US20170044864A1 - Method of sealing wells by squeezing sealant - Google Patents
Method of sealing wells by squeezing sealant Download PDFInfo
- Publication number
- US20170044864A1 US20170044864A1 US15/185,334 US201615185334A US2017044864A1 US 20170044864 A1 US20170044864 A1 US 20170044864A1 US 201615185334 A US201615185334 A US 201615185334A US 2017044864 A1 US2017044864 A1 US 2017044864A1
- Authority
- US
- United States
- Prior art keywords
- sealant
- annulus
- string
- wellbore
- tubular
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
- E21B33/14—Methods or devices for cementing, for plugging holes, crevices, or the like for cementing casings into boreholes
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
Definitions
- the present disclosure generally relates to a method of sealing wells by squeezing a sealant into an annulus thereof.
- the hard impermeable sheath deposited in the annular space in a well by primary cementing is subjected to a number of stresses during the lifetime of the well.
- the pressure inside the casing can increase or decrease as the fluid filling it changes or as additional pressure is applied to the well, such as when the drilling fluid is replaced by a completion fluid or by a fluid used in a stimulation operation.
- a change of temperature also creates stress in the cement sheath, at least during the transition period before the temperatures of the steel and the cement come into equilibrium. As a result of pressure and temperature changes, the integrity of the cement sheath can be compromised. Thus, it can become necessary to repair the primary cement sheath, such as during a plug and abandonment operation.
- One way to repair the primary cement sheath is by squeeze cementing, i.e., squeezing Portland cement thereinto.
- a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and an outer tubular string, thereby repairing a cement sheath present in the annulus.
- a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and the wellbore, thereby repairing a cement sheath present in the annulus.
- FIG. 1 illustrates delivery of an equipment package to a platform for performing the squeeze operation, according to one embodiment of the present disclosure.
- FIG. 2A illustrates perforation of a production casing string.
- FIG. 2B illustrates deployment of a sealing string.
- FIGS. 3A-3C illustrate operation of a mixing unit of the equipment package to form sealant.
- FIG. 4 illustrates squeezing of the sealant into an annulus formed between the production casing string and a surface casing string.
- FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure.
- FIGS. 6A and 6B illustrate a second alternative sealing operation, according to another embodiment of the present disclosure.
- FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure.
- FIG. 1 illustrates an illustrative equipment package 1 used for performing the squeeze operation, and located on a platform 2 , according to one embodiment of the present disclosure.
- the platform 2 may be part of a well 3 further including a subsea wellbore 4 , a drive pipe 5 , a surface casing string 6 , a production casing string 7 , and a production tubing string 8 .
- the drive pipe 5 is commonly set from above a surface 9 s (aka waterline) of the sea 9 , through the sea, and into the seafloor 9 f (aka mudline).
- the drive pipe 5 allows the wellhead (not shown) to be located on the platform 2 above the waterline 9 s.
- the subsea wellbore 4 is drilled into the seafloor 9 f within the envelope of the drive pipe 5 .
- the surface casing string 6 is then run-in the drive pipe 5 and into the wellbore 4 and cemented into place by forming a cement sheath 10 b.
- the production casing 7 is run-into the wellbore 4 and cemented into place with cement sheath 10 c .
- the production casing string 7 is perforated 12 to permit the fluid hydrocarbons (not shown) to flow into the interior thereof.
- the hydrocarbons are transported from the formation 11 through the production tubing string 8 .
- An annulus 13 defined between the production casing string 7 and the production tubing string 8 is commonly isolated from the producing formation 11 with a production packer 14 .
- the equipment package 1 is delivered to the platform 2 via a transport vessel (not shown).
- the equipment package includes a coiled tubing unit 15 , a mixing unit 16 , and a squeeze pump 17 .
- the coiled tubing unit 15 includes a drum having coiled tubing 22 ( FIG. 2B ) wrapped therearound, a gooseneck, an injector head for driving the coiled tubing, controls, and a hydraulic power unit.
- a wireline winch 18 onboard the platform 2 may also be used to facilitate the squeeze operation.
- the wireline winch 18 typically includes a drum having wireline 19 ( FIG. 2A ) wrapped therearound and a motor for winding and unwinding the wireline, thereby raising and lowering a distal end of the wireline relative to the platform 2 .
- FIG. 2A illustrates perforation of the production casing string 7 .
- FIG. 2A shows the condition of the well during an abandonment or closing in operation, wherein a lower cement plug 21 has been set and the production tubing string 8 has been cut.
- the well 3 abandonment operation commences by connecting a bottomhole assembly (BHA) (not shown) to the wireline 19 extending through a lubricator (not shown).
- BHA bottomhole assembly
- the BHA includes a cablehead, a collar locator, and a tubing perforator, such as a perforating gun.
- one or more valves of the tree are opened and the BHA is deployed into the production tubing string in the wellbore 4 using the wireline 19 .
- the BHA is deployed to a depth adjacent to and above the production packer 14 .
- electrical power or an electrical signal is supplied to the BHA via the wireline 19 to fire the perforating gun into the production tubing string 8 , thereby forming tubing perforations 20 through the wall thereof.
- the BHA is retrieved to the lubricator and the lubricator is then removed from the production tree.
- Cement slurry (not shown) is then pumped through the production tree head, down the production tubing string 8 , and into the annulus 13 via the created tubing perforations 20 .
- Wellbore fluid displaced by the cement slurry will flow up the annulus 13 , through the wellhead and to the platform 2 .
- an annulus valve of the wellhead is closed while continuing to pump the cement slurry, thereby forcing or “squeezing” cement slurry into the adjacent formation 11 .
- the cement slurry is allowed to cure for a predetermined amount of time, such as one hour, six hours, twelve hours, or one day, thereby forming the cement plug 21 in the annulus, the surrounding formation, and within the lower portion of the production tubing string 8 .
- a second BHA (not shown) is connected to the wireline 19 in the lubricator and deployed through the production tree.
- the second BHA commonly includes a cablehead, a collar locator, an anchor, a hydraulic power unit (HPU), an electric motor, and a tubing cutter.
- the second BHA is deployed into the production tubing string 8 to a depth adjacent to and above the production packer 14 .
- the HPU is operated by supplying electrical power via the wireline 19 to extend blades of the tubing cutter and operate the motor to rotate the extended blades, thereby severing an upper portion of the production tubing string 8 from a lower portion thereof.
- the second BHA is then retrieved to the lubricator and the lubricator is removed from the production tree.
