TECHNIQUE FOR STEAM INJECTION
United States Patent 3559738
This invention relates to a method for thermally insulating a well used in a thermal process for oil recovery. The well is insulated by a falling film of liquid which is introduced at the well head in the annular space between the casing and the tubing. The film coats the internal surface of the casing to reduce the transfer of heat from the tubing string to the casing string and to conduct heat to an oil-bearing formation.
US Patent References:
Method for producing hydrocarbons in an in situ combustion operation
Ten Brink - December 1961 - 3013609
Method and apparatus for injecting steam into subsurface formations
Doscher - July 1964 - 3142336
Method for producing hydrocarbons in an in situ combustion operation
Shook - January 1966 - 3228471
Method for insulating oil wells
Bloom - June 1968 - 3386512
SHUT-OFF CONTROL FOR AN IN-SITU COMBUSTION PRODUCTION WELL
Cummings - March 1969 - 3430696
Method for producing hydrocarbons in an in situ combustion operation
Ten Brink - December 1961 - 3013609
Method and apparatus for injecting steam into subsurface formations
Doscher - July 1964 - 3142336
Method for producing hydrocarbons in an in situ combustion operation
Shook - January 1966 - 3228471
Method for insulating oil wells
Bloom - June 1968 - 3386512
SHUT-OFF CONTROL FOR AN IN-SITU COMBUSTION PRODUCTION WELL
Cummings - March 1969 - 3430696
Application Number:
04/803865
Publication Date:
02/02/1971
Filing Date:
03/03/1969
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Export Citation:
Primary Class:
International Classes:
E21B36/00; E21B43/24
Field of Search:
166/57,256,261,303,272
US Patent References:
Primary Examiner:
Novosad, Stephen J.
Claims:
I claim
1. A process for thermally insulating casing in a well in which the well has a casing string, a tubing string suspended within the casing string, and an annular space which is defined by the casing string and tubing string and which is substantially unobstructed for at least a portion of its length which comprises introducing into the annular space at a location near the top of the casing a liquid which near the point of introduction contacts the casing and which only partially fills the annular space to provide a falling film of liquid on the casing to reduce the transfer of heat from the central portion of the well to the casing.
2. A process as defined in claim 1 wherein the liquid is water.
3. A process as defined in claim 2 wherein the water contains a surface active agent.
4. A process as defined in claim 1 wherein a gas is introduced into the annulus between the casing and a tubing string to depress the liquid level within the well.
5. A process as defined in claim 4 wherein the gas is a hydrocarbon.
6. A process as defined in claim 5 wherein the gas is methane.
7. A method for thermally insulating casing in a well which comprises forming a film of liquid on the internal surface of the casing by injecting the liquid at a location near the top of the casing and continuing the injection of the liquid to cause the film to flow down the internal surface of the casing.
8. A method of thermally insulating a casing in a thermal injection well which has a string of casing, a string of tubing suspended within the casing for the injection of a heated fluid into a subterranean oil-bearing formation and an annular space which is defined by the casing string and the tubing string which comprises flowing water into the casing string at a location near the top of the casing string, confining the flow path of the water to contact the casing string with the water and to restrict contact of the tubing string by the water, and releasing a film of water from the confined flow path, said film being in contact with the casing string and filling only a portion of the annular space between the casing string and the tubing string.
1. A process for thermally insulating casing in a well in which the well has a casing string, a tubing string suspended within the casing string, and an annular space which is defined by the casing string and tubing string and which is substantially unobstructed for at least a portion of its length which comprises introducing into the annular space at a location near the top of the casing a liquid which near the point of introduction contacts the casing and which only partially fills the annular space to provide a falling film of liquid on the casing to reduce the transfer of heat from the central portion of the well to the casing.
2. A process as defined in claim 1 wherein the liquid is water.
3. A process as defined in claim 2 wherein the water contains a surface active agent.
4. A process as defined in claim 1 wherein a gas is introduced into the annulus between the casing and a tubing string to depress the liquid level within the well.
5. A process as defined in claim 4 wherein the gas is a hydrocarbon.
6. A process as defined in claim 5 wherein the gas is methane.
7. A method for thermally insulating casing in a well which comprises forming a film of liquid on the internal surface of the casing by injecting the liquid at a location near the top of the casing and continuing the injection of the liquid to cause the film to flow down the internal surface of the casing.
