HK1131198A - Controlling the pressure within an annular volume of a wellbore - Google Patents

Description

Controlling pressure within an annular volume of a wellbore

Technical Field

The present invention relates to a method of controlling the pressure generated by fluid within a confined volume as the fluid within the confined volume is being heated. In a preferred embodiment, the present invention relates to a method of controlling the pressure within an annular volume described by a casing string assembly within a wellbore.

Background

In the drilling of a wellbore, such as an oil well, it is common to secure together individual sections of larger diameter metal tubing to form a casing string or liner disposed within each section of the wellbore. Each casing string may be suspended from wellhead equipment near the surface. Alternatively, some of the casing strings may be in the form of liners extending from near the depth of burial of a previous portion of casing. In this case, the liner string will be suspended from the previous portion of casing on the liner hanger. The casing string is typically made up of a number of joints or segments, each approximately forty feet long, connected to each other by threaded joints or other connection devices. These joints are typically metal pipes, but may also be non-metallic materials such as composite pipes. Such casing strings are used to improve wellbore integrity by preventing collapse of the cavity walls. In addition, the casing string prevents the movement of fluids from one formation to another formation through which the wellbore passes.

Typically, each section of the casing string is cemented within the wellbore prior to drilling the next section of the wellbore. Thus, each subsequent section of the wellbore must have a smaller diameter than the previous section. For example, a first portion of the wellbore may receive a surface (or guide) casing string that is 20 inches in diameter. Subsequent sections of the wellbore may receive intermediate (or protective) casing strings having diameters of 16 inches, 13 inches and 3/8 inches, and 9 inches and 5/8 inches, respectively. The last section of the wellbore may receive production casing strings having diameters of 7 inches and 4 and 1/2 inches, respectively. When the cementing operation is completed and the cement sets, there is a column of cement in the annulus described by the outer surface of each casing string.

Subterranean zones penetrated by wellbores are typically sealed by hydraulic cement compositions. In such applications, hydraulic cement compositions are used to secure pipe strings, such as casings and liners, in the wellbore. In performing these primary cementing operations, a hydraulic cement composition is pumped into an annular space defined by the borehole wall and the outer surface of the tubular string disposed therein. The cement composition is allowed to cure in the annular space to form an annular sheath of hardened substantially impermeable cement that supports and positions the pipe string in the wellbore and seals the outer surface of the pipe string to the wall of the wellbore. Hydraulic cement compositions are also used in various other cementing operations, such as sealing a high permeability zone or fracture in a subterranean zone, plugging a crack or hole in a pipe string, and the like.

Casing assemblies comprising more than one casing string describe one or more annular volumes between adjacent concentric casing strings within the wellbore. Typically, each annular volume is at least to some extent filled with the fluid present in the wellbore when the casing string is installed. In deep wells, the amount of fluid within the annular volume (i.e., the annular fluid) may be substantial. Each annulus 1 inch thick by 5000 feet long will contain approximately 50,000 gallons, depending on the diameter of the casing string.

In oil and gas wells it is not uncommon that a portion of the formation must be isolated from the rest of the well. This is typically achieved as follows: the top of the cement column of the subsequent string is brought up into the annulus above the previous casing shoe. When this isolates the formation, the cement is brought up inside the casing shoe, which effectively blocks the safety valve provided by the natural fracture gradient. Instead of leaking at the shoe, any pressure build-up will be exerted on the casing unless it can bleed at the surface. Most land wells and some offshore platform wells are equipped with wellheads that provide access to each casing annulus and can quickly vent the apparent pressure rise. On the other hand, most subsea wellhead installations do not provide access to the casing annulus and may create a sealed annulus. Because the annulus is sealed, the internal pressure may increase significantly in response to the increase in temperature.

The fluid in the annular volume will typically be at or near the ambient temperature of the seafloor during installation of the casing string. When the annular fluid is heated, it expands and may cause a substantial pressure increase. Such conditions are typically present in all production wells, but are most pronounced in deep water wells. Deep water wells are likely to be damaged by annulus pressure buildup because of the low temperature of the displacement fluid compared to the high temperature of the production fluid during production. The temperature of the fluid in the annular volume (when it is sealed) will typically be ambient temperature, which may be in the range of 0-100 ° f (e.g. 34 ° f), with lower temperatures most commonly occurring in subsea wells with considerable water depth above the well. During production from a reservoir, produced fluids pass through production tubing at relatively high temperatures. Temperatures of 50F-300F are contemplated and temperatures of 125F-250F are often encountered.

The higher temperature of the produced fluid increases the temperature of the annular fluid between the casing strings and increases the pressure to each casing string. Conventional liquids for annular volumes expand with temperature at constant pressure; in a constant volume of the annular space, the increased fluid temperature results in a significant pressure increase. At constant pressure, aqueous fluids that are substantially incompressible may increase in volume by more than 5% during the temperature change from ambient conditions to production conditions. At constant volume, this increase in temperature can result in an increase in pressure up to about 10,000 psig. The increased pressure significantly increases the probability of casing string failure with catastrophic consequences to the operation of the well.

