US3664424A - Method for insulating a well - Google Patents

Abstract

An improved method for thermally insulating a well for use in a thermal process for oil recovery. In a process for forming a coating of alkali metal silicate on a tubing string within the well, excess alkali metal silicate solution is displaced from the tubing-well annular space by a fluid having a low solubility for the silicate coating.

Description

United States Patent Penberthy, Jr. et al.

METHOD FOR INSULATING A WELL Walter L. Penberthy, Jr.; Jack H. Bayless; Robert C. West, all of Houston, Tex.

Esso Production Research Company Dec. 21, 1970 Inventors:

Assignee:

Filed:

Appl. No.:

US. Cl ..l66l303 Int. Cl ..E21b 43/24 Field of Search 1 66/288, 302, 303, 57, DIG. l

References Cited UNITED STATES PATENTS Cornelius 166/303 [451 May 23, 1972 Pryor 166/303 Parker Bayless 166/303 Primary Examiner-Robert L. Wolfe Attorney-James A. Reilly, John B. Davidson, Lewis l-l. Eatherton, James E. Gilchrist, Robert L. Graham and James E. Reed [57] ABSTRACT 10 Claims, No Drawings METHOD FOR INSULATING A WELL BACKGROUND OF THE INVENTION 1. Field of the Invention This invention relates to a process for thermally insulating a wellbore. More particularly, the invention relates to a process for removing excess alkali metal silicate solution from a well.

2. Description of the Prior Art Among the more promising methods that have been suggested or tried for the recovery of oil from viscous oil reservoirs are those which introduce thermal energy into the reservoirs. The thermal energy may be in a variety of forms such as hot water, in situ combustion, steam and the like. Each of these thermal energy agents may be useful under certain conditions. However, steam is generally the most efficient and economical and is clearly the most widely employed thermal energy agent.

One thermal oil recovery technique which utilizes steam is the steam-drive process. In this process, steam is injected into one well which drives oil before it to a second producing well. In another method, commonly called the huff-andpuff process, a single well is used for both steam injection and production of oil. The steam is injected through the tubing and into the formation. Injection is then interrupted and the well 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 Following the heat-soak the well is placed on a production cycle and the heated fluids are withdrawn by way of the well to the surface.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 efiective. 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 from the wellbore.

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 as the steam travels through the tubing string, the process is naturally less efficient. On even a shallow well, the thermal losses of the steam during its travel down the tubing may be so high that the initially high temperature superheated or saturated steam will condense into hot water before reaching the formation. Such condensation 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.

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 formation may contact the easing 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 from the injection tubmg.

It has been suggested that'an inert gas, such as nitrogen, be introduced into the annular space between the casing and tubing and pumped down the annulus to the formation. This method requires, however, a source of gas, means for pumping the gas down the annulus, and means for separating the inert gas from the produced well fluids.

A recent proposal has overcome many of the problems of these prior methods of combating excessive heat losses in a well. US. Pat. No. 3,525,399 issued Aug. 25, 1970, to Bayless and Penberthy teaches a method for coating a tubing string with an alkali metal silicate. In this method, the tubing string is run into the well and set in place with a packer. An aqueous solution of a water-soluble silicate is introduced into the annular space between the tubing string and the well. Steam is then injected through the tubing string to raise the temperature of the silicate solution in the annular space above its boiling point. Boiling of the silicate solution removes its water and deposits a coating of alkali metal silicate on the tubing string. The dehydrated silicate coating is a cellular solid or solid foam having a remarkably low thermal conductivity.

While this silicate insulation technique has proven to be remarkably efficient and inexpensive, some difficulty has been experienced in employing the technique. In some instances, particularly in wells of extreme depth, it may not be possible to remove all the liquid :within the annular space by boiling. Thefoam may build up at a rapid rate on the tubing and insulate the annular space so effectively that the temperature of the liquid remaining in the annular space drops below its boiling point. While it has been suggested that this excess liquid may be removed from the annular space by employing a reverse circulating device in the tubing and displacing the remaining solution from the annular space it has been found that this displacement is at times difficult to accomplish. The remaining liquid may be highly viscous and cannot be effectively displaced with a gaseous displacing agent such as natural gas. Nor is water a totally satisfactory displacing agent. Although the dehydrated coating is not instantly soluble in water, it will deteriorate and dissolve when contacted by water for an extended period. Also, the length of time that the coating can resist deterioration by water is reduced by the relatively high temperature existing in the well following boiling of the silicate solution. Since a number of hours would be required to remove a fresh water displacing fluid from the annulus of a deep well, the use of water as a displacing fluid may cause deterioration of the silicate coating.

