US3525399A - Technique for insulating a wellbore with silicate foam - Google Patents

Description

Aug. 5, mm

J. H. BAYLESS ETAL TECHNIQUE FOR INSQLATING A WELLBQRE WITH SILICATE FOAM Filed Aug. 23, 1968 WALTER L. PENBERTHY, JR. INVENTORS JACK H. BAYLESS ATTQRNEY United States Patent 3,525,399 TECHNIQUE FOR INSULATING A WELLBORE WITH SILICATE FOAM Jack H. Bayless and Walter L. Penberthy, Jr., Houston,

Tex., assiguors to Esso Production Research Company,

a corporation of Delaware Filed Aug. 23, 1968, Ser. No. 754,887 Int. Cl. E21b 43/24 US. Cl. 166303 8 Claims ABSTRACT OF THE DISCLOSURE A method and apparatus for thermally insulating a well for use in a thermal process for oil recovery. The Well is insulated by boiling a silicate solution in contact with the well tubing to form a coating of alkali metal silicate foam on the tubing. The insulated. tubing may be fabricated on the surface or within the wellbore.

BACKGROUND OF THE INVENTION Field of the invention This invention relates to a process for constructing well elements. More particularly, the invention relates to a process for thermally insulating a wellbore. The invention also relates to an apparatus for insulating the wellbore.

Description of the prior art In the recovery of heavy petroleum crude oils, the industry has for many years recognized the desirability of thermal stimulation as a means for lowering the oil viscosity and thereby increasing the production of oil.

One form of thermal stimulation 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 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 Following the heat soak, the well is placed on a production cycle and the heated fluids are withdrawn by way of the well to the surface.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, lowviscosity oils. This is particularly true where such oils exist in thick, low permeability sands where present fracturing techniques are not eflective. 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 downthe 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 casing with suflicient 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 tubing.

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.

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.

SUMMARY OF THE INVENTION This invention relates to a process and apparatus for thermally insulating elements of a well, such as a tubing string. The tubing string is run into the well and set in place. An aqueous solution of water soluble silicate is introduced into the annular space between the casing and the tubing string. Steam is injected into the tubing string to raise the temperature of the silicate solution above its boiling point. Boiling of the silicate solution removes its water and deposits a coating of alkali metal silicate foam on the tubing string. The silicate foam is relatively thin and has a remarkable low thermal conductivity.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic representation of a vertical section of the earth showing a well containing casing and steam injection strings.

FIG. 2 is a schematic representation of the well after deposition of the silicate foam.

DESCRIPTION OF THE PREFERRED EMBODIMENT In the embodiment shown in FIG. 1, a well shown generally at 1-0 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 well-head 16 to the oil-bearing formation. The

tubing string is equipped with an inlet line 17 and the casing has an inlet line 18.

A swab cup packer 19 is set on the tubing string and run into the well to the desired level. A suitable swab cup packer is Type GW, Guiberson Cup Packer, sold by Dresser Industries, Inc. A swab cup packer is simply a resilient cup which is sealed on the tubing at its base and extends outward to contact the casing with the lip at the top of the packer. The elastomeric material of the cup may be reinforced with spring steel wires for added strength. The packer cup should be chosen so that the flexible lip has an outside diameter which exceeds the inside diameter of the casing so that immedaite compression of cup against the casing is obtained for instantaneous and positive sealing.

In the practice of this invention the packer cup is installed on the tubing with the base toward the bottom of the well and the lip extending upward. In this manner, a higher positive pressure above the cup will prevent fluids from moving downward past the cup. The greater the differential pressure across the cup, the more tightly the cup will seal. While it is preferred to employ a cup type packer, other packer assemblies known to those skilled in the art may be employed such as anchor type packers, hook wall packers, tension packers, or thermal packers.

After the tubing string with packer assembly is run into the hole and set in place, an aqueous solution of water soluble slilcate is injected through inlet line 18 into the annular space 20 between the casing and tubing. The packer element will prevent the silicate solution from traveling below the packer assembly. Preferably, suflicient solution will be employed to fill the annular space.