What is needed is a method of replacing at least a portion of a conventional fluid within an annular volume with a fluid system that decreases in specific volume as the temperature of the fluid increases. The problem of Annulus Pressure Buildup (APB) is well known in the oil drilling/production industry. See: moe and p. edition, "Annular pressure build: what it is and What to doabout it, "deep water Technology, p.21-23, August (2000) and P.Oudeman and M.Kerem," Transmission floor of annular pressure in HP/HT wells, "J.of Petroleum Technology, v.18, No.3, p.58-67 (2005). Several possible solutions have been reported previously: A. such as "Practical and Practical preliminary prevention of Annular Pressure filtration on the Marlin Project," Practical and Practical-SPE analytical Technical reference and acceptance, p.1235-1244, (2002) injection of a nitrogen-foamed cement barrier, B. such as "Application of Vacuum-Insulated tubular filtration Pressure," J.H.Azzol et al, Vacuum-Insulated pipes, such as "Practical-SPE analytical Technical reference and acceptance, p.1899-1905(2004), C. such as" C.P.Leach and A.J.Adams, "for A novel analytical Control of Annular Pressure filtration, (79826) extrusion of a cement-permeable barrier, such as" cement-permeable barrier "(" cement-permeable barrier "; or" permeable barrier "; preferably" cement-permeable barrier "; and extrusion;" filtration barrier "; and filtration of" cement-permeable barrier "; and" filtration barrier "; such as" filtration barrier "; and filtration of the" filtration membrane filtration of the "cement-filtration of the" cement-filtration of the "and extrusion, such as" filtration of the "cement-filtration of the" filtration of the "filtration of the, reinforced casing (stronger) and the use of compressible fluids, and e.g. using burst disk assemblies as described in j.staudt, U.S. patent #6,457,528(2002) and U.S. patent #6,675,898 (2004). These prior art examples, while potentially useful, do not provide complete protection against APB problems due to implementation difficulties or prohibitive costs, or both. Our invention is relatively easy to implement and cost effective.

Disclosure of Invention

Accordingly, there is provided a method of controlling pressure within a confined volume, the method comprising:

a) providing a volume having a first fluid therein, the first fluid having a first pressure and a first temperature;

b) replacing at least a portion of the first fluid within the volume with a second fluid;

c) sealing the volume to create a confined volume;

d) heating the fluid within the confined volume to bring the fluid to a second pressure and a second temperature,

wherein the second fluid is preselected such that the second pressure is lower than the pressure at the second temperature when the confined volume contains only the first fluid.

In a separate embodiment, a method of controlling pressure within a casing structure of a wellbore is provided, wherein the pressure may vary depending on location within the wellbore. In this embodiment, the pressure and temperature relate to a single location within the annular volume. Thus, the method comprises:

a) providing an annular volume described by two casing strings within a wellbore and containing a first fluid having a first pressure and a first temperature at a selected location within the annular volume;

b) replacing at least a portion of the first fluid within the annular volume with a second fluid;

c) sealing the annular volume to create a confined volume; and

d) heating the fluid within the confined volume so that the fluid at the selected location is at a second pressure and a second temperature,

wherein the second fluid is preselected such that the second pressure at the selected location is lower than the pressure at the selected location within the confined volume when the confined volume contains only the first fluid at the second temperature.

In one embodiment, the second pressure present at the selected location within the annular volume at the second temperature is equal to the first pressure at the location, despite the increased temperature of the fluid within the annular volume. In another embodiment, the second pressure at the selected location is at most 50%, preferably at most 30%, more preferably at most 15% higher than the first pressure at the selected location.

In a separate embodiment, the method involves a maximum pressure within the annular volume. For an annular volume of substantial vertical length, the hydrostatic pressure created by the annular fluid causes a pressure gradient across the vertical distance, with the pressure at the deepest location of the annular volume being greater than the pressure at the top of the wellbore, where the location relates to the center of the earth. Thus, there is a location within the annular volume where the pressure is the highest pressure. Accordingly, in this embodiment, there is provided a method of controlling maximum pressure within a casing structure of a wellbore, the method comprising:

a) providing an annular volume described by two casing strings within a wellbore and containing within the annular volume a first fluid having a first maximum pressure at a first temperature;

b) replacing at least a portion of the first fluid within the annular volume with a second fluid;

c) sealing the annular volume to create a confined volume; and

d) heating the fluid within the confined volume to an elevated temperature above the first temperature such that at least a portion of the fluid is at a second maximum pressure;

wherein the second fluid is preselected such that the second highest pressure is lower than the highest pressure within the confined volume when the confined volume contains only the first fluid at the elevated temperature.

In one embodiment, the second highest pressure within the annular volume is equal to the first highest pressure. In this embodiment, there is no net pressure increase within the sealed annular volume despite the increased temperature of the fluid within the annular volume. In another embodiment, the second highest pressure is at most 50%, preferably at most 30%, more preferably at most 15% higher than the first highest pressure.

In another independent embodiment, a method of controlling pressure within a confined volume is provided, the method comprising:

a) providing a volume containing a first fluid and a second fluid, the first and second fluids being at a first pressure and a first temperature;

b) sealing the volume to create a confined volume;

c) heating the first fluid and the second fluid within the confined volume to bring the first fluid and the second fluid to a second pressure and a second temperature,

wherein the second fluid is preselected such that the second pressure is lower than the pressure at the second temperature when the confined volume contains only the first fluid.

In a particular embodiment, the second fluid comprises a monomer that polymerizes with a concomitant reduction in volume at a temperature and pressure in accordance with the conditions within the sealed annular volume. Accordingly, there is provided a method of controlling pressure within a confined volume comprising:

a) providing a volume containing a first fluid, a portion of which is at a first pressure and a first temperature;

b) replacing at least a portion of the first fluid within the volume with a second fluid;

c) sealing the volume to create a confined volume;

d) heating the fluid within the confined volume such that at least a portion of the fluid within the confined volume is at a second pressure and a second temperature,

wherein the second fluid comprises a monomer that polymerizes at a second pressure and a temperature in a range between the first temperature and the second temperature.

Among other factors, the present invention is based on the discovery of fluid systems having unusual thermal expansion properties, as the fluid expands at constant pressure to a lesser extent than would be expected for an incompressible fluid. Thus, while confined in the sealed volume, the fluid of the present invention, when heated, causes a lower pressure increase within the sealed volume than would be expected for a conventional fluid.