SUMMARY OF THE INVENTION This invention relates to a process for thermally insulating elements of awell such as the tubing string. An aqueous solution of a water-soluble silicate is introduced into the annular space between the well and the tubing string. Steam is injected into the tubing string to boil the silicate solution and deposit a coating of alkali metal silicate on the tubing string. Excess silicate solution remaining in the annular space is displaced by a fluid having a low solubility for the silicate coating.

DESCRIPTION OF THE PREFERRED EMBODIMENT A preferred use for this invention is in insulating a conventional steam injection well. A brief description of such a well, as might be adapted for the practice of this invention, follows and will aid in the understanding of the invention.

The well is drilled from the surface of the earth to a subterranean oil-bearing formation and is generally lined with a number of joints of large diameter pipe commonly called a casing string. This casing string is cemented in place using conventional techniques and is perforated at the location of the oil-bearing formation to permit fluid communication between the formation and the interior of the casing. A length of small diameter pipe or tubing string is suspended from a wellhead at the surface of the earth and extends through the casing to the vicinity of the oil-bearing formation. Generally, centralizers will be secured to the tubing so that the tubing will be generally concentrically disposed with respect to the casing. A suitable packer, such as a thermal packer, is attached to the tubing string and seals the annular space between the tubing string and the casing at a location above the oil-bearing formation. The lower portion of the tubing string will extend below the packer and will have an opening which will permit the flow of fluids between the tubing string and the oil-bearing formation. A landing nipple is provided in the tubing string near its lower end which provides a seat for a blanking plug. Such a blanking plug is a conventional device which can be installed at the landing nipple to block fluid flow between the interior of the tubing and the oil-bearing formation and which can be removed by conventional wire line methods to reestablish such fluid communication. The tubing is also equipped with means for establishing fluid communication between the interior of the tubing and the tubing-casing annulus at a location above the packer assembly and above the landing nipple. A side pocket, gas-lift mandrel is a conventional device for such a purpose. A blanking or dummy valve may be inserted in the gas-lift mandrel to interrupt fluid flow between the tubing-casing annulus and the interior of the tubing string. When desired, such a valve may be removed to reestablish flow communication at this point. The wellhead at the surface of the earth seals the upper end of the tubing-casing annulus by means of suitable flanges. The wellhead is equipped with suitably valved,v flow lines which are in fluid communication with the tubing string and with the casing-tubing annulus.

The foregoing description is illustrative of a well assembly which may be used in the practice of this invention. it should be understood, however, that this invention is not limited to the use of the specific well installation described and that other conventional assemblies may be satisfactorily employed.

In the practice of this invention an aqueous solution of a water-soluble silicate is displaced into the casing-tubing annular space above the packer assembly. Preferably, sufficient solution will be employed to fill this annular space. This solution may be introduced into the annulus by injection through the flow line in fluid communication with the annulus at the wellhead. It is preferred, however, to inject the solution down the tubing, through the gas-lift mandrel, and up the tubingcasing annulus. During this displacement operation, the blanking plug is seated in the landing nipple to prevent flow of the solution out of the bottom of the tubing, the gas-lift mandrel is open to fluid flow, and the wellhead flow line to the annulus is opened to vent fluids displaced by the solution.

Following placement of the solution in the annulus, a blind valve is installed in the gas-lift mandrel and the blanking plug is removed from the landing nipple. Thus, fluid flow between the tubing and the annulus is blocked and fluid flow between the tubing and the oil-bearing formation is established. Steam is then introduced into the tubing at the wellhead which flows through the tubing string and into the oil-bearing formation at the perforations in the casing. The valve on the annulus flow line at the wellhead is opened to vent the annular space.

The steam passing down the tubing will heat the solution in the annulus and cause it to boil near the tubing. This boiling will cause the deposition of a coating of cellular alkali silicate or silicate foam on the surface of the tubing. During this heating and boiling operation, steam and excess silicate solution will be discharged from the annulus by way of the ventline at the wellhead.

It is preferred to inject the steam at a relatively high temperature, approximately 600 F., and at a relatively high mass flow rate. The high temperatures and the high mass flow rates will permit rapid heating of the tubing string and will swiftly remove water from the silicate solution.

The silicates employed in the practice of this invention are those of the alkali metals which readily dissolve in water. This group is commonly termed the soluble silicates and includes any of the silicates of the alkali metals, with the exception of lithium. However, in the practice of this invention, it is preferred to employ silicate solutions containing sodium or potassium, as the alkali metal, due to the relatively low cost and ready commercial availability of such solutions.

