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Publication numberUS3812913 A
Publication typeGrant
Publication dateMay 28, 1974
Filing dateOct 18, 1971
Priority dateOct 18, 1971
Publication numberUS 3812913 A, US 3812913A, US-A-3812913, US3812913 A, US3812913A
InventorsHardy W, Schultze E, Shepard J
Original AssigneeSun Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of formation consolidation
US 3812913 A
Abstract
A process of formation consolidation is provided wherein the formation is heated and a substance which acts as a bonding agent when heated is then flowed into the formation. To insure a clean bonding surface, in situ combustion may be initiated in the area to be consolidated prior to injection of the bonding substance. Heat may be supplied to the formation after injection of the bonding substance.
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United States Patent 1191 Hardy et al.

[ May 28, 1974 I METHOD OF FORMATION 3,373,812 11 1 1011 Smith lm zxx CONSOL'DATON 3333313 31132; if il 122153;

, Ul'lC 1 1 lnvenlorsi gi gi D fi ol i 3,680,636 8/1972 Berry etal, 166/302 war c utze, a as; nC. Shepard, Richardson, all of Tex. Primary Examiner Bobby R- Gay [73] Assignee: Sun Oil Company, Dallas, Tex. Assistant Examiner-Lawrence J. Staab Attorney, Agent, or Firm-George L. Church; Donald [22] Flled' 1971 R. Johnson; Anthony J. Dixon [2]] Appl. No.: 189,854

[57] ABSTRACT 52 US. Cl 256 1 166/288 0 g A process of formation consolidation is provided [51] Intel E21b33/13 E21b43/24 wherein the formation is heated and a substance [58] Field 166/288 6 292 294 which acts as a bonding agent when heated is then 166/295 flowed into the formation. To insure a clean bonding surface, in situ combustion may be initiated in the 1561 sgizzszzniz sfiiiziy 11215351111312 2231513,;

UNITED STATES PATENTS after lllJeCtlOfl of the bonding substance. 2,853,136 9/]958 Moore et al. 166/302 3,003,555 10/1961 Freeman et a1 166/288 6 Claims, 1 Drawing Figure 3. I mv g 24 1 1 is; 11 1|: l. 28

1 aoooe oeoe PATENFEBIAY 2 i874 INVENTORS WILLIAM C. HARDY EDWARD F. SCHULTZE JOHN C. SHEPARD A TTORNE Y 1 METHOD OF FORMATION CONSOLIDATIO BACKGROUND OF THE INVENTION This invention relates to a method of treating unconsolidated sub-surface formations, and more particularly to a method of bonding particles of such formations into a permeable unitary mass to prevent movement of the particles into the wellbore which penetrates the unconsolidated formation.

In many oil or gas-bearing formations, the particles comprising the formation are not effectively cemented together, which results in the formation being either substantially unconsolidated or only loosely consolidated. These formations are ordinarily comprised of sand or sandstone. When fluids are produced from such formations, solid particles of the formation flow into the well. If these formation fluids in the unconsolidated formations are under high pressure, the solid particles will flow through the tubing and other equipment in the well at high velocities, causing severe erosion of the well equipment. If the flow rates are not at high velocity, the solid particles flow into the well and plug the tubing. It is then necessary to perform expensive workover operations on the well to place it back in operation. In extreme cases, the unconsolidated oil bearing formation surrounding the well is washed out and undermines the overlying formations penetrated by the well.

