METHOD TO REPAIR LEAKS IN A CEMENTED ANNULUS

Abstract

A method of providing pressure containment of a well having a well annulus. The well annulus contains a set cement, and the cement contains flow paths which communicate a well pressure to the surface. The method includes placing a containment cement slurry in a reception area at the top of the well and installing an injection delivery system within the reception area. The method may further include preparing a settable fluid for injection into the flow paths and injecting the settable fluid through the injection delivery system into the flow paths. In one disclosed embodiment, the injection delivery system may include a series of injection tubulars configured to deliver the settable fluid to the flow paths. The injection delivery system may include a template having a first, second, third and fourth injection tubular. According to this disclosure, the method may also include allowing the settable fluid to set, monitoring the pressure of the well annulus, and performing remedial well action based on the observed pressures.

Description

BACKGROUND OF THE INVENTION

This invention relates to a cemented annulus in an oil and gas well. More specifically, but not by way of limitation, this invention relates to a method for repairing leaks to a cemented annulus in a well.

Oil and gas wells are constructed using steel pipe known as casing to line and structurally support the wellbore. Typically, a drive pipe is driven into the ground followed by a large surface casing that is run a few hundred feet into a drilled hole. As well understood by those of ordinary skill in the art, cement is pumped around the surface casing to seal the space between the casing and the drive pipe. The cement supports the casing, isolates the subterrean reservoirs and protects ground water zones. The operator then drills a deeper wellbore and a smaller diameter casing, known as the intermediate casing, is run into the surface casing to the bottom of the wellbore. The intermediate casing is also cemented into the ground, with the cement being placed in the intermediate casing annulus all the way to surface in most instances.

The wellbore may be drilled further to a specified depth through a productive zone. At this point, the operator may run in the wellbore with a smaller diameter casing, known as a production casing, through the productive zone. The production casing may be cemented all the way to the surface.

The operator will then place a wellhead over the wellbore. In some instances, the operator may place the wellhead over some, but not all, of the casing annuluses. For instance, the production casing and the intermediate casing may be covered by the wellhead, but not the surface casing annulus. Under this scenario, the surface casing annulus must rely on the cement to isolate the subterranean zones. Gas leaks can occur in this surface casing annulus which ultimately can escape into the environment. As readily understood by those of ordinary skill in the art, these leaks can lead to problems. Also, these surface leaks can be present in old wells as well as recently drilled wells.

Possible sources of the leaking gas include a shallow gas zone penetrated by the surface casing or a leak allowing communication from the intermediate casing to the surface casing. In either case, the cement in the surface and intermediate casing annulus must have a flow path to allow the gas to reach the surface.

SUMMARY OF THE INVENTION

A method of providing pressure containment of a well having a well annulus cemented to the surface and without the mechanical isolation of a wellhead is disclosed. In one embodiment, the well annulus contains a set cement, and the cement contains flow paths which communicate a well pressure. The method comprises creating a reception area at the top of the well, placing a containment cement slurry in the reception area and installing an injection delivery system within the reception area. The method may further include preparing a settable fluid for injection into the flow paths and injecting the settable fluid through the injection delivery system into the flow paths of the well annulus. In one embodiment, the settable fluid is a resin selected from the group consisting of: Bisphenal F type resin with a diluent such as Epodil and catalyzed with an epoxide catalyst such as Ancamide 506, Ancamide 2386 or W Hardener. In another embodiment, the settable fluid may be a micro-fine cement slurry comprising: microfine cement such as MC500 and water; the micro-fine cement slurry may also contain a dispersant, a fluid loss additive and a retarder. Also, the containment cement slurry may comprise: a Class A cement, between 0% to about 15% BWOC Gypsum, and between 0% to about 3% BWOC CaC12;. In one disclosed embodiment, the injection delivery system may include a series of injection tubulars configured to deliver the settable fluid to the flow paths. The injection delivery system may include a template having a first, second, third and fourth injection tubular. The injection may include applying a squeeze pressure of resin that is injected into the tubular above an established breakdown pressure and below a burst/collapse pressure of the well casing. According to this disclosure, the method may also include allowing the settable fluid to set, monitoring the pressure of the well annulus, observing a pressure increase in the well annulus, and then repeating the steps of injecting the settable fluid. If no pressure increase is observed, the injection delivery system may be removed from the reception area.