Drawings

Figure 1 shows an embodiment of the method of the invention showing an open annular volume during which a second fluid is being added to the annular volume.

Fig. 2 illustrates one embodiment of the inventive method, showing a sealed annular volume containing a second fluid disclosed herein at a second temperature and a second pressure.

Figure 3 shows the results of an experiment testing one embodiment of the present invention.

Fig. 4 shows the results of an experiment testing one embodiment of the present invention.

Detailed Description

The present invention provides a fluid system that increases in pressure when heated within a confined volume to a lower value than conventional systems. The confined volume is sealed to prevent escape of fluid. The present invention therefore provides fluids and methods for reducing the effect of pressure increase within a sealed or confined volume when the fluid within the volume is heated to an elevated temperature.

In one embodiment, the volume may be any fluid-containing volume that is sealed and then heated. A non-limiting example of a volume of the present invention is a reaction vessel for performing, for example, a chemical reaction. The volume (initially filled with the first fluid) is open, meaning that fluid can be made to enter and leave the volume. A second fluid is caused to enter the volume, thereby displacing at least a portion of the first fluid in the volume, before the volume is sealed. The volume is then sealed to prevent further flow of fluid into and out of the volume, and the fluid within the volume is heated. This heating causes the pressure within the volume to increase to a considerable extent, particularly with liquid phase fluids, and more particularly with liquid phase fluids that are substantially incompressible. The invention therefore provides a second fluid having the property that, when contained within a sealed volume and heated to a target temperature, the pressure within that volume is lower than when that volume contains only the first fluid.

In a particular embodiment, the present invention provides a method of controlling pressure within an annular volume within a wellbore, particularly within a casing assembly that has been installed in a wellbore intended to extract resources, for example, from a reservoir. Examples of resources include crude oil, natural gas liquids, petroleum vapors (e.g., natural gas), syngas (e.g., carbon monoxide), other gases (e.g., carbon dioxide, nitrogen), and water or aqueous solutions.

The casing assembly includes a casing string for protecting the sides of a wellbore formed by drilling into the earth. The annular volume is bounded by two adjacent concentric casing strings within the casing assembly. During the construction of oil and gas wells, rotary drilling rigs are typically used to drill into subterranean earth formations to form a wellbore. As the rotary drill rig drills into the earth, drilling fluid (referred to in the industry as "mud") is circulated through the wellbore. The mud is typically pumped from the surface through the interior of the drill pipe. By continuously pumping drilling fluid through the drill pipe, the drilling fluid may flow out of the bottom of the drill pipe and back to the well surface via the annular space between the borehole wall and the drill pipe. When certain geological information is desired and when the mud is to be recycled, it is typically returned to the surface. The mud is used to help lubricate and cool the drill bit and to facilitate the removal of cuttings as the borehole is drilled. In addition, the hydrostatic pressure created by the column of mud in the hole prevents blow-outs that may occur due to the high pressures encountered within the wellbore. To prevent blowout caused by high pressure, weights are put into the mud so that the mud has a hydrostatic pressure greater than any pressure expected in drilling.

Different types of mud must be used at different depths because the pressure in the wellbore increases as the depth of the wellbore increases. For example, the pressure at 2,500ft is much higher than the pressure at 1,000ft. Mud used at 1,000ft may not be heavy enough to be used at a depth of 2,500ft and blow out may occur. The weight of the mud at extreme depths in subsea wells must be particularly heavy to counteract the high pressure. However, the hydrostatic pressure of this particularly heavy mud may cause the mud to begin to invade or leak into the formation, thereby creating lost circulation of the mud. Casing strings are used to line the wellbore to prevent leakage of drilling mud.

To enable the use of different types of mud, different casing strings are employed to eliminate the wide pressure gradient that occurs in the wellbore. To begin, a borehole is drilled using a light mud to a depth where a heavy mud is required. This typically occurs slightly over 1,000ft. At this stage, a casing string is inserted into the wellbore. A cement slurry is pumped into the casing and a plug flow of fluid, such as drilling mud or water, is pumped behind the cement slurry to push the cement into the annulus between the exterior of the casing and the interior of the wellbore. The amount of water used to form the cement slurry will vary over a wide range depending on the type of hydraulic cement selected, the desired consistency of the slurry, the strength requirements of the particular job and the general job conditions at hand.

Typically, hydraulic cement, especially portland cement, is used to secure the well casing within the wellbore. Hydraulic cements are cements that set and exhibit compressive strength due to the occurrence of a hydration reaction that allows them to set or cure underwater. The cement slurry is allowed to set and harden to secure the casing in place. The cement also provides zonal isolation of the subsurface formation and helps prevent collapse or erosion of the wellbore. After setting the first casing, drilling continues until the wellbore is again drilled to a depth where heavy mud is needed and the needed heavy mud will begin to invade and leak into the formation, typically at about 2,500 feet. Again, a casing string is inserted into the wellbore inside the previously installed casing string and cement slurry is added as before.

Multiple casing strings may also be used in a wellbore to isolate two or more formations that should not be in communication with each other. For example, a special case found in the gulf of mexico is high pressure freshwater sand flowing at a depth of about 2,000 feet. Due to the high pressures, additional casing strings are often required at that level. Otherwise, the sand will leak into the mud or production fluid. A subsea wellhead typically has an outer housing secured to the seafloor and an inner wellhead housing received within the outer wellhead housing. During completion of an offshore well, casing and tubing hangers are lowered into a support location within the wellhead housing via a blowout preventer stack (BOP stack) mounted above the housing. After completion of the well, the bop stack is replaced with a Christmas tree (Christmas tree) with appropriate valves for controlling production of well fluids. The casing hanger is sealed from the casing bore and the tubing hanger is sealed from the casing hanger or casing bore so that a fluid barrier is effectively formed in the annulus between the casing and the tubing string and the casing bore above the tubing hanger. After deployment and sealing of the casing hanger, casing annulus seals are installed for pressure control. If the seal is on the surface wellhead, typically the seal may have a port communicating with the casing annulus. However, in a subsea wellhead housing, there is a large diameter low pressure housing and a smaller diameter high pressure housing. Because of the high pressure, the high pressure housing must be free of any ports for safety. Once the high pressure casing is sealed, there is no way for a hole to be made under the casing hanger for blowout prevention.