- the production tree is removed from the wellhead and the severed upper portion of the production tubing string 8 is removed from the wellbore 4 , leaving the wellbore in the state shown in FIG. 2A .
- a third BHA (not shown) is connected to the wireline 19 in the lubricator and deployed through the wellhead.
- the third BHA commonly includes a cablehead, a collar locator, a setting tool, and a bridge plug 23 .
- the third BHA is deployed to a setting depth along a portion of the production casing string 7 adjacent, and above, the lower terminus of the surface casing string 6 .
- electrical power is supplied to the third BHA via the wireline 19 to operate the setting tool, thereby expanding the bridge plug 23 against an inner surface of the production casing string 7 .
- the bridge plug 23 Once the bridge plug 23 has been set as shown in FIG. 2A , the bridge plug 23 is released from the setting tool.
- the third BHA (minus the bridge plug 23 ) is then retrieved to the lubricator and the lubricator is removed from the wellhead.
- a fourth BHA 24 is then connected to the wireline 19 in the lubricator and deployed through the wellhead.
- the fourth BHA 24 commonly includes a cablehead, a collar locator, and a casing perforator, such as a perforating gun.
- the fourth BHA 24 is deployed to a firing depth adjacent to and above the bridge plug 23 .
- electrical power or an electrical signal is supplied to the fourth BHA via the wireline 19 to fire the perforating gun into the production casing string 7 , thereby forming casing perforations 25 through a wall thereof as shown in FIG. 2A .
- the fourth BHA 24 is then retrieved to the lubricator and the lubricator is removed from the wellhead.
- FIG. 2B illustrates deployment of a sealing string.
- a fifth BHA 26 is connected to the coiled tubing 22 in a snubbing unit (not shown) and deployed through the wellhead.
- the fifth BHA 26 includes a squeeze packer and a setting tool.
- the injector head of the coiled tubing unit 15 is operated to lower the fifth BHA 26 to a squeezing depth adjacent to and above the casing perforations 25 .
- the squeeze pump 17 is operated to pump a setting plug (not shown), such as a ball, through the coiled tubing 22 to a seat of the setting tool.
- Fluid pressure may then be exerted on the seated ball to operate the setting tool, thereby expanding the squeeze packer against an inner surface of the production casing string 7 to thereby seal the annuals between the coiled tubing 22 and the production casing string 7 .
- additional fluid pressure is then applied to drive the ball through the seat of the setting tool, thereby reopening the bore of the coiled tubing 22 .
- FIGS. 3A-3C illustrate operation of the mixing unit 16 to form sealant 28 .
- the mixing unit 16 in the embodiment includes two or more liquid totes 29 a,b , and a transfer pump 30 a, b for each liquid tote, a dispensing hopper 31 , and a blender 32 .
- Each transfer pump 30 a,b is, in the embodiment, a metering pump and the dispensing hopper 31 is a metering hopper.
- An inlet of each transfer pump 30 a,b is connected to a respective liquid tote 29 a,b.
- a first liquid tote 29 a of the liquid totes 29 a,b includes a resin 33 r.
- the resin 33 r may be an epoxide, such as bisphenol F.
- the viscosity of the sealant 28 may be adjusted by premixing the resin 33 r with a diluent, such as alkyl glycidyl ether or benzyl alcohol. The viscosity of the sealant 28 may range between fifty and two thousand centipoise.
- the epoxide may also be premixed with a bonding agent, such as silane.
- a second liquid tote 29 b of the liquid totes 29 a,b may include a hardener 33 h selected based on the temperature in the wellbore 4 .
- the hardener 33 h may be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine, such as tetraethylenepentamine.
- the hardener 33 h may be an aromatic amine or polyamine, such as diethyltoluenediamine.
- the dispensing hopper 31 includes a particulate weighting material 34 having a specific gravity of at least two.
- the weighting material 34 may be barite, hematite, hausmannite ore, or sand.
- wellbore fluid may be non-aqueous and the resin 33 r may also be premixed with a surfactant to maintain cohesion thereof.
- the resin 33 r may also be premixed with a defoamer.
- the first transfer pump 30 a is operated to dispense the resin 33 r into the blender 32 .
- a motor of the blender 32 is then activated to churn the resin 33 r.
- the hopper 31 is then operated to dispense the weighting material 34 into the blender 32 .
- the weighting material 34 is added, as required, in a proportionate quantity such that a density of the sealant 28 corresponds to a density of the wellbore fluid.
- the density of the sealant 28 may be equal to, slightly greater than, or slightly less than the density of the wellbore fluid.
- the second transfer pump 30 b is operated to dispense the hardener 33 h into the blender 32 .
- the hardener 33 h is added in a proportionate quantity such that the thickening time of the sealant 28 corresponds to the time required to pump the sealant through the coiled tubing 22 , plus the time required to squeeze the sealant into the annulus 36 ( FIG. 4 ) formed between the production casing string 7 and the surface casing string 6 , plus a safety factor, such as one hour.
- FIG. 4 illustrates squeezing of the sealant 28 into the annulus 36 .
- the squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and into the coiled tubing 22 .
- the pumping may be monitored using the pressure gauge 37 of the equipment package 1 .
- the inlet of the squeeze pump 17 is then connected to a supply of chaser fluid (not shown), such as seawater, and the squeeze pump 17 is operated to pump the chaser fluid into the coiled tubing 22 , thereby driving the sealant 28 through the coiled tubing 22 and into the annulus 36 via the casing perforations 25 .
- chaser fluid not shown
- the sealant 28 flows into or through voids in the cement sheath 10 c present in the annulus 36 , thereby filling the voids and restoring the integrity of the cement sheath 10 c.
- a stroke counter of the squeeze pump 17 may be monitored during pumping and the squeeze pump shutoff once a desired volume of the chaser fluid has been pumped based on a certain number of strokes, corresponding to the internal volume of the coiled tubing 22 extending from the squeeze pump 17 , thereby ensuring that all of the sealant 28 has been discharged from the coiled tubing 22 .
- a portion of the sealant 28 also typically forms a bore plug in the production casing string 7 .
- the sealant 28 may also plug a portion of the cement sheath 10 c adjacent to the surface casing string 6 .
- the squeeze packer is then unset, such as by exerting tension on (pulling on) the coiled tubing 22 .
