CA2531920A1 - Friction pressure reducing agents for gases - Google Patents
Friction pressure reducing agents for gases Download PDFInfo
- Publication number
- CA2531920A1 CA2531920A1 CA002531920A CA2531920A CA2531920A1 CA 2531920 A1 CA2531920 A1 CA 2531920A1 CA 002531920 A CA002531920 A CA 002531920A CA 2531920 A CA2531920 A CA 2531920A CA 2531920 A1 CA2531920 A1 CA 2531920A1
- Authority
- CA
- Canada
- Prior art keywords
- gas
- graphite
- coiled tubing
- particulate
- friction
- 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
- 239000007789 gas Substances 0.000 title claims description 51
- 239000003638 chemical reducing agent Substances 0.000 title claims 3
- 239000007787 solid Substances 0.000 claims abstract description 11
- 230000000638 stimulation Effects 0.000 claims abstract description 6
- 239000012530 fluid Substances 0.000 claims abstract description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 26
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical group [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 20
- 229910002804 graphite Inorganic materials 0.000 claims description 20
- 239000010439 graphite Substances 0.000 claims description 20
- 238000000034 method Methods 0.000 claims description 13
- 229910052757 nitrogen Inorganic materials 0.000 claims description 11
- 239000000314 lubricant Substances 0.000 abstract description 3
- 230000015572 biosynthetic process Effects 0.000 description 18
- 238000005755 formation reaction Methods 0.000 description 18
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 16
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 14
- 238000005086 pumping Methods 0.000 description 11
- 238000007792 addition Methods 0.000 description 7
- 238000002347 injection Methods 0.000 description 7
- 239000007924 injection Substances 0.000 description 7
- 230000001050 lubricating effect Effects 0.000 description 7
- 238000000576 coating method Methods 0.000 description 6
- 229910052742 iron Inorganic materials 0.000 description 6
- 239000011248 coating agent Substances 0.000 description 5
- 238000004519 manufacturing process Methods 0.000 description 5
- 229910001873 dinitrogen Inorganic materials 0.000 description 4
- 239000007788 liquid Substances 0.000 description 4
- 239000003345 natural gas Substances 0.000 description 4
- 230000009286 beneficial effect Effects 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 230000002708 enhancing effect Effects 0.000 description 1
- 230000002045 lasting effect Effects 0.000 description 1
- 238000005461 lubrication Methods 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 239000011148 porous material Substances 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
- 239000000344 soap Substances 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 230000008961 swelling Effects 0.000 description 1
- 238000011144 upstream manufacturing Methods 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/84—Compositions based on water or polar solvents
- C09K8/845—Compositions based on water or polar solvents containing inorganic compounds
Abstract
A well stimulation fluid which includes a gas and a solid particulate as a lubricant.
Description
2 FRICTION PRESSURE REDUCING ACrENTS FOR GASES
'I'he basis of this invention is a method of reducing gas friction pressures in high-rate gas pumping operations through the addition of graphite or similar solid particulate with lubricating qualities to the gas stream. Also included in this invention is a method by which the particulate is introduced to the gas stream.
A secondary application of this invention is the reduction of gas friction pressures within a fracture system of a gas producing formation.
Background to the Invention Wells are drilled and completed for the production of oil and natural gas.
Subsequent to the completion, well stimulation is often required to allow the wells to produce at commercial rates. These stimulations may be required initially before commercial production is achieved, or may occur at a later stage in the life of the well, as a means of restoring well productivity.
A common example of an initial stu-nulation would be the fracturing of a coalbed methane formation with nitrogen. In these stimulations, high rate nitrogen is injected through coiled tubing into the coalbed fozxnation to create and extend a fracture systezn.
that allows natural gas that is entrained in the coals to flow to the wellbore. Common operations such as this use coiled tubing of outer diameters ranging from 2-
'I'he basis of this invention is a method of reducing gas friction pressures in high-rate gas pumping operations through the addition of graphite or similar solid particulate with lubricating qualities to the gas stream. Also included in this invention is a method by which the particulate is introduced to the gas stream.