In another embodiment, a method of providing pressure containment of a well is disclosed. The well may contain a surface casing having a surface annulus, an intermediate casing having an intermediate annulus, and a production casing having a production annulus, and wherein the surface annulus, the intermediate annulus and the production annulus contains cement. The surface annulus contains flow paths capable of releasing pressure from a subterranean zone. The method includes placing a containment cement slurry in a reception area at the top of the well, installing a first tubular member within the reception area, and placing a valve on the first tubular member. The method may include fluidly connecting the first tubular member to a pump member, preparing a settable fluid, and pumping the settable fluid through the first tubular member into the flow paths of the surface annulus. The step of pumping the settable fluid may include creating a squeeze pressure and the method further includes maintaining the squeeze pressure until the settable fluid hardens within the flow paths of the surface annulus. The settable fluid may be selected from a group consisting of a resin and a micro-fine cement slurry.

In yet another embodiment, a method of providing pressure containment of a well having a well annulus containing cement is disclosed, wherein the cement contains flow paths. The method comprises placing a containment cement slurry in a reception area at the top of the well, installing a tubular member within the reception area, and preparing a resin, wherein the resin is selected from the group consisting of Bisphenal F type resin with a diluent such as Epodil and catalyzed with an epoxide catalyst such as Ancamide 506, Ancamide 2386 or W Hardener. The method may further comprise injecting the resin through the tubular member into the flow paths of the well annulus.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a schematic illustration of a prior art wellbore having a plurality of casing strings extending into subterranean zones.

FIG. 2 is a schematic illustration of an embodiment of the present invention adapted to a wellbore.

FIG. 3 is a top view of the schematic illustration of the embodiment of FIG. 2 taken along line 3-3 of FIG. 2.

FIG. 4 is a top view of the template of the present disclosure.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring now to FIG. 1, a schematic illustration of a prior art wellbore 2 is depicted, wherein the wellbore 2 contains a plurality of casing strings extending into subterranean zones. More particularly, an operator will drive a drive pipe “DP” or conductor pipe and thereafter drill an initial hole with a drill bit. Next, the operator will place a surface casing 4 within the drive pipe DP. The operator will then place cement into the surface casing annulus 6 through known techniques and allow the cement to set. A typical cement slurry for the surface casing annulus 6 is commercially available from Halliburton Energy Services under the name HalCem™. As well understood by those of ordinary skill in the art, the depth of the surface casing will vary, but generally is placed from 300′ to about 2000′.

Next, the operator will drill within the surface casing 4, and concentrically place the intermediate casing 8 within the newly drilled hole. After placement of the intermediate casing 8, the intermediate casing annulus 10 is filled with a cement slurry, and wherein the cement slurry is allowed to set. The operator may continue drilling to a deeper depth within the intermediate casing 8. As shown in FIG. 1, a production casing 12 is then placed in the well thereby creating a production casing annulus 14. The production casing 12 intersects a subterranean zone 16 that may contain hydrocarbons. The production casing 12 is run all the way to the surface in the embodiment shown. The production casing annulus 14 is filled with a cement slurry of similar composition to the surface annulus cement and the intermediate casing annulus cement. The wellbore 2 may be perforated at the subterranean zone 16 so that the subterranean zone 16 is placed in communication with the inner bore 18 for production of hydrocarbons, as well understood by those of ordinary skill in the art.

FIG. 1 also depicts the wellhead, seen generally at 20. The wellhead 20, sometimes referred to as the Christmas tree 20, contains a series of valves for controlling flow out of the wellbore 2 as well as flow into the wellbore 2 via the inner bore 18. The wellhead 20 may include a master valve 22 as well as wing valves 24, 26. The wellhead 20 covers and seals the intermediate casing annulus 10 as well as the production casing annulus 14. However, the surface casing annulus 6 is not covered by the wellhead and thus open to the atmosphere. Hence, in the event that flow paths develop in surface casing annulus 6, hydrocarbon liquids and gas (as well as in-situ water) may be leaked to the surface. Also, if there is communication between the intermediate casing annulus 10 and the surface casing annulus 6, liquids and gas can be channeled to the surface casing annulus 6 and into the environment. These leaks pose many safety and health risks.