When water is removed from solutions of the soluble silicates, they crystalize to form glass-like materials. When the soluble silicates are dried rapidly at boiling temperatures, the solutions intumesce and form a solid mass of bubbles having 30-100 times their original volume. The dried foam is a light weight glassy material having excellent structural and insulating properties. i

In the practice of this invention, commercially available sodium silicate solutions have been found suitable. Such solutions have a density of approximately 40 B. at 20 C. and a silica dioxide/sodium oxide weight ratio of approximately 3.2/1. Alternatively, commercially available potassium silicate solutions may be employed. Commercial potassium silicate solutions have a density of approximately 30 B. at 20 C. and a silica dioxide/potassium oxide weight ratio of approximately 2.4/l. The silica dioxide/alkali metal oxide weight ratio is not critical to the practice of this invention and may range between 1.3/1 and 5.0/1. The density of the solutions may range between 22 B. and 50 B. at 20 C. It is only important that sufficient solids be contained in the solution so that upon boiling a coating of approximately one-eighth of an inch or greater will be deposited upon the tubing string.

As was previously noted, in some instances and particularly in wells of extreme depth, it is not always possible to boil off all of the liquid within the annular space. The solid insulating foam on the tubing may build up at a rapid rate and insulate the annular space so effectively that the temperature of the liquid remaining in the annular space drops below its boiling point. At times, as much as one-half of the sodium silicate solution remains in the annulus after the formation of the insulating silicate coating on the tubing. This remaining liquid can create operational problems. If this liquid is allowed to remain in the annular space, it can dehydrate during subsequent thermal operations to form a solid or semi-solid plug above the packer making it difficult to retrieve the tubing string and packer from the well.

It has now been found that this excess silicate solution can be effectively displaced from the annulus using a fluid which has a low solubility for the silicate coating. Although, it is not a requisite for the practice of this invention, improved results may be realized in certain instances by first contacting the excess silicate solution with a quantity of relatively fresh water. This fresh water is then displaced with a fluid having a low solubility for the silicate coating.

The preferred manner for displacing the excess silicate solution is to inject the displacing agent down the tubing, through the gas-lift mandrel, and up the annulus. When performed in this manner, no difficulty will be experienced in attempting to force the relatively viscous silicate solution through the narrow constrictions of the gas-lift mandrel. However, it is recognized that the circulation could be performed in the reverse manner with the displacing agent introduced down the annulus and up the tubing. In either event, prior to injecting the displacing agent, the blanking plug is installed at the landing nipple in the tubing and the dummy valve is pulled from the gaslift mandrel. With the blanking plug installed and the dummy valve removed, fluid communication will be established between the interior of the tubing and the annulus.

The quantity of displacing fluid introduced into the well should be equal to or in excess of the volume of the casingtubing annulus. Preferably, at least one and one-half times the annular volume is introduced to insure substantially complete removal of the excess silicate solution. Following displacement of the excess silicate solution, the displacing fluid is mately equal length, and these sections were placed in graduated cylinders. Each of the graduated cylinders was then filled with sufficient saturated inorganic salt solution to immerse the coated section of tube and the condition of the silicate coating removed in any convenient manner such as gas-lifting or 5 was observed over a 7-day period. For comparison, one seeswabbing the tubing. Finally, the annulus may be further tion of tubing was immersed in water. The results of these obdehydrated by injecting further quantities of steam down the servations are shown in the following Table.

TABLE I Aqueous solution in cylinder Concentration of additive Silicate coating condition weight Inorganic additive percent 3 days 6 days 7 days Aluminum sulfate- No change Coatin soft and de adin Calcium chloride do No cha nge. gr g Sodium chloride 26 do N 0 change Do. Sodium carbonate 30 Slightp cipitate in cylinder Precipitate in cylinder. Sodium sulfate 25 Deteriorating rapidly. Coating Coating completely removed Coating completely removed from tube gollecting at bottom of cylinfrom tube section. section.

er. Magnesium chloride 25 Slight precipitate Slight precipitate. Magnesium sulfate. 30 ..do Do. Water Coatlng soit. Some coating Coating degrading. More coat- Coating very mushy and soft. Coating very collecting at bottom of cylinder.

ing collecting. uneven. Much coating collected.

tubing string and into the oil-bearing formation. This addi- 2 tional steaming will remove any minor quantities of displacing fluid remaining in the annular space.