Several methods have been used to combat the flow of sands into the well from unconsolidated formations. One such method is to set a slotted liner in the borehole through the producing formation and produce formation fluids through the slots of the liner. Sometimes the setting ofa slotted liner is combined with a gravel packing operation in which sand or gravel is packed around the liner to provide support for the unconsolidated formation. Both of these methods have the shortcoming that sands in the incompetent formation are still free to move, and therefore, can plug the gravel pack or liner. Because the gravel pack is comprised of sand or gravel that is not adhered together, the sand or gravel is free to move to allow formation sand to work its way through the gravel pack to plug up the liner. To prevent this. it has been suggested that the particles in the gravel pack be treated by a resin which coats the gravel pack particles, followed by condensation or polymerization to bond the particles into a unitary mass. Care must be taken to insure preservation of the permeability of the gravel or sand pack after the resin treatment. Another difficulty with such a method is finding a suitable resin which can be made to set at conditions existing in the pay zone to form a resin of adequate strength and insolubility in formation fluids to produce a bond which will hold the particles together for long periods. Additionally, satisfactory adhesion of the resin to the particles, which are ordinarily covered with oil and wate or both, is extremely difficult.

Another method that has been suggested to stabilize unconsolidated formations is to displace into the formation a mixture ofliquid plastic and a catalyst for setting the plastic. In theory the mixture will coat the sand particles and the plastic will act as a bonding agent when set by the catalyst. The main problems with this procedure are the maintenance of a proper mixture of catalyst and plastic and a critical time factor. These two problems are interrelated in that improper mixture can create a time problem. If for example a portion of the mixture contains an excessive amount of catalyst the plastic may set up prior to entering the formation. Also, the reverse might occur when an insufficient amount of catalyst causes the plastic and catalyst solution to be produced into the wellbore when production is recommended because the resin has not set up in the formation.

Another timing problem arises with catalyst since once a catalyst is added to the liquid plastic the plastic starts to set up. If a delay occurs in injecting the mixture into the formation, the plastic will set up wherever it is located. Not infrequently delays will occur caused by such things as pump breakdown.

In lieu of injecting a mixture of plastic and catalyst into the formation so as to avoid the problems associated therewith, there was attempted the injection of the plastic and the catalyst separately in successive steps. This procedure obviated the problem of the plastic setting up prior to entering the formation. Because of the problem of achieving a good mixture in the formation it was not more practical than the premix method. The poor mixtures leave many areas unconolidated.

Another method of stabilizing an unconsolidated formation is to bond the particles of the formation into a consolidated mass with coke formed in place in the formation by a reverse burn in situ combustion process. In such a process, air used to support the combustion of the formation fluids is flowed counter-current.to the direction of the burn. This is usually accomplished by injecting air in an injection well and providing heat at the production well. Once ignition occurs, the flame front will move toward the source of oxygen, i.e., the injection well. The characteristic of such a reverse burn in situ combustion process is that a residue of coke is left on the particles of the formation. This coke residue effectively bonds together the sand grains making up the formation. It is however, often difficult to maintain permeability in the formation when coking is accomplished by a reverse burn.

It is therefore an object of the present invention to provide an improved method of formation consolidation.

SUMMARY OF THE INVENTION BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is an elevational view partly in section of a downhole catalytic heater located adjacent an unconsolidated formation.

DESCRIPTION OF THE PREFERRED EMBODIMENT Referring to FIG. 1, there is seen an unconsolidated formation 36 penetrated by casing 12 having perforations 30 therein located adjacent the unconsolidated ing 12 and extends from the surface to a point adjacent the perforations 30. Located partly within and extending below tubing 14 is heater 50.The weight of heater 50 is supported by seating nipple 48 located at the bottom of tubing 14. No-go flange 28 rests on seating nipple 48. Armored thermocouple cable 16 extending from the surface is connected to the heater by cable head 20. O-rings 42 form a seal between the midportion of the heater 50 and the seating nipple 48, thereby preventing communication between the interior of the tubing 14 and the exterior of the catalytic portion 32 of heater 50. Between cable head 20 and no go flange 28 there is located upper stand off member 40. Passages 22 extend through the side walls of the upper stand off member 40 to connect the interior of tubing 14 with gas distribution tube 44. This gas distribution tube 44 extendsfrom the cablehead 20 to the lower end of thecatalytic portion 32 of the heater 50. In the catalytic portion 32, the gas distribution tube 44 has perforations to'allow communication between the tubing interior and the interior of the catalytic portion 32. Separating the catalytic portion 32 of heater 50 from the lower end of the tubing 14 is lower stand off member 38. Positioned on the exterior of catalytic portion 32 of heater 50 is thermocouple 46 which is connected to the surface by armored thermocouple cable 16. Connected with the annulus 24 between tubing 14 and casing 12 is compressor 18 and pump 52, which are controlled by valves 26. Connected with the interior of tubing 14 are compressor 12 and pump 54 controlled by valves 34.