FIG. 1 is exemplary of a wellhead and casing implementation. However, it is possible that some changes may occur. For instance, for reasons pertaining to engineering and reservoir specifics, a number of additional casing strings may be employed. Moreover, some casing strings (besides the surface casing) may not be covered by the wellhead 20. The disclosure herein is applicable to any casing annuluses cemented to surface and not covered by a wellhead.

Referring now to FIG. 2, a schematic illustration of an embodiment of the present invention adapted to a wellbore 30 will now be discussed. In the various figures, like numbers in the figures refer to like components. More specifically, a drive pipe DP, a surface casing 32, an intermediate casing 34, and a production casing string 36 is shown. The surface casing 32 and drive pipe DP form the surface casing annulus 38 and the intermediate casing 34 and surface casing 32 form the intermediate casing annulus 40. The surface casing annulus 38 has a set cement therein and the intermediate casing annulus 40 has a set cement therein, and the composition of the set cement may be the composition previously mentioned. As noted earlier, the cement in the surface annulus may contain flow pathsrepresentively shown at 42, that serve as a path for liquids and gas.

FIG. 2 further depicts the reception area, seen generally at 44, for placement of a containment barrier as will be more fully explained later. Generally, the reception area 44 is the area on top of the surface casing annulus area at the surface, and wherein the operator would clean-out this area. This area could be at the surface of a land well as well as a subsea well. A containment cement slurry is placed in the reception area 42 as will be more fully explained later. The containment cement slurry is seen generally by the cross-hatched area of the reception area 44. FIG. 2 further depicts the squeeze pipes 46, 48 disposed through the containment cement slurry and within the reception area 44. As will be described later in this disclosure, in one embodiment, four (4) squeeze pipes are positioned within the reception area 44. Additionally, a valve member 50 is operatively associated with the pipe 46 and a valve member 52 is operatively associated with pipe 48 are included, wherein the valve members 50, 52 regulate the flow into and out of pipes 46, 48 respectively. The valves 50, 52 are commercially available from North Houston Valve and Fitting under the name Swagelok.

Referring now to FIG. 3, a top view of the schematic illustration of the embodiment depicted in FIG. 2 will now be described. The surface casing 32 and the intermediate casing 34 are shown along with the squeeze pipe 46 and squeeze pipe 48, wherein the squeeze pipe 46 and squeeze pipe 48 are in a 180 degree phase (i.e. opposite each other). Also shown is the squeeze pipe 54 and the squeeze pipe 56. In the embodiment depicted in FIG. 3, the four pipes are in a 90 degree phase 58.

Referring collectively to FIGS. 2 and 3, the method herein disclosed creates a pressure containment barrier. In one of the disclosed methods, a relatively small area at the top of the surface casing annulus 38, which in one embodiment is 15″ deep, should be free of set cement. The method includes creating the pressure containment barrier 44 with the containment cement slurry. A template for the squeeze pipes may be placed within the reception area 38. The materials for the containment cement slurry may comprise: a Class A cement, about 0 to about 15% BWOC Gypsum, and about 0% to about 3% BWOC CaC12 at 15.6 pound per gallon; water is mixed with the cement, Gypsum and CaC12 to form a slurry with a density between 12-18 pounds per gallon. The containment cement is commercially available from Lehigh under the name Class A or Type I. The gypsum is commercially available from US Gypsum and CaC12 is commercially available from JT Products. The containment cement slurry is then poured into the reception area 38. The method includes placing the four (4) squeeze pipes, with the pipes being ±24″ long stainless steel pipes in one embodiment, into the containment cement slurry and within the template. In one embodiment, the pipes are evenly spaced around the center of the surface casing annulus 38 and held in place with the template. The cement containment slurry is allowed to set and firmly hold the pipes into place. As noted earlier, the squeeze pipes provide a contained path to squeeze the settable fluid into the flow paths while the containment cement provides a squeeze barrier. At this point, it is probable that the gas may permeate through the fresh cement around the squeeze pipes. This is not an issue since the containment cement still provides a sufficient pressure barrier for a successful squeeze.

