US20090272545A1 - System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space - Google Patents
System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space Download PDFInfo
- Publication number
- US20090272545A1 US20090272545A1 US12/432,306 US43230609A US2009272545A1 US 20090272545 A1 US20090272545 A1 US 20090272545A1 US 43230609 A US43230609 A US 43230609A US 2009272545 A1 US2009272545 A1 US 2009272545A1
- Authority
- US
- United States
- Prior art keywords
- pressure
- recited
- collapsing
- capsules
- containment space
- 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
- 239000012530 fluid Substances 0.000 title claims abstract description 135
- 239000002775 capsule Substances 0.000 title claims abstract description 63
- 238000000034 method Methods 0.000 title claims abstract description 26
- 239000007788 liquid Substances 0.000 claims abstract description 29
- 239000000203 mixture Substances 0.000 claims abstract description 19
- 239000004005 microsphere Substances 0.000 claims description 56
- 239000011521 glass Substances 0.000 claims description 34
- 239000000463 material Substances 0.000 claims description 15
- 229920000642 polymer Polymers 0.000 claims description 7
- 239000000919 ceramic Substances 0.000 claims description 6
- 229910052751 metal Inorganic materials 0.000 claims description 6
- 239000002184 metal Substances 0.000 claims description 6
- 238000013459 approach Methods 0.000 claims description 2
- 230000015572 biosynthetic process Effects 0.000 description 26
- 238000005755 formation reaction Methods 0.000 description 26
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 25
- 239000004568 cement Substances 0.000 description 19
- 238000004519 manufacturing process Methods 0.000 description 18
- 239000007789 gas Substances 0.000 description 15
- 238000005553 drilling Methods 0.000 description 14
- 239000003921 oil Substances 0.000 description 10
- 239000012267 brine Substances 0.000 description 6
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 6
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 238000005086 pumping Methods 0.000 description 4
- 239000002699 waste material Substances 0.000 description 4
- 230000008859 change Effects 0.000 description 3
- 239000003795 chemical substances by application Substances 0.000 description 3
- 238000002347 injection Methods 0.000 description 3
- 239000007924 injection Substances 0.000 description 3
- 238000002955 isolation Methods 0.000 description 3
- 239000011435 rock Substances 0.000 description 3
- 238000005728 strengthening Methods 0.000 description 3
- 239000000725 suspension Substances 0.000 description 3
- XKRFYHLGVUSROY-UHFFFAOYSA-N Argon Chemical compound [Ar] XKRFYHLGVUSROY-UHFFFAOYSA-N 0.000 description 2
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 2
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 2
- 230000006378 damage Effects 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 239000010881 fly ash Substances 0.000 description 2
- 239000010438 granite Substances 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- 239000003129 oil well Substances 0.000 description 2
- 229920000620 organic polymer Polymers 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 239000011800 void material Substances 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 1
- 239000001856 Ethyl cellulose Substances 0.000 description 1
- ZZSNKZQZMQGXPY-UHFFFAOYSA-N Ethyl cellulose Chemical compound CCOCC1OC(OC)C(OCC)C(OCC)C1OC1C(O)C(O)C(OC)C(CO)O1 ZZSNKZQZMQGXPY-UHFFFAOYSA-N 0.000 description 1
- 229920002907 Guar gum Polymers 0.000 description 1
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 1
- 208000034699 Vitreous floaters Diseases 0.000 description 1
- 229910052786 argon Inorganic materials 0.000 description 1
- 229960000892 attapulgite Drugs 0.000 description 1
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 1
- 239000010428 baryte Substances 0.000 description 1
- 229910052601 baryte Inorganic materials 0.000 description 1
- 239000002199 base oil Substances 0.000 description 1
- 239000000440 bentonite Substances 0.000 description 1
- 229910000278 bentonite Inorganic materials 0.000 description 1
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 230000008602 contraction Effects 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 239000012809 cooling fluid Substances 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 229920001249 ethyl cellulose Polymers 0.000 description 1
- 235000019325 ethyl cellulose Nutrition 0.000 description 1
- 230000001747 exhibiting effect Effects 0.000 description 1
- 239000000945 filler Substances 0.000 description 1
- 229910021485 fumed silica Inorganic materials 0.000 description 1
- ZZUFCTLCJUWOSV-UHFFFAOYSA-N furosemide Chemical compound C1=C(Cl)C(S(=O)(=O)N)=CC(C(O)=O)=C1NCC1=CC=CO1 ZZUFCTLCJUWOSV-UHFFFAOYSA-N 0.000 description 1
- 239000000665 guar gum Substances 0.000 description 1
- 229960002154 guar gum Drugs 0.000 description 1
- 235000010417 guar gum Nutrition 0.000 description 1
- 150000004677 hydrates Chemical class 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 239000011261 inert gas Substances 0.000 description 1
- 229910010272 inorganic material Inorganic materials 0.000 description 1
- 239000011147 inorganic material Substances 0.000 description 1
- 239000002480 mineral oil Substances 0.000 description 1
- 235000010446 mineral oil Nutrition 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 229910052625 palygorskite Inorganic materials 0.000 description 1
- 239000001103 potassium chloride Substances 0.000 description 1
- 235000011164 potassium chloride Nutrition 0.000 description 1
- 238000003825 pressing Methods 0.000 description 1
- 230000001902 propagating effect Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000009528 severe injury Effects 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- 239000011343 solid material Substances 0.000 description 1
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
- E21B33/12—Packers; Plugs
- E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
Definitions
- the present application is directed to systems and methods for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid.
- geothermal wells are completed in porous geothermal formations having naturally high permeability and which contain heated brine and/or steam in relative close proximity to the surface of the earth. These hydrothermal formations are found in a number of locations around the world.
- HDR hot dry rock
- Enhanced geothermal systems (EGS) are used to extract thermal energy from deep HDR formations exhibiting low permeability.
- Most HDR formations grow hotter with increasing depth, and in a related aspect, it is advantageous to isolate zones deep in the formation that generate the most heat.
- EGS wells completed in deep granite basement rock having in situ temperatures ranging from 150° C. to greater than 350° C. are capable of producing large quantities of thermal energy.
- Drilling and completion of oil and gas wells and geothermal wells involves forming a subterranean wellbore by rotating an earth boring bit into an earth formation as weight is applied to the bit.
- the drilled wellbore is normally lined with a string of tubulars known as casing and the well is completed by pumping cement into the annulus between the casing and the wellbore wall.
- the casing string is often cemented at the bottom.
- fluid is often trapped in the annulus between the casing string and the wellbore wall or between two casing strings. Trapped annular fluid thermally expands when the wellbore is heated during drilling, production and other well operations. The thermal expansion of trapped annular fluid can cause annular pressure build-up (APB) and result in collapse of the casing string.
- APIB annular pressure build-up
- Expandable or inflatable packers have also been used in the oil and gas and geothermal industries for well related operations such as zone isolation and formation treating. Expandable packers are used to block the flow of fluids through the annular spaces within the wellbore. Expandable packers are typically filled with a material such as cement, water, or drilling fluid to inflate an expandable packer element. The cement eventually hydrates to form a hard, solid material. In order to remove the packer, the cement and expandable packer must be drilled out. For some applications, it is desirable to both inflate and subsequently deflate a packer once a given operation within a well is completed. A filler material consisting of a liquid such as water, drilling fluid, oil, and other downhole fluids may be used for such an operation.
- a filler material consisting of a liquid such as water, drilling fluid, oil, and other downhole fluids may be used for such an operation.
- a system comprises a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well and a pressured operating fluid filling at least a portion of the containment space.
- the pressured operating fluid comprises a mixture of substantially incompressible liquid and pressure actuated collapsing capsules. At least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
- FIG. 1 illustrates an exemplary system for protecting a subterranean containment space in a subterranean well or formation from over-pressure according to one embodiment
- FIG. 2A illustrates an exemplary pressured operating fluid according to one embodiment
- FIG. 2B illustrates exemplary pressure actuated collapsing capsules according to one embodiment
- FIG. 3 illustrates an exemplary system for protecting a subterranean containment space in an annulus of a subterranean well from over-pressure according to one embodiment
- FIGS. 4A through 4F illustrate an exemplary system for protecting a subterranean containment space in the annulus of a subterranean well from over-pressure according to another embodiment
- FIGS. 5A through 5E illustrate an exemplary system for protecting a downhole packer from over-pressure according to one embodiment
- FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well from over-pressure according to one embodiment.
- subterranean wells including, but not limited to, geothermal wells, oil wells, gas wells, water wells, injection wells or any other well known in the art for producing or injecting fluids.
- FIG. 1 illustrates an exemplary system for protecting a subterranean containment space 106 in a subterranean well 102 or formation 100 from over-pressure according to one embodiment.
- the subterranean well 102 may be a geothermal well, oil well, gas well, water well, injection well or any other well known in the art.
- subterranean pressured fluid receiving containment spaces 106 may form in the wellbore 104 or in the subterranean formation 100 .
- a subterranean containment space 106 such as a downhole packer may be introduced into the subterranean well 102 in an annulus between the production conduit 110 and the casing string 112 or in an annulus 114 between the casing string 112 and the wellbore wall 116 .
- a subterranean containment space 106 may form in the annulus 114 during a primary well operation such as, cementing of the casing string 112 .
- Subterranean containment spaces 106 may also be naturally occurring voids or cavities in the subterranean formation 100 . Downhole fluids may become trapped in subterranean containment spaces 106 during drilling, completion, production and other well operations. If the subterranean well 102 including the wellbore wall 116 and/or fluids within the wellbore 104 are heated during well operations, trapped fluids will thermally expand and pressurize the subterranean containment spaces 106 . Thermally expanding downhole fluids can damage the subterranean well 102 and/or elements within the well 102 including, but not limited to, well casing, well liners, well packers, production conduit, downhole tools and other downhole tubulars within the wellbore 104 . Thermally expanding downhole fluids can also cause damage to the subterranean formation 100 by propagating undesired fractures within the formation 100 .
- subterranean containment spaces 106 are at least partially filled with pressured operating fluid 108 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules.
- the pressure actuated collapsing capsules rupture, implode or collapse when pressure in the subterranean containment space 106 exceeds a predetermined limit, thus compensating for the thermal expansion of the liquid in the containment space 106 and preventing over-pressure from damaging the subterranean well 102 .
- the pressured operating fluid 108 may also be pumped or circulated into a plurality of laterally or vertically arranged subterranean zones 120 , 122 in the formation 100 to protect the formation from undesired fracture propagation.
- Containment spaces 106 in the well 100 and the formation 100 may be partially or fully filled with pressured operating fluid 108 by pumping or circulating the pressured operating fluid 108 into wellbore 104 through the production conduit 110 , the casing string 112 , or the annulus 114 between the casing string 112 and the wellbore wall 116 .
- FIG. 2A illustrates an exemplary pressured operating fluid 30 comprising a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 32 according to one embodiment.
- the pressure actuated collapsing capsules 34 are suspended in the substantially incompressible liquid 32 .
- a viscosifying agent may be added to the pressured operating fluid 30 to aid in the suspension of the pressure actuated collapsing capsules 34 .
- the viscosifying agent may be an organic polymer such as hydro ethyl cellulose, hydropropyl guar, guar gum, and/or any other compatible organic polymer capable of aiding in the suspension of the pressure actuated collapsing capsules 34 .
- the viscosifying agent may also be an inorganic material such as fumed silica, bentonite, or attapulgite. Weighting materials such as barite or hausmanite may also be added to the pressured operating fluid 30 to modify the density of the fluid.
- the pressured operating fluid 30 comprising a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 34 is designed to accommodate thermal expansion of liquid in a subterranean containment space, including but not limited to, an expandable bladder of a well packer, an annulus between the casing string and the wellbore wall, an annulus between the production conduit and the casing string, an annulus between two casing strings, a fracture in the subterranean formation or any other downhole tubular, downhole tool, or void in a subterranean well or formation capable of containing liquid.