Following injection of the silicate solution, steam is introduced into the tubing through inlet line 17, down the tubing string 15, and into the oil-bearing formation through perforations 14. The casing inlet 18 is opened to the atmosphere to permit discharge of the water vapor which boils from the silicate solution. It is preferred to inject steam at a relatively high temeperature, approximately 600 F., and a relatively high mass flow rate. The high temperatures and high mass flow rates will permit immediate heating of the tubing string 15 to a high temperature and will rapidly remove the water from the silicate solution. In some instances, particularly in wells of extreme depth, it may not be possible to boil off all of the liquid within the annular space. The foam 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. In Wells of this type, it may be preferred to employ a reverse circulating device in the tubing string above the packe Such devices are well known to those skilled in the art and permit fluid communication between the annular space and the tubing above the packer. These devices can be opened and closed by wireline methods under pressure without moving the tubing or disturbing the packer setting. The remaining solution may then be displaced from the annular space.

As shown in FIG. 2 as the silicate solution boils, the water is removed .and a thin film of alkali metal silicate foam is formed on the exterior of the tubing string. A more surprising aspect of this invention is the fact that the silicate foam will only deposit on the relatively hot steam injection tubing and will not deposit on the relatively cool casing string. This can be a decided advantage, particularly when a relatively permanent packer assembly such as a hook wall or thermal packer is employed. If substantial quantities of the silicate were deposited on the casing string, there might be a problem in withdrawing the tubing and packer assembly when desired.

Minor depositions of silicate foam on tthe interior of the casing string is not totally undesirable, however, since any silicate deposited upon the casing will provide further insulation. Due to the high water solubility of the silicate foam, any minor deposits on the wall of the casing may be removed by circulating water down the annulus prior to pulling the packer.

It is not fully understood why the silicate foam deposits only upon high temperature surface. It is possible that is a result of the boiling which occurs in the immediate vicinity of the high temperature surface. It is also possible that the foam deposition is due to a molecular interaction between the iron-containing surface and the silicate solution at high temperatures.

As shown in FIG. 2 after the silicate solution has been boiled and the water of solution removed, a thin, relatively-hard shell of alkali metal silicate foam 21 is deposited about the tubing string. This foam has amazing insulating properties. The thermal conductivity of such a foam may range as low as 7.() 10 (cal.)(cm.)/(sec.) (cm?) (C.).

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 excel lent structural and insulating properties.

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 ap proximately 30 B. at 20 C. and a silica dioxide/potassium oxide weight ratio of approximately 2.4/1. 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 sutlicient solids be contained in the solution so that upon boiling a coating of approximately Vs of an inch or greater will be deposited upon the tubing string.

As is previously stated, it has been found that the silicate foam will form only on the heated surface of the steam injection tubing. In many instances it may be necessary to place centralizers on the tubing to prevent contact with the casing wall and consequent transfer of heat from the tubing to the casing by conduction. These centralizers can be easily thermally insulated from the injection tubing by wrapping the tubing at such points with any suitable, heat-insulated material such as asbestos.

Under general operating conditions when extremely high temperature (600 F. or higher) steam is injected through the tubing, the swab cup packer may deteriorate permitting steam leakage across the packer. This will generally present no problem even though the silicate foam is water soluble. So long as the casing is shut in, there will be little tendency for steam to rise in the annular space and attack the silicate foam. If there is minor encroachment of steam above the packer after it deteriorates, the thermal insulation of the injection string can be maintained by utilizing several joints of heat reflective shielding just above the packer. This heat reflective shielding may also be used to advantage where a more permanent type packer is employed rather than cup type packers. This heat reflective shielding at the bottom of the tubing string will prevent deposition of the silicate foam immediately above the packer which might prevent the packer from being pulled. A suitable heat reflective shield is sold by Summit Steam Techniques, Inc. under the trade name Thermoguard.

The following examples demonstrate the ease with which the suitability of various soluble silicate solutions can be determined. One of ordinary skill in the art using such techniques can readily determine the suitability for various operating conditions of solutions having various densities, silica dioxide/alkali metal oxide weight ratios, percentages of silica dioxide, percentages of alkali metal oxide, and viscosities.