In one embodiment, the settable fluid is a two part resin system. The resin is selected from the group consisting of: Bisphenal F type resin with a diluent such as Epodil and catalyzed with an epoxide catalyst selected from the group consisting of amidoamines and modified polyamidomines The amidoamines are commercially available from Riteks under the names Ancamide 506 and Ancamide 2386; the modified polyamidomine is commercially available from Riteks under the name W Hardener. Also note that the diluent Epodil is commerically available from Air Products. A weighting agent may be added, wherein the weighting agent is selected from the group consisting of barite, silica flour and silica sand. In one embodiment, the resin is commercially available from Riteks under the name BFE170. In one preferred embodiment, the resins do not contain any solids. This allows the resin to penetrate the extremely small leak paths in the surface cement and still be able to set. The resin is injected into the four stainless steel pipes in a specified sequence of rates and pressures. The resin is forced into the leak paths and allowed to set. Resin squeezes are applied to the squeeze pipes as needed until the gas leaks are stopped.

In another embodiment, the settable fluid is a low viscosity, micro-fine cement. The micro-fine cement comprises microfine cement, dispersant, fluid loss additive, retarder, and water. The micro-fine cement is commercially available from De Neef Construction Chemicals under the name MC500. The micro-fine cement is forced into the leak paths and allowed to set.

In one embodiment, the procedure includes ensuring that a depth of about 15″ is clear in the surface casing annulus 6 above the top of the primary cement. If not, then the operator would chip away the primary cement to the approximately 15″ depth. Next, the operator checks to ensure that the four squeeze pipes can be spaced 90 degrees apart (as seen in FIG. 3). The operator mixes the containment cement slurry. As noted earlier, in one embodiment, the containment cement slurry comprises a Class A cement, about 0-15% BWOC Gypsum and about 0-3% BWOC CaC12 at 15.6 pound per gallon. Once the containment cement slurry is mixed, the slurry can be poured into the reception area.

With this embodiment, the operator places the squeeze pipes into the containment cement slurry as shown in FIG. 3. In one embodiment, the support template may be used to brace the squeeze pipes and hold the squeeze pipes upright until the containment cement is set. FIG. 4 is a top view of the template structure “T” of the present disclosure. The template “T” includes four (4) openings therein for the injection tubulars, namely openings 80, 82, 84, 86, as well as the opening 88 for the casing 32. Generally, the containment cement will set in about 24 hours. Next, according to this embodiment, the valve members (such as valves 50, 52 seen in FIG. 2) are attached to the squeeze pipes. The operator can then rig-up the pump, pump lines, and pressure vessels to the squeeze pipes. In this embodiment, the operator can then perform a communication-breakdown test with water on each of the squeeze pipes. Hence, the communication-breakdown test may include the operator closing all of the valve members on the squeeze pipes, pump water into each squeeze pipe one at a time (i.e. open a valve member of one of the squeeze pipes being injected), and establish which squeeze pipe has the most pressure at a specific flow rate such as 200 mL/min. The test results may be recorded. With this embodiment and based on the specifics of these test, the operator may begin squeezing the squeeze pipes in those squeeze pipes where an injection rate was recorded. This may be accomplished by closing the valves (for instance valves 50, 52) on the other squeeze pipes while squeezing. The order in which to squeeze may be based on the pressure obtained from the communication/breakdown test with water, as noted above. Next, the operator would squeeze the pipe with the lowest breakdown pressure first and then move to the next lowest and so on.

Once an injection schedule is arranged, the operator will mix the settable fluid thoroughly and load the settable fluid into the pressure vessel holding cell. The operator will squeeze the settable fluid into the pipes according to the squeeze schedule determined earlier. Generally, the operator will allow the settable fluid to cure for about 24 hours, but this may vary depending on the specific settable fluid used and other environmental factors. The operator will also monitor for leaks. If leaks are observed, the operator will perform another communication/breakdown test and repeat the earlier steps of injecting the settable fluid. If no leaks are observed, the operator may sever the squeeze pipes at the level of the surface casing. The operator may then fill the remaining annular space with settable fluid for an added leak barrier, and thereafter, allow the settable fluid to set.