Representatively illustrated in fig. 1 is a method of practicing the principles of the present invention. In the following description of the methods and other apparatus and methods described herein, directional terms, such as "above," "below," "upper," "lower," etc., are used for convenience in referring to the accompanying drawings. Moreover, it is to be understood that the various embodiments of the invention described herein can be used in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention. The methods described herein may be applied to wellbores in both land and underwater locations. It should be understood that the wellbore terminates at the end of the wellbore that enters the earth. In the case of an underwater location, the endpoint is at the water/land interface.

It should be understood that the terms "wellbore" and "casing string" as used herein should not be construed to limit the present invention to the particular illustrated components of the method. A wellbore may be any wellbore, such as a branch of another wellbore, and does not necessarily extend directly to the surface. The casing string may be any type of tubular string, such as a liner string, etc. The terms "casing string" and "liner" are used herein to refer to any type of tubular string, such as a segmented or non-segmented tubular string, a tubular string made of any material (including non-metallic materials), and the like. Accordingly, the reader will appreciate that these and other descriptive terms, as used herein, are merely for convenience in explaining exemplary embodiments of the present invention and are not intended to limit the scope of the invention.

Figure 1 shows one embodiment of the present invention. The wellbore 10 has been drilled using a drill string 50, and a casing assembly 20 has been pre-installed, comprising at least two casing strings concentrically arranged with respect to each other. Not shown is a drilling rig having a support device for supporting a drill string, installing a casing string and supplying fluid to the wellbore. In FIG. 1, a casing string 22 has been installed and sealed at or near one end opposite the wellbore 10 by a cement plug 24.

Attention is now directed in particular to casing string 40 which has been installed to extend to wellbore destination 34. It will be apparent that the termination point 34 may be a temporary termination point so that the wellbore may be extended further after the casing string 40 is installed. Alternatively, the casing string 40 may be run to the final depth in the formation 5 and the wellbore is not run until production begins. When casing string 40 is installed, an annular volume 42 defined by the inner surface of casing string 22 and the outer surface of casing string 40 is filled with a fluid, and is typically filled with the fluid present within wellbore volume 36. Conventional fluids that may be initially present in the annular volume include drilling fluids or completion fluids, depending on the environment of the drilling operation. The properties of the fluid (referred to herein as the first fluid) initially within the annular volume are selected to meet the needs of a drilling professional drilling the well to complete the well. In one embodiment, the first fluid is an incompressible fluid using conventional definitions.

At a stage in the method shown in fig. 1, the annular volume 42 is in fluid communication with the wellbore volume 36 via an opening 44 at one end of the casing. The other end of the annular volume, indicated at 46, is in fluid communication with surface equipment, such as a drilling rig (not shown), which has means to recover fluid exiting the annular volume via 46. Environmental concerns provide incentive to minimize the amount of fluid lost to the environment via 46.

In the present method, a second fluid is introduced into the wellbore volume 36 via the opening 48 to displace at least a portion of the first fluid in the annular volume 42. The opening 48 is in fluid communication with the means for supplying the second fluid. For example, a pumping device may be provided on a drilling or workover rig for this purpose. The second fluid is supplied to the volume as a plug flow or slug and passes down through the wellbore volume 36 in a relatively pure form. At the wellbore terminus 34, the second fluid enters the annular volume 42 via opening 44 and flows upward, driving the first fluid initially in the annular volume 42 ahead of the second fluid slug and exiting the annular volume via opening 46. The amount of second fluid supplied to the annular volume is a matter of engineering choice, depending on the amount of pressure that can be tolerated inside the sealed annular volume 42. Such amount is further influenced by, for example, the size of the well system, the temperature of the second fluid when supplied to the annular volume, the temperature of the fluid to be produced in the well, the expected temperature of the fluid in the annular volume during production, the design and specifications of the casing string, etc.

After a sufficient amount of the second fluid has been added to the annular volume 42 to replace at least a portion of the first fluid contained therein, the annular volume 42 is sealed. Figure 2 shows an annular volume 42 sealed by a cement plug at 26 and a casing annulus plug at 28. Typically, casing annulus seals seal the top of the wellbore, preventing fluid from escaping from the wellbore to the environment. Thus, the sealed or confined volume represented by the annular volume 42 of the casing string contains fluid that is confined in place and prevented from leaking from the volume to any significant extent.

In the embodiment shown in fig. 2, at least a portion of a first fluid contained within a volume, such as annular volume 42, and having a first pressure and a first temperature within the volume is replaced with a second fluid such that the volume is filled with the combination of the first and second fluids. The annular volume 42 between the casing strings 22 and 40 is sealed by the cement plug 26 and casing annulus plug 28. The temperature of the fluid containing the second fluid within the annular volume 42 is typically in the range of 0-100 ° f. For subsea installations, the fluid temperature (i.e., the first temperature) is typically less than 60 ° f, or less than 40 ° f, or, for example, in the temperature range of 25 ° f to 35 ° f.