A secondary application of this invention is the reduction of gas friction pressures within a fracture system of a gas producing formation.
Background to the Invention Wells are drilled and completed for the production of oil and natural gas.
Subsequent to the completion, well stimulation is often required to allow the wells to produce at commercial rates. These stimulations may be required initially before commercial production is achieved, or may occur at a later stage in the life of the well, as a means of restoring well productivity.
A common example of an initial stu-nulation would be the fracturing of a coalbed methane formation with nitrogen. In these stimulations, high rate nitrogen is injected through coiled tubing into the coalbed fozxnation to create and extend a fracture systezn.
that allows natural gas that is entrained in the coals to flow to the wellbore. Common operations such as this use coiled tubing of outer diameters ranging from 2-
3/8 inch (60.3 millimetres) to 3-1/2 inch (88.9 millimetres). Rates presently used to create and extend the fracture system are in the range of 26,500 standard cubic feet per minute (750 standard cubic metres per minute) to as high as 70,500 standard cubic feet per mi.n.ute (2000 standard cubic metres per minute) or higher. At gas rates such as these, through relatively small tubulars, friction pressures arc high and can place a significant burden on both the pumping equipment and coiled tubing. Fatigue of coiled tubing increases, and consequently the life of the coiled tubi.ng decreases, as the pressure at which the coiled tubing is incxeased. Minimizing puniping pressures therefore would enhance the life of a string of coiled tubing. Additionally, the pressure that a pumping unit is required to operate at determines its power requirements and ene.rgy consumption, and depending on the design of the ptunping equipment, higher pressures may lead to increased wear and maintenance of the pumping un.it.
Other operations also exist which require the high-rate injection of nitrogen or othcr gases_ An example of a stimu.lation occurring later in the life of a well would be the injection of nitrogen or a similar gas to remove sand or fill from the wellbore which is plugging the wellbore and hindering production. These operations rnay be conductcd with tubulars of a wide range in size, often from less than 1.25 inches (31.8 millimetres) to greater than 2 inches (50.8 millimetres) but due to the amount of fill or debris to be removed from the wellbore will require high rates of gas and result in significant friction pressures.
For the reasons descrxbed above, it is beneficial to minimize friction pressure losses and minunize the pumping pressure in these operations.
Various methods are available to reduce friction pressure losses in pumping operation.s through tubulars. Where liquids are being pumped, the addition of a small volume of friction-reduczng liquid such as a soap or surfactant substance can signifiaantly reduce the friction pressure. Where gas is the fluid being pumped, small volumes of these liquids can also assist in reducing friction pressure losses. However, in many operations where gas is being pumped, the formations being contacted with the gas cannot tolerate contact with liquid. This may be due to swelling of clays, plugging of formation pore throats, or a variety of other reasons. In such cases, particularly those of a relatively high gas rate for the tubular being used, another method of reducing friction pressure losses must be found.
Description of the invention This invention has specific reference to the addition of a solid particulate to the gas stream for the purpose of reducing fri.ction pressure losses. Where the operation is a
Other operations also exist which require the high-rate injection of nitrogen or othcr gases_ An example of a stimu.lation occurring later in the life of a well would be the injection of nitrogen or a similar gas to remove sand or fill from the wellbore which is plugging the wellbore and hindering production. These operations rnay be conductcd with tubulars of a wide range in size, often from less than 1.25 inches (31.8 millimetres) to greater than 2 inches (50.8 millimetres) but due to the amount of fill or debris to be removed from the wellbore will require high rates of gas and result in significant friction pressures.
For the reasons descrxbed above, it is beneficial to minimize friction pressure losses and minunize the pumping pressure in these operations.
Various methods are available to reduce friction pressure losses in pumping operation.s through tubulars. Where liquids are being pumped, the addition of a small volume of friction-reduczng liquid such as a soap or surfactant substance can signifiaantly reduce the friction pressure. Where gas is the fluid being pumped, small volumes of these liquids can also assist in reducing friction pressure losses. However, in many operations where gas is being pumped, the formations being contacted with the gas cannot tolerate contact with liquid. This may be due to swelling of clays, plugging of formation pore throats, or a variety of other reasons. In such cases, particularly those of a relatively high gas rate for the tubular being used, another method of reducing friction pressure losses must be found.