Experimental tests were performed on the method herein disclosed. The tests consisted of a 24″ tall section of 16″ casing with a 9-⅝″ casing located inside. The casings are vertically oriented and a plate is welded to the bottom to hold pressure from beneath. A source of pressurized air is plumbed into the side of the 16″×9-⅝ annulus just above the bottom plate to simulate the leaking gas. The primary cement is poured into the annulus and allowed to set. Pressurized air bubbles were created through the primary cement as it sets to serve as the gas leaks paths. the leaking annulus was then repaired by applying this invention. A total of 20 full size test set-ups were built and used to test different materials and methods of this disclosure.

The first fifteen (15) full size tests were used to determine the ideal squeeze pipe placement, pressure containment material, squeeze resin composition, and squeeze schedule (pressure and rates). Each completed full size test was cut open to determine the path of the settable squeeze fluid. Once the initial 15 test were completed, an optimized combination of squeeze pipe placement, pressure containment material, squeeze resin recipe, and squeeze schedule (pressures and rates) was established. This procedure was tested five additional times to ensure the success of the method and its repeatability. Each of the confirmation tests were monitored for at least 30 days to ensure long-term leak containment. Every final procedure confirmation test confirmed the sealing effect of the disclosed method. The treatment data from one of the final confirmation tests is shown in the table below.

Annulus #17 Resin Squeeze Schedule and Results
	Pressure (psi)
Pipe #	Volume (mL)	Rate (mL/min)	Initial	End
1	500	200	300	400
	500	100	650	820
	500	20	330	700
	500	5	500	550
2	500	20	300	420
	500	5	380	680
3	500	20	1300	830
			(breakdown)
	500	5	600	740
4	0	—	Injection into the tubular
			was unable to be established
			(the tubular did not connect
			to any of the leak flow paths
			to allow injection).

An aspect of the present disclosure is to create a pressure containment system in order to force a settable fluid into the flow paths, thereby allowing the settable fluid to set and stop the gas by blocking the leak paths.

Although the present invention has been described in considerable detail with reference to certain preferred versions thereof, other versions are possible. Therefore, the spirit and scope of the appended claims should not be limited to the description of the preferred versions contained therein.

Claims

1. A method of providing pressure containment of a well having a well annulus open to the atmosphere at the surface, the well annulus containing a set cement therein, and wherein the cement contains flow paths which communicate a well pressure, the method comprises:

creating a reception area at the top of the well;

placing a containment cement slurry in said reception area;

installing an injection delivery system within said reception area;

preparing a settable fluid for injection into the flow paths;

injecting the settable fluid through said injection delivery system into the flow paths of the well annulus.

2. The method of claim 1 wherein said settable fluid comprises: a Bisphenal F type resin with a diluent and an epoxide catalyst selected from the group consisting of: amidoamines and modified polyamidomines; and a weighting agent selected from the group consisting of barite, silica flour and silica sand.

3. The method of claim 2 wherein said containment cement slurry comprises: a cement selected from the group consisting of: a Class A cement and |[WU1] a Type I cement; between 0% to about 30% BWOC Gypsum; and between 0% to about 6% BWOC CaC12 and water which is mixed to form a slurry with a density between 12-18 lbs per gallon.

4. The method of claim 3 wherein said injection delivery system comprises a series of injection tubulars configured to deliver the resin to the flow paths.

5. The method of claim 3 wherein said injection delivery system comprises a template having a first, a second, a third and a fourth injection tubular configured to deliver the resin to the flow paths.

6. The method of claim 3 wherein said injection step includes applying a squeeze pressure of resin that is injected into the tubulars above an established breakdown pressure and below a burst/collapse pressure of the well casing.

7. The method of claim 3 wherein the method further comprises:

allowing the settable fluid to set;

monitoring the pressure of the well annulus;

observing a pressure increase in the well annulus;

repeating the step of injecting the settable fluid.