The first step in the processes for consolidation of the formation 36 is lowering the heater 50 into the wellbore adjacent to and above the perforations in casing 12. As depicted in FIG. 1, the heater 50 is a catalytic heater such as is described in US Ser. No. 92,836, entitled Method And Apparatus For Catalytically Heating Wellbores, filed Nov. 25, I970, a continuation-impart of Ser. No. 889,059 filed Dec. 30, 1969. This'heater is lowered insidethe tubing until no go flange 28 contacts the seating nipple 48 located at the lower end of the tubing 14. The armored thermocouple cable 16 is used in such lowering operation.

Once the heater 50 is positioned adjacent the formation 36 to be consolidated, heat may be supplied to formation 36 by two methods. One method comprises flowing a non-oxidizing gas into the formation 36 so that its temperature is raised but reservoir fluids are not oxidized. Another method of supplying 'heat to formation 36 is by flowing a heated oxidizing gas in the formation for the purpose of initiating in situ combustion therein. I

One method of heating the formation with a nonoxidizing gas is to flow. an oxygen-containing gas from compressor 12 down the tubing 14. Upon reaching upper stand off member 40 the oxygen containing gas enters gas distribution tube 44 through passages 22. As the oxygen-containing gas proceeds down gas distribution tube 44, it reaches the interior of the catalytic portion 32 of heater 50. The catalyst contained in said heater is preferably one or more of the platinum group and their oxides. Upon the oxygen-containing gas reaching the lower end of heater 50, perforations in the gas distributiontube 44 allow the oxygen-containing gas to diffuse through the catalytic portion 32, thereby coming into contact with the catalyst.

A fuel gas which is normally natural gas is flowed from compressor 18 through valve 26 down annulus 24 to come into contact with the exterior of the catalytic portion 32 of heater 0. Thus, the oxygen-containing gas and the fuel'gas meet adjacent the catalyst to comprise a fuel mixture. A method of intiating a catalytic reaction of the fuel mixture is to include hydrogen with the fuel gas flowing down the annulus 24 and into contact with the exterior of catalytic portion 32 of heater 50. The hydrogen and oxygen containing gas comprises a fuel mixture which will spontaneously react in the presence of the catalyst'Thermocouple 46 located on the skin of the catalytic portion 32 of heater 50 allows continuous monitoring of the catalytic reaction temperature. Such thermocouple information proceeds up armored thermocouple cable 16 to the surface, where the temperature is monitored and controls are operated in conformity with such information. When the thermocouple information indicates that the reaction temperature of the fuel gas flowing down annulus 24 is reached, the hydrogen portion of such fuel gas is terminated. If the fuel gas is natural gas, such reaction temperature would be approximately 250F.

In order to insure that fluids contained in the reservoir 36 are not oxidized, only a stoichiometric amount of oxygen is allowed to be flowed down the tubing 14, andinto contact with the catalytic portion 32 of the heater 50. The limited oxygen insures that heat from the catalytic heater 50 is carried into the formation by a non-oxidizing gas entering formation 36 by flowing down the annulus 24 and into perforations 30. The fuel gas and the non-oxidizing heat-carrying gas may be the same gas, for instance natural gas, comprising primarily methane. The methane reacts with the oxygen entering the the catalytic portion 32 of heater 50, and additionally functions as a heat carrier medium. Also, an inert gas such as nitrogen can be used to carry the heat into the formation 36.