8. A method of thermally insulating a casing in a thermal injection well which has a string of casing, a string of tubing suspended within the casing for the injection of a heated fluid into a subterranean oil-bearing formation and an annular space which is defined by the casing string and the tubing string which comprises flowing water into the casing string at a location near the top of the casing string, confining the flow path of the water to contact the casing string with the water and to restrict contact of the tubing string by the water, and releasing a film of water from the confined flow path, said film being in contact with the casing string and filling only a portion of the annular space between the casing string and the tubing string.
Description:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to a process for thermally insulating a wellbore.
2. Description of the Prior Art
In the recovery of heavy petroleum crude oils, the industry has for many years recognized the desirability of thermal treatment as a means for lowering the oil viscosity and thereby increasing the production of oil.
One thermal process which has recently received wide acceptance by the industry is a process of injecting steam into the well and into the reservoir. This process is a thermal drive technique where steam is injected into one well which drives oil before it to a second, producing well. In an alternative method, a single well is used for both steam injection and production of the oil. The steam is injected through the tubing and into the formation. Injection is then interrupted, and the formation is permitted to heat soak for a period of time. Following the heat soak, the well is placed on a production cycle and the heated fluids are withdrawn by way of the well to the surface.
Steam injection can increase oil production through a number of mechanisms. The viscosity of most oils is strongly dependent upon its temperature. In many cases, the viscosity of the reservoir oil can be reduced by 100 fold or more if the temperature of the oil is increased several hundred degrees. Steam injection can have substantial benefits in recovering even relatively-light, low-viscosity oils. This is particularly true where such oils exist in thick, low permeability sands where present fracturing techniques are not effective. In such cases, a minor reduction in viscosity of the reservoir oil can sharply increase productivity. Steam injection is also useful in removing wellbore damage at injection and producing wells. Such damage is often attributable to asphaltic or paraffinic components of the crude oil which clog the pore spaces of the reservoir sand in the immediate vicinity of the well. Steam injection can be used to remove these deposits.
Injection of high temperature steam which may be 650° F. or even higher does, however, present some special operational problems. When the steam is injected through the tubing, there may be substantial transfer of heat across the annular space to the well casing. When the well casing is firmly cemented into the wellbore, as it generally is, the thermally induced stresses may result in casing failure. Moreover, the primary object of any steam injection process is to transfer the thermal energy from the surface of the earth to the oil-bearing formation. Where significant quantities of thermal energy are lost to the surrounding earth as the steam travels through the tubing string, the process is naturally less efficient. This represents a tremendous loss in the amount of thermal energy that the injected fluid is able to carry into the reservoir.
A number of proposals have been advanced to combat excessive heat losses in steam injection processes. It has been suggested that a temperature resistant, thermal packer be employed to isolate the annular space between the casing and injection tubing. Such equipment will reduce heat losses due to convection between the tubing string and the casing string by forming a closed, dead-gas space in the annulus. Such specialized equipment is not only highly expensive, but does nothing to prevent radiant thermal losses from the injection tubing to the surrounding formations.
It has been suggested that the wells be completed with a bitumastic coating. This completion technique utilizes a material to coat the casing which will melt at high temperature. When melting occurs, the casing is free to expand thus relieving the stresses which would otherwise be placed on the casing due to an increase in its temperature. This method has not proven to be universally successful in preventing casing failure. In some instances the formations may contact the casing with sufficient force to prevent free expansion and contraction of the casing during heating and cooling. Under these circumstances, casing failure is possible due to the unrelieved stresses. Moreover, such a completion technique does nothing to prevent the loss of thermal energy to the surrounding formations.
Another means which has been successfully employed to lower heat losses from steam injection tubing is the heat reflector system. This is a shell of heat-reflective, metal pipe which surrounds the tubing string. It is assembled in joints which are equal in length to the joints of the tubing and run into the hole with the tubing string as an integrated unit. The outer shell may be sealed at the top and bottom to prevent the entry of well fluids into the space between the steam injection tubing and the heat reflective shell. Such a system has utility in preventing the losses of thermal energy from injection tubing due to radiation, conduction, and convection. Such a system, of course, is relatively expensive since it requires two strings of metallic pipe--the injection tubing and the heat reflective shell. Moreover, the use of the heat reflective shell will reduce the diameter of the tubing which may be effectively employed in any given well. This can be particularly important where multiple strings of tubing are employed in a single well.