The fluid used to displace the excess silicate solution should have a low solubility for the silicate coating, it should be capable of effectively displacing the silicate solution, it should be capable of being displaced at least as readily as the excess silicate solution and should not have any substantial adverse effeet on the insulating properties of the silicate coating. It has been found that aqueous solutions of inorganic compounds meet these criteria and are remarkably effective. Typical inorganic compounds include aluminum sulfate, calcium chloride, sodium chloride, sodium carbonate, magnesium chloride and magnesium sulfate. Of these materials, sodium chloride is preferred due to its ready availability and low cost. This listing, of course, is intended to be exemplary of the useful substances and not exhaustive.

An intermediate or buffer solution may be injected prior to the displacing fluid to reduce undesired interaction between the silicate solution and components of the displacing fluid. Such a buffer solution will be particularly desirable where the displacing fluid contains divalent cations since such cations can form insoluble precipitates with the aqueous silicate solution. The buffer slug may be substantially fresh water or an aqueous solution substantially free of divalent cations. The volume of this buffer solution is preferably relatively. small compared to the quantity of displacing fluid. Under most circumstances, a volume equal to from about one-tenth to about one-half of the volume of the casing-tubing annulus will be satisfactory.

The concentration of the inorganic compounds to be employed in the displacing solutions may vary widely. Useful concentrations may range as low as 1.0 percent by weight up to the saturation limit of the compound in water. In manyinstances, it will be preferred to use a saturated solution of these compounds due to the lower solubility of the silicate coating in such a saturated solution. One of ordinary skill in the art can readily determine suitable displacing fluids and satisfactory concentration ranges of additives using simple laboratory investigations. Typical, routine investigating procedures are 4 described in the following Examples 1 and II.

EXAMPLE l tube was then cut into a number of short sections of approxi- 75 It will be noted from the above Table that with the exception of sodium sulfate, that these inorganic solutions are superior to water in preserving the .structure of the silicate coating. It also appears from these tests that sodium chloride and calcium chloride are most effective in preserving the silicate coating. it will also be noted that these observations extended over a 7-day period at room temperature (approximately F.). In actual operation, the well will be at a much higher temperature (200 F. or greater). At these higher temperatures, the silicate coating will deteriorate in the presence of fresh water much more rapidly. The coating can sufi'er substantial damage in a'matter of hours under such circumstances.

The effectiveness of the displacing fluids having a low solubility for the silicate coating were also tested under conditions which were scaled to approximate a casing-tubing annular space in a well. A one-quarter inchOD stainless steel tube was used to approximate a tubing string. A l-inch OD galvanized line pipe, approximately 3 feet in length, -was slipped over the tubing string to approximate the casing and was sealed at its top and bottom with an inlet and outlet for the stainless tubing. Valved taps were drilled at the top and bottom of the easing to permit fluid circulation within the annular space. The annular space was filled with 700'milliliters of a commercial grade sodium silicate solution having a density of approximately 40 B. at 20C. and a silica dioxide/sodium oxide weight ratio of approximately 3.2/1. Saturated steam (400 F. and 250 psia) was injected in the top of the stainless steel tubing and discharged through the bottom .to boil the sodium silicate solution in the annular space. This boiling was continued for approximately one and one-half hours during which time the upper tap on the galvanized line pipe was open to recover condensed steam and discharged silicate solution. At the end of one and one-half hours, approximately 400 milliliters of liquid was recovered from the annulus. Steam injection was then discontinued and fresh water was injected into the annular space through the lower tap on the galvanized pipe until 1,400 milliliters of overflow had been discharged through the upper tap. The upper and lower taps were then closed and the assembly including the silicate-coated stainless steel tubing was allowed to soak in the fresh water for approximately 5 hours. The annulus was then drained of liquid and steam was again passed through the stainless steel tubing to remove any excess liquid remaining within the annular space. The as sembly was then dismantled and it was found that the silicate coating had radically deteriorated. The thickness of the coating was reduced and in some places the exterior of the stainless steel tubing was completely bare. it should be noted that the higher temperatures used in this test caused the silicate coating to deteriorate in the presence of fresh water even more rapidly than in the tests of Example I.

In a corresponding test, a sodium silicate coating was formed on the stainless steel tubing in the manner previously described. Following formation of the coating, one annulus volume of fresh water (approximately 700 milliliters) was circulated up the annulus and out the discharge to remove excess sodium silicate. Following the fresh water, one annulus volume of a saturated aqueous sodium chloride solution was injected. This solution was allowed to stand in the annulus and soak into the coating for 20 hours, after which time the salt solution was drained. Steam was again injected into the stainless steel tubing to remove any excess water remaining in the annular space. The assembly was then dismantled and it was found that the stainless steel tubing was entirely coated with cellular sodium silicate approximately one-quarter inch in thickness having an excellent appearance.