Heat may be supplied to the formation 36 for various purposes. One such purpose is to elevate the temperature of the formation to a level exceeding the coking temperature of a hydrocarbon injected into such formation. in order to insure that well equipment and the formation are not damaged from being exposed to excessive heat, the heater temperature should be limited to700F. If the hydrocarbon to be injected into the formation for coking purposes is in liquid form, the heater 50 should be removed from the wellbore to prevent damage to the heater. If a catalytic heater of the type described in Ser. No. 92,836, is used, a liquid coking fluid would contaminate the catalyst. Similarly, if an electrical heater is used, the electrical contacts might be fouled by the cokable liquid hydrocarbon. A preferred liquid is a hydrocarbon liquid which cokes below about l,00OF.

Thus, one method for consolidating the formation is to raise the temperature of the formation with a heatcarrying, non-oxidizing gas to a level in excess of the coking temperatures of a hydrocarbon heavier than methane. The heater is then removed from the wellbore in the event a hydrocarbon in liquid form is being injected into the formation 36 to prevent contamination of the heater. Once the formation has been heated,

containing fluid is injected into the formation. Such fluid should be rich in hydrocarbons heavier than methane, which will either be coked upon contacting the heated formation or will be placed in an unheated formation and subsequently heated. A non-oxidizing gas which may be methane, nitrogen, or similar gaseous material, is also flowed into the formation for the purpose of maintaining flow channels through the formation for subsequent production of reservoir fluids. The non-oxidizing non-coking gas should be flowed at such a rate as to keep the perforations clear of coke.

If a gaseous hydrocarbon such as LPG is used for coking, the hydrocarbon on its way to the formation passes by the heater, which is maintained in excess of the hydrocarbon coking temperature. In this process the heater is not removed since the gas will not contaminate an electrical or catalytic heater. The flow rate of the cokable hydrocarbon and permeability maintaining gas should be at a rate to prevent coking on the heater or in the perforations.

Once sufficient coke has been formed, such hydrocarbon injection is terminated. The non-oxidizing noncoking gas should be continued for a period after the termination of coking the hydrocarbon, to further insure sufficient formation permeability. If the heater has not been previously removed from the wellbore, it should be removed before termination of injecting gases into the formation, thereby preventing damage to the heater by reservoir fluids flowing into the wellbore. At this point, injected gases are terminated and the well is allowed to be returned to production.

lf, through accident or miscalculation, permeability of the formation has been destroyed, or the sand has not been properly consolidated, the heater can be returned to the wellbore for the purpose of igniting the formation to remove the coke by burning. The coking process may then be repeated or another sand consolidation technique may be employed. This sand consolidation technique can be employed at the time the well is being completed, or after production of such well indicates a sand consolidation problem. It also may be used after an old gravel pack.

in order to operate the catalytic heater and prevent an oxidizing gas from entering the formation, only a stoiciometric amount 'of oxygen is supplied to the heater. An amount of methane, in excess of that necessary for providing fuel to the heater, may be provided in sufficient quantity to act as a heat carrying gas.

Additionally, the methane which flows into the formation, operates to maintain permeability to allow flow of formation fluids to the wellbore. The heater temperature should be maintained at a level slightly in excess of the coking temperature of the heavy hydrocarbons so that coke is not deposited on the heater in excessive amounts.

A similar sand consolidation method utilizing essentially identical apparatus involves locating a heater in the wellbore and flowing an oxidizing gas past the heater to form a part of the fuel mixture for the heater, and as a heat carrier medium to initiate in situ combustion in the formation. The burn is allowed to proceed radially from the wellbore the distance desired to be consolidated, whereupon such burn is terminated by ceasing injection of the oxidizing gas. This burn is for the purpose of cleaning the formation for easier adherence of a bonding material. The heater is then removed and a material which acts as a bonding agent, after the application of heat is flowed into the formation. When sufficient bonding material is flowed into the formation, such injection is terminated and the heater is returned to the wellbore. A non-oxidizing heat carrying gas is then injected into the formation to convert the material into a bonding agent. This procedure affords the advantages of a clean bonding surface and ensures that uniform consolidation is accomplished.