Description of the invention This invention has specific reference to the addition of a solid particulate to the gas stream for the purpose of reducing fri.ction pressure losses. Where the operation is a
4 high-rate gas fracturing operation of a formation such as a coalbed methane formation, it is desirable for, the solid particulate to be of small particle size so as not to create any plugging of the fracture created by the gas injection.
For the purpose of describing the invention, the following embodiment is described, and illustrated in Figure 1. A subsurface formation (101) has been penetrated by a wellbore (102) drilled for the production of natural gas. The wellbore has been cased with a steel casing (103) and the casin.g bas been anchored into the earth by way of cement (104) between the casing and the earth. The casing is of 4-1/2 inch (114.3millimetre) outer diameter. The casing has been perforated (105) one or more times, at depths commonly in the range of 600 feet (200 metres) from surface to 1800 feet (600 metres) from surface, to communicate the casing with one or more subsurface forniations. The subsurface formations are coalbed methane formations containing low pressure natural gas. Coiled tubing (106) is introduced to the wellbore for the purpose of providing a means of communicating the perforations with a source of high-rate and high pressure gas at surface. High-rate cryogenic nitrogen is delivered from one or more nitrogen pumping units (108) through a system of treating iron and valving (110) to a rotating joint (103) on the coiled tubing reel. The rotating joirtt allows the gas to be pumped into the coil while the coiled tubing is stationary, or while it is moviztg.
The gas introduced to the coiled tubing is isolated to a specific set of perforations through a coiled tubing fracturing tool (107), which uses one or more sets of opposing cups that seal against the casing under applied gas pressure to contain gas rate and pressure between the cups and force the gas into the set of perforations. The coiled tubing (106) is 2-7/8 inch outer diameter. Nitrogen gas is pumped at rates of 1200 standard cubic metres per minute for the purpose of creating a system of fractures (109) for the enhanced production of natural gas_ In this embodiment, pumping pressLtres may attain levels of 5000 pounds per square inch (35 MegaPascals) or higher, depending on the resident formation pressure and the depth of the formation. and the density of wellbore perforations.
The invention encompasses the addition of a solid particulate as a lubricant, to the nitrogen gas stream downstream of the nitrogen pumping unit (108), and typically upstream of the coiled tubing rotating joint (103). A,lternatively the particulate could be added to the coiled tubing which is fixed inside the coiled tubing reel_ In this embodiment of the invention, the solid particulate used to reduce gas friction pressure losses is graphite. Other small particulate solids with natural or synthetic lubricating qualities are not excluded from this invention.
Figure 2 shows one method of introduction of the particulate to the stream. In this case, a length of tubular (201) is connected to the treating iron (202) but isolated b-om the treating iron by a first valve or set o#'valves (203). The tubular may be a joint of tubing or treating iron, in this case a joi.ttt of treating iron of 2 inch (50.8 millimetre) diameter aztd 4 foot (1.25 metres) length but could be of another length or another diameter.
This valve or valves, when opened, will expose the tubular to nitrogen gas. A second valve or set of valves (204) is located at the end of the tubular to isolate the inside of the tubular from the atmosphere. With these valves or sets of valves, both cnds of the tubular can be isolated when the valves or sets of valves are closed.
To add the particulate to the gas stream under active nitrogen pumping operations, the first valve or set of valves (203) are closed and the second valve or set of valves (204) are opened and graphite poured into the tubular. The second valve or set of valves (204) are closed and the first valve or set of valves (203) are opened to allow the graphite to enter the gas stream. This system can be used to introduce the graphite as a batch treatment which can be replenished by reloading the tubular by the method described above, or by using a control valve or set of valves as the first valve or set of valves (203) the graphite can be introduced to the nitrogen gas as a slow and steady source until the tubular is evacuated of graphite.