EXAMPLE I A one-quarter inch O.'D. stainless steel tube, 4 /2 feet in length was used to approximate a tubing string. A one-half inch I.D. galvanized line pipe was slipped over the tubing string to approximate the casing and sealed at its top and bottom with an inlet and outlet for the stainless seel tubing. A tap was drilled in the top of the galvanized line pipe and the annular space between the tubing and line pipe was partially filled with 135 cc. of sodium silicate solution, 40 B., 3.2/1 silica dioxide/ sodium oxide ratio. Steam was injected through the center tube at 400 F. and 250 p.s.i.a. After one-half hour, 75 cc. of liquid had boiled out of the annular space. The assembly was then dismantled and it was found that the casing (the outer .pipe) was essentially devoid of sodium silicate deposits. The tubing (the inner pipe) was coated with a sodium silicate foam shell which was essentially uniform and inch in thickness.

The thin deposition of sodium silicate foam was remarkably effective in reducing the transfer of heat from the interior of the tubing to the exterior. With the outer casing removed from the tubing, high temperature steam (420 F. 325 p.s.i.a.) was injected into one end of the tubing and discharged at substantially the same temperature and pressure at the other end. After injecting the high temperature steam for 45 minutes, the highest temperature which was measured on the surface of the sodium silicate foam was 150 F.

EXAMPLE II An apparatus similar to that described in Example I was employed to evaluate the depositional characteristics of potassium silicate solutions and the thermal properties of the resultant potassium silicate foam.

The annular space was filled with 600 cc. of a potassium silicate solution, 30 B. and 24/1 silica dioxide/ potasisum oxide weight ratio. Steam was injected through the inch stainless steel tubing at 400 F. and 250 p.s.i.a. for approximately one hour.

After one hour the model was disassembled, and the casing and the tubing strings were visually inspected. The stainless steel tubing was coated with a layer varying from inch to inch in thickness. The wall of the casing was substantially free of potassium silicate deposits.

The thermal conductivity of potassium silicate foam was evaluated in the manner described in Example I. After injecting high temperature steam (420 F.325 p.s.i.a.) for approximately one-half hour, the highest temperature reported on the surface of the potassium silicate foam was approximately 200 F. The temperature on an uninsulated portion of the stainless steel tubing was 390 F.

In some instances, it may be desirable to coat the tubing at the surface with the silicate solution rather than within the well. This may be particularly desirable in instances where the silicate deposit is to be coated with a waterproofing material before running the insulated tubing string into the well. Various plastics and resins which are not water soluble and have the ability to withstand the high temperatures encountered in thermal operations would be suitable for this purpose.

What is claimed is:

1. A process for thermally insulating a tubing string suspended within a wellbore comprising:

(a) injecting into the wellbore-tubing string annular space a solution consisting essentially of water and a water soluble silicate;

(b) 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

(c) venting the annular space between the tubing string and the wellbore to discharge water vapor removed from the solution.

2. A process as defined in claim 1 wherein the water is removed from the solution by passing steam through the tubing string.

3. A process as defined in claim 1 wherein the water soluble silicate is a potassium silicate.

4. A process as defined in claim 1 wherein the water soluble silicate is a sodium silicate.

5. A process as defined in claim 1 further including installing a packer on the tubing string to retain the solution in the annular space until the water of solution is removed.

'6. A process as defined in claim 1 further including removing excess solution from the annular space.

7. A process as defined in claim 1 further including installing centralizers on the tubing string to prevent tubing-wellbore contact.

8. A process as defined in claim 1 wherein the water soluble silicate has a density from 22 to 50 B. at 20 C. and a silicate oxide/alkali metal oxide weight ratio of 1.3/1 to 5.0/1.

References Cited UNITED STATES PATENTS 515,222 2/1894 Heil -1171'35.1 X 2,734,578 2/1956 Walter 166-57 X 2,978,361 4/1961 Seidl 117-135.1 X 3,276,518 10/ 1966 Schlicht et al. 3,410,344 11/1968 Cornelius 166-303 3,438,442 4/ 1969 Pryor et al. 166-57 X 3,451,479 6/1969 Parker 166303 OTHER REFERENCES Baker, E. Jack, Jr.: New Applications for Sodium Silicate, 12th National SAMPE Symposium, October, 1967.

ERNEST R. PURSER, Primary Examiner I. A. CALVERT, Assistant Examiner US. Cl. X.R. 1 66-57

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