- the coiled tubing 22 and the fifth BHA 26 is retrieved to the platform 2 and the sealant is allowed to cure for a time, such as between one to five days. If the abandonment operation is permanent, once the sealant 28 has cured, the drive pipe 5 , surface casing string 6 , and production casing string 7 will typically be cut at or just below the seafloor 9 f, thereby completing the abandonment operation.
- FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure.
- a sixth BHA 27 is deployed instead of the fourth BHA 24 .
- the sixth BHA 27 is deployed to the firing depth adjacent to and above the bridge plug 23 .
- the sixth BHA 27 is similar to the fourth BHA 24 except for having a deep casing perforator, such as a perforating gun, instead of the casing perforator.
- the deep casing perforating gun has a charge strength sufficient to form deep perforations 38 through the walls of the production 7 and surface 6 casing strings and the cement sheath 10 c without damaging the wall of the drive pipe 5 , thereby establishing access to the cement sheath 10 b in an annulus 39 formed between the production and surface casing strings.
- the sixth BHA 27 is retrieved to the lubricator and the lubricator is removed from the wellhead.
- the fifth BHA 26 is then connected to the coiled tubing 22 and the injector head of the coiled tubing unit 15 is operated to lower the fifth BHA to the squeezing depth adjacent to and above the deep perforations 38 .
- the squeeze packer of the fifth BHA 26 is set.
- the squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and into the coiled tubing 22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving the sealant 28 through the coiled tubing 22 and into the annuli 36 , 39 via the casing perforations 38 .
- the sealant 28 flows into and through voids in the cement sheathes 10 b,c present in the respective annuli 36 , 39 , thereby filling the voids and restoring the integrity thereof.
- the sealant 28 may also plug a portion of the cement sheath 10 c adjacent to the surface casing string 6 and a portion of the cement sheath 10 b adjacent to the drive pipe 5 .
- FIGS. 6A and 6B illustrate a second alternative sealing operation, according to another embodiment of the present disclosure.
- the third BHA is deployed into the production casing string 7 to an alternative setting depth adjacent to a top of the severed production tubing string 8 and adjacent to the wellbore wall instead of along a portion of the production casing string 7 adjacent to the surface casing string 6 .
- the bridge plug 23 is set and released from the setting tool.
- the third BHA (minus the bridge plug 23 ) is then be retrieved to the lubricator and the lubricator is then removed from the wellhead.
- the fourth BHA 24 is then connected to the wireline 19 in the lubricator and deployed through the wellhead.
- the fourth BHA 24 is deployed to an alternative firing depth adjacent to and above the bridge plug 23 .
- electrical power or an electrical signal is supplied to the fourth BHA via the wireline 19 to fire the perforating gun into the production casing string 7 , thereby forming alternative casing perforations 40 through a wall thereof.
- the fourth BHA 24 is then retrieved to the lubricator and the lubricator is removed from the wellhead.
- the fifth BHA 26 is then connected to the coiled tubing 22 and the injector head of the coiled tubing unit 15 is operated to lower the fifth BHA to an alternative squeezing depth adjacent to and above the alternative casing perforations 40 .
- the squeeze packer of the fifth BHA 26 is set.
- the squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and into the coiled tubing 22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving the sealant 28 through the coiled tubing 22 and into the annulus 36 via the alternative casing perforations 40 .
- the sealant 28 flows into and through the voids in the cement sheath 10 c present in the annulus 36 thereby filling the voids and restoring the integrity of the cement sheath.
- the sealant 28 thus plugs a portion of the cement sheath 10 c adjacent to the wellbore wall.
- FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure.
- the bridge plug 23 is set at the alternative setting depth.
- the sixth BHA 27 is then deployed to a second alternative firing depth adjacent to and above a shoe of the surface casing string 6 and fired to form alternative deep perforations 41 through walls of the production 7 and surface 6 casing strings and the cement sheath 10 c.
- the fifth BHA 26 is then connected to the coiled tubing 22 and the injector head of the coiled tubing unit 15 is operated to lower the fifth BHA to a second alternative squeezing depth adjacent to and above the alternative deep perforations 41 .
- the squeeze packer of the fifth BHA 26 is set.
- the squeeze pump 17 is operated to pump the sealant 28 from the blender 32 and into the coiled tubing 22 and then to chase the sealant with an alternative fluid such as seawater, thereby driving the sealant 28 through the coiled tubing 22 and into the annuli 36 , 39 via the casing perforations 38 .
- the sealant 28 flows into and through voids in the cement sheathes 10 b,c present in the respective annuli 36 , 39 , thereby filling the voids and restoring the integrity thereof.
- the sealant 28 plugs a portion of the cement sheath 10 c adjacent to the surface casing string 6 and a portion thereof adjacent to the wellbore wall.
- the sealant 28 may also plug a portion of the cement sheath 10 b adjacent to the wellbore wall.
- a pipe string is used instead of the coiled tubing 22 to transport the sealant into the wellbore 4 .
- the pipe string typically includes joints of drill pipe or production tubing connected together, such as by threaded couplings.
- a cement plug is used instead of or in addition to the bridge plug 23 .
- the well 2 may further include one or more intermediate casing strings between the surface 6 and production 7 casing strings and the sealant is squeezed into one or more annuli formed between the production casing string and the intermediate casing strings.
- the sealant is squeezed into an annulus formed between a liner string and a casing string and/or between the liner string and the wellbore wall.
- the wellbore 4 may be subsea having a wellhead located adjacent to the seafloor and any of the sealing operations may be staged from an offshore drilling unit or an intervention vessel.
- the wellbore 4 may be subterranean and any of the sealing operations may be staged from drilling or workover rig located on a terrestrial pad adjacent thereto.
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
Description
- Field of the Disclosure
- The present disclosure generally relates to a method of sealing wells by squeezing a sealant into an annulus thereof.
- Description of the Related Art
- The hard impermeable sheath deposited in the annular space in a well by primary cementing is subjected to a number of stresses during the lifetime of the well. The pressure inside the casing can increase or decrease as the fluid filling it changes or as additional pressure is applied to the well, such as when the drilling fluid is replaced by a completion fluid or by a fluid used in a stimulation operation. A change of temperature also creates stress in the cement sheath, at least during the transition period before the temperatures of the steel and the cement come into equilibrium. As a result of pressure and temperature changes, the integrity of the cement sheath can be compromised. Thus, it can become necessary to repair the primary cement sheath, such as during a plug and abandonment operation. One way to repair the primary cement sheath is by squeeze cementing, i.e., squeezing Portland cement thereinto.