- a subterranean containment space including but not limited to, an expandable bladder of a well packer, an annulus between the casing string and the wellbore wall, an annulus between the production conduit and the casing string, an annulus between two casing strings, a fracture in the subterranean formation or any other downhole tubular, downhole tool, or void in a subterranean well or formation capable of
- the substantially incompressible liquid 32 component of the pressured operating fluid 30 may be selected based on the specific application of the pressured operating fluid 30 and/or the downhole fluids present in the well such as, drilling fluids and production fluids.
- the substantially incompressible liquid 32 may comprise water.
- the substantially incompressible liquid 32 may also comprise one or more components that make up a drilling fluid present in the well to maintain compatibility between the pressured operating fluid 30 and the drilling fluid.
- the substantially incompressible liquid 32 may comprise the drilling fluid or a competent thereof such as the base oil.
- the substantially incompressible liquid 32 may also comprise mineral oil and/or synthetic oil.
- the substantially incompressible liquid 32 may comprise various concentrations of potassium chloride brine, sodium chloride brine, production brine and/or other substantially incompressible liquid that is compatible with downhole fluids present in the subterranean well.
- pressure actuated collapsing capsules 34 are designed to rupture, implode or collapse at a predetermined pressure during thermal expansion of the substantially incompressible liquid 32 .
- the pressure actuated collapsing capsules 34 may be of substantially fixed volume or they may have variable volumes within the substantially incompressible liquid 32 .
- the pressure actuated collapsing capsules 34 may also be partially or fully filled with gas 38 .
- the gas 38 may be air or an inert gas such as, nitrogen or argon to prevent chemical reaction with downhole fluids after collapse of the pressure actuated collapsing capsules 34 .
- the gas 38 may also be one or more gases present in the subterranean well such as nitrogen, methane or other hydrocarbon gases.
- the pressure actuated collapsing capsules 34 may be substantially void of gas.
- the pressure actuated collapsing capsules 34 may be manufactured to have a predetermined collapse pressure.
- the pressure actuated collapsing capsules 34 may also be a waste byproduct which have non-uniform or graduated collapse pressures.
- the pressure actuated collapsing capsules 34 may be hollow and encased in a frangible material 36 .
- the pressure actuated collapsing capsules 34 may be spherical, cratered or ellipsoidal. Hollow microspheres, because of their spherical form, can have a high isotropic compressive strength and are therefore well suited for applications that require high collapse pressures.
- the pressure actuated collapsing capsules 34 may be designed to have a substantially uniform collapse pressure, such that the majority of pressure actuated collapsing capsules 34 fail or collapse at the same pressure.
- the pressure actuated collapsing capsules 34 may also be designed to have non-uniform or variable collapse pressures.
- the frangible material 36 may comprise glass, ceramic, polymer, metal or combinations thereof. The composition of the frangible material 36 may be selected to have a particular collapse strength which will determine the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
- the wall thickness of the frangible material 36 and the density of the pressure actuated collapsing capsules 34 may also be varied to increase or decrease the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
- the frangible material 36 may be coated with a strengthening material 40 to increase the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
- the strengthening material 40 may comprise glass, ceramic, polymer, metal or combinations thereof.
- the wall thickness of the strengthening material 40 may also be varied to increase or decrease the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
- the pressured operating fluid 30 can be optimized to mitigate a large range of over-pressure conditions within a subterranean containment space in a subterranean well.
- it is desirable to establish an upper pressure limit within a subterranean containment space by filling at least a portion of the subterranean containment space with pressured operating fluid 30 having a composition of pressure actuated collapsing capsules 34 that have uniform collapse pressures. All or a majority of the pressure actuated collapsing capsules 34 may be designed to rupture, collapse or implode as pressure in a subterranean containment space approaches the upper-pressure limit.
- pressure actuated collapsing capsules 34 that have non-uniform or graduated collapse pressures to accommodate varying over-pressure conditions.
- a percentage of pressure actuated collapsing capsules 34 may be designed to rupture collapse or implode at two or more operating pressures within a subterranean containment space.
- the pressure actuated collapsing capsules 34 may have a collapse pressure less than or equal to 1000 psi of one another.
- the pressure actuated collapsing capsules 34 may have a collapse pressure of greater than 1000 psi of one another.
- the pressure actuated collapsing capsules may be glass, ceramic, polymer or metal encased microspheres 34 , such as those manufactured by 3M Company.
- the microspheres 34 may be designed to rupture, implode or collapse when pressure exceeds a predetermined limit.
- the microspheres 34 may be designed to have a substantially uniform collapse pressure, such that the majority of microspheres 34 fail or collapse at the same pressure.
- the pressured operating fluid 30 may be tailored to provide overpressure protection above a predetermined pressure limit with the use of a minimum quantity, weight or concentration of microspheres 34 .
- Exemplary collapse pressures of glass, ceramic, polymer and/or metal encased microspheres 34 include, but are not limited to, 250 psi, 1000 psi, 2000 psi, 3000 psi, 4000 psi, 6000 psi, 10,000 psi and greater than 10,000 psi.
- the pressure actuated collapsing closed capsules are pozzolan or glass encased microspheres 34 provided from the waste stream of a coal-fired power plant.
- Hollow pozzolan or glass encased microspheres 34 known as floaters or cenospheres are formed in the coal burning process of coal-fired power plants.
- Cenospheres collect on the surface of disposal ponds where waste fly ash is deposited as part of the waste stream of a coal-fired power plant.
- Cenospheres are essentially thin-walled pozzolan or glass encased microspheres with a similar composition of fly ash.
- Pozzolan or glass encased microspheres 34 produced from cenospheres are cheaper than manufactured microspheres 34 .
- Pozzolan or glass encased microspheres 34 produced from cenospheres also have non-uniform or variable collapse pressures.
- a pressured operating fluid 30 having pozzolan or glass encased microspheres 34 that have non-uniform or graduated collapse pressures it is desirable to introduce a pressured operating fluid 30 into a plurality of subterranean containment spaces in a plurality of subterranean zones having dissimilar temperatures and pressures at varying depths within the subterranean well.
- the plurality of subterranean containment spaces may be at least partially filled with a pressured operating fluid 30 having a composition of pozzolan or glass encased microspheres 34 that have non-uniform or graduated collapse pressures to accommodate thermal expansion of downhole fluids at varying temperatures and pressures within each subterranean zone.
- pozzolan or glass encased microspheres 34 produced from cenospheres rupture, implode or collapse between 8000 psi and 10,000 psi.
- pozzolan or glass encased microspheres 34 produced from cenospheres rupture, implode or collapse between 10,000 psi and 12,000 psi.
- Tables I through III provide example embodiments of pressured operating fluids having glass encased microspheres suspended in water. The addition of a negligible volume of polymer to aid in suspension of microspheres was assumed. A constant volume subterranean containment space was assumed. The well temperature was increased to cause thermal expansion of the pressured operating fluid.
- Table I provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C.
- the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
- Operating Fluid 1 contains 1 kg of water and 0.2 kg of 3000 psi collapse rated glass encased microspheres.
- Operating Fluid 2 contains 1 kg of water and 0.3 kg of 3000 psi collapse rated glass encased microspheres.
- Operating Fluid 3 contains 1 kg of water and 0.4 kg of 3000 psi collapse rated glass encased microspheres.
- Table II provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C.
- the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
- Operating Fluid 1 contains 1 kg of water and 0.2 kg of 6000 psi collapse rated glass encased microspheres.
- Operating Fluid 2 contains 1 kg of water and 0.3 kg of 6000 psi collapse rated glass encased microspheres.
- Operating Fluid 3 contains 1 kg of water and 0.4 kg of 6000 psi collapse rated glass encased microspheres.
- Table III provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C.
- the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
- Operating Fluid 1 contains 1 kg, of water and 0.2 kg of 10,000 psi collapse rated glass encased microspheres.
- Operating Fluid 2 contains 1 kg of water and 0.3 kg of 10,000 psi collapse rated glass encased microspheres.
- Operating Fluid 3 contains 1 kg of water and 0.4 kg of 10,000 psi collapse rated glass encased microspheres.
- FIG. 3 illustrates an exemplary system for protecting a containment space 218 in an annulus 210 of a subterranean well 200 from over-pressure according to one embodiment.
- a plurality of casing strings including an inner casing string 204 and an outer casing string 206 are disposed in the wellbore 202 .
- the inner annulus 208 between the inner casing string 204 and the wellbore wall 212 is filled with cement 214 below the mud line 216 .
- the outer annulus 210 between the outer casing string 206 and the wellbore wall 212 is filled with cement 214 below the mud line 216 .
- subterranean pressured fluid receiving containment spaces 218 form in the inner annulus 208 and the outer annulus 210 between the cement 214 and the mud line 216 . Downhole fluids may become trapped in subterranean containment spaces 218 during drilling, completion, production, injection or other well operations.
- a pressured operating fluid 220 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into the subterranean containment spaces 218 to prevent casing collapse.
- the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space 218 exceeds a predetermined limit, thus releasing pressure in the containment space 218 .
- the pressured operating fluid 220 may be circulated into subterranean containment spaces 218 to prevent casing collapse before, during and/or after cement is circulated into the inner annulus 208 or outer annulus 210 of the wellbore 202 .
- the pressured operating fluid 220 may also be circulated into subterranean containment spaces 218 as part of the cement 214 .
- FIGS. 4A through 4F illustrate an exemplary system for protecting a subterranean containment space 320 in the annulus 306 of a subterranean well 300 from over-pressure according to another embodiment.
- a two stage cement process is used to secure well casing 308 to the wellbore wall 304 .
- Cement 318 is pumped or circulated into the first stage 324 through the inner diameter of the well casing 308 and back up the annulus 306 near or above a stage tool 310 .
- Pressure may be applied to the wellbore 302 through the inner diameter of the well casing 308 to open the stage tool 310 .
- An opening dart 312 may also be dropped into the well casing 308 on top of the stage tool 310 before pressure is applied to the wellbore 302 to open the stage tool 310 . Once the stage tool 310 is opened, the annulus 306 above the tool 310 is circulated clean back to the surface.
- a first stage plug 314 is launched into the well casing 308 to plug off the first stage 324 .
- Cement 318 is circulated into the second stage 322 through the inner diameter of the well casing 308 and up the annulus 306 of the wellbore 302 .
- a displacement plug 316 may be launched into the well casing 308 to further facilitate displacement and circulation of cement 318 into the annulus 306 .
- spaces, gaps or voids do not form in the annulus 306 in the first stage 324 or the second stage 322 during circulation of cement 318 .
- subterranean containment spaces 320 including gaps, voids and cavities are often created due to lack of volume or lost circulation of cement 318 in the first stage 324 or second stage 322 .
- Downhole fluids may become trapped in subterranean containment spaces 320 in first stage 324 , the second stage 322 or between the first stage 324 and the second stage 322 of the annulus 306 .
- a pressured operating fluid 326 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into the subterranean containment spaces 320 in the first stage 324 , the second stage or between the first stage 324 and the second stage 322 of the annulus 306 .
- the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space 320 exceeds a predetermined limit, thus accommodating thermal expansion of fluid in the subterranean containment space 320 .
- the pressured operating fluid 326 may be circulated into subterranean containment spaces 320 to prevent casing collapse before, during and/or after cement 318 is circulated into the first stage 324 or second stage 322 of the annulus 306 .
- the pressured operating fluid 326 may also be circulated into subterranean containment spaces 320 as part of the cement 318 .
- FIGS. 5A through 5E illustrate an subterranean containment system for protecting a downhole packer 406 from over-pressure according to one embodiment.