Another method by which the graphite can be entered into the gas stream is shown in Figure 3. In this case the upper valve or set of valves as shown in Figiire 2 is replaced by a flange cap (301) rated for the treating pressures to be seen in the operation.
Introduction is as described above by elosing the first valve or set of valves (302) to isolate the tubing or chamber (303) from the gas stream, opening the flange cap to fi11 the tubing or chamber with graphite, closing the flange cap and opening the first valve or set of valves (302) to allow the graphite to enter the gas stream._ In a third embodiment as shown in Figure 4, an injection device (401) is attached to the treating iron (402) and used for the introduction of graphite_ The injection device may be a device spccially designed and manufactured for the intxoduction of graphite, or may simply be a ball injector. A ball injecto.r is a common device in coiled tubing operations and is used for the addition of ball devices to the coiled tubing under pressure for operating downhole tools, sealing flow ports, or other such uses. The injection device may contain a plurality of ball or injection chambers which can be electrically or hydraulically rotated or otherwise activated such that a numbeT of discreet additions can be achieved before needing to reload or replenish the device.
Through the methods described above of introducing the graphite into the gas stream, the graphite provides a coating of lubricant on the inside of the coiled tubing to reduce the effective rougbness of the coiled tubing as well as to reduce interfacial friction between the gas and the coiled tubing. In the operation described in the embodiment above, the coiled tubing is already in the wellborc and the particulate is added to the coiled tubing and any excess particulate is exhausted to the wellbore and potentially the formation with the gas. In some operations it may be seen as beneficial to optimize the coating process by pumping a tubing plug or tubing pig aftcr addition of the graphite to provide a more uniform and longer lasting coating, effectively enhancing both the lubrication qualities and the longevity of the coating. In this case the particulate would be added to a gas stream and pumped through the coiled tubirtg with the coiled tubing removcd from the wellbore such that the tubing pig or tubing plug can be recovered without it cntering the wellboze_ This method may also be used when it is undesirable for excess particulate to enter the formation.
In some situations it may bc seen as desirable for additional particulate to be placed in the formation for the purpose of reducing friction for gas flow within the formation itself. The productivity of low pressure gas fozmations can be significantly affected by the resistance to flow due to gas friction pressures_ Just as the graphite or particulate provides a lubricating coating inside the tubulars, this can also result in a lubricating coating on the face of formation fractures. This would be more prevalent in coalbed formations in which fractures are created with solid faces, or cleats, which would be made smoother with a reduced roughness as a result of the graphite.
The foregoing describes one common embodiment of the invention, and some variations have also been described throughout this description. Several modified embodirueats are obvious, including the use of jointed tubulars rather than coiled tubing, the application of this treatment to fracturing operations on sandstone or carbonate formations rather than coalbed methane, the application of this treatinent in.
any gas stimulation operations such as cleanouts or blowdowns, the use of alternate gases rather than nitrogen, the use of aIternate lubricating particulates other than graphite, and alternate means of introducing the lubricating particulates into the gas stream. The description also references certain gas flow rates, tubular diameters and operating depths strictly for the intent of providing evidence of application of this invention to a realistic operation. This description, therefore, should not be considered to be exclusive of higher or lower gas rates, larger or smaller tubulars, or shallower or deeper depths, or operations other than fracturing. The invention is inteztded to be applicable to any situation where it is desirable to reduce gas friction pressure losses in tubulars. This invention is intended to describe the practice and method of adding a lubricating particulate to a gas stream for the purpose of friction pressure reduction.
For the purpose of describing the invention, the following embodiment is described, and illustrated in Figure 1. A subsurface formation (101) has been penetrated by a wellbore (102) drilled for the production of natural gas. The wellbore has been cased with a steel casing (103) and the casin.g bas been anchored into the earth by way of cement (104) between the casing and the earth. The casing is of 4-1/2 inch (114.3millimetre) outer diameter. The casing has been perforated (105) one or more times, at depths commonly in the range of 600 feet (200 metres) from surface to 1800 feet (600 metres) from surface, to communicate the casing with one or more subsurface forniations. The subsurface formations are coalbed methane formations containing low pressure natural gas. Coiled tubing (106) is introduced to the wellbore for the purpose of providing a means of communicating the perforations with a source of high-rate and high pressure gas at surface. High-rate cryogenic nitrogen is delivered from one or more nitrogen pumping units (108) through a system of treating iron and valving (110) to a rotating joint (103) on the coiled tubing reel. The rotating joirtt allows the gas to be pumped into the coil while the coiled tubing is stationary, or while it is moviztg.