It has been suggested that an inert gas, such as nitrogen, be introduced into the annular space between the casing and tubing. The inert gas serves as an insulator in the annular space to prevent the transfer of thermal energy from the tubing to the casing. Such a method, however, is not totally successful in preventing the transfer of heat from the tubing to the casing. Inert gases, such as nitrogen and helium, are not effective barriers to the transfer to radiant energy. Moreover, convection currents within the annular space permits the conduction of heat by means of the gas from the tubing to the casing surface.
SUMMARY OF THE INVENTION
This invention relates to a process for thermally insulating the casing of a well in thermal processes for producing oil. A thin film of liquid is introduced at the wellhead into the annular space between the tubing and the casing. The falling liquid film travels down the internal surface of the casing string. As hot fluids travel through the tubing string, thermal energy passes through the annulus and contacts the falling liquid film. The liquid film carries off heat which would otherwise be transferred to the casing string. Much of the heat captured by the falling liquid is eventually transferred to the oil-bearing formation when the heated film reaches the perforations and passed into the formation.
BRIEF DESCRIPTION OF THE DRAWING
The FIG. is a schematic representation of a vertical section of the earth showing a well containing casing and steam injection tubing and the falling liquid film for insulating the casing.
DESCRIPTION OF THE PREFERRED EMBODIMENT
In the embodiment shown in the FIG., a well shown generally at 10 is drilled from the surface of the earth 11 to an oil-bearing formation 12. The well has a casing string 13 with perforations 14 in the oil-bearing formation to permit fluid communication between the oil-bearing formation and the casing. Steam injection tubing 15 extends from the wellhead 16 to the oil-bearing formation. The tubing string is equipped with an inlet line 17 and the casing has inlet lines 18 and 19. Concentrically disposed within the casing 13 is a sleeve 20 which extends from the wellhead for a short distance into the casing. The casing 13 and the sleeve 20 define a narrow annular passage 21 for directing the flow of liquid in a thin film down the internal surface of the casing. The fluid enters the passage 21 by means of the casing inlet 18.
The process of this invention has its primary utility in protecting casing during steam injection operations. In such operations steam is injected down the tubing string 15 and injected into the oil-bearing formation 12. Concurrently with the injection of steam, water at or near surface temperature is introduced through inlet line 18 into the annular ring 21 and passes as a thin film 22 downwardly on the interior of the casing string. When the water reaches the perforations 14, it is forced with the steam through the perforations and into the oil-bearing formation 12. The falling water film 22 effectively prevents the transfer of excess thermal energy to the casing string and conducts thermal energy to oil-bearing formation 12 which would otherwise be lost to the formations surrounding the wellbore.
In the practice of this invention, it is preferred to use water for the falling liquid film due to its ready availability and low cost. Water has the ability to carry significant quantities of sensible heat and can take on even larger quantities of thermal energy if vaporized due to its high latent heat of vaporization.
It may be desirable to dissolve certain additives in the liquid prior to its introduction into the casing. Surface active agents will promote the liquid wettability of the casing string and will assist in keeping the film in contact with the casing. Corrosion inhibitors may be added to prevent corrosion of the casing string at the high temperatures existing in such thermal operations.
In the application of this process, the desired flow rate of the falling liquid film is dictated by a number of conditions including the steam injection rate and the maximum desired casing temperature. The proper rate to be used under any given set of circumstances can be readily calculated by one of ordinary skill in the art using conventional heat and material balance calculations.
In certain instances it may be preferred to use a liquid other than water for the falling liquid film. For instance, it may be desired to inject a light hydrocarbon solvent, such as diesel fuel, down the casing while steam is injected down the tubing for a steam-solvent injection process. In such an instance, the light hydrocarbon liquid could be injected into the annulus and introduced into the formation in the manner previously described.
In the event water builds up within the borehole and threatens to block the introduction of steam through perforations 14, a high pressure gas may be introduced through casing inlet 19 to force the water to the lower perforations. The upper perforations would then be effectively cleared for the introduction of steam into the formation.