EXAMPLE Ill A typical field example in which this invention may be practiced follows. A well extends from the surface of the earth 3,500 feet to an oil-producing formation. The well is completed in a conventional manner with 7-inch, 23 pound casing and three and one-half inch EUE tubing. A thermal packer has been run into the well on the tubing and is set in the casing above the producing formation. 96 barrels of 40 8., 3.2/1 silica dioxide/sodium oxide ratio, sodium silicate solution is circulated down the tubing and up the annulus by means of a side pocket gas-lift mandrel. The tubing has been closed off from the producing formation by means of a blanking plug set in a landing nipple below the thermal packer. After the silicate solution has been displaced into the tubingcasing annulus, a dummy valve is placed in the gas-lift mandrel and the blanking plug in the tubing is removed. Steam is injected through the tubing and into the formation for approximately 2 hours at a rate of 25,000 pounds per hour (expressed as a corresponding weight of water at 60 F.). The annulus flow line at the wellhead is open during this steaming to provide a vent for fluid discharged from the annulus. After this period of time, approximately 60 percent of the silicate liquid has boiled out of the annulus and discharged. The blanking plug is again placed in seating nipple to block fluid communication between the tubing and the formation, and the dummy valve is pulled from the gas-lift mandrel to establish communication between the tubing and the annular space. 25 barrels of fresh water is then injected through the tubing and followed by 150 barrels of water saturated with sodium chloride. The excess water is then removed from the annular space by conven tional means such as gas-lifting through the mandrel or swabbing the water from the annular space through the tubing. The gas-lift mandrel is then plugged and the tubing is open. Steam is then injected into the formation by means of the tubing.

The principle of the invention and the best mode in which it is contemplated to apply that principle have been described. It is to be understood that the foregoing is illustrative only and that other means and techniques can be employed without departing from the true scope of the invention as defined in the following claims.

What is claimed is:

I. An improved process for insulating a tubing string suspended within a well by injecting into the annulus of the well a solution containing water-soluble silicate, introducing thermal energy into the tubing string to remove water from the solution and to deposit a coating of the silicate on the tubing string, and venting the annulus between the tubing string and the well to provide a discharge for water vapor wherein the improvement comprises introducing into the annulus a fluid having low solubility for the silicate coating to displace silicate solution from the annulus.

2. A process as defined by claim 1 in which the fluid is an aqueous solution.

3. A process as defined by claim 2 wherein the aqueous solution contains dissolved solids.

4. A process as defined by claim 3 wherein the concentration of dissolved solids in the aqueous solution is from approximately l.0 percent by weight to approximately the saturation limit of the solids in the solution.

5. A process as defined by claim 3 wherein the aqueous solution is substantially saturated with the dissolved solids.

6. A process as defined by claim 3 wherein the dissolved solids comprise sodium chloride.

7. A process as defined by claim 1 further comprising injecting a solution substantially free of divalent cations prior to introducing the fluid having a low solubility for the silicate foam.

8. A process as defined by claim 1 wherein the fluid having low solubility for the silicate coating is injected down the tubing string, passed through means for fluid communication between the tubing and the annulus, and displaced up the annulus.

9. A process as defined by claim 1 further comprising removing the fluid having a low solubility for the silicate coating from the annulus.

10. A process as defined by claim 9 further comprising, sub sequent to removing the fluid having a low solubilit for the silicate coating, introducing further quantities of thermal energy down the tubing string to further dehvdrate the annulus.

Claims (9)

1. 2. A process as defined by claim 1 in which the fluid is an aqueous solution.
2. 3. A process as defined by claim 2 wherein the aqueous solution contains dissolved solids.
3. 4. A process as defined by claim 3 wherein the concentration of dissolved solids in the aqueous solution is from approximately 1.0 percent by weight to approximately the saturation limit of the solids in the solution.
4. 5. A process as defined by claim 3 wherein the aqueous solution is substantially saturated with the dissolved solids.
5. 6. A process as defined by claim 3 wherein the dissolved solids comprise sodium chloride.
6. 7. A process as defined by claim 1 further comprising injecting a solution substantially free of divalent cations prior to introducing the fluid having a low solubility for the silicate foam.
7. 8. A process as defined by claim 1 wherein the fluid having low solubility for the silicate coating is injected down the tubing string, passed through means for fluid communication between the tubing and the annulus, and displaced up the annulus.
8. 9. A process as defined by claim 1 further comprising removing the fluid having a low solubility for the silicate coating from the annulus.
9. 10. A process as defined by claim 9 further comprising, subsequent to removing the fluid having a low solubility for the silicate coating, introducing further quantities of thermal energy down the tubing string to further dehydrate the annulus.