Various materials can be used which will act as a bonding agent upon the application of heat. One such material is a slurry of inorganic material such as calcium oxide, or calcium oxychloride or portland cement. This material, upon flowing into the formation, would either react with clay in the formation or be filtered out and lodged in the interstices of the formation. The subsequent application of heat sets the cement and the non-oxidizing heat carrying fluid also operates to maintain permeability in the formation.

Another material which can be injected into the formation to act as a bonding agent after the application of heat is a solution of organic material in a volatile liquor. After this solution is injected into the formation, the heater is lowered into the borehole, and the volatile liquid is driven from the organic material. Such organic material should be soluble in a convenient solvent, but insoluble in water or crude oil. Organic materials and volatile liquid combinations which may be used include lucite and diethylene chloride; asphalt and benzene; epoxies and ketones; and polyvinyl chloride and alcohol.

Plastics are additional materials which may be used to act as a bonding agent. Such plastic materials could be any material which will withstand reservoir temperatures in excess of 200F and one resistant to weak acids and alkalis. Polycarbonates, polypropylene, polyethylene, nylons as well as many other plastics might be suitable for this sand consolidation process. Additionally, the creation of polymers in the formation can be ac complished by injecting a thermosetting monomer into the formation and subsequently applying heat to complete the polymerization which may have been initiated by use of a catalyst. Thermosetting resins, such as the phenolic resins, may be set up in the same manner. Prior to injection of the bonding materials, i.e., plastics, monomers, resins, etc., it is preferable to have relatively clean sand to which the bonding material is to attach. Since the sand is often water wet which causes difficulty in bonding, it is preferable to clean the sand by either in situ combustion or by drying the sand with a non-oxidizing heated gas. Chelating agents may also be used to aid in attaching the bonding material to the sand grains.

Referring again to FIG. 1, the apparatus shown therein can be utilized for the method of setting a material injected into the formation. A fuel gas such as methane would be injected into the tubing 14 and would enter gas distribution tube 44 through passages 22. Upon exiting the gas distribution tube 44 by way of perforations located within the lower end thereof, the fuel gas would come into contact with the catalytic portion 42 of heater 50. An oxygen-containing gas such as air coming from compressor 18 through valve 26 descends the annulus 24 whereupon it contacts the exterior surface of the catalytic portion 32 of heater 50. A catalytic reaction of the air and methane may be initiated by including hydrogen in the fuel gas injected into the tubing 14. Air in excess of that required for such catalytic reaction is flowed down the annulus 24 to carry the heat into the formation 36 through perforations 30. Once sufficient heat is carried into the formation, hydrocarbons contained therein will oxidize and initiate in situ combustion in the formation. Once in situ combustion is initiated, the fuel gas flowing down the tubing 14 may be terminated, while air is continued to be supplied to the formation 36 to support the in situ combustion. This combustion is allowed to proceed outwardly from the wellbore the distance desired to be consolidatedfwhereupon the air flowing down the annulus 24 is terminated. Such air termination snuffs out the in situ combustion and the formation then begins to cool. The heater S is withdrawn from the wellbore by armored thermocouple cable 16. Subsequent to such heater withdrawal, a substance capable of being a bonding agent after the application of heat such as a cokable hydrocarbon fluid plastics, resins, monomers,

etc. is injected into the formation 36 through tubing 14 i by pump 54. After a volume ofsuch substance: has been injected which is sufficient to saturate the portion of the formation 36 which has been subjected to in situ combustion, such injection is terminated. Compressor I8 is then activated to supply a non-oxidizing gas to the formation for insuring permeability of the formation. Such gas should contain or consist of a fuel gas such as methane for contacting the exterior of the catalytic portion 32 of heater 50. An oxygen-containing gas is supplied by compressor 12 to the interior of the catalytic portion 32 of heater 50, and an oxygen and fuel gas reaction is initiated by including hydrogen in the gas stream flowing down the annulus 24. Only a stoiciometric amount of oxygen is used to prevent further in situ combustion in the formation. Heat is carried into the formation 36 by the gas flowing down the annulus 24 past the heater and through perforations 30 in the casing 12. This heat is continuously supplied to the formation 36 until the cement, resin or other plastic material is set, or until the volatile liquid is driven from the organic material.