When hydrocarbon fluids begin to be produced and flow upward through the production conduit 52 and out of the wellbore 10, these fluids are typically at a higher temperature than the first temperature. Production fluid temperatures of 50-300 ° f are contemplated and temperatures of 125-250 ° f are often encountered. The hotter production fluid in the conduit 52 heats the fluid in the confined annular volume 42 to a second pressure and a second temperature. In conventional systems, the fluid pressure within the sealed annular volume will begin to increase to significantly higher pressures as the temperature increases. In contrast, according to the present invention, the second fluid is preselected such that after the temperature of the fluid within the confined volume is increased to a second temperature, the second pressure within the confined volume is lower than when the confined volume contains only the first fluid at the second temperature.

The benefits and advantages obtained from the practice of the present invention are in contrast to the deficiencies of conventional processes. The annular volume is initially filled with a first fluid. The temperature of the first fluid may be at or below ambient temperature, depending on the conditions of the wellbore during the addition of the first fluid. For a subsea wellbore, a first fluid may be cooled by water, through which the first fluid flows en route to the wellbore from a source at the drilling platform. Under these conditions, the first fluid will typically be at a temperature in the range of 0-100 ° f. For subsea installations, the fluid temperature (i.e., the first temperature) is typically less than 60 ° f, or less than 40 ° f, or, for example, in the temperature range of 25 ° f to 35 ° f. After the fluid is sealed within the annular volume, it is heated by production fluid passing up through the production tubing 52 in the wellbore; elevated temperatures often result in increased pressures, sometimes to a catastrophic extent.

Annulus pressure

Instead, this pressure within the annular volume is controlled to a manageable degree by the method of the invention. In the practice of the present invention, a confined volume containing a fluid is heated so that the fluid within the confined volume is at a second pressure and a second temperature. In one embodiment, the second pressure is uniform throughout the confined volume. In another embodiment, the second pressure may be different from place to place within the volume. In this embodiment, therefore, the second pressure (and second temperature) is referenced to a particular location within the annular volume, referred to as a selected location. For example, an annular volume within a casing assembly in a wellbore may have a vertical depth of hundreds, or even thousands of feet. The hydrostatic pressure within the fluid-filled wellbore is therefore expected to be higher at the bottom of the wellbore than at its top. In another embodiment, therefore, the method of the present invention involves controlling the maximum pressure within the annular volume, taking into account the hydrostatic head within that volume and other factors.

For the purposes of this disclosure, the target pressure is the pressure required within the annular volume during the practice of the invention. In one embodiment, the target pressure in the practice of the invention is a second pressure that is lower than when the confined volume contains only the first fluid. In another embodiment, the second pressure is equal to the first pressure within the annular volume. In another embodiment, the second fluid is preselected such that a second pressure of the second fluid contained within the sealed annular volume at the second temperature is at most 50%, preferably at most 30%, more preferably at most 15% higher than a first pressure of an unsealed annular volume at the first temperature and containing only the first fluid.

In many cases, the first pressure, the first temperature, the second pressure, and the second temperature may be measured and the respective values may be known. However, those skilled in the art will recognize that the invention may be fully practiced without knowledge of the numerical values of these parameters. It is sufficient for the practice of the invention that the second pressure be maintained at less than the pressure limit at which the integrity of the vessel (e.g., casing string) in which the fluid is contained would be compromised to an unacceptable degree.

Second fluid system

As used herein, the fluid added to the annular volume to control the pressure within the annular volume is referred to as the second fluid or, in the alternative, as the annular fluid. Thus, the second fluid has thermal expansion properties which cause a lower pressure increase within the annular volume than would be expected for a substantially incompressible liquid. The fluid present in the wellbore volume 36 during installation of the casing string 40, and thus the fluid initially within the annular volume 42 when the casing string is installed, is referred to as a first fluid. The composition of the first fluid is not critical to the present invention and will generally be one of a variety of fluids used in drilling and completion, including, for example, drilling fluids or completion fluids. The drilling fluid may be water or oil based and may further comprise surfactants, salts, weighting agents and any other materials needed to effectively cool the drill bit, remove cuttings and protect and condition the wellbore for fluid production. Likewise, completion fluids may be water or oil based and may further contain materials used to clean the wellbore and the installed structures in preparation for the production of fluids from the formation.

In the practice of the invention, the first fluid within the annular volume is at least partially replaced by a second fluid. Generally, the second fluid comprises a liquid component and additional components that contribute to the properties described herein. In one embodiment, the second fluid is an incompressible fluid. In a separate embodiment, the combination of the first fluid and the second fluid is an incompressible fluid when using conventional devices. The liquid component may comprise water, hydrocarbons, or both, including, for example, one or more components of the drilling fluid. An aqueous solution containing dissolved organic and/or inorganic salts, acids or bases may be included in the second fluid system. May include hydrocarbon mixtures including materials typically found in drilling fluids or completion fluids. Examples include diesel, C₆-C₂₀Mixtures, alcohols, aldehydes, ketones, ethers, carbonyls, aromatics, paraffins and naphthenes. May include an emulsion having a continuous aqueous phase and a discontinuous organic phase; alternatively, an emulsion having a continuous organic phase and a discontinuous aqueous phase may be included. In addition, the second fluid may comprise a liquid phase as a continuous phase and also solids, which may be present as a slurry or as bulk particles. Alternatively, the second fluid may comprise a liquid as a continuous phase having a layer of a gas phase, or a gas phase in the form of bubbles within a liquid. In another embodiment, the second fluid comprises a liquid, a gas, and a solid phase in any or all of the above forms. In each alternative, the second fluid has unexpected expansion properties with respect to an increase in fluid temperature.