The gas to be employed for this purpose may be any readily available gaseous substance. Hydrocarbon gases such as methane are preferred for this use due to their solubility in the crude oil which will assist in lowering its viscosity and due to their relatively, noncorrosive nature.
1. Field of the Invention
This invention relates to a process for thermally insulating a wellbore.
2. Description of the Prior Art
In the recovery of heavy petroleum crude oils, the industry has for many years recognized the desirability of thermal treatment as a means for lowering the oil viscosity and thereby increasing the production of oil.
One thermal process which has recently received wide acceptance by the industry is a process of injecting steam into the well and into the reservoir. This process is a thermal drive technique where steam is injected into one well which drives oil before it to a second, producing well. In an alternative method, a single well is used for both steam injection and production of the oil. The steam is injected through the tubing and into the formation. Injection is then interrupted, and the formation is permitted to heat soak for a period of time. Following the heat soak, the well is placed on a production cycle and the heated fluids are withdrawn by way of the well to the surface.
Steam injection can increase oil production through a number of mechanisms. The viscosity of most oils is strongly dependent upon its temperature. In many cases, the viscosity of the reservoir oil can be reduced by 100 fold or more if the temperature of the oil is increased several hundred degrees. Steam injection can have substantial benefits in recovering even relatively-light, low-viscosity oils. This is particularly true where such oils exist in thick, low permeability sands where present fracturing techniques are not effective. In such cases, a minor reduction in viscosity of the reservoir oil can sharply increase productivity. Steam injection is also useful in removing wellbore damage at injection and producing wells. Such damage is often attributable to asphaltic or paraffinic components of the crude oil which clog the pore spaces of the reservoir sand in the immediate vicinity of the well. Steam injection can be used to remove these deposits.
Injection of high temperature steam which may be 650° F. or even higher does, however, present some special operational problems. When the steam is injected through the tubing, there may be substantial transfer of heat across the annular space to the well casing. When the well casing is firmly cemented into the wellbore, as it generally is, the thermally induced stresses may result in casing failure. Moreover, the primary object of any steam injection process is to transfer the thermal energy from the surface of the earth to the oil-bearing formation. Where significant quantities of thermal energy are lost to the surrounding earth as the steam travels through the tubing string, the process is naturally less efficient. This represents a tremendous loss in the amount of thermal energy that the injected fluid is able to carry into the reservoir.
A number of proposals have been advanced to combat excessive heat losses in steam injection processes. It has been suggested that a temperature resistant, thermal packer be employed to isolate the annular space between the casing and injection tubing. Such equipment will reduce heat losses due to convection between the tubing string and the casing string by forming a closed, dead-gas space in the annulus. Such specialized equipment is not only highly expensive, but does nothing to prevent radiant thermal losses from the injection tubing to the surrounding formations.
It has been suggested that the wells be completed with a bitumastic coating. This completion technique utilizes a material to coat the casing which will melt at high temperature. When melting occurs, the casing is free to expand thus relieving the stresses which would otherwise be placed on the casing due to an increase in its temperature. This method has not proven to be universally successful in preventing casing failure. In some instances the formations may contact the casing with sufficient force to prevent free expansion and contraction of the casing during heating and cooling. Under these circumstances, casing failure is possible due to the unrelieved stresses. Moreover, such a completion technique does nothing to prevent the loss of thermal energy to the surrounding formations.
Another means which has been successfully employed to lower heat losses from steam injection tubing is the heat reflector system. This is a shell of heat-reflective, metal pipe which surrounds the tubing string. It is assembled in joints which are equal in length to the joints of the tubing and run into the hole with the tubing string as an integrated unit. The outer shell may be sealed at the top and bottom to prevent the entry of well fluids into the space between the steam injection tubing and the heat reflective shell. Such a system has utility in preventing the losses of thermal energy from injection tubing due to radiation, conduction, and convection. Such a system, of course, is relatively expensive since it requires two strings of metallic pipe--the injection tubing and the heat reflective shell. Moreover, the use of the heat reflective shell will reduce the diameter of the tubing which may be effectively employed in any given well. This can be particularly important where multiple strings of tubing are employed in a single well.