- a downhole packer 408 including an expandable bladder 412 and packer body 410 is positioned within a wellbore 400 .
- the expandable bladder 412 is attached to the packer body 410 which includes port sleeves 416 , sleeve receiving apertures 418 and inflation ports 420 in fluid communication with the expandable bladder 412 attached thereto.
- the expandable bladder 412 is positioned in the wellbore annulus 404 between a tubular 406 and the wellbore wall 402 .
- the tubular 406 may be well casing, casing liner, drill pipe, production conduit or other downhole tubular known in the art.
- a dart seat 414 may be positioned inside the tubular 406 and/or attached to the packer body 410 .
- a seating dart 422 is launched into the tubular 406 to plug the dart seat 414 .
- Pressure is applied to the well packer 408 by pumping or circulating pressured operating fluid 424 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules through the tubular 406 .
- the pressure drives the port sleeves 416 into the sleeve receiving apertures 418 , causes the inflation ports 420 to align and permits the pressured operating fluid 424 to fill the expandable bladder 412 .
- the inflated bladder 412 forms a seal in the annulus 404 between the tubular 406 and the wellbore wall 402 .
- any additional pressure applied to the packer 408 through the tubular 406 will cause the port sleeves 416 to withdraw from the sleeve receiving apertures 418 and close the inflation ports 420 .
- the seating dart 422 may also be pushed through the dart seat 414 by applying pressure to the tubular 406 .
- the inflated downhole packer 408 provides hydraulic isolation in the annulus 404 to allow for pumping or circulation of fluids below the packer 408 .
- Temperature in the well may increase during production of hotter fluids, such as oil, gas, geothermal water, brine and/or steam.
- the temperature of the well and fluids therein may also increase in a geothermal well approaching the geostatic temperature.
- the expandable bladder 412 of the downhole packer 408 can be at least partially filled with the pressured operating fluid 424 to protect the expandable bladder 412 from over-pressure.
- Pressure actuated collapsing capsules suspended in the pressured operating fluid 424 rupture, implode or collapse when the pressure in the expandable bladder 412 exceeds a predetermined limit, thus accommodating for thermal expansion of fluids in the expandable bladder 412 .
- the wellbore 400 and packer 408 may be cooled with cooling fluid 426 to cause contraction of the pressured operating fluid 424 in the expandable bladder 412 .
- the volume of the pressured operating fluid 424 within the expandable bladder 412 may be reduced substantially (e.g. 10-20 percent reduction in volume) by cooling the pressured operating fluid 424 after a portion of the pressure actuated collapsing capsules have ruptured, imploded or collapsed. This allows easy removal of the packer 408 from the wellbore 400 without the need to drill out the packer 408 or remove the pressured operating fluid 424 from the expandable bladder 412 .
- FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well 500 from over-pressure according to one embodiment.
- a geothermal well 500 is created by drilling a wellbore 502 into a geothermal formation 504 capable of producing heat from fractures 506 within the formation 504 .
- the wellbore wall 524 is lined with casing 510 and a production conduit 512 is positioned within the wellbore 504 interior of the casing 510 .
- An annulus 508 may exist between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512 .
- a downhole packer 514 including an expandable bladder 516 may be positioned in the well 500 to provide hydraulic or zonal isolation within the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512 .
- Annular cavities 518 may form in the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512 during drilling, completion, production and/or other well operations. Downhole fluids may become trapped within subterranean containment spaces including, but not limited to, an annular cavity 518 , an expandable packer bladder 516 , or a naturally occurring fracture 506 in the formation 504 .
- Geothermal wells completed in deep granite basement rock can have well temperatures greater than 300° C. The thermal expansion of water or other substantially incompressible fluids used in well operations could cause severe damage to the geothermal well and formation at temperatures as low as 100° C.
- the pressured operating fluids having a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 32 herein disclosed are capable of accommodating thermal expansion and resulting over-pressure in subterranean containment spaces.
- a pressured operating fluid 522 comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into annular cavities 518 , the expandable packer bladder 516 , or naturally occurring fractures 506 in the formation 504 .
- the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space exceeds a predetermined limit, thus accommodating thermal expansion of liquid in the subterranean containment space.
- Example embodiments have been described hereinabove regarding improved systems and methods for use of microspheres suspended in a thermally expanding fluid. Various modifications to and departures from the disclosed example embodiments will occur to those having ordinary skill in the art. The subject matter that is intended to be within the spirit of this disclosure is set forth in the following claims.
Abstract
Systems and methods for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space are herein disclosed. According to one embodiment, a system comprises a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well and a pressured operating fluid filling at least a portion of the containment space. The pressured operating fluid comprises a mixture of substantially incompressible liquid and pressure actuated collapsing capsules. At least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
Description
- This application claims priority from U.S. provisional application No. 61/049,288, entitled “SYSTEM AND METHOD FOR USE OF MICROSPHERES SUSPENDED IN A THERMALLY EXPANDING FLUID IN AN EXPANDABLE WELL PACKER,” filed on Apr. 30, 2008 and U.S. provisional application No. 61/049,294, entitled, “SYSTEM AND METHOD FOR USE OF MICROSPHERES SUSPENDED IN A FLUID TO MITIGATE ANNULAR PRESSURE BUILD-UP IN A WELL-STRING,” filed on Apr. 30, 2008, which are both incorporated by reference in their entirety, for all purposes, herein.
- The present application is directed to systems and methods for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid.
- Traditionally, geothermal wells are completed in porous geothermal formations having naturally high permeability and which contain heated brine and/or steam in relative close proximity to the surface of the earth. These hydrothermal formations are found in a number of locations around the world. However, the vast majority of geothermal resources exist in hot dry rock (HDR) formations that contain little to no geothermal fluid. Enhanced geothermal systems (EGS) are used to extract thermal energy from deep HDR formations exhibiting low permeability. Most HDR formations grow hotter with increasing depth, and in a related aspect, it is advantageous to isolate zones deep in the formation that generate the most heat. EGS wells completed in deep granite basement rock having in situ temperatures ranging from 150° C. to greater than 350° C. are capable of producing large quantities of thermal energy.
- Drilling and completion of oil and gas wells and geothermal wells involves forming a subterranean wellbore by rotating an earth boring bit into an earth formation as weight is applied to the bit. The drilled wellbore is normally lined with a string of tubulars known as casing and the well is completed by pumping cement into the annulus between the casing and the wellbore wall. In oil and gas wells, the casing string is often cemented at the bottom. During cementing and completion of oil, gas and geothermal wells, fluid is often trapped in the annulus between the casing string and the wellbore wall or between two casing strings. Trapped annular fluid thermally expands when the wellbore is heated during drilling, production and other well operations. The thermal expansion of trapped annular fluid can cause annular pressure build-up (APB) and result in collapse of the casing string.
- Expandable or inflatable packers have also been used in the oil and gas and geothermal industries for well related operations such as zone isolation and formation treating. Expandable packers are used to block the flow of fluids through the annular spaces within the wellbore. Expandable packers are typically filled with a material such as cement, water, or drilling fluid to inflate an expandable packer element. The cement eventually hydrates to form a hard, solid material. In order to remove the packer, the cement and expandable packer must be drilled out. For some applications, it is desirable to both inflate and subsequently deflate a packer once a given operation within a well is completed. A filler material consisting of a liquid such as water, drilling fluid, oil, and other downhole fluids may be used for such an operation. However, when the packer is exposed to an increase in temperature the thermal expansion of the liquid water or other downhole fluids within the packer may cause a pressure increase within the packer. This pressure increase, if sufficiently large, could lead to either the rupture of the inflatable element of the packer and/or the crushing of elements inside the packer.
- Conventional systems and methods for completing oil, gas and geothermal wells including casing strings and well packers are typically not capable of accommodating significant thermal expansion of downhole fluids.
- Systems and methods for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space are herein disclosed. According to one embodiment, a system comprises a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well and a pressured operating fluid filling at least a portion of the containment space. The pressured operating fluid comprises a mixture of substantially incompressible liquid and pressure actuated collapsing capsules. At least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
- The foregoing and other objects, features and advantages of the present disclosure will become more readily apparent from the following detailed description of exemplary embodiments as disclosed herein.
- Embodiments of the present application are described, by way of example only, with reference to the attached Figures, wherein:
-
FIG. 1 illustrates an exemplary system for protecting a subterranean containment space in a subterranean well or formation from over-pressure according to one embodiment; -
FIG. 2A illustrates an exemplary pressured operating fluid according to one embodiment; -
FIG. 2B illustrates exemplary pressure actuated collapsing capsules according to one embodiment; -
FIG. 3 illustrates an exemplary system for protecting a subterranean containment space in an annulus of a subterranean well from over-pressure according to one embodiment; -
FIGS. 4A through 4F illustrate an exemplary system for protecting a subterranean containment space in the annulus of a subterranean well from over-pressure according to another embodiment; -
FIGS. 5A through 5E illustrate an exemplary system for protecting a downhole packer from over-pressure according to one embodiment; and -
FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well from over-pressure according to one embodiment. - It will be appreciated that for simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the example embodiments described herein. However, it will be understood by those of ordinary skill in the art that the example embodiments described herein may be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the embodiments described herein. It will be understood by those of ordinary skill in the art that the systems and methods herein disclosed may be applied to subterranean wells including, but not limited to, geothermal wells, oil wells, gas wells, water wells, injection wells or any other well known in the art for producing or injecting fluids.