Anhydrous inorganic material

In one embodiment, the second fluid comprises an anhydrous inorganic material in an aqueous carrier fluid. The addition of anhydrous inorganic crystals or materials to the annular volume absorbs excess water into its structure and alleviates the annulus pressure problem. For example, each formula weight of anhydrous calcium sulfate (including industrial types such as gypsum and gypsum board (board-of-paris)) absorbs 10 waters of hydration into its crystal structure. Inorganic compounds such as barium oxide or calcium oxide are also effective, and they also absorb water. Aluminosilicate materials, including crystalline aluminosilicates such as zeolites, dehydrate liquids by trapping water at the molecular level. Examples of zeolites for this application are 3A, 4A, 13X and Y zeolites. These zeolites do not expand after hydration and, in fact, release air during the process. Any air released during hydration will be introduced into the confined annular volume. Because air is compressible, the air pockets created by the hydrated zeolites provide a pressure buffer when the fluid in the annular volume is heated.

In a preferred embodiment of the invention, the pellets of water-absorbing inorganic compound may be encapsulated with any material that can slowly dissolve in the retentate, such as a slowly soluble polymer, so that the reaction can be delayed enough to provide a cycle time before the absorbent action is exerted. This may also be effective in binary or ternary systems where water is a minor component of the trapped mixture (e.g., 6% water, with the remainder being mineral oil or other such blend). Non-limiting examples of slowly soluble polymers include poly (vinyl alcohol), carboxymethyl cellulose, and gelatin.

In a separate embodiment, at least a portion of the inorganic material supplied to the annular volume in the second fluid comprises zirconium tungstate or zirconium molybdate having a negative coefficient of thermal expansion.

Crosslinked polymeric materials

In a separate embodiment, one or more crosslinked organic/polymeric materials are included in the annular fluid of the present invention to counteract the pressure increase when heating the annular fluid within the sealed volume. Any dimensionally stable open cell foam material (e.g., polystyrene foam and polyurethane foam) may be suitable for this purpose. The effectiveness of the polymeric material in counteracting the effects of increased pressure is enhanced when coated with a slowly soluble polymer. In this way, the polymeric material coated with the slowly soluble polymer is introduced into the annular volume. After cementing, the slowly soluble polymer dissolves, exposing the crosslinked polymer to the annular fluid. Increasing the pressure causes the crosslinked polymer to wrinkle, which both reduces the pressure within the annular volume and drives out the vapors originally trapped within the crosslinked polymer. Both the wrinkling of the polymer and the generation of compressed gas contribute to the pressure reduction in the annular volume.

Polymerization system

In a separate embodiment, a method of controlling pressure within a confined volume is provided as follows: providing a second fluid comprising a monomer that polymerizes at a second pressure and a temperature in a range between the first temperature and the second temperature, with a concomitant reduction in specific volume. According to this embodiment, the pressure within the sealed annular volume is reduced when heated due to the polymerization of the monomer added to the annular fluid prior to sealing the annular volume. When added to the annular volume, both water-soluble monomers and water-insoluble monomers can polymerize with a concomitant volume reduction (associated pressure drop within the annular volume). In the confined volume of the sealed annulus, such a reduction in volume will result in a reduction in pressure within the confined volume relative to a similar system without polymerization of the particular monomers of the invention,

the monomers of the invention may be mixed with water, oil or more complex mixtures having the characteristics of drilling muds, including the high density component of the second fluid preparation. The monomer will be present in the second fluid in an amount of from 1 to 99 vol%, more preferably from 5 to 75 vol%, still more preferably from 10 to 50 vol%. Example the second fluid comprises 20 vol% monomer and 80 vol% of a second component comprising water and a high density material such as barium sulphate.

As monomers polymerize, including acrylates, such as methyl acrylate and methyl methacrylate, volume shrinkage between liquid monomers and solid polymers of up to 25% may result from this polymerization process. See, for example，＂Acrylic and Methacrylic EsterPolymers＂，Encyclopedia of Polymer Science and EngineeringSecond edition, j.kroschwitz, ed., John Wiley&Sons, inc., vol.1, table 20, p.266, (1985) and d.a.tildebrook et al, "diagnosis of polymerization Shrinkage Using Molecular Modeling," j.poly.sci; part B: the molecular weight of the Polymer Physics,41,528-548(2003). In a preferred embodiment of the invention, the monomer is suspended or emulsified (using soap) in water as a water/oil mixture containing a suitable polymerization initiator, pumped into the annular space, and after cementation, polymerization occurs (again, using slow kinetics at near setting temperature), wherein a total volume reduction of up to 5% can be achieved with a 20% vol/vol mixture of monomer and water. Non-limiting examples of other vinyl monomers that may be useful in such in situ polymerization processes include other acrylic esters, methacrylic esters, butadiene, styrene, vinyl chloride, N-vinyl pyrrolidone, N-vinyl caprolactam, or other such oil and/or water soluble monomers.

Additional benefits may be obtained from the selection of initiators for the polymerization process. Azo-type initiators generate nitrogen as a by-product during the polymerization process. The resulting gas phase component (due to being a compressible fluid) produced in the confined annular volume can help control the pressure within the confined annular volume as the annular fluid is being heated by the product fluid passing through the production tubing. Peroxide initiators may also be used depending on the temperature and chemical inhibition of the product fluid. Alternatively, if encapsulated as described above to control the timing at which polymerization occurs, a redox initiator system such as ammonium persulfate and the activator N, N, N 'N' -tetramethylethylenediamine, or potassium persulfate and the activator ferrous sulfate/sodium bisulfite may also be used.

Gas generating material

In another embodiment, the addition of gas generating material provides a compressible gas pocket that alleviates the annulus pressure problem. Examples of gas generating materials useful in the present invention include citric acid and bicarbonate (in a 1:2 weight ratio) combined with a small amount of witch hazel extract into a moldable product that evolves carbon dioxide gas when hydrated with water. Preferably, pellets of such material are coated and/or encapsulated with the above-described slow water soluble polymer. In using these pellets in the practice of the present invention, the coated pellets are pumped into an annular volume which is then sealed as described. The "timed release" of the pellets produces an exhaust gas that is trapped at a high level in the annular volume.

