WO2016154732A1 - Processus de fracturation hydraulique - Google Patents

Processus de fracturation hydraulique Download PDF

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Publication number
WO2016154732A1
WO2016154732A1 PCT/CA2016/000106 CA2016000106W WO2016154732A1 WO 2016154732 A1 WO2016154732 A1 WO 2016154732A1 CA 2016000106 W CA2016000106 W CA 2016000106W WO 2016154732 A1 WO2016154732 A1 WO 2016154732A1
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WO
WIPO (PCT)
Prior art keywords
zone
interface
wellbore
same
treatment fluid
Prior art date
Application number
PCT/CA2016/000106
Other languages
English (en)
Inventor
James Frederick Pyecroft
Peter Chernik
Jurgen Lehmann
David MEEKS
Original Assignee
Nexen Energy Ulc
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Nexen Energy Ulc filed Critical Nexen Energy Ulc
Publication of WO2016154732A1 publication Critical patent/WO2016154732A1/fr

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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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/11—Perforators; Permeators
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/11—Perforators; Permeators
    • E21B43/116—Gun or shaped-charge perforators
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14—Obtaining from a multiple-zone well
    • 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
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells

Definitions

  • the present disclosure relates to processes for hydraulic fracturing of wellbores to stimulate hydrocarbon production.
  • a wellbore In order to produce hydrocarbons from within a subterranean formation, a wellbore is drilled, penetrating the subterranean formation. This provides a partial flow path for hydrocarbon, received by the wellbore, to be conducted to the surface. In order to be received by the wellbore at a sufficiently desirable rate, there must exist a sufficiently unimpeded flow path from the hydrocarbon-bearing formation to the wellbore through which the hydrocarbon may be conducted to the wellbore.
  • hydraulic fracturing fluid is injected through wellbore into the subterranean formation at sufficient rates and pressures for the purpose of hydrocarbon production stimulation.
  • the fracturing fluid injection rate exceeds the filtration rate into the formation producing increasing hydraulic pressure at the sand face.
  • the pressure exceeds a critical value, the formation rock cracks and fractures.
  • proppant may be flowed downhole within the wellbore and deposited in the fracture to prevent the fracture from closing once the fluid injection is suspended, thereby helping to preserve the integrity of the flow path.
  • multistage horizontal well fracturing multiple treatment intervals or zones of the subterranean formation are fractured independently.
  • other zones are typically isolated from the zone being fractured using mechanical diversion means, such as packers, bridge plugs, multi-stage ball and baffles, or ball sealers, to prevent the injected hydraulic fracturing fluid from entering zones other than the desired zone.
  • mechanical diversion means such as packers, bridge plugs, multi-stage ball and baffles, or ball sealers
  • a process of