-
FIG. 1 illustrates an exemplary system for protecting asubterranean containment space 106 in asubterranean well 102 orformation 100 from over-pressure according to one embodiment. Thesubterranean well 102 may be a geothermal well, oil well, gas well, water well, injection well or any other well known in the art. During drilling, completion and production, subterranean pressured fluid receivingcontainment spaces 106 may form in thewellbore 104 or in thesubterranean formation 100. For instance, asubterranean containment space 106, such as a downhole packer may be introduced into thesubterranean well 102 in an annulus between theproduction conduit 110 and thecasing string 112 or in anannulus 114 between thecasing string 112 and thewellbore wall 116. In other instances, asubterranean containment space 106 may form in theannulus 114 during a primary well operation such as, cementing of thecasing string 112. -
Subterranean containment spaces 106 may also be naturally occurring voids or cavities in thesubterranean formation 100. Downhole fluids may become trapped insubterranean containment spaces 106 during drilling, completion, production and other well operations. If thesubterranean well 102 including thewellbore wall 116 and/or fluids within thewellbore 104 are heated during well operations, trapped fluids will thermally expand and pressurize thesubterranean containment spaces 106. Thermally expanding downhole fluids can damage the subterranean well 102 and/or elements within thewell 102 including, but not limited to, well casing, well liners, well packers, production conduit, downhole tools and other downhole tubulars within thewellbore 104. Thermally expanding downhole fluids can also cause damage to thesubterranean formation 100 by propagating undesired fractures within theformation 100. - In order to accommodate thermal expansion of downhole fluids and protect the
subterranean well 102 and downhole elements within thewell 102 from over-pressure,subterranean containment spaces 106 are at least partially filled with pressuredoperating fluid 108 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules. The pressure actuated collapsing capsules rupture, implode or collapse when pressure in thesubterranean containment space 106 exceeds a predetermined limit, thus compensating for the thermal expansion of the liquid in thecontainment space 106 and preventing over-pressure from damaging thesubterranean well 102. - The pressured
operating fluid 108 may also be pumped or circulated into a plurality of laterally or vertically arrangedsubterranean zones formation 100 to protect the formation from undesired fracture propagation.Containment spaces 106 in the well 100 and theformation 100 may be partially or fully filled with pressured operatingfluid 108 by pumping or circulating the pressuredoperating fluid 108 intowellbore 104 through theproduction conduit 110, thecasing string 112, or theannulus 114 between thecasing string 112 and thewellbore wall 116. -
FIG. 2A illustrates an exemplary pressured operatingfluid 30 comprising a mixture of substantiallyincompressible liquid 32 and pressure actuated collapsingcapsules 32 according to one embodiment. The pressure actuated collapsingcapsules 34 are suspended in the substantiallyincompressible liquid 32. A viscosifying agent may be added to the pressured operatingfluid 30 to aid in the suspension of the pressure actuated collapsingcapsules 34. The viscosifying agent may be an organic polymer such as hydro ethyl cellulose, hydropropyl guar, guar gum, and/or any other compatible organic polymer capable of aiding in the suspension of the pressure actuated collapsingcapsules 34. The viscosifying agent may also be an inorganic material such as fumed silica, bentonite, or attapulgite. Weighting materials such as barite or hausmanite may also be added to the pressured operatingfluid 30 to modify the density of the fluid. The pressuredoperating fluid 30 comprising a mixture of substantiallyincompressible liquid 32 and pressure actuated collapsingcapsules 34 is designed to accommodate thermal expansion of liquid in a subterranean containment space, including but not limited to, an expandable bladder of a well packer, an annulus between the casing string and the wellbore wall, an annulus between the production conduit and the casing string, an annulus between two casing strings, a fracture in the subterranean formation or any other downhole tubular, downhole tool, or void in a subterranean well or formation capable of containing liquid. - The substantially
incompressible liquid 32 component of the pressured operatingfluid 30 may be selected based on the specific application of the pressured operatingfluid 30 and/or the downhole fluids present in the well such as, drilling fluids and production fluids. For most applications, the substantiallyincompressible liquid 32 may comprise water. The substantiallyincompressible liquid 32 may also comprise one or more components that make up a drilling fluid present in the well to maintain compatibility between the pressured operatingfluid 30 and the drilling fluid. For instance, if the well contains a synthetic oil-based drilling fluid, the substantiallyincompressible liquid 32 may comprise the drilling fluid or a competent thereof such as the base oil. The substantiallyincompressible liquid 32 may also comprise mineral oil and/or synthetic oil. In geothermal and other applications, the substantiallyincompressible liquid 32 may comprise various concentrations of potassium chloride brine, sodium chloride brine, production brine and/or other substantially incompressible liquid that is compatible with downhole fluids present in the subterranean well. - Referring to
FIGS. 2A through 2B , pressure actuated collapsingcapsules 34 are designed to rupture, implode or collapse at a predetermined pressure during thermal expansion of the substantiallyincompressible liquid 32. The pressure actuated collapsingcapsules 34 may be of substantially fixed volume or they may have variable volumes within the substantiallyincompressible liquid 32. The pressure actuated collapsingcapsules 34 may also be partially or fully filled withgas 38. Thegas 38 may be air or an inert gas such as, nitrogen or argon to prevent chemical reaction with downhole fluids after collapse of the pressure actuated collapsingcapsules 34. Thegas 38 may also be one or more gases present in the subterranean well such as nitrogen, methane or other hydrocarbon gases. In other embodiments, the pressure actuated collapsingcapsules 34 may be substantially void of gas. - The pressure actuated collapsing
capsules 34 may be manufactured to have a predetermined collapse pressure. The pressure actuated collapsingcapsules 34 may also be a waste byproduct which have non-uniform or graduated collapse pressures. In accordance with the example embodiment shown inFIG. 2B , the pressure actuated collapsingcapsules 34 may be hollow and encased in afrangible material 36. The pressure actuated collapsingcapsules 34 may be spherical, cratered or ellipsoidal. Hollow microspheres, because of their spherical form, can have a high isotropic compressive strength and are therefore well suited for applications that require high collapse pressures. - The pressure actuated collapsing
capsules 34 may be designed to have a substantially uniform collapse pressure, such that the majority of pressure actuated collapsingcapsules 34 fail or collapse at the same pressure. The pressure actuated collapsingcapsules 34 may also be designed to have non-uniform or variable collapse pressures. Thefrangible material 36 may comprise glass, ceramic, polymer, metal or combinations thereof. The composition of thefrangible material 36 may be selected to have a particular collapse strength which will determine the pressure at which the pressure actuated collapsingcapsules 34 rupture, implode or collapse. The wall thickness of thefrangible material 36 and the density of the pressure actuated collapsingcapsules 34 may also be varied to increase or decrease the pressure at which the pressure actuated collapsingcapsules 34 rupture, implode or collapse. Thefrangible material 36 may be coated with a strengtheningmaterial 40 to increase the pressure at which the pressure actuated collapsingcapsules 34 rupture, implode or collapse. The strengtheningmaterial 40 may comprise glass, ceramic, polymer, metal or combinations thereof. The wall thickness of the strengtheningmaterial 40 may also be varied to increase or decrease the pressure at which the pressure actuated collapsingcapsules 34 rupture, implode or collapse. - The pressured
operating fluid 30 can be optimized to mitigate a large range of over-pressure conditions within a subterranean containment space in a subterranean well. During well operations that substantially and rapidly heat the subterranean well, it is desirable to establish an upper pressure limit within a subterranean containment space by filling at least a portion of the subterranean containment space with pressured operatingfluid 30 having a composition of pressure actuated collapsingcapsules 34 that have uniform collapse pressures. All or a majority of the pressure actuated collapsingcapsules 34 may be designed to rupture, collapse or implode as pressure in a subterranean containment space approaches the upper-pressure limit. - During well operations that gradually heat the subterranean well over a large range of temperatures, it is desirable to use pressure actuated collapsing
capsules 34 that have non-uniform or graduated collapse pressures to accommodate varying over-pressure conditions. A percentage of pressure actuated collapsingcapsules 34 may be designed to rupture collapse or implode at two or more operating pressures within a subterranean containment space. In one embodiment, the pressure actuated collapsingcapsules 34 may have a collapse pressure less than or equal to 1000 psi of one another. In another embodiment, the pressure actuated collapsingcapsules 34 may have a collapse pressure of greater than 1000 psi of one another. - In one example embodiment, the pressure actuated collapsing capsules may be glass, ceramic, polymer or metal encased
microspheres 34, such as those manufactured by 3M Company. Themicrospheres 34 may be designed to rupture, implode or collapse when pressure exceeds a predetermined limit. Themicrospheres 34 may be designed to have a substantially uniform collapse pressure, such that the majority ofmicrospheres 34 fail or collapse at the same pressure. By designing themicrospheres 34 to collapse at a uniform pressure, the pressured operatingfluid 30 may be tailored to provide overpressure protection above a predetermined pressure limit with the use of a minimum quantity, weight or concentration ofmicrospheres 34. Exemplary collapse pressures of glass, ceramic, polymer and/or metal encasedmicrospheres 34 include, but are not limited to, 250 psi, 1000 psi, 2000 psi, 3000 psi, 4000 psi, 6000 psi, 10,000 psi and greater than 10,000 psi. - In another example embodiment, the pressure actuated collapsing closed capsules are pozzolan or glass encased
microspheres 34 provided from the waste stream of a coal-fired power plant. Hollow pozzolan or glass encasedmicrospheres 34 known as floaters or cenospheres are formed in the coal burning process of coal-fired power plants. Cenospheres collect on the surface of disposal ponds where waste fly ash is deposited as part of the waste stream of a coal-fired power plant. Cenospheres are essentially thin-walled pozzolan or glass encased microspheres with a similar composition of fly ash. Pozzolan or glass encasedmicrospheres 34 produced from cenospheres are cheaper than manufacturedmicrospheres 34. Pozzolan or glass encasedmicrospheres 34 produced from cenospheres also have non-uniform or variable collapse pressures. - To accommodate a wide range of pressures in a particular subterranean containment space, it is desirable to introduce a pressured operating
fluid 30 having pozzolan or glass encasedmicrospheres 34 that have non-uniform or graduated collapse pressures. For instance, it may be desirable to introduce a pressured operatingfluid 30 into a plurality of subterranean containment spaces in a plurality of subterranean zones having dissimilar temperatures and pressures at varying depths within the subterranean well. The plurality of subterranean containment spaces may be at least partially filled with a pressured operatingfluid 30 having a composition of pozzolan or glass encasedmicrospheres 34 that have non-uniform or graduated collapse pressures to accommodate thermal expansion of downhole fluids at varying temperatures and pressures within each subterranean zone. In one example embodiment, pozzolan or glass encasedmicrospheres 34 produced from cenospheres rupture, implode or collapse between 8000 psi and 10,000 psi. In another example embodiment, pozzolan or glass encasedmicrospheres 34 produced from cenospheres rupture, implode or collapse between 10,000 psi and 12,000 psi. - Tables I through III provide example embodiments of pressured operating fluids having glass encased microspheres suspended in water. The addition of a negligible volume of polymer to aid in suspension of microspheres was assumed. A constant volume subterranean containment space was assumed. The well temperature was increased to cause thermal expansion of the pressured operating fluid.
-
TABLE I 3000 psi Collapse Rated Spheres Heated From 80° F. (26° C.) Percent Pressured Glass Final Final Spheres Operating Water Spheres Temperature Temperature Collapsed Fluid (kg) (kg) (° F.) (° C.) (%) 1 1 0.2 260 126.7 14 1 1 0.2 360 182.2 28 1 1 0.2 460 237.8 48 1 1 0.2 560 293.3 76 2 1 0.3 260 126.7 9 2 1 0.3 360 182.2 19 2 1 0.3 460 237.8 32 2 1 0.3 560 293.3 51 3 1 0.4 260 126.7 7 3 1 0.4 360 182.2 14 3 1 0.4 460 237.8 24 3 1 0.4 560 293.3 38 - Table I provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C. The percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid. Operating Fluid 1 contains 1 kg of water and 0.2 kg of 3000 psi collapse rated glass encased microspheres.
Operating Fluid 2 contains 1 kg of water and 0.3 kg of 3000 psi collapse rated glass encased microspheres. Operating Fluid 3 contains 1 kg of water and 0.4 kg of 3000 psi collapse rated glass encased microspheres. An initial temperature of 26° C. was assumed. The percentage of microsphere collapse necessary to accommodate the thermal expansion of the pressured operating fluid increases as temperature increases. At temperatures approaching and above 250° C. the percentage of microsphere collapse necessary to accommodate the thermal expansion of the pressured operating fluid substantially increases. -
TABLE II 6000 psi Collapse Rated Spheres Heated From 80° F. (26° C.) Percent Pressured Glass Final Final Spheres Operating Water Spheres Temperature Temperature Collapsed Fluid (kg) (kg) (° F.) (° C.) (%) 1 1 0.2 260 126.7 18 1 1 0.2 360 182.2 36 1 1 0.2 460 237.8 62 1 1 0.2 560 293.3 99 2 1 0.3 260 126.7 12 2 1 0.3 360 182.2 24 2 1 0.3 460 237.8 42 2 1 0.3 560 293.3 66 3 1 0.4 260 126.7 9 3 1 0.4 360 182.2 18 3 1 0.4 460 237.8 31 3 1 0.4 560 293.3 49 - Table II provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C. The percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid. Operating Fluid 1 contains 1 kg of water and 0.2 kg of 6000 psi collapse rated glass encased microspheres.