Binary fluid system

In another embodiment, the second fluid system is a binary fluid system comprising two liquids having a negative blending volume factor. By negative blending volume factor is meant having the property that when the two liquids are blended together the volume of the blended liquid is less than the total volume of the two liquids prior to blending. Example fluids having this particular property include blends of alcohols with aqueous fluids. Example alcohols include C₁-C₈An alcohol; preferred alcohols are methanol, ethanol, propanol and butanol. In this case, the aqueous fluid may be drilling fluid present in the annular volume after installation of the casing string.

It is important (as stated) to maintain the alcohol as a separate phase until the annular volume is sealed, and then form a blend containing the second liquid. In one embodiment, the alcohol is pumped into the annular volume as a relatively pure plug flow; wherein substantial mixing of the alcohol phase and the aqueous phase occurs within the annular volume after sealing the annular volume. Alternatively, the alcohol is encapsulated with any material that can be slowly dissolved in the retentate, such as a slowly soluble polymer, so that mixing of the two phases is delayed enough to ensure that mixing occurs after the volume is sealed. Non-limiting examples of slowly soluble polymers include poly (vinyl alcohol), carboxymethyl cellulose, and gelatin.

Thus, before or during heating of the annular volume during hot fluid production, the slowly soluble polymer dissolves and the alcohol phase mixes with the water phase, resulting in a pressure within the annular volume that is lower than the pressure that would exist if the alcohol phase were added as described. In carrying out this embodiment, an alcohol phase is added in an amount up to 90%, preferably from 5 vol% to 80 vol%, more preferably from 10 vol% to 50 vol%, based on the total volume of liquid in the annular volume, depending on the particular application.

Examples

Laboratory experiments confirmed the effective volume shrinkage of the methyl methacrylate mixture in the emulsion polymerization process and by the following example, the process proved to be effective in an apparatus that maintained the volume constant while monitoring the pressure during the heating cycle (example 1), and in field trials using a 500 foot test well (example 2).

Example 1

The pressure gauge was filled with an aqueous fluid at 200psig starting pressure. The downhole gauge was then sealed to prevent fluid from escaping from the vessel and heated from 24 ℃ to 100 ℃. As shown in FIG. 3, the pressure of the fluid within the downhole gauge increased to 14,000psig during the heating cycle.

The downhole pressure gauge used above was filled at 200psig start-up pressure with an aqueous emulsion fluid containing 20% by volume loading of methyl methacrylate (with azo-type initiator). The gauge was then sealed to prevent fluid from escaping the gauge and heated from 24 ℃ to 100 ℃. As shown in FIG. 3, the pressure of the fluid within the downhole gauge increased to about 3000psig, but at a lower rate than the aqueous fluid alone. At about 70 ℃, polymerization of the methyl methacrylate monomer was initiated and the pressure within the downhole pressure gauge was reduced to less than the initial pressure within the downhole pressure gauge.

Example 2

Scale up field trials were also performed. Water was used for a 500 foot deep test well in the annular space bounded by 7 inch and 9 and 5/8 inch casing. After placing the fluid, the annular space was pre-pressurized to 500psig and then heated by circulating hot water inside the 7 inch tube. Over a 2 hour period, the temperature input was 190 ° f and the temperature output was 160 ° f (due to the heat absorbed by the lower-hole formation). The resulting pressure was about 2100psig (figure 4).

A similar emulsion fluid as described in example 1, containing 20% by volume loading of methyl methacrylate (with azo-type initiator), was used for the same test well. Within minutes after the initial 500 pre-pressurization, it was noted that the pressure had dropped to zero, so the annulus was again pressurized to 500 psig. Over 2 hours, the temperature rose as before, and it was noted that the input and output temperatures were almost the same due to the heat generated by the polymerization reaction. The pressure was again reduced to zero and then slowly increased to a final stable pressure of 240psig (figure 4). The significant drop in pressure is due to monomer to polymer shrinkage. Samples collected at the end of the experiment were analyzed for monomers and polymers. The presence of trace amounts of monomer (< 1%) was confirmed and the polymer had a weight average molecular weight of nearly 3 million.

Claims (42)

1. A method of controlling pressure within a confined volume comprising:

a) providing a volume containing a first fluid, the first fluid having a first pressure and a first temperature within the volume;

b) replacing at least a portion of the first fluid within the volume with a second fluid;

c) sealing the volume to create a confined volume;

d) heating the fluid within the confined volume to bring the fluid to a second pressure and a second temperature;

wherein the second fluid is preselected such that the second pressure is lower than the pressure at the second temperature when the confined volume contains only the first fluid.

2. The method of claim 1, wherein the volume is an annular volume.

3. The method of claim 1, wherein the annular volume is described by two concentric casing strings within the wellbore.

4. The method of claim 1, wherein the first temperature is from 0 ° f to 100 ° f.

5. The method according to claim 1, wherein the second temperature is in the range of 50 ° f to 300 ° f.

6. The method according to claim 5, wherein the second temperature is in the range of 125 ° F to 250 ° F.

7. The method of claim 1, wherein the fluid within the confined volume of step (c) is at a first pressure and a first temperature.

8. The process according to claim 1, wherein the first pressure is the maximum pressure of the first fluid within the volume of step (a), wherein the second pressure is the maximum pressure of the fluid within the volume of step (d).

9. The method of claim 1, wherein a first pressure of the fluid within the volume of step (a) at a first temperature is at a selected location within the volume, and wherein a second pressure of the fluid within the volume of step (d) at a second temperature is at the selected location within the volume.