8. The method of claim 3 wherein the method further comprises:

monitoring the pressure of the well annulus;

observing a constant pressure in the well annulus;

removing the injection delivery system from the reception area.

9. The method of claim 1 wherein said settable fluid is a micro-fine cement slurry comprising: a microfine cement, a dispersant, a fluid loss additive, a retarder, and water.

10. The method of claim 9 wherein said injection delivery system comprises a series of injection tubulars configured to deliver the low viscosity cement slurry to the flow paths 11. A method of providing pressure containment of a well, the well containing a surface casing having a surface annulus, an intermediate casing having an intermediate annulus, and a production casing having a production annulus, wherein the surface annulus, the intermediate annulus and the production annulus contains cement, and wherein the surface annulus contains flow paths capable of releasing pressure from a subterranean zone, the method comprising:

placing a containment cement slurry in a reception area at the top of the well;

installing a first tubular member within said reception area;

placing a valve means on said first tubular member;

fluidly connecting said first tubular member to a pump member;

preparing a settable fluid;

pumping the settable fluid through said first tubular member into the flow paths of the surface annulus.

12. The method of claim 11 wherein the step of pumping the settable fluid includes creating a squeeze pressure and the method further includes maintaining the squeeze pressure until the settable fluid hardens within the flow paths of the surface annulus.

13. The method of claim 11 wherein said settable fluid a Bisphenal F type resin with a diluent and an epoxide catalyst selected from the group consisting of: amidoamines and modified polyamidomines.

14. The method of claim 12 wherein said containment cement slurry comprises: a cement selected from the group consisting of a Class A cement |[WU2] and a Type I cement; about 0-30% BWOC Gypsum; and about 0-6% BWOC CaCl2.

15. The method of claim 13 further comprising a second, a third and a fourth tubular member, and wherein said first, said second, said third, and said fourth tubular members are configured to deliver the resin to the flow paths of the surface annulus cement.

16. The method of claim 13 wherein said injection delivery system comprises a template including said first tubular member and a second, a third and a fourth tubular member.

17. The method of claim 13 wherein said first tubular member contains a valve member, said valve member having an open position and a closed position, wherein said valve member controlling the pumping of the resin through said first tubular member and into the flow paths of the surface annulus cement.

18. The method of claim 13 wherein said squeeze pressure of resin injection into the tubulars is above an established breakdown pressure and below a burst/collapse pressure of the well casing.

19. The method of claim 16 wherein the method further comprises:

monitoring the pressure of the surface annulus;

observing a pressure increase in the surface annulus;

repeating the step of injecting the settable fluid.

20. The method of claim 16 wherein the method further comprises:

monitoring the pressure of the surface annulus;

observing a constant pressure in the surface annulus;

removing the injection delivery system from the reception area.

21. The method of claim 12 wherein said settable fluid is a low viscosity, micro-fine cement slurry comprising: a microfine cement, a dispersant, a fluid loss additive, a retarder, and water.

22. A method of providing pressure containment of a well having a well annulus containing cement, wherein the cement contains flow paths therein, the method comprises:

placing a containment cement slurry in a reception area at the top of the well;

installing a tubular member within said reception area;

preparing a resin, wherein the resin is selected from the group consisting of x, y, and z;

injecting the resin through said tubular member into the flow paths of the well annulus.

23. The method of claim 22 wherein said containment cement slurry comprises: a cement selected from a group consisting of: a Class A cement |[WU3] and a Type I cement; about 0-30% BWOC Gypsum; and about 0-6% BWOC CaC12.

24. The method of claim 23 further comprising a second, a third and a fourth tubular members and a template configured to hold said first, said second, said third and said fourth tubular members in the reception area during injection of the resin.

25. The method of claim 24 wherein said injection includes applying a squeeze pressure of resin that is injected into the tubular member above and established breakdown pressure and below a burst/collapse pressure of the well casing.

26. The method of claim 25 wherein the method further comprises:

allowing the resin to harden;

monitoring the pressure of the well annulus;

observing a constant pressure in the well annulus.