- The use of conventional Portland cement for squeeze cementing has limitations, for instance, if the primary cement sheath is leaking fluid, such as gas, through micro-channels, squeeze cementing is not feasible, even using micro-fine ground Portland cement.
- The present disclosure generally relates to a method of sealing wells by squeezing sealant into the annulus between the inner and outer tubular strings. In one embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and an outer tubular string, thereby repairing a cement sheath present in the annulus.
- In another embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and the wellbore, thereby repairing a cement sheath present in the annulus.
- So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.
-
FIG. 1 illustrates delivery of an equipment package to a platform for performing the squeeze operation, according to one embodiment of the present disclosure. -
FIG. 2A illustrates perforation of a production casing string.FIG. 2B illustrates deployment of a sealing string. -
FIGS. 3A-3C illustrate operation of a mixing unit of the equipment package to form sealant. -
FIG. 4 illustrates squeezing of the sealant into an annulus formed between the production casing string and a surface casing string. -
FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure. -
FIGS. 6A and 6B illustrate a second alternative sealing operation, according to another embodiment of the present disclosure. -
FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure. -
FIG. 1 illustrates an illustrative equipment package 1 used for performing the squeeze operation, and located on aplatform 2, according to one embodiment of the present disclosure. Theplatform 2 may be part of a well 3 further including asubsea wellbore 4, adrive pipe 5, asurface casing string 6, aproduction casing string 7, and aproduction tubing string 8. Thedrive pipe 5 is commonly set from above asurface 9 s (aka waterline) of the sea 9, through the sea, and into theseafloor 9 f (aka mudline). Thedrive pipe 5 allows the wellhead (not shown) to be located on theplatform 2 above thewaterline 9 s. - Once the
drive pipe 5 has been set, and (if desired cemented 10 a, thesubsea wellbore 4 is drilled into theseafloor 9 f within the envelope of thedrive pipe 5. Thesurface casing string 6 is then run-in thedrive pipe 5 and into thewellbore 4 and cemented into place by forming acement sheath 10 b. When thewellbore 4 reaches a hydrocarbon-bearing formation 11, i.e., crude oil and/or natural gas, theproduction casing 7 is run-into thewellbore 4 and cemented into place withcement sheath 10 c. Thereafter, theproduction casing string 7 is perforated 12 to permit the fluid hydrocarbons (not shown) to flow into the interior thereof. The hydrocarbons are transported from the formation 11 through theproduction tubing string 8. Anannulus 13 defined between theproduction casing string 7 and theproduction tubing string 8 is commonly isolated from the producing formation 11 with aproduction packer 14. - During production of hydrocarbons from the
well 3, it may become necessary to workover the well, install an artificial lift system, and/or stimulate or treat the formation 11. To facilitate any of these operations, it is typically desirable to temporarily plug thewell 3. Also, once the formation 11 has been produced to depletion, regulations often require permanently plugging the well 3 prior to abandoning thewell 3. If either or both of thecement sheathes 10 b,c have become compromised, they will need to be repaired during either the temporary or permanent plugging and abandonment operation, using the squeeze operation. - In order to prepare for the squeeze operation, the equipment package 1 is delivered to the
platform 2 via a transport vessel (not shown). The equipment package includes a coiledtubing unit 15, amixing unit 16, and asqueeze pump 17. The coiledtubing unit 15 includes a drum having coiled tubing 22 (FIG. 2B ) wrapped therearound, a gooseneck, an injector head for driving the coiled tubing, controls, and a hydraulic power unit. Awireline winch 18 onboard theplatform 2 may also be used to facilitate the squeeze operation. Thewireline winch 18 typically includes a drum having wireline 19 (FIG. 2A ) wrapped therearound and a motor for winding and unwinding the wireline, thereby raising and lowering a distal end of the wireline relative to theplatform 2. -
FIG. 2A illustrates perforation of theproduction casing string 7.FIG. 2A shows the condition of the well during an abandonment or closing in operation, wherein alower cement plug 21 has been set and theproduction tubing string 8 has been cut. To establish this condition, the well 3 abandonment operation commences by connecting a bottomhole assembly (BHA) (not shown) to thewireline 19 extending through a lubricator (not shown). In the embodiment, the BHA includes a cablehead, a collar locator, and a tubing perforator, such as a perforating gun. - To deploy the BHA into the well bore, one or more valves of the tree are opened and the BHA is deployed into the production tubing string in the
wellbore 4 using thewireline 19. The BHA is deployed to a depth adjacent to and above theproduction packer 14. Once the BHA has been deployed to the desired depth, electrical power or an electrical signal is supplied to the BHA via thewireline 19 to fire the perforating gun into theproduction tubing string 8, thereby formingtubing perforations 20 through the wall thereof. The BHA is retrieved to the lubricator and the lubricator is then removed from the production tree. - Cement slurry (not shown) is then pumped through the production tree head, down the
production tubing string 8, and into theannulus 13 via the createdtubing perforations 20. Wellbore fluid displaced by the cement slurry will flow up theannulus 13, through the wellhead and to theplatform 2. Once a desired quantity of cement slurry has been pumped into theannulus 13, an annulus valve of the wellhead is closed while continuing to pump the cement slurry, thereby forcing or “squeezing” cement slurry into the adjacent formation 11. Once pumped into place, the cement slurry is allowed to cure for a predetermined amount of time, such as one hour, six hours, twelve hours, or one day, thereby forming thecement plug 21 in the annulus, the surrounding formation, and within the lower portion of theproduction tubing string 8. - Once the
cement plug 21 has cured, a second BHA (not shown) is connected to thewireline 19 in the lubricator and deployed through the production tree. The second BHA commonly includes a cablehead, a collar locator, an anchor, a hydraulic power unit (HPU), an electric motor, and a tubing cutter. The second BHA is deployed into theproduction tubing string 8 to a depth adjacent to and above theproduction packer 14. Once the second BHA has been deployed to the cutting depth, the HPU is operated by supplying electrical power via thewireline 19 to extend blades of the tubing cutter and operate the motor to rotate the extended blades, thereby severing an upper portion of theproduction tubing string 8 from a lower portion thereof. The second BHA is then retrieved to the lubricator and the lubricator is removed from the production tree. The production tree is removed from the wellhead and the severed upper portion of theproduction tubing string 8 is removed from thewellbore 4, leaving the wellbore in the state shown inFIG. 2A . - Once the severed portion of the