10. The method according to claim 1, wherein the second fluid comprises at least one anhydrous inorganic material.

11. The method according to claim 10, wherein the anhydrous inorganic material is selected from the group consisting of calcium sulfate, barium oxide, calcium oxide, zeolite 3A, zeolite 4A, zeolite 13X, and zeolite Y.

12. The method according to claim 10, wherein the at least one anhydrous inorganic material is encapsulated in a slowly soluble polymer.

13. The method according to claim 12, wherein the slowly soluble polymer is selected from the group consisting of poly (vinyl alcohol), carboxymethyl cellulose, and gelatin.

14. The method of claim 1, wherein the second fluid comprises a porous foam material.

15. The method according to claim 14, wherein the cellular foam material is selected from the group consisting of polystyrene and polyurethane foam.

16. A method according to claim 14, wherein the porous foam material is encapsulated in a slowly soluble polymer.

17. The method of claim 1, wherein the second fluid comprises a monomer that polymerizes at the second pressure and at a temperature in a range between the first temperature and the second temperature.

18. The method according to claim 17, wherein the monomer polymerizes with a decrease in pressure within the confined volume.

19. The method according to claim 18, wherein the monomer is selected from the group consisting of acrylates and methacrylates.

20. The process according to claim 19, wherein the polymerization process is initiated by an initiator selected from the group consisting of: azo type initiators, peroxide initiators, or ammonium persulfate/N, N, N ', N' -tetramethylethylenediamine redox initiator systems.

21. The method of claim 1, wherein the second fluid comprises a gas generating material.

22. The method of claim 21, wherein the gas generating material is a combination of citric acid and bicarbonate.

23. The method of claim 22, wherein the gas generant material is encapsulated in a slowly soluble polymer.

24. The method according to claim 23, wherein the slowly soluble polymer is selected from the group consisting of poly (vinyl alcohol), carboxymethyl cellulose, and gelatin.

25. The method of claim 1, wherein the second fluid comprises a binary fluid system comprising an aqueous fluid and an alcohol.

26. The method according to claim 25, wherein the alcohol is selected from C₁-C₈An alcohol.

27. The method according to claim 25, wherein the binary fluid system comprises 5 vol% to 80 vol% alcohol.

28. The method according to claim 25, wherein the alcohol within the second fluid is isolated from the water phase until the annular volume is sealed.

29. The method according to claim 25, wherein the alcohol introduced into the second fluid is encapsulated with a slowly soluble polymer.

30. A method of controlling pressure within a casing structure of a wellbore, comprising:

a) providing an annular volume described by two casing strings within a wellbore and containing a first fluid having a first pressure and a first temperature at a selected location within the annular volume;

b) replacing at least a portion of the first fluid within the annular volume with a second fluid;

c) sealing the annular volume to create a confined volume;

d) heating the fluid within the confined volume so that the fluid at the selected location is at a second pressure and a second temperature;

wherein the second fluid is preselected such that the second pressure at the selected location is lower than the pressure at the selected location within the confined volume when the confined volume contains only the first fluid at the second temperature.

31. The method according to claim 30, wherein the second pressure is at most 50% higher than the first pressure.

32. The method according to claim 30, wherein the second pressure is at most 30% higher than the first pressure.

33. The method according to claim 30, wherein the second pressure is at most 15% higher than the first pressure.

34. The method of claim 30, wherein the second pressure is equal to the first pressure.

35. A method of controlling pressure within a casing structure of a wellbore, comprising:

a) providing an annular volume described by two casing strings within a wellbore and containing within the annular volume a first fluid having a first maximum pressure at a first temperature;

b) replacing at least a portion of the first fluid within the annular volume with a second fluid;

c) sealing the annular volume to create a confined volume;

(i) heating the fluid within the confined volume to an elevated temperature above the first temperature such that at least a portion of the fluid is at a second maximum pressure;

wherein the second fluid is preselected such that the second highest pressure is lower than the highest pressure within the confined volume when the confined volume contains only the first fluid at the elevated temperature.

36. A method of controlling pressure within a confined volume comprising:

a) providing a volume containing a first fluid and a second fluid, the first and second fluids being at a first pressure and a first temperature;

b) sealing the volume to create a confined volume;

c) heating the first and second fluids within the confined volume to bring the first and second fluids to a second pressure and a second temperature;

wherein the second fluid is preselected such that the second pressure is lower than the pressure at the second temperature when the confined volume contains only the first fluid.

37. A method of controlling pressure in an annular volume within a wellbore, comprising:

a) filling the annular volume with a first fluid;

b) replacing at least a portion of the first fluid with a second fluid within the annular volume, the second fluid comprising a material selected from the group consisting of an anhydrous inorganic material, a polymeric system, and a binary fluid system; and

c) the annular volume is sealed.

38. The method according to claim 37, wherein the anhydrous inorganic material is selected from the group consisting of calcium sulfate, barium oxide, calcium oxide, zeolite 3A, zeolite 4A, zeolite 13X, and zeolite Y.

39. The method of claim 37, wherein the anhydrous inorganic material is selected from the group consisting of zirconium tungstate and zirconium molybdate, the anhydrous inorganic material having a negative coefficient of thermal expansion.

40. The method according to claim 37, wherein the polymerization system comprises an initiator and a monomer selected from the group consisting of acrylates and methacrylates.

41. The method according to claim 40, wherein the initiator is selected from the group consisting of: azo type initiators, peroxide initiators, or ammonium persulfate/N, N, N ', N' -tetramethylethylenediamine redox initiator systems.

42. The method according to claim 37, wherein the binary fluid system comprises an aqueous fluid and an alcohol.