U.S. patent number 3,812,913 [Application Number 05/189,854] was granted by the patent office on 1974-05-28 for method of formation consolidation.
This patent grant is currently assigned to Sun Oil Company. Invention is credited to William C. Hardy, Edward F. Schultze, John C. Shepard.
United States Patent |
3,812,913 |
Hardy , et al. |
May 28, 1974 |
**Please see images for:
( Certificate of Correction ) ** |
METHOD OF FORMATION CONSOLIDATION
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.
Inventors: |
Hardy; William C. (Richardson,
TX), Schultze; Edward F. (Dallas, TX), Shepard; John
C. (Richardson, TX) |
Assignee: |
Sun Oil Company (Dallas,
TX)
|
Family
ID: |
22699036 |
Appl.
No.: |
05/189,854 |
Filed: |
October 18, 1971 |
Current U.S.
Class: |
166/288; 166/292;
166/256; 166/294; 166/295 |
Current CPC
Class: |
E21B
33/13 (20130101); E21B 43/025 (20130101); E21B
43/243 (20130101) |
Current International
Class: |
E21B
33/13 (20060101); E21B 43/243 (20060101); E21B
43/16 (20060101); E21B 43/02 (20060101); E21b
033/13 (); E21b 043/24 () |
Field of
Search: |
;166/288,302,292,294,295 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Gay; Bobby R.
Assistant Examiner: Staab; Lawrence J.
Attorney, Agent or Firm: Church; George L. Johnson; Donald
R. Dixon; Anthony J.
Claims
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 1,000.degree.F. 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.
Description
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 of a 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 of liquid
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
With this and other objects in view, the present invention
contemplates heating an unconsolidated reservoir and subsequently
injecting a material which becomes a bonding agent after the
application of heat. Additional heat may be supplied to the
formation after injection of the bonding material. Heat may be
supplied by a downhole heater, which is preferably electrical or
catalytic. A complete understanding of this invention may be had by
reference to the following detailed description, when read in
conjunction with the accompanying Drawings.
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 formation 36. Positioned within the
casing 12 is tubing 14. Tubing 14 is smaller than and concentric
with casing 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 mid-portion 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 extends from the cable head 20 to the lower
end of the catalytic 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 30 in casing 12. As depicted in FIG. 1, the
heater 50 is a catalytic heater such as is described in U.S. Ser.
No. 92,836, entitled "Method And Apparatus For Catalytically
Heating Wellbores," filed Nov. 25, 1970, a continuation-in-part of
Ser. No. 889,059 filed Dec. 30, 1969. This heater is lowered inside
the 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.
One method of heating the formation with a non-oxidizing 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
distribution tube 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 50. 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 250.degree.F.
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, and into 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 to 700.degree.F. 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 1,000.degree.F.
Thus, one method for consolidating the formation is to raise the
temperature of the formation with a heat-carrying, 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, and if necessary the
heater removed, a hydrocarbon-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 non-coking 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.
If, 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 200.degree.F 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
accomplished 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
consolidated, whereupon 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 50 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 by pump 54. After a volume of such
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 18 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 non-oxidizing 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.
* * * * *