production tubing string 8 has been removed, a third BHA (not shown) is connected to thewireline 19 in the lubricator and deployed through the wellhead. The third BHA commonly includes a cablehead, a collar locator, a setting tool, and abridge plug 23. The third BHA is deployed to a setting depth along a portion of theproduction casing string 7 adjacent, and above, the lower terminus of thesurface casing string 6. Once the third BHA has been deployed to the setting depth, electrical power is supplied to the third BHA via thewireline 19 to operate the setting tool, thereby expanding thebridge plug 23 against an inner surface of theproduction casing string 7. Once thebridge plug 23 has been set as shown inFIG. 2A , thebridge plug 23 is released from the setting tool. The third BHA (minus the bridge plug 23) is then retrieved to the lubricator and the lubricator is removed from the wellhead. - A
fourth BHA 24 is then connected to thewireline 19 in the lubricator and deployed through the wellhead. Thefourth BHA 24 commonly includes a cablehead, a collar locator, and a casing perforator, such as a perforating gun. Thefourth BHA 24 is deployed to a firing depth adjacent to and above thebridge plug 23. Once thefourth BHA 24 has been deployed to the firing depth, electrical power or an electrical signal is supplied to the fourth BHA via thewireline 19 to fire the perforating gun into theproduction casing string 7, thereby formingcasing perforations 25 through a wall thereof as shown inFIG. 2A . Thefourth BHA 24 is then retrieved to the lubricator and the lubricator is removed from the wellhead. -
FIG. 2B illustrates deployment of a sealing string. Afifth BHA 26 is connected to the coiledtubing 22 in a snubbing unit (not shown) and deployed through the wellhead. Thefifth BHA 26 includes a squeeze packer and a setting tool. The injector head of the coiledtubing unit 15 is operated to lower thefifth BHA 26 to a squeezing depth adjacent to and above thecasing perforations 25. Once thefifth BHA 26 has been deployed to the squeezing depth, thesqueeze pump 17 is operated to pump a setting plug (not shown), such as a ball, through the coiledtubing 22 to a seat of the setting tool. Fluid pressure may then be exerted on the seated ball to operate the setting tool, thereby expanding the squeeze packer against an inner surface of theproduction casing string 7 to thereby seal the annuals between thecoiled tubing 22 and theproduction casing string 7. In the embodiment, additional fluid pressure is then applied to drive the ball through the seat of the setting tool, thereby reopening the bore of the coiledtubing 22. -
FIGS. 3A-3C illustrate operation of the mixingunit 16 to formsealant 28. The mixingunit 16 in the embodiment includes two or moreliquid totes 29 a,b, and atransfer pump 30 a, b for each liquid tote, adispensing hopper 31, and ablender 32. - Each transfer pump 30 a,b is, in the embodiment, a metering pump and the
dispensing hopper 31 is a metering hopper. An inlet of each transfer pump 30 a,b is connected to a respectiveliquid tote 29 a,b. - A first
liquid tote 29 a of the liquid totes 29 a,b includes aresin 33 r. Theresin 33 r may be an epoxide, such as bisphenol F. The viscosity of thesealant 28 may be adjusted by premixing theresin 33 r with a diluent, such as alkyl glycidyl ether or benzyl alcohol. The viscosity of thesealant 28 may range between fifty and two thousand centipoise. The epoxide may also be premixed with a bonding agent, such as silane. A secondliquid tote 29 b of the liquid totes 29 a,b may include ahardener 33 h selected based on the temperature in thewellbore 4. The contents of the liquid totes 29 a, b may be reversed. For low temperature applications, thehardener 33 h may be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine, such as tetraethylenepentamine. For high temperature applications, thehardener 33 h may be an aromatic amine or polyamine, such as diethyltoluenediamine. Thedispensing hopper 31 includes aparticulate weighting material 34 having a specific gravity of at least two. Theweighting material 34 may be barite, hematite, hausmannite ore, or sand. - Alternatively, wellbore fluid may be non-aqueous and the
resin 33 r may also be premixed with a surfactant to maintain cohesion thereof. Alternatively, theresin 33 r may also be premixed with a defoamer. - To form the
sealant 28, thefirst transfer pump 30 a is operated to dispense theresin 33 r into theblender 32. A motor of theblender 32 is then activated to churn theresin 33 r. Thehopper 31 is then operated to dispense theweighting material 34 into theblender 32. Theweighting material 34 is added, as required, in a proportionate quantity such that a density of thesealant 28 corresponds to a density of the wellbore fluid. The density of thesealant 28 may be equal to, slightly greater than, or slightly less than the density of the wellbore fluid. - The
second transfer pump 30 b is operated to dispense thehardener 33 h into theblender 32. Thehardener 33 h is added in a proportionate quantity such that the thickening time of thesealant 28 corresponds to the time required to pump the sealant through the coiledtubing 22, plus the time required to squeeze the sealant into the annulus 36 (FIG. 4 ) formed between theproduction casing string 7 and thesurface casing string 6, plus a safety factor, such as one hour. Once theblender 32 has formed the components of thesealant 28 into a homogenous mixture, asupply valve 35 connecting the outlet of the blender ultimately to thesqueeze pump 17 may be opened. -
FIG. 4 illustrates squeezing of thesealant 28 into theannulus 36. Thesqueeze pump 17 is operated to pump thesealant 28 from theblender 32 and into the coiledtubing 22. The pumping may be monitored using thepressure gauge 37 of the equipment package 1. Once thesealant 28 has been pumped into the coiledtubing 22 downstream of thesqueeze pump 17, the inlet of thesqueeze pump 17 is then connected to a supply of chaser fluid (not shown), such as seawater, and thesqueeze pump 17 is operated to pump the chaser fluid into the coiledtubing 22, thereby driving thesealant 28 through the coiledtubing 22 and into theannulus 36 via thecasing perforations 25. Thesealant 28 flows into or through voids in thecement sheath 10 c present in theannulus 36, thereby filling the voids and restoring the integrity of thecement sheath 10 c. As the stroke volume of the squeeze pump may be known or calculated, a stroke counter of thesqueeze pump 17 may be monitored during pumping and the squeeze pump shutoff once a desired volume of the chaser fluid has been pumped based on a certain number of strokes, corresponding to the internal volume of the coiledtubing 22 extending from thesqueeze pump 17, thereby ensuring that all of thesealant 28 has been discharged from the coiledtubing 22. A portion of thesealant 28 also typically forms a bore plug in theproduction casing string 7. Thesealant 28 may also plug a portion of thecement sheath 10 c adjacent to thesurface casing string 6. - The squeeze packer is then unset, such as by exerting tension on (pulling on) the coiled