Operating Fluid 2 contains 1 kg of water and 0.3 kg of 6000 psi collapse rated glass encased microspheres. Operating Fluid 3 contains 1 kg of water and 0.4 kg of 6000 psi collapse rated glass encased microspheres. An initial temperature of 26° C. was assumed. At temperatures approaching and above 250° C. the percentage of microsphere collapse necessary to accommodate the thermal expansion of the pressured operating fluid substantially increases. The theoretical percentage of microsphere collapse in Operating Fluid 1 is 99% at 293.3° C. Therefore, a greater composition of microspheres must be suspended in Operating Fluid 1 to accommodate the potential thermal expansion and resulting over-pressure created at temperatures above 293.3° C. -
TABLE III 10,000 psi Collapse Rated Spheres Heated From 80° F. (26° C.) Percent Pressured Glass Final Final Spheres Operating Water Spheres Temperature Temperature Collapsed Fluid (kg) (kg) (° F.) (° C.) (%) 1 1 0.2 260 126.7 25 1 1 0.2 360 182.2 50 1 1 0.2 460 237.8 87 1 1 0.2 560 293.3 138 2 1 0.3 260 126.7 17 2 1 0.3 360 182.2 33 2 1 0.3 460 237.8 58 2 1 0.3 560 293.3 92 3 1 0.4 260 126.7 12 3 1 0.4 360 182.2 25 3 1 0.4 460 237.8 43 3 1 0.4 560 293.3 69 - Table III provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7° C., 182.2° C., 237.8° C. and 293.3° C. The percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid. Operating Fluid 1 contains 1 kg, of water and 0.2 kg of 10,000 psi collapse rated glass encased microspheres.
Operating Fluid 2 contains 1 kg of water and 0.3 kg of 10,000 psi collapse rated glass encased microspheres. Operating Fluid 3 contains 1 kg of water and 0.4 kg of 10,000 psi collapse rated glass encased microspheres. An initial temperature of 26° C. was assumed. At temperatures approaching and above 250° C. the percentage of microsphere collapse necessary to accommodate the thermal expansion of the pressured operating fluid substantially increases. The theoretical percentage of microsphere collapse in Operating Fluid 1 is over 100% at 293.3° C. Therefore, Operating Fluid 1 is not designed to compensate for the potential thermal expansion and resulting over-pressure created at 293.3° C. The theoretical percentage of microsphere collapse inOperating Fluid 2 is over 92% at 293.3° C. Therefore, a greater composition of microspheres must be suspended inOperating Fluid 2 to accommodate the potential thermal expansion and resulting over-pressure created at temperatures above 293.3° C. -
FIG. 3 illustrates an exemplary system for protecting acontainment space 218 in anannulus 210 of a subterranean well 200 from over-pressure according to one embodiment. A plurality of casing strings including aninner casing string 204 and anouter casing string 206 are disposed in thewellbore 202. To secure theinner casing string 204 against thewellbore wall 212, theinner annulus 208 between theinner casing string 204 and thewellbore wall 212 is filled withcement 214 below themud line 216. To secure theouter casing string 206 against thewellbore wall 212, theouter annulus 210 between theouter casing string 206 and thewellbore wall 212 is filled withcement 214 below themud line 216. Due to insufficient volume and circulation ofcement 214, subterranean pressured fluid receivingcontainment spaces 218 form in theinner annulus 208 and theouter annulus 210 between thecement 214 and themud line 216. Downhole fluids may become trapped insubterranean containment spaces 218 during drilling, completion, production, injection or other well operations. - If trapped downhole fluids are heated while in the
subterranean containment spaces 218, the thermal expansion of the fluid can cause theinner casing string 204 to burst or theouter casing string 206 to collapse. A pressuredoperating fluid 220 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into thesubterranean containment spaces 218 to prevent casing collapse. The pressure actuated collapsing capsules rupture, implode or collapse when the pressure in thesubterranean containment space 218 exceeds a predetermined limit, thus releasing pressure in thecontainment space 218. The pressuredoperating fluid 220 may be circulated intosubterranean containment spaces 218 to prevent casing collapse before, during and/or after cement is circulated into theinner annulus 208 orouter annulus 210 of thewellbore 202. The pressuredoperating fluid 220 may also be circulated intosubterranean containment spaces 218 as part of thecement 214. -
FIGS. 4A through 4F illustrate an exemplary system for protecting asubterranean containment space 320 in theannulus 306 of a subterranean well 300 from over-pressure according to another embodiment. A two stage cement process is used to secure well casing 308 to thewellbore wall 304.Cement 318 is pumped or circulated into thefirst stage 324 through the inner diameter of thewell casing 308 and back up theannulus 306 near or above astage tool 310. Pressure may be applied to thewellbore 302 through the inner diameter of thewell casing 308 to open thestage tool 310. Anopening dart 312 may also be dropped into the well casing 308 on top of thestage tool 310 before pressure is applied to thewellbore 302 to open thestage tool 310. Once thestage tool 310 is opened, theannulus 306 above thetool 310 is circulated clean back to the surface. - After permitting the
cement 318 in the first stage to set, afirst stage plug 314 is launched into thewell casing 308 to plug off thefirst stage 324.Cement 318 is circulated into thesecond stage 322 through the inner diameter of thewell casing 308 and up theannulus 306 of thewellbore 302. Adisplacement plug 316 may be launched into thewell casing 308 to further facilitate displacement and circulation ofcement 318 into theannulus 306. Ideally, spaces, gaps or voids do not form in theannulus 306 in thefirst stage 324 or thesecond stage 322 during circulation ofcement 318. However,subterranean containment spaces 320 including gaps, voids and cavities are often created due to lack of volume or lost circulation ofcement 318 in thefirst stage 324 orsecond stage 322. Downhole fluids may become trapped insubterranean containment spaces 320 infirst stage 324, thesecond stage 322 or between thefirst stage 324 and thesecond stage 322 of theannulus 306. - If temperature in the well 300 increases substantially during production of hotter fluids, such as oil, gas, geothermal water, brine and/or steam, thermal expansion of trapped fluid can cause the
casing 308 to collapse. A pressuredoperating fluid 326 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into thesubterranean containment spaces 320 in thefirst stage 324, the second stage or between thefirst stage 324 and thesecond stage 322 of theannulus 306. The pressure actuated collapsing capsules rupture, implode or collapse when the pressure in thesubterranean containment space 320 exceeds a predetermined limit, thus accommodating thermal expansion of fluid in thesubterranean containment space 320. The pressuredoperating fluid 326 may be circulated intosubterranean containment spaces 320 to prevent casing collapse before, during and/or aftercement 318 is circulated into thefirst stage 324 orsecond stage 322 of theannulus 306. The pressuredoperating fluid 326 may also be circulated intosubterranean containment spaces 320 as part of thecement 318. -
FIGS. 5A through 5E illustrate an subterranean containment system for protecting adownhole packer 406 from over-pressure according to one embodiment. Adownhole packer 408 including anexpandable bladder 412 andpacker body 410 is positioned within awellbore 400. Theexpandable bladder 412 is attached to thepacker body 410 which includesport sleeves 416,sleeve receiving apertures 418 andinflation ports 420 in fluid communication with theexpandable bladder 412 attached thereto. Theexpandable bladder 412 is positioned in thewellbore annulus 404 between a tubular 406 and thewellbore wall 402. The tubular 406 may be well casing, casing liner, drill pipe, production conduit or other downhole tubular known in the art. Adart seat 414 may be positioned inside the tubular 406 and/or attached to thepacker body 410. Aseating dart 422 is launched into the tubular 406 to plug thedart seat 414. - Pressure is applied to the
well packer 408 by pumping or circulating pressured operatingfluid 424 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules through the tubular 406. The pressure drives theport sleeves 416 into thesleeve receiving apertures 418, causes theinflation ports 420 to align and permits the pressuredoperating fluid 424 to fill theexpandable bladder 412. Theinflated bladder 412 forms a seal in theannulus 404 between the tubular 406 and thewellbore wall 402. After thedownhole packer 408 is filled, any additional pressure applied to thepacker 408 through the tubular 406 will cause theport sleeves 416 to withdraw from thesleeve receiving apertures 418 and close theinflation ports 420. - The
seating dart 422 may also be pushed through thedart seat 414 by applying pressure to the tubular 406. The inflateddownhole packer 408 provides hydraulic isolation in theannulus 404 to allow for pumping or circulation of fluids below thepacker 408. Temperature in the well may increase during production of hotter fluids, such as oil, gas, geothermal water, brine and/or steam. The temperature of the well and fluids therein may also increase in a geothermal well approaching the geostatic temperature. Theexpandable bladder 412 of thedownhole packer 408 can be at least partially filled with the pressuredoperating fluid 424 to protect theexpandable bladder 412 from over-pressure. Pressure actuated collapsing capsules suspended in the pressuredoperating fluid 424 rupture, implode or collapse when the pressure in theexpandable bladder 412 exceeds a predetermined limit, thus accommodating for thermal expansion of fluids in theexpandable bladder 412. Thewellbore 400 andpacker 408 may be cooled with cooling fluid 426 to cause contraction of the pressuredoperating fluid 424 in theexpandable bladder 412. The volume of the pressuredoperating fluid 424 within theexpandable bladder 412 may be reduced substantially (e.g. 10-20 percent reduction in volume) by cooling the pressuredoperating fluid 424 after a portion of the pressure actuated collapsing capsules have ruptured, imploded or collapsed. This allows easy removal of thepacker 408 from thewellbore 400 without the need to drill out thepacker 408 or remove the pressured operating fluid 424 from theexpandable bladder 412. -
FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well 500 from over-pressure according to one embodiment. A geothermal well 500 is created by drilling a wellbore 502 into a geothermal formation 504 capable of producing heat from fractures 506 within the formation 504. The wellbore wall 524 is lined with casing 510 and a production conduit 512 is positioned within the wellbore 504 interior of the casing 510. An annulus 508 may exist between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512. A downhole packer 514 including an expandable bladder 516 may be positioned in the well 500 to provide hydraulic or zonal isolation within the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512. - Annular cavities 518 may form in the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512 during drilling, completion, production and/or other well operations. Downhole fluids may become trapped within subterranean containment spaces including, but not limited to, an annular cavity 518, an expandable packer bladder 516, or a naturally occurring fracture 506 in the formation 504. Geothermal wells completed in deep granite basement rock can have well temperatures greater than 300° C. The thermal expansion of water or other substantially incompressible fluids used in well operations could cause severe damage to the geothermal well and formation at temperatures as low as 100° C.
- It is undesirable to propagate fractures 506 beyond the efficient heat recovery rate of the geothermal well 500. The thermal expansion of incompressible fluids trapped in fractures 506 in the formation 504 can cause undesirable fracture propagation. The pressured operating fluids having a mixture of substantially
incompressible liquid 32 and pressure actuated collapsingcapsules 32 herein disclosed are capable of accommodating thermal expansion and resulting over-pressure in subterranean containment spaces. To protect the geothermal well 500 and formation 504 from over-pressure a pressured operating fluid 522 comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into annular cavities 518, the expandable packer bladder 516, or naturally occurring fractures 506 in the formation 504. The pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space exceeds a predetermined limit, thus accommodating thermal expansion of liquid in the subterranean containment space. - Example embodiments have been described hereinabove regarding improved systems and methods for use of microspheres suspended in a thermally expanding fluid. Various modifications to and departures from the disclosed example embodiments will occur to those having ordinary skill in the art. The subject matter that is intended to be within the spirit of this disclosure is set forth in the following claims.
Claims (28)
1. A system comprising:
a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well; and
a pressured operating fluid filling at least a portion of the containment space and comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules wherein at least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
2. The system as recited in claim 1 , wherein the pressured fluid receiving containment space is an expandable bladder of a downhole packer.
3. The system as recited in claim 1 , wherein the pressured fluid receiving containment space is an annulus space between a drilled wellbore and a casing string.
4. The system as recited in claim 1 , wherein the pressured fluid receiving containment space is an annulus space between a plurality of casing strings.
5. The system as recited in claim 1 , wherein the pressure actuated collapsing capsules are hollow and encased in a frangible material.
6. The system as recited in claim 5 , wherein the pressure actuated collapsing capsules are of substantially fixed volume and at least partially gas-filled.
7. The system as recited in claim 5 , wherein the frangible material is one of glass, ceramic, polymer, metal or pozzolan.