The gas introduced to the coiled tubing is isolated to a specific set of perforations through a coiled tubing fracturing tool (107), which uses one or more sets of opposing cups that seal against the casing under applied gas pressure to contain gas rate and pressure between the cups and force the gas into the set of perforations. The coiled tubing (106) is 2-7/8 inch outer diameter. Nitrogen gas is pumped at rates of 1200 standard cubic metres per minute for the purpose of creating a system of fractures (109) for the enhanced production of natural gas_ In this embodiment, pumping pressLtres may attain levels of 5000 pounds per square inch (35 MegaPascals) or higher, depending on the resident formation pressure and the depth of the formation. and the density of wellbore perforations.
The invention encompasses the addition of a solid particulate as a lubricant, to the nitrogen gas stream downstream of the nitrogen pumping unit (108), and typically upstream of the coiled tubing rotating joint (103). A,lternatively the particulate could be added to the coiled tubing which is fixed inside the coiled tubing reel_ In this embodiment of the invention, the solid particulate used to reduce gas friction pressure losses is graphite. Other small particulate solids with natural or synthetic lubricating qualities are not excluded from this invention.
Figure 2 shows one method of introduction of the particulate to the stream. In this case, a length of tubular (201) is connected to the treating iron (202) but isolated b-om the treating iron by a first valve or set o#'valves (203). The tubular may be a joint of tubing or treating iron, in this case a joi.ttt of treating iron of 2 inch (50.8 millimetre) diameter aztd 4 foot (1.25 metres) length but could be of another length or another diameter.
This valve or valves, when opened, will expose the tubular to nitrogen gas. A second valve or set of valves (204) is located at the end of the tubular to isolate the inside of the tubular from the atmosphere. With these valves or sets of valves, both cnds of the tubular can be isolated when the valves or sets of valves are closed.
To add the particulate to the gas stream under active nitrogen pumping operations, the first valve or set of valves (203) are closed and the second valve or set of valves (204) are opened and graphite poured into the tubular. The second valve or set of valves (204) are closed and the first valve or set of valves (203) are opened to allow the graphite to enter the gas stream. This system can be used to introduce the graphite as a batch treatment which can be replenished by reloading the tubular by the method described above, or by using a control valve or set of valves as the first valve or set of valves (203) the graphite can be introduced to the nitrogen gas as a slow and steady source until the tubular is evacuated of graphite.
Another method by which the graphite can be entered into the gas stream is shown in Figure 3. In this case the upper valve or set of valves as shown in Figiire 2 is replaced by a flange cap (301) rated for the treating pressures to be seen in the operation.
Introduction is as described above by elosing the first valve or set of valves (302) to isolate the tubing or chamber (303) from the gas stream, opening the flange cap to fi11 the tubing or chamber with graphite, closing the flange cap and opening the first valve or set of valves (302) to allow the graphite to enter the gas stream._ In a third embodiment as shown in Figure 4, an injection device (401) is attached to the treating iron (402) and used for the introduction of graphite_ The injection device may be a device spccially designed and manufactured for the intxoduction of graphite, or may simply be a ball injector. A ball injecto.r is a common device in coiled tubing operations and is used for the addition of ball devices to the coiled tubing under pressure for operating downhole tools, sealing flow ports, or other such uses. The injection device may contain a plurality of ball or injection chambers which can be electrically or hydraulically rotated or otherwise activated such that a numbeT of discreet additions can be achieved before needing to reload or replenish the device.