tubing 22. The coiledtubing 22 and thefifth BHA 26 is retrieved to theplatform 2 and the sealant is allowed to cure for a time, such as between one to five days. If the abandonment operation is permanent, once thesealant 28 has cured, thedrive pipe 5,surface casing string 6, andproduction casing string 7 will typically be cut at or just below theseafloor 9 f, thereby completing the abandonment operation. -
FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure. In this alternative method of sealing, asixth BHA 27 is deployed instead of thefourth BHA 24. Thesixth BHA 27 is deployed to the firing depth adjacent to and above thebridge plug 23. Thesixth BHA 27 is similar to thefourth BHA 24 except for having a deep casing perforator, such as a perforating gun, instead of the casing perforator. The deep casing perforating gun has a charge strength sufficient to formdeep perforations 38 through the walls of theproduction 7 andsurface 6 casing strings and thecement sheath 10 c without damaging the wall of thedrive pipe 5, thereby establishing access to thecement sheath 10 b in anannulus 39 formed between the production and surface casing strings. After performing the perforation step, thesixth BHA 27 is retrieved to the lubricator and the lubricator is removed from the wellhead. - The
fifth BHA 26 is then connected to the coiledtubing 22 and the injector head of the coiledtubing unit 15 is operated to lower the fifth BHA to the squeezing depth adjacent to and above thedeep perforations 38. Once thefifth BHA 26 has been deployed to the squeezing depth, the squeeze packer of thefifth BHA 26 is set. Thesqueeze pump 17 is operated to pump thesealant 28 from theblender 32 and into the coiledtubing 22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving thesealant 28 through the coiledtubing 22 and into theannuli casing perforations 38. Thesealant 28 flows into and through voids in the cement sheathes 10 b,c present in therespective annuli sealant 28 may also plug a portion of thecement sheath 10 c adjacent to thesurface casing string 6 and a portion of thecement sheath 10 b adjacent to thedrive pipe 5. -
FIGS. 6A and 6B illustrate a second alternative sealing operation, according to another embodiment of the present disclosure. In this second alternative sealing method, the third BHA is deployed into theproduction casing string 7 to an alternative setting depth adjacent to a top of the severedproduction tubing string 8 and adjacent to the wellbore wall instead of along a portion of theproduction casing string 7 adjacent to thesurface casing string 6. Once the third BHA has been deployed to the alternative setting depth, thebridge plug 23 is set and released from the setting tool. The third BHA (minus the bridge plug 23) is then be retrieved to the lubricator and the lubricator is then removed from the wellhead. - The
fourth BHA 24 is then connected to thewireline 19 in the lubricator and deployed through the wellhead. Thefourth BHA 24 is deployed to an alternative firing depth adjacent to and above thebridge plug 23. Once thefourth BHA 24 has been deployed to the alternative firing depth, electrical power or an electrical signal is supplied to the fourth BHA via thewireline 19 to fire the perforating gun into theproduction casing string 7, thereby formingalternative casing perforations 40 through a wall thereof. Thefourth BHA 24 is then retrieved to the lubricator and the lubricator is removed from the wellhead. - The
fifth BHA 26 is then connected to the coiledtubing 22 and the injector head of the coiledtubing unit 15 is operated to lower the fifth BHA to an alternative squeezing depth adjacent to and above thealternative casing perforations 40. Once thefifth BHA 26 has been deployed to the alternative squeezing depth, the squeeze packer of thefifth BHA 26 is set. Thesqueeze pump 17 is operated to pump thesealant 28 from theblender 32 and into the coiledtubing 22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving thesealant 28 through the coiledtubing 22 and into theannulus 36 via thealternative casing perforations 40. Thesealant 28 flows into and through the voids in thecement sheath 10 c present in theannulus 36 thereby filling the voids and restoring the integrity of the cement sheath. Thesealant 28 thus plugs a portion of thecement sheath 10 c adjacent to the wellbore wall. -
FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure. In this alternative, thebridge plug 23 is set at the alternative setting depth. Thesixth BHA 27 is then deployed to a second alternative firing depth adjacent to and above a shoe of thesurface casing string 6 and fired to form alternativedeep perforations 41 through walls of theproduction 7 andsurface 6 casing strings and thecement sheath 10 c. - The
fifth BHA 26 is then connected to the coiledtubing 22 and the injector head of the coiledtubing unit 15 is operated to lower the fifth BHA to a second alternative squeezing depth adjacent to and above the alternativedeep perforations 41. Once thefifth BHA 26 has been deployed to the second alternative squeezing depth, the squeeze packer of thefifth BHA 26 is set. Thesqueeze pump 17 is operated to pump thesealant 28 from theblender 32 and into the coiledtubing 22 and then to chase the sealant with an alternative fluid such as seawater, thereby driving thesealant 28 through the coiledtubing 22 and into theannuli casing perforations 38. Thesealant 28 flows into and through voids in the cement sheathes 10 b,c present in therespective annuli sealant 28 plugs a portion of thecement sheath 10 c adjacent to thesurface casing string 6 and a portion thereof adjacent to the wellbore wall. Thesealant 28 may also plug a portion of thecement sheath 10 b adjacent to the wellbore wall. - Alternatively, a pipe string is used instead of the coiled
tubing 22 to transport the sealant into thewellbore 4. The pipe string typically includes joints of drill pipe or production tubing connected together, such as by threaded couplings. - Alternatively, a cement plug is used instead of or in addition to the
bridge plug 23. - Alternatively, the
well 2 may further include one or more intermediate casing strings between thesurface 6 andproduction 7 casing strings and the sealant is squeezed into one or more annuli formed between the production casing string and the intermediate casing strings. Alternatively, the sealant is squeezed into an annulus formed between a liner string and a casing string and/or between the liner string and the wellbore wall. - Alternatively, the
wellbore 4 may be subsea having a wellhead located adjacent to the seafloor and any of the sealing operations may be staged from an offshore drilling unit or an intervention vessel. Alternatively, thewellbore 4 may be subterranean and any of the sealing operations may be staged from drilling or workover rig located on a terrestrial pad adjacent thereto. - While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.