It has been suggested that an inert gas, such as nitrogen, be introduced into the annular space between the casing and tubing. The inert gas serves as an insulator in the annular space to prevent the transfer of thermal energy from the tubing to the casing. Such a method, however, is not totally successful in preventing the transfer of heat from the tubing to the casing. Inert gases, such as nitrogen and helium, are not effective barriers to the transfer to radiant energy. Moreover, convection currents within the annular space permits the conduction of heat by means of the gas from the tubing to the casing surface.
SUMMARY OF THE INVENTION
This invention relates to a process for thermally insulating the casing of a well in thermal processes for producing oil. A thin film of liquid is introduced at the wellhead into the annular space between the tubing and the casing. The falling liquid film travels down the internal surface of the casing string. As hot fluids travel through the tubing string, thermal energy passes through the annulus and contacts the falling liquid film. The liquid film carries off heat which would otherwise be transferred to the casing string. Much of the heat captured by the falling liquid is eventually transferred to the oil-bearing formation when the heated film reaches the perforations and passed into the formation.
BRIEF DESCRIPTION OF THE DRAWING
The FIG. is a schematic representation of a vertical section of the earth showing a well containing casing and steam injection tubing and the falling liquid film for insulating the casing.
DESCRIPTION OF THE PREFERRED EMBODIMENT
In the embodiment shown in the FIG., a well shown generally at 10 is drilled from the surface of the earth 11 to an oil-bearing formation 12. The well has a casing string 13 with perforations 14 in the oil-bearing formation to permit fluid communication between the oil-bearing formation and the casing. Steam injection tubing 15 extends from the wellhead 16 to the oil-bearing formation. The tubing string is equipped with an inlet line 17 and the casing has inlet lines 18 and 19. Concentrically disposed within the casing 13 is a sleeve 20 which extends from the wellhead for a short distance into the casing. The casing 13 and the sleeve 20 define a narrow annular passage 21 for directing the flow of liquid in a thin film down the internal surface of the casing. The fluid enters the passage 21 by means of the casing inlet 18.
The process of this invention has its primary utility in protecting casing during steam injection operations. In such operations steam is injected down the tubing string 15 and injected into the oil-bearing formation 12. Concurrently with the injection of steam, water at or near surface temperature is introduced through inlet line 18 into the annular ring 21 and passes as a thin film 22 downwardly on the interior of the casing string. When the water reaches the perforations 14, it is forced with the steam through the perforations and into the oil-bearing formation 12. The falling water film 22 effectively prevents the transfer of excess thermal energy to the casing string and conducts thermal energy to oil-bearing formation 12 which would otherwise be lost to the formations surrounding the wellbore.
In the practice of this invention, it is preferred to use water for the falling liquid film due to its ready availability and low cost. Water has the ability to carry significant quantities of sensible heat and can take on even larger quantities of thermal energy if vaporized due to its high latent heat of vaporization.
It may be desirable to dissolve certain additives in the liquid prior to its introduction into the casing. Surface active agents will promote the liquid wettability of the casing string and will assist in keeping the film in contact with the casing. Corrosion inhibitors may be added to prevent corrosion of the casing string at the high temperatures existing in such thermal operations.
In the application of this process, the desired flow rate of the falling liquid film is dictated by a number of conditions including the steam injection rate and the maximum desired casing temperature. The proper rate to be used under any given set of circumstances can be readily calculated by one of ordinary skill in the art using conventional heat and material balance calculations.
In certain instances it may be preferred to use a liquid other than water for the falling liquid film. For instance, it may be desired to inject a light hydrocarbon solvent, such as diesel fuel, down the casing while steam is injected down the tubing for a steam-solvent injection process. In such an instance, the light hydrocarbon liquid could be injected into the annulus and introduced into the formation in the manner previously described.
In the event water builds up within the borehole and threatens to block the introduction of steam through perforations 14, a high pressure gas may be introduced through casing inlet 19 to force the water to the lower perforations. The upper perforations would then be effectively cleared for the introduction of steam into the formation.
The gas to be employed for this purpose may be any readily available gaseous substance. Hydrocarbon gases such as methane are preferred for this use due to their solubility in the crude oil which will assist in lowering its viscosity and due to their relatively, noncorrosive nature.