in the event that in situ combustion is not desired as a method of cleaning the formation to be consolidated, the formation can instead be dried prior to injection of the bonding material. A heated non-oxidizing gas is flowed into the formation to raise the temperature so as to dry off the sand grains. This is accomplished in the same manner as that for supplying a heated nonoxidizing gas for setting a bonding material. After drying the formation, the heater is removed, the bonding material is injected into the formation and the formation is again heated by returning the heater to the wellbore. The non-oxidizing gas is continuously flowed into the formation to ensure permeability once the bonding material is placed in the formation.

While particular embodiments of the present invention have been shown and described, it is apparent that changes and modifications may be made without departing from this invention in its broader aspects, and therefore, the aim in the appended claims is to cover all such changes and modifications as fall within the true spirit and scope of this invention.

What is claimed is:

1. In a formation comprising unconsolidated material penetrated by a wellbore and wellpipe therein, the process of consolidating such material to prevent its encroachment into the wellbore comprising:

a. locating adjacent to the formation to be consolidated a catalytic heater, having a fluid flow channel therein wherein a hydrocarbon containing fuel gas is flowed down an annulus between the wellpipe and the wellbore and a stoichiometric amount of oxygen in an oxygen-containing gas is flowed down the wellpipe into contact with the fluid flow channel of the catalytic heater whereupon the fuel gas and the oxygen react thereby providing heat,

b. providing the heat to said formation from said catalytic heater via a non-oxidizing heat carrying gas selected from the goup consisting of excess fuel gas and nitrogen,

c. bonding said formation with a substance which acts as a bonding agent when subjected to heat in sai formation and d. continuing the flow of said non-oxidizing gas at a rate sufficient to maintain permeability in said formation and to control the temperature of the bonding process.

2. The process of claim 1 wherein said heat is sufficient to coke a hydrocarbon heavier than methane and said bonding agent is one selected from the group consisting of hydrocarbon liquid, and hydrocarbon gas injected into said formation.

3. The process of claim 1 wherein said bonding agent is selected from the group consisting of an injected liquid hydrocarbon which cokes below about 1,000F. and an injected hydrocarbon gas and the catalytic heater is removed prior to injection of said bonding agent.

4. The process of claim 1 wherein said bonding agent is a slurry of inorganic material.

5. The process of claim 1 wherein said bonding agent is an organic material in a volatile liquor.

6. The process of claim 1 wherein said bonding agent is selected from the group consisting of plastics, thermosetting monomers and thermosetting resins.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3 3 Dated May 28, 197A n fl William c. Hardv. Edward F. Schultze, John 0. Shepard It is certified that error appears in the above-identified patent and that said Letters Patent are hereby corrected as shown below:

Assignee Sun Oil Company (Delaware) Signed and sealeu this 17th day of September 1974.

(SEAL) Attest':

MCCOY M. GLBSUN JR. C. MARSHALL DANN Attesting Otficer Commissioner of Patents FORM PC4050 H0459) USCOMM-DC 60376-P69 U.S. GOVERNMENT PRINTING OFFICE: 969 0366334

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Classifications
U.S. Classification166/288, 166/294, 166/292, 166/295, 166/256
International ClassificationE21B43/243, E21B33/13, E21B43/02, E21B43/16
Cooperative ClassificationE21B33/13, E21B43/243, E21B43/025
European ClassificationE21B33/13, E21B43/243, E21B43/02B