Claims (20)
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US15/185,334 US20170044864A1 (en) | 2015-08-10 | 2016-06-17 | Method of sealing wells by squeezing sealant |
CA2934362A CA2934362A1 (en) | 2015-08-10 | 2016-06-28 | Method of sealing wells by squeezing sealant |
EP16177362.7A EP3130746A1 (en) | 2015-08-10 | 2016-06-30 | Method of sealing wells by squeezing sealant |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201562203140P | 2015-08-10 | 2015-08-10 | |
US15/185,334 US20170044864A1 (en) | 2015-08-10 | 2016-06-17 | Method of sealing wells by squeezing sealant |
Publications (1)
Publication Number | Publication Date |
---|---|
US20170044864A1 true US20170044864A1 (en) | 2017-02-16 |
Family
ID=56292557
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US15/185,334 Abandoned US20170044864A1 (en) | 2015-08-10 | 2016-06-17 | Method of sealing wells by squeezing sealant |
Country Status (3)
Country | Link |
---|---|
US (1) | US20170044864A1 (en) |
EP (1) | EP3130746A1 (en) |
CA (1) | CA2934362A1 (en) |
Cited By (22)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20180100373A1 (en) * | 2015-04-22 | 2018-04-12 | Welltec A/S | Downhole tool string for plug and abandonment by cutting |
US10174583B2 (en) | 2016-06-07 | 2019-01-08 | Csi Technologies Llc | Method of placing sealant into an offshore well to abandon a production zone |
WO2019013650A1 (en) * | 2017-07-13 | 2019-01-17 | Tyrfing Innovation As | A downhole apparatus and a method at a downhole location |
US10214988B2 (en) | 2015-08-12 | 2019-02-26 | Csi Technologies Llc | Riserless abandonment operation using sealant and cement |
EP3502207A1 (en) | 2017-12-19 | 2019-06-26 | CSI Technologies LLC | Emulsion of aqueous-based slurry in resin as a well sealant |
US10428261B2 (en) | 2017-06-08 | 2019-10-01 | Csi Technologies Llc | Resin composite with overloaded solids for well sealing applications |
US11136849B2 (en) | 2019-11-05 | 2021-10-05 | Saudi Arabian Oil Company | Dual string fluid management devices for oil and gas applications |
US11156052B2 (en) | 2019-12-30 | 2021-10-26 | Saudi Arabian Oil Company | Wellbore tool assembly to open collapsed tubing |
US11230904B2 (en) | 2019-11-11 | 2022-01-25 | Saudi Arabian Oil Company | Setting and unsetting a production packer |
US11253819B2 (en) | 2020-05-14 | 2022-02-22 | Saudi Arabian Oil Company | Production of thin film composite hollow fiber membranes |
US11260351B2 (en) | 2020-02-14 | 2022-03-01 | Saudi Arabian Oil Company | Thin film composite hollow fiber membranes fabrication systems |
CN114320217A (en) * | 2020-09-30 | 2022-04-12 | 中国石油天然气股份有限公司 | Secondary well cementation and water plugging method for pipe outside channeling well |
US11448026B1 (en) | 2021-05-03 | 2022-09-20 | Saudi Arabian Oil Company | Cable head for a wireline tool |
US11549329B2 (en) | 2020-12-22 | 2023-01-10 | Saudi Arabian Oil Company | Downhole casing-casing annulus sealant injection |
US11598178B2 (en) | 2021-01-08 | 2023-03-07 | Saudi Arabian Oil Company | Wellbore mud pit safety system |
US11655685B2 (en) | 2020-08-10 | 2023-05-23 | Saudi Arabian Oil Company | Downhole welding tools and related methods |
US11773677B2 (en) | 2021-12-06 | 2023-10-03 | Saudi Arabian Oil Company | Acid-integrated drill pipe bars to release stuck pipe |
US11828128B2 (en) | 2021-01-04 | 2023-11-28 | Saudi Arabian Oil Company | Convertible bell nipple for wellbore operations |
US11859815B2 (en) | 2021-05-18 | 2024-01-02 | Saudi Arabian Oil Company | Flare control at well sites |
US11905791B2 (en) | 2021-08-18 | 2024-02-20 | Saudi Arabian Oil Company | Float valve for drilling and workover operations |
US11913298B2 (en) | 2021-10-25 | 2024-02-27 | Saudi Arabian Oil Company | Downhole milling system |
US11939835B2 (en) | 2022-04-04 | 2024-03-26 | Saudi Arabian Oil Company | Repairing wellbores with fluid movement behind casing |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10378299B2 (en) | 2017-06-08 | 2019-08-13 | Csi Technologies Llc | Method of producing resin composite with required thermal and mechanical properties to form a durable well seal in applications |
Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20080135251A1 (en) * | 2006-02-10 | 2008-06-12 | Halliburton Energy Services, Inc. | Compositions and applications of resins in treating subterranean formations |
US20110203795A1 (en) * | 2010-02-24 | 2011-08-25 | Christopher John Murphy | Sealant for forming durable plugs in wells and methods for completing or abandoning wells |
US20130233551A1 (en) * | 2010-11-30 | 2013-09-12 | Lijun Lin | Methods for Servicing Subterranean Wells |
Family Cites Families (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
BR112015032813A2 (en) * | 2013-09-04 | 2017-07-25 | Halliburton Energy Services Inc | method of treating a well treatment zone, and, composition |
WO2016024990A1 (en) * | 2014-08-15 | 2016-02-18 | Halliburton Energy Services, Inc. | Napthol-based epoxy resin additives for use in well cementing |
-
2016
- 2016-06-17 US US15/185,334 patent/US20170044864A1/en not_active Abandoned
- 2016-06-28 CA CA2934362A patent/CA2934362A1/en not_active Abandoned
- 2016-06-30 EP EP16177362.7A patent/EP3130746A1/en not_active Withdrawn
Patent Citations (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20080135251A1 (en) * | 2006-02-10 | 2008-06-12 | Halliburton Energy Services, Inc. | Compositions and applications of resins in treating subterranean formations |
US20110203795A1 (en) * | 2010-02-24 | 2011-08-25 | Christopher John Murphy | Sealant for forming durable plugs in wells and methods for completing or abandoning wells |
US20130233551A1 (en) * | 2010-11-30 | 2013-09-12 | Lijun Lin | Methods for Servicing Subterranean Wells |
Non-Patent Citations (2)
Title |
---|
Ellis. Chemistry and Technology of Epoxy Resins- Chapters 1-2 (1993) * |
Solids and Metals - Specific Gravities * |