Through the methods described above of introducing the graphite into the gas stream, the graphite provides a coating of lubricant on the inside of the coiled tubing to reduce the effective rougbness of the coiled tubing as well as to reduce interfacial friction between the gas and the coiled tubing. In the operation described in the embodiment above, the coiled tubing is already in the wellborc and the particulate is added to the coiled tubing and any excess particulate is exhausted to the wellbore and potentially the formation with the gas. In some operations it may be seen as beneficial to optimize the coating process by pumping a tubing plug or tubing pig aftcr addition of the graphite to provide a more uniform and longer lasting coating, effectively enhancing both the lubrication qualities and the longevity of the coating. In this case the particulate would be added to a gas stream and pumped through the coiled tubirtg with the coiled tubing removcd from the wellbore such that the tubing pig or tubing plug can be recovered without it cntering the wellboze_ This method may also be used when it is undesirable for excess particulate to enter the formation.
In some situations it may bc seen as desirable for additional particulate to be placed in the formation for the purpose of reducing friction for gas flow within the formation itself. The productivity of low pressure gas fozmations can be significantly affected by the resistance to flow due to gas friction pressures_ Just as the graphite or particulate provides a lubricating coating inside the tubulars, this can also result in a lubricating coating on the face of formation fractures. This would be more prevalent in coalbed formations in which fractures are created with solid faces, or cleats, which would be made smoother with a reduced roughness as a result of the graphite.
The foregoing describes one common embodiment of the invention, and some variations have also been described throughout this description. Several modified embodirueats are obvious, including the use of jointed tubulars rather than coiled tubing, the application of this treatment to fracturing operations on sandstone or carbonate formations rather than coalbed methane, the application of this treatinent in.
any gas stimulation operations such as cleanouts or blowdowns, the use of alternate gases rather than nitrogen, the use of aIternate lubricating particulates other than graphite, and alternate means of introducing the lubricating particulates into the gas stream. The description also references certain gas flow rates, tubular diameters and operating depths strictly for the intent of providing evidence of application of this invention to a realistic operation. This description, therefore, should not be considered to be exclusive of higher or lower gas rates, larger or smaller tubulars, or shallower or deeper depths, or operations other than fracturing. The invention is inteztded to be applicable to any situation where it is desirable to reduce gas friction pressure losses in tubulars. This invention is intended to describe the practice and method of adding a lubricating particulate to a gas stream for the purpose of friction pressure reduction.
Claims (9)
1. A well stimulation fluid comprising a gas and a solid particulate.
2. A fluid according to claim 1 wherein the particulate is graphite.
3. A fluid according to claim 2 wherein the gas is nitrogen.
4. The use of a solid particulate as a friction reducer in a gas stream.
S. The use according to claim 4 wherein the friction reducer is graphite.
6. The use according to claim 5 wherein the gas stream is a high-rate gas stream.
7. A method of reducing friction in fracturing comprising the step of adding a solid particulate to a gas being injected into a well.
8. The method according to claim 7 wherein the particulate is graphite.
9. A method according to claim 8 wherein the gas is nitrogen.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002531920A CA2531920A1 (en) | 2005-12-29 | 2005-12-29 | Friction pressure reducing agents for gases |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002531920A CA2531920A1 (en) | 2005-12-29 | 2005-12-29 | Friction pressure reducing agents for gases |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2531920A1 true CA2531920A1 (en) | 2007-06-29 |
Family
ID=38227643
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002531920A Abandoned CA2531920A1 (en) | 2005-12-29 | 2005-12-29 | Friction pressure reducing agents for gases |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2531920A1 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7875574B2 (en) | 2006-02-17 | 2011-01-25 | Canyon Technical Services, Ltd. | Method of treating a formation using deformable proppants |
-
2005
- 2005-12-29 CA CA002531920A patent/CA2531920A1/en not_active Abandoned
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7875574B2 (en) | 2006-02-17 | 2011-01-25 | Canyon Technical Services, Ltd. | Method of treating a formation using deformable proppants |
| US8062998B2 (en) | 2006-02-17 | 2011-11-22 | Canyon Technical Services, Ltd. | Method of treating a formation using deformable proppants |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| FZDE | Discontinued |
Effective date: 20130909 |
|
| FZDE | Discontinued |
Effective date: 20130909 |