity of the corrosion inhibited packer liquid is slightly greater than 1, giving a pressure gradient of 0.45 p.s.i. per foot. The specific gravity of the dense liquid in the manometer-type fluid piston is exactly twice that of the packer liquid, giving a pressure gradient of 0.90 p.s.i. per foot. Thus the pressure exerted at interface 18 is equal to (9,000 feet - 1,000 feet) times 0.90 p.s.i./ft. or 7,200 p.s.i. The pressure at the casinghead is equal to 7,200 p.s.i. minus the hydrostatic pressure exerted by the packer fluid in compartment 21 above interface 18 or 7,200 - (9,000 × 0.45)= 3,150 p.s.i. the desired P C . Therefore, a condition of pressure balance across packer 19 is obtained.