Cited By (26)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10724328B2 (en) * | 2015-04-22 | 2020-07-28 | Welltec A/S | Downhole tool string for plug and abandonment by cutting |
US20180100373A1 (en) * | 2015-04-22 | 2018-04-12 | Welltec A/S | Downhole tool string for plug and abandonment by cutting |
US10214988B2 (en) | 2015-08-12 | 2019-02-26 | Csi Technologies Llc | Riserless abandonment operation using sealant and cement |
US10174583B2 (en) | 2016-06-07 | 2019-01-08 | Csi Technologies Llc | Method of placing sealant into an offshore well to abandon a production zone |
US10378306B2 (en) | 2016-06-07 | 2019-08-13 | Csi Technologies Llc | Method of placing sealant into an offshore well to abandon a production zone |
US10428261B2 (en) | 2017-06-08 | 2019-10-01 | Csi Technologies Llc | Resin composite with overloaded solids for well sealing applications |
GB2578546B (en) * | 2017-07-13 | 2021-12-08 | Tyrfing Innovation As | A downhole apparatus and a method at a downhole location |
WO2019013650A1 (en) * | 2017-07-13 | 2019-01-17 | Tyrfing Innovation As | A downhole apparatus and a method at a downhole location |
GB2578546A (en) * | 2017-07-13 | 2020-05-13 | Tyrfing Innovation As | A downhole apparatus and a method at a downhole location |
EP3502207A1 (en) | 2017-12-19 | 2019-06-26 | CSI Technologies LLC | Emulsion of aqueous-based slurry in resin as a well sealant |
US11136849B2 (en) | 2019-11-05 | 2021-10-05 | Saudi Arabian Oil Company | Dual string fluid management devices for oil and gas applications |
US11230904B2 (en) | 2019-11-11 | 2022-01-25 | Saudi Arabian Oil Company | Setting and unsetting a production packer |
US11156052B2 (en) | 2019-12-30 | 2021-10-26 | Saudi Arabian Oil Company | Wellbore tool assembly to open collapsed tubing |
US11260351B2 (en) | 2020-02-14 | 2022-03-01 | Saudi Arabian Oil Company | Thin film composite hollow fiber membranes fabrication systems |
US11253819B2 (en) | 2020-05-14 | 2022-02-22 | Saudi Arabian Oil Company | Production of thin film composite hollow fiber membranes |
US11655685B2 (en) | 2020-08-10 | 2023-05-23 | Saudi Arabian Oil Company | Downhole welding tools and related methods |
CN114320217A (en) * | 2020-09-30 | 2022-04-12 | 中国石油天然气股份有限公司 | Secondary well cementation and water plugging method for pipe outside channeling well |
US11549329B2 (en) | 2020-12-22 | 2023-01-10 | Saudi Arabian Oil Company | Downhole casing-casing annulus sealant injection |
US11828128B2 (en) | 2021-01-04 | 2023-11-28 | Saudi Arabian Oil Company | Convertible bell nipple for wellbore operations |
US11598178B2 (en) | 2021-01-08 | 2023-03-07 | Saudi Arabian Oil Company | Wellbore mud pit safety system |
US11448026B1 (en) | 2021-05-03 | 2022-09-20 | Saudi Arabian Oil Company | Cable head for a wireline tool |
US11859815B2 (en) | 2021-05-18 | 2024-01-02 | Saudi Arabian Oil Company | Flare control at well sites |
US11905791B2 (en) | 2021-08-18 | 2024-02-20 | Saudi Arabian Oil Company | Float valve for drilling and workover operations |
US11913298B2 (en) | 2021-10-25 | 2024-02-27 | Saudi Arabian Oil Company | Downhole milling system |
US11773677B2 (en) | 2021-12-06 | 2023-10-03 | Saudi Arabian Oil Company | Acid-integrated drill pipe bars to release stuck pipe |
US11939835B2 (en) | 2022-04-04 | 2024-03-26 | Saudi Arabian Oil Company | Repairing wellbores with fluid movement behind casing |
Also Published As
Publication number | Publication date |
---|---|
EP3130746A1 (en) | 2017-02-15 |
CA2934362A1 (en) | 2017-02-10 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US20170044864A1 (en) | Method of sealing wells by squeezing sealant | |
US11401777B2 (en) | Through tubing P and A with two-material plugs | |
US11391113B2 (en) | Tandem cement retainer and bridge plug | |
US7779926B2 (en) | Wellbore plug adapter kit and method of using thereof | |
EP3098380A1 (en) | Method of sealing wells by injection of sealant | |
US10053949B2 (en) | Cement retainer and squeeze technique | |
US11293253B2 (en) | Dual sub-surface release plug with bypass for small diameter liners | |
US10378306B2 (en) | Method of placing sealant into an offshore well to abandon a production zone | |
US8789621B2 (en) | Hydrocarbon well completion system and method of completing a hydrocarbon well | |
US10801291B2 (en) | Tubing hanger system, and method of tensioning production tubing in a wellbore | |
US20110162844A1 (en) | Assembly and method for placing a cement plug | |
EP3694949A1 (en) | Thixotropic cement slurry and placement method to cure lost circulation | |
US11767732B2 (en) | Systems and methods for plugging a well | |
US20110315381A1 (en) | Compositions and method for use in plugging a well | |
US20160208569A1 (en) | Sealing insert and method | |
US20240060376A1 (en) | Back pressure valve capsule | |
US20230417122A1 (en) | System and method for running and cementing fabric-nested casing | |
US20240117708A1 (en) | Production sub including degradable orifice | |
Hertfelder et al. | Are Swelling-Elastomer Technology, Preperforated Liner; and Intelligent-Well Technology Suitable Alternatives to Conventional Completion Architecture? | |
US20190003281A1 (en) | Configuring a velocity string in a production tubing of a wet gas production well | |
Erland | Centralization of casings in wells | |
Giorgi et al. | Design and Implementation of Calibration Plug as a Key to Success of Tubingless Completion in Tunu Field |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: CSI TECHNOLOGIES LLC, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:SABINS, FRED;MEADE, CLIFTON;BROWN, DAVID;AND OTHERS;SIGNING DATES FROM 20160621 TO 20160623;REEL/FRAME:039075/0523 |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: NON FINAL ACTION MAILED |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |
|
AS | Assignment |
Owner name: WILD WELL CONTROL, INC., TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:CSI TECHNOLOGIES, L.L.C.;REEL/FRAME:053091/0345 Effective date: 20200618 |