8. The system as recited in claim 7 , wherein the pressure actuated collapsing capsules are microspheres.
9. The system as recited in claim 8 , wherein the microspheres have a substantially uniform collapse pressure.
10. The system as recited in claim 9 , wherein the microspheres have a collapse pressure within 1000 psi of one another.
11. The system as recited in claim 8 , wherein the microspheres have a non-uniform collapse pressure.
12. The system as recited in claim 11 , wherein the microspheres have at least two different collapse pressures.
13. The system as recited in claim 11 , wherein the difference in collapse pressure of a plurality of the microspheres is at least 1000 psi.
14. A method comprising:
defining a subterranean pressured fluid receiving containment space in a wellbore of a subterranean well; and
filling at least a portion of the containment space with a pressured operating fluid comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules wherein at least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
15. The method as recited in claim 14 , wherein the pressured fluid receiving containment space is an expandable bladder of a downhole packer.
16. The method as recited in claim 14 , wherein the pressured fluid receiving containment space is an annulus space between a drilled wellbore and a casing string.
17. The method as recited in claim 14 , wherein the pressured fluid receiving containment space is an annulus space between a plurality of casing strings.
18. The method as recited in claim 14 , wherein the pressure actuated collapsing capsules are hollow and encased in a frangible material.
19. The method as recited in claim 18 , wherein the pressure actuated collapsing capsules are of substantially fixed volume and at least partially gas-filled.
20. The method as recited in claim 18 , wherein the frangible material is one of glass, ceramic, polymer, metal or pozzolan.
21. The method as recited in claim 20 , wherein the pressure actuated collapsing capsules are microspheres.
22. The method as recited in claim 21 , wherein the microspheres have a substantially uniform collapse pressure.
23. The method as recited in claim 22 , wherein the microspheres have a collapse: pressure within 1000 psi of one another.
24. The method as recited in claim 21 , wherein the microspheres have a non-uniform collapse pressure
25. The method as recited in claim 24 , wherein the microspheres have at least two different collapse pressures.
26. The method as recited in claim 24 , wherein the difference in collapse pressure of a plurality of the microspheres is at least 1000 psi.
27. An system comprising:
a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well; and
a pressure take-up means for establishing an upper-pressure limit with a pressured operating fluid filling at least a portion of the containment space and comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules wherein at least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space approaches the upper-pressure limit.
28. The system as recited in claim 27 , wherein the pressured fluid receiving containment space is one of either an expandable bladder of a downhole packer or an annulus space between a plurality of casing strings.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US12/432,306 US20090272545A1 (en) | 2008-04-30 | 2009-04-29 | System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space |
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US4929408P | 2008-04-30 | 2008-04-30 | |
US4928808P | 2008-04-30 | 2008-04-30 | |
US12/432,306 US20090272545A1 (en) | 2008-04-30 | 2009-04-29 | System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space |
Publications (1)
Publication Number | Publication Date |
---|---|
US20090272545A1 true US20090272545A1 (en) | 2009-11-05 |
Family
ID=40935152
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/432,306 Abandoned US20090272545A1 (en) | 2008-04-30 | 2009-04-29 | System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space |
Country Status (2)
Country | Link |
---|---|
US (1) | US20090272545A1 (en) |
WO (1) | WO2009134902A1 (en) |
Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN103670372A (en) * | 2013-12-20 | 2014-03-26 | 中国石油天然气集团公司 | System and method for judging strain of casing string of thermal production well |
US9181931B2 (en) | 2012-02-17 | 2015-11-10 | David Alan McBay | Geothermal energy collection system |
WO2017104563A1 (en) * | 2015-12-15 | 2017-06-22 | 帝石削井工業株式会社 | Packer |
US11215032B2 (en) | 2020-01-24 | 2022-01-04 | Saudi Arabian Oil Company | Devices and methods to mitigate pressure buildup in an isolated wellbore annulus |
Families Citing this family (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8322423B2 (en) | 2010-06-14 | 2012-12-04 | Halliburton Energy Services, Inc. | Oil-based grouting composition with an insulating material |
US9062240B2 (en) | 2010-06-14 | 2015-06-23 | Halliburton Energy Services, Inc. | Water-based grouting composition with an insulating material |
Citations (82)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3195630A (en) * | 1961-05-22 | 1965-07-20 | Phillips Petroleum Co | Sealing formations |
US3273642A (en) * | 1966-09-20 | Method of imploding frangible capsules used in well treatments | ||
US3390723A (en) * | 1965-06-16 | 1968-07-02 | Halliburton Co | Method of preparing and using a plugging or diverting agent |
US3526097A (en) * | 1966-08-04 | 1970-09-01 | Arthur J Nelson | Submergible apparatus |
US3942101A (en) * | 1973-12-06 | 1976-03-02 | Sayer Wayne L | Method for locating and evaluating geothermal sources of energy by sensing electrostatic voltage gradients |
US3960736A (en) * | 1974-06-03 | 1976-06-01 | The Dow Chemical Company | Self-breaking viscous aqueous solutions and the use thereof in fracturing subterranean formations |
US4039480A (en) * | 1975-03-21 | 1977-08-02 | Reynolds Metals Company | Hollow ceramic balls as automotive catalysts supports |
US4055399A (en) * | 1976-11-24 | 1977-10-25 | Standard Oil Company (Indiana) | Tracers in predetermined concentration ratios |
US4111713A (en) * | 1975-01-29 | 1978-09-05 | Minnesota Mining And Manufacturing Company | Hollow spheres |
US4126406A (en) * | 1976-09-13 | 1978-11-21 | Trw Inc. | Cooling of downhole electric pump motors |
US4223729A (en) * | 1979-01-12 | 1980-09-23 | Foster John W | Method for producing a geothermal reservoir in a hot dry rock formation for the recovery of geothermal energy |
US4391646A (en) * | 1982-02-25 | 1983-07-05 | Minnesota Mining And Manufacturing Company | Glass bubbles of increased collapse strength |
US4520666A (en) * | 1982-12-30 | 1985-06-04 | Schlumberger Technology Corp. | Methods and apparatus for determining flow characteristics of a fluid in a well from temperature measurements |
US4559818A (en) * | 1984-02-24 | 1985-12-24 | The United States Of America As Represented By The United States Department Of Energy | Thermal well-test method |
US4573537A (en) * | 1981-05-07 | 1986-03-04 | L'garde, Inc. | Casing packer |
US4577679A (en) * | 1978-10-25 | 1986-03-25 | Hibshman Henry J | Storage systems for heat or cold including aquifers |
US4637990A (en) * | 1978-08-28 | 1987-01-20 | Torobin Leonard B | Hollow porous microspheres as substrates and containers for catalysts and method of making same |
US4716984A (en) * | 1985-03-27 | 1988-01-05 | Honda Giken Kogyo Kabushiki Kaisha | Automotive vehicle power train |
US4749035A (en) * | 1987-04-30 | 1988-06-07 | Cameron Iron Works Usa, Inc. | Tubing packer |
US4832121A (en) * | 1987-10-01 | 1989-05-23 | The Trustees Of Columbia University In The City Of New York | Methods for monitoring temperature-vs-depth characteristics in a borehole during and after hydraulic fracture treatments |
US4926949A (en) * | 1988-12-07 | 1990-05-22 | Drilex Systems, Inc. | Thermal shield for drilling motors |
US4976142A (en) * | 1989-10-17 | 1990-12-11 | Baroid Technology, Inc. | Borehole pressure and temperature measurement system |
US5143155A (en) * | 1991-03-05 | 1992-09-01 | Husky Oil Operations Ltd. | Bacteriogenic mineral plugging |
US5163321A (en) * | 1989-10-17 | 1992-11-17 | Baroid Technology, Inc. | Borehole pressure and temperature measurement system |
US5165235A (en) * | 1990-12-12 | 1992-11-24 | Nitschke George S | System for using geopressured-geothermal reservoirs |
US5246860A (en) * | 1992-01-31 | 1993-09-21 | Union Oil Company Of California | Tracer chemicals for use in monitoring subterranean fluids |
US5515679A (en) * | 1995-01-13 | 1996-05-14 | Jerome S. Spevack | Geothermal heat mining and utilization |
US5595245A (en) * | 1995-08-04 | 1997-01-21 | Scott, Iii; George L. | Systems of injecting phenolic resin activator during subsurface fracture stimulation for enhanced oil recovery |
US5691059A (en) * | 1995-11-21 | 1997-11-25 | Minnesota Mining And Manfacturing Company | Glass and glass-ceramic bubbles having an aluminum nitride coating |
US5723781A (en) * | 1996-08-13 | 1998-03-03 | Pruett; Phillip E. | Borehole tracer injection and detection method |
US5837088A (en) * | 1991-03-13 | 1998-11-17 | Minnesota Mining And Manufacturing Company | Radio frequency induction heatable compositions |
US5890536A (en) * | 1997-08-26 | 1999-04-06 | Exxon Production Research Company | Method for stimulation of lenticular natural gas formations |
US5931000A (en) * | 1998-04-23 | 1999-08-03 | Turner; William Evans | Cooled electrical system for use downhole |
US5944446A (en) * | 1992-08-31 | 1999-08-31 | Golder Sierra Llc | Injection of mixtures into subterranean formations |
US6016191A (en) * | 1998-05-07 | 2000-01-18 | Schlumberger Technology Corporation | Apparatus and tool using tracers and singles point optical probes for measuring characteristics of fluid flow in a hydrocarbon well and methods of processing resulting signals |
US6125934A (en) * | 1996-05-20 | 2000-10-03 | Schlumberger Technology Corporation | Downhole tool and method for tracer injection |
US6291404B2 (en) * | 1998-12-28 | 2001-09-18 | Venture Innovations, Inc. | Viscosified aqueous chitosan-containing well drilling and servicing fluids |
US6543538B2 (en) * | 2000-07-18 | 2003-04-08 | Exxonmobil Upstream Research Company | Method for treating multiple wellbore intervals |
US20030079877A1 (en) * | 2001-04-24 | 2003-05-01 | Wellington Scott Lee | In situ thermal processing of a relatively impermeable formation in a reducing environment |
US20030130134A1 (en) * | 2002-01-04 | 2003-07-10 | Balmoral Group Ltd | Macrospheres for dual gradient drilling |
US6659175B2 (en) * | 2001-05-23 | 2003-12-09 | Core Laboratories, Inc. | Method for determining the extent of recovery of materials injected into oil wells during oil and gas exploration and production |
US20040074642A1 (en) * | 2001-11-13 | 2004-04-22 | Price-Smith Colin J. | Expandable completion system and method |
US6758271B1 (en) * | 2002-08-15 | 2004-07-06 | Sensor Highway Limited | System and technique to improve a well stimulation process |
US20050124499A1 (en) * | 2002-08-14 | 2005-06-09 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US20050194144A1 (en) * | 2004-03-02 | 2005-09-08 | Halliburton Energy Services, Inc. | Well fluids and methods of use in subterranean formations |
US20060016599A1 (en) * | 2004-07-22 | 2006-01-26 | Badalamenti Anthony M | Cementing methods and systems for initiating fluid flow with reduced pumping pressure |
US20060042798A1 (en) * | 2004-08-30 | 2006-03-02 | Badalamenti Anthony M | Casing shoes and methods of reverse-circulation cementing of casing |
US7032662B2 (en) * | 2001-05-23 | 2006-04-25 | Core Laboratories Lp | Method for determining the extent of recovery of materials injected into oil wells or subsurface formations during oil and gas exploration and production |
US20060113077A1 (en) * | 2004-09-01 | 2006-06-01 | Dean Willberg | Degradable material assisted diversion or isolation |
US20060180311A1 (en) * | 2005-02-14 | 2006-08-17 | Halliburton Energy Services, Inc. | Methods of cementing with lightweight cement compositions |
US20060202309A1 (en) * | 2003-07-29 | 2006-09-14 | Wong Marvin G | Integrated circuit substrate material |
US20070083331A1 (en) * | 2005-10-07 | 2007-04-12 | Craig David P | Methods and systems for determining reservoir properties of subterranean formations with pre-existing fractures |
US7207389B2 (en) * | 2003-03-07 | 2007-04-24 | Leader Energy Services Corp. | Hybrid coiled tubing/fluid pumping unit |
US20070114033A1 (en) * | 2005-11-18 | 2007-05-24 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US20070114034A1 (en) * | 2005-11-18 | 2007-05-24 | Chevron U.S.A. Inc. | Controlling pressure and static charge build up within an annular volume of a wellbore |
US7265079B2 (en) * | 2002-10-28 | 2007-09-04 | Schlumberger Technology Corporation | Self-destructing filter cake |
US20070223999A1 (en) * | 2004-06-23 | 2007-09-27 | Terrawatt Holdings Corporation | Method of Developing and Producing Deep Geothermal Reservoirs |
US7296625B2 (en) * | 2005-08-02 | 2007-11-20 | Halliburton Energy Services, Inc. | Methods of forming packs in a plurality of perforations in a casing of a wellbore |
US7299873B2 (en) * | 2001-03-12 | 2007-11-27 | Centriflow Llc | Method for pumping fluids |
US20070272407A1 (en) * | 2006-05-25 | 2007-11-29 | Halliburton Energy Services, Inc. | Method and system for development of naturally fractured formations |
US20080026956A1 (en) * | 2002-08-14 | 2008-01-31 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US20080023205A1 (en) * | 2003-02-20 | 2008-01-31 | Schlumberger Technology Corporation | System and Method for Maintaining Zonal Isolation in a Wellbore |
US7347260B2 (en) * | 2004-10-22 | 2008-03-25 | Core Laboratories Lp, A Delaware Limited Partnership | Method for determining tracer concentration in oil and gas production fluids |
US20080083536A1 (en) * | 2006-10-10 | 2008-04-10 | Cavender Travis W | Producing resources using steam injection |
US20080128108A1 (en) * | 2004-06-24 | 2008-06-05 | Steven Joseph Clark | Convective earrh coil |
US20080210423A1 (en) * | 2007-03-02 | 2008-09-04 | Curtis Boney | Circulated Degradable Material Assisted Diversion |
US20080236823A1 (en) * | 2005-06-20 | 2008-10-02 | Willberg Dean M | Degradable Fiber Systems for Stimulation |
US20090037112A1 (en) * | 2007-07-31 | 2009-02-05 | Soliman Mohamed Y | Methods and systems for evaluating and treating previously-fractured subterranean formations |
US20090065253A1 (en) * | 2007-09-04 | 2009-03-12 | Terratek, Inc. | Method and system for increasing production of a reservoir |
US7523024B2 (en) * | 2002-05-17 | 2009-04-21 | Schlumberger Technology Corporation | Modeling geologic objects in faulted formations |
US7565929B2 (en) * | 2006-10-24 | 2009-07-28 | Schlumberger Technology Corporation | Degradable material assisted diversion |
US20090205828A1 (en) * | 2008-02-19 | 2009-08-20 | Chevron U.S.A. Inc. | Production and Delivery of a Fluid Mixture to an Annular Volume of a Wellbore |
US7591320B2 (en) * | 2004-11-09 | 2009-09-22 | Schlumberger Technology Corporation | Method of cementing expandable well tubing |
US20110120716A1 (en) * | 2009-11-20 | 2011-05-26 | Robert Williams | Compositions and Methods for Mitigation of Annular Pressure Buildup in Subterranean Wells |
US7972555B2 (en) * | 2004-06-17 | 2011-07-05 | Exxonmobil Upstream Research Company | Method for fabricating compressible objects for a variable density drilling mud |
US7998269B2 (en) * | 2006-06-02 | 2011-08-16 | Catalyst Partners, Inc. | Cement blend |
US8047282B2 (en) * | 2009-08-25 | 2011-11-01 | Halliburton Energy Services Inc. | Methods of sonically activating cement compositions |
US8076269B2 (en) * | 2004-06-17 | 2011-12-13 | Exxonmobil Upstream Research Company | Compressible objects combined with a drilling fluid to form a variable density drilling mud |
US8080498B2 (en) * | 2008-10-31 | 2011-12-20 | Bp Corporation North America Inc. | Elastic hollow particles for annular pressure buildup mitigation |
US8088716B2 (en) * | 2004-06-17 | 2012-01-03 | Exxonmobil Upstream Research Company | Compressible objects having a predetermined internal pressure combined with a drilling fluid to form a variable density drilling mud |
US8088717B2 (en) * | 2004-06-17 | 2012-01-03 | Exxonmobil Upstream Research Company | Compressible objects having partial foam interiors combined with a drilling fluid to form a variable density drilling mud |
US20120296029A1 (en) * | 2011-05-20 | 2012-11-22 | Guojun Liu | Fluorine-containing multifunctional microspheres and uses thereof |
Family Cites Families (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP0338154B1 (en) * | 1988-04-22 | 1992-12-30 | Cooper Industries, Inc. | Submerged actuator |
US5038865A (en) * | 1989-12-29 | 1991-08-13 | Cooper Industries, Inc. | Method of and apparatus for protecting downhole equipment |
-
2009
- 2009-04-29 WO PCT/US2009/042137 patent/WO2009134902A1/en active Application Filing
- 2009-04-29 US US12/432,306 patent/US20090272545A1/en not_active Abandoned
Patent Citations (97)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3273642A (en) * | 1966-09-20 | Method of imploding frangible capsules used in well treatments | ||
US3195630A (en) * | 1961-05-22 | 1965-07-20 | Phillips Petroleum Co | Sealing formations |
US3390723A (en) * | 1965-06-16 | 1968-07-02 | Halliburton Co | Method of preparing and using a plugging or diverting agent |
US3526097A (en) * | 1966-08-04 | 1970-09-01 | Arthur J Nelson | Submergible apparatus |
US3942101A (en) * | 1973-12-06 | 1976-03-02 | Sayer Wayne L | Method for locating and evaluating geothermal sources of energy by sensing electrostatic voltage gradients |
US3960736A (en) * | 1974-06-03 | 1976-06-01 | The Dow Chemical Company | Self-breaking viscous aqueous solutions and the use thereof in fracturing subterranean formations |
US4111713A (en) * | 1975-01-29 | 1978-09-05 | Minnesota Mining And Manufacturing Company | Hollow spheres |
US4039480A (en) * | 1975-03-21 | 1977-08-02 | Reynolds Metals Company | Hollow ceramic balls as automotive catalysts supports |
US4126406A (en) * | 1976-09-13 | 1978-11-21 | Trw Inc. | Cooling of downhole electric pump motors |
US4055399A (en) * | 1976-11-24 | 1977-10-25 | Standard Oil Company (Indiana) | Tracers in predetermined concentration ratios |
US4637990A (en) * | 1978-08-28 | 1987-01-20 | Torobin Leonard B | Hollow porous microspheres as substrates and containers for catalysts and method of making same |
US4577679A (en) * | 1978-10-25 | 1986-03-25 | Hibshman Henry J | Storage systems for heat or cold including aquifers |
US4223729A (en) * | 1979-01-12 | 1980-09-23 | Foster John W | Method for producing a geothermal reservoir in a hot dry rock formation for the recovery of geothermal energy |
US4573537A (en) * | 1981-05-07 | 1986-03-04 | L'garde, Inc. | Casing packer |
US4391646A (en) * | 1982-02-25 | 1983-07-05 | Minnesota Mining And Manufacturing Company | Glass bubbles of increased collapse strength |
US4520666A (en) * | 1982-12-30 | 1985-06-04 | Schlumberger Technology Corp. | Methods and apparatus for determining flow characteristics of a fluid in a well from temperature measurements |
US4559818A (en) * | 1984-02-24 | 1985-12-24 | The United States Of America As Represented By The United States Department Of Energy | Thermal well-test method |
US4716984A (en) * | 1985-03-27 | 1988-01-05 | Honda Giken Kogyo Kabushiki Kaisha | Automotive vehicle power train |
US4749035A (en) * | 1987-04-30 | 1988-06-07 | Cameron Iron Works Usa, Inc. | Tubing packer |
US4832121A (en) * | 1987-10-01 | 1989-05-23 | The Trustees Of Columbia University In The City Of New York | Methods for monitoring temperature-vs-depth characteristics in a borehole during and after hydraulic fracture treatments |
US4926949A (en) * | 1988-12-07 | 1990-05-22 | Drilex Systems, Inc. | Thermal shield for drilling motors |
US4976142A (en) * | 1989-10-17 | 1990-12-11 | Baroid Technology, Inc. | Borehole pressure and temperature measurement system |
US5163321A (en) * | 1989-10-17 | 1992-11-17 | Baroid Technology, Inc. | Borehole pressure and temperature measurement system |
US5165235A (en) * | 1990-12-12 | 1992-11-24 | Nitschke George S | System for using geopressured-geothermal reservoirs |
US5143155A (en) * | 1991-03-05 | 1992-09-01 | Husky Oil Operations Ltd. | Bacteriogenic mineral plugging |
US5837088A (en) * | 1991-03-13 | 1998-11-17 | Minnesota Mining And Manufacturing Company | Radio frequency induction heatable compositions |
US5246860A (en) * | 1992-01-31 | 1993-09-21 | Union Oil Company Of California | Tracer chemicals for use in monitoring subterranean fluids |
US5944446A (en) * | 1992-08-31 | 1999-08-31 | Golder Sierra Llc | Injection of mixtures into subterranean formations |
US5515679A (en) * | 1995-01-13 | 1996-05-14 | Jerome S. Spevack | Geothermal heat mining and utilization |
US5595245A (en) * | 1995-08-04 | 1997-01-21 | Scott, Iii; George L. | Systems of injecting phenolic resin activator during subsurface fracture stimulation for enhanced oil recovery |
US5691059A (en) * | 1995-11-21 | 1997-11-25 | Minnesota Mining And Manfacturing Company | Glass and glass-ceramic bubbles having an aluminum nitride coating |
US6125934A (en) * | 1996-05-20 | 2000-10-03 | Schlumberger Technology Corporation | Downhole tool and method for tracer injection |
US5723781A (en) * | 1996-08-13 | 1998-03-03 | Pruett; Phillip E. | Borehole tracer injection and detection method |
US5890536A (en) * | 1997-08-26 | 1999-04-06 | Exxon Production Research Company | Method for stimulation of lenticular natural gas formations |
US5931000A (en) * | 1998-04-23 | 1999-08-03 | Turner; William Evans | Cooled electrical system for use downhole |
US6016191A (en) * | 1998-05-07 | 2000-01-18 | Schlumberger Technology Corporation | Apparatus and tool using tracers and singles point optical probes for measuring characteristics of fluid flow in a hydrocarbon well and methods of processing resulting signals |
US6291404B2 (en) * | 1998-12-28 | 2001-09-18 | Venture Innovations, Inc. | Viscosified aqueous chitosan-containing well drilling and servicing fluids |
US6543538B2 (en) * | 2000-07-18 | 2003-04-08 | Exxonmobil Upstream Research Company | Method for treating multiple wellbore intervals |
US7299873B2 (en) * | 2001-03-12 | 2007-11-27 | Centriflow Llc | Method for pumping fluids |
US20030079877A1 (en) * | 2001-04-24 | 2003-05-01 | Wellington Scott Lee | In situ thermal processing of a relatively impermeable formation in a reducing environment |
US7032662B2 (en) * | 2001-05-23 | 2006-04-25 | Core Laboratories Lp | Method for determining the extent of recovery of materials injected into oil wells or subsurface formations during oil and gas exploration and production |
US6659175B2 (en) * | 2001-05-23 | 2003-12-09 | Core Laboratories, Inc. | Method for determining the extent of recovery of materials injected into oil wells during oil and gas exploration and production |
US20040074642A1 (en) * | 2001-11-13 | 2004-04-22 | Price-Smith Colin J. | Expandable completion system and method |
US20030130134A1 (en) * | 2002-01-04 | 2003-07-10 | Balmoral Group Ltd | Macrospheres for dual gradient drilling |
US7523024B2 (en) * | 2002-05-17 | 2009-04-21 | Schlumberger Technology Corporation | Modeling geologic objects in faulted formations |
US20050124499A1 (en) * | 2002-08-14 | 2005-06-09 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US6906009B2 (en) * | 2002-08-14 | 2005-06-14 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US20080026956A1 (en) * | 2002-08-14 | 2008-01-31 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US7767629B2 (en) * | 2002-08-14 | 2010-08-03 | 3M Innovative Properties Company | Drilling fluid containing microspheres and use thereof |
US6758271B1 (en) * | 2002-08-15 | 2004-07-06 | Sensor Highway Limited | System and technique to improve a well stimulation process |
US7265079B2 (en) * | 2002-10-28 | 2007-09-04 | Schlumberger Technology Corporation | Self-destructing filter cake |
US20080023205A1 (en) * | 2003-02-20 | 2008-01-31 | Schlumberger Technology Corporation | System and Method for Maintaining Zonal Isolation in a Wellbore |
US7207389B2 (en) * | 2003-03-07 | 2007-04-24 | Leader Energy Services Corp. | Hybrid coiled tubing/fluid pumping unit |
US7135767B2 (en) * | 2003-07-29 | 2006-11-14 | Agilent Technologies, Inc. | Integrated circuit substrate material and method |
US20060202309A1 (en) * | 2003-07-29 | 2006-09-14 | Wong Marvin G | Integrated circuit substrate material |
US20060231251A1 (en) * | 2004-03-02 | 2006-10-19 | Vargo Richard F Jr | Well fluids and methods of use in subterranean formations |
US20050194144A1 (en) * | 2004-03-02 | 2005-09-08 | Halliburton Energy Services, Inc. | Well fluids and methods of use in subterranean formations |
US8076269B2 (en) * | 2004-06-17 | 2011-12-13 | Exxonmobil Upstream Research Company | Compressible objects combined with a drilling fluid to form a variable density drilling mud |
US7972555B2 (en) * | 2004-06-17 | 2011-07-05 | Exxonmobil Upstream Research Company | Method for fabricating compressible objects for a variable density drilling mud |
US8088716B2 (en) * | 2004-06-17 | 2012-01-03 | Exxonmobil Upstream Research Company | Compressible objects having a predetermined internal pressure combined with a drilling fluid to form a variable density drilling mud |
US8088717B2 (en) * | 2004-06-17 | 2012-01-03 | Exxonmobil Upstream Research Company | Compressible objects having partial foam interiors combined with a drilling fluid to form a variable density drilling mud |
US20070223999A1 (en) * | 2004-06-23 | 2007-09-27 | Terrawatt Holdings Corporation | Method of Developing and Producing Deep Geothermal Reservoirs |
US20080128108A1 (en) * | 2004-06-24 | 2008-06-05 | Steven Joseph Clark | Convective earrh coil |
US7252147B2 (en) * | 2004-07-22 | 2007-08-07 | Halliburton Energy Services, Inc. | Cementing methods and systems for initiating fluid flow with reduced pumping pressure |
US20060016599A1 (en) * | 2004-07-22 | 2006-01-26 | Badalamenti Anthony M | Cementing methods and systems for initiating fluid flow with reduced pumping pressure |
US20060042798A1 (en) * | 2004-08-30 | 2006-03-02 | Badalamenti Anthony M | Casing shoes and methods of reverse-circulation cementing of casing |
US7322412B2 (en) * | 2004-08-30 | 2008-01-29 | Halliburton Energy Services, Inc. | Casing shoes and methods of reverse-circulation cementing of casing |
US7938186B1 (en) * | 2004-08-30 | 2011-05-10 | Halliburton Energy Services Inc. | Casing shoes and methods of reverse-circulation cementing of casing |
US20110094742A1 (en) * | 2004-08-30 | 2011-04-28 | Badalamenti Anthony M | Casing Shoes and Methods of Reverse-Circulation Cementing of Casing |
US7503399B2 (en) * | 2004-08-30 | 2009-03-17 | Halliburton Energy Services, Inc. | Casing shoes and methods of reverse-circulation cementing of casing |
US7621336B2 (en) * | 2004-08-30 | 2009-11-24 | Halliburton Energy Services, Inc. | Casing shoes and methods of reverse-circulation cementing of casing |
US20060113077A1 (en) * | 2004-09-01 | 2006-06-01 | Dean Willberg | Degradable material assisted diversion or isolation |
US7347260B2 (en) * | 2004-10-22 | 2008-03-25 | Core Laboratories Lp, A Delaware Limited Partnership | Method for determining tracer concentration in oil and gas production fluids |
US7591320B2 (en) * | 2004-11-09 | 2009-09-22 | Schlumberger Technology Corporation | Method of cementing expandable well tubing |
US20060180311A1 (en) * | 2005-02-14 | 2006-08-17 | Halliburton Energy Services, Inc. | Methods of cementing with lightweight cement compositions |
US20080236823A1 (en) * | 2005-06-20 | 2008-10-02 | Willberg Dean M | Degradable Fiber Systems for Stimulation |
US7296625B2 (en) * | 2005-08-02 | 2007-11-20 | Halliburton Energy Services, Inc. | Methods of forming packs in a plurality of perforations in a casing of a wellbore |
US20070083331A1 (en) * | 2005-10-07 | 2007-04-12 | Craig David P | Methods and systems for determining reservoir properties of subterranean formations with pre-existing fractures |
US7950460B2 (en) * | 2005-11-18 | 2011-05-31 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US7441599B2 (en) * | 2005-11-18 | 2008-10-28 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US20070114033A1 (en) * | 2005-11-18 | 2007-05-24 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US7743830B2 (en) * | 2005-11-18 | 2010-06-29 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US20070114034A1 (en) * | 2005-11-18 | 2007-05-24 | Chevron U.S.A. Inc. | Controlling pressure and static charge build up within an annular volume of a wellbore |
US7870905B2 (en) * | 2005-11-18 | 2011-01-18 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US7963333B2 (en) * | 2005-11-18 | 2011-06-21 | Chevron U.S.A. Inc. | Controlling the pressure within an annular volume of a wellbore |
US20070272407A1 (en) * | 2006-05-25 | 2007-11-29 | Halliburton Energy Services, Inc. | Method and system for development of naturally fractured formations |
US7998269B2 (en) * | 2006-06-02 | 2011-08-16 | Catalyst Partners, Inc. | Cement blend |
US20080083536A1 (en) * | 2006-10-10 | 2008-04-10 | Cavender Travis W | Producing resources using steam injection |
US7565929B2 (en) * | 2006-10-24 | 2009-07-28 | Schlumberger Technology Corporation | Degradable material assisted diversion |
US20080210423A1 (en) * | 2007-03-02 | 2008-09-04 | Curtis Boney | Circulated Degradable Material Assisted Diversion |
US20090037112A1 (en) * | 2007-07-31 | 2009-02-05 | Soliman Mohamed Y | Methods and systems for evaluating and treating previously-fractured subterranean formations |
US20090065253A1 (en) * | 2007-09-04 | 2009-03-12 | Terratek, Inc. | Method and system for increasing production of a reservoir |
US20090205828A1 (en) * | 2008-02-19 | 2009-08-20 | Chevron U.S.A. Inc. | Production and Delivery of a Fluid Mixture to an Annular Volume of a Wellbore |
US8080498B2 (en) * | 2008-10-31 | 2011-12-20 | Bp Corporation North America Inc. | Elastic hollow particles for annular pressure buildup mitigation |
US8047282B2 (en) * | 2009-08-25 | 2011-11-01 | Halliburton Energy Services Inc. | Methods of sonically activating cement compositions |
US20110120716A1 (en) * | 2009-11-20 | 2011-05-26 | Robert Williams | Compositions and Methods for Mitigation of Annular Pressure Buildup in Subterranean Wells |
US20120296029A1 (en) * | 2011-05-20 | 2012-11-22 | Guojun Liu | Fluorine-containing multifunctional microspheres and uses thereof |
Cited By (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9181931B2 (en) | 2012-02-17 | 2015-11-10 | David Alan McBay | Geothermal energy collection system |
US9927151B2 (en) | 2012-02-17 | 2018-03-27 | David Alan McBay | Geothermal energy collection system |
US10605491B2 (en) | 2012-02-17 | 2020-03-31 | David Alan McBay | Geothermal energy collection system |
US11131484B2 (en) | 2012-02-17 | 2021-09-28 | David Alan McBay | Geothermal energy collection system |
US11519639B2 (en) | 2012-02-17 | 2022-12-06 | David Alan McBay | Geothermal energy collection system |
CN103670372A (en) * | 2013-12-20 | 2014-03-26 | 中国石油天然气集团公司 | System and method for judging strain of casing string of thermal production well |
WO2017104563A1 (en) * | 2015-12-15 | 2017-06-22 | 帝石削井工業株式会社 | Packer |
US10801299B2 (en) | 2015-12-15 | 2020-10-13 | Teiseki Drilling Co., Ltd. | Packer |
US11215032B2 (en) | 2020-01-24 | 2022-01-04 | Saudi Arabian Oil Company | Devices and methods to mitigate pressure buildup in an isolated wellbore annulus |
Also Published As
Publication number | Publication date |
---|---|
WO2009134902A1 (en) | 2009-11-05 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US8640772B2 (en) | Enhanced geothermal systems and reservoir optimization | |
US7096944B2 (en) | Well fluids and methods of use in subterranean formations | |
US7963333B2 (en) | Controlling the pressure within an annular volume of a wellbore | |
US20070027036A1 (en) | Variable density drilling mud | |
US20090272545A1 (en) | System and method for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid in a subterranean containment space | |
GB2398582A (en) | System and method for maintaining zonal isolation in a wellbore | |
US9631132B2 (en) | Mitigating annular pressure buildup using temperature-activated polymeric particulates | |
CA2970650C (en) | Establishing control of oil and gas producing well bore through application of self-degrading particulates | |
CN111271036B (en) | Liquid nitrogen fracturing process method | |
Yuan et al. | Technical difficulties in the cementing of horizontal shale gas wells in Weiyuan block and the countermeasures | |
NO20170969A1 (en) | Lost circulation materials comprising brown mud | |
EP4048857B1 (en) | Method for plugging and abandoning oil and gas wells | |
Baumgärtner et al. | Progress at the European HDR project at Soultz–Sous–Forêts: Preliminary results from the deepening of the well GPK2 to 5000 m | |
Dreesen et al. | Open hole packer for high pressure service in a five hundred degree fahrenheit precambrian wellbore | |
CN116480284A (en) | Underground large-aperture seepage channel reconstruction method suitable for geothermal energy | |
Wang et al. | Using a Novel Spacer and Ultralow Density Cement System to Control Lost Circulation in Coalbed Methane (CBM) Wells | |
FEDERER-KOVACS et al. | REASONS AND RESOLUTIONS OF TRAPPED ANNULAR PRESSURE | |
GB2226583A (en) | Method of placing a pipe string in a borehole and pipe section for use in the method |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: ALTAROCK ENERGY INC., WASHINGTON Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:BOUR, DANIEL L;REEL/FRAME:022806/0829 Effective date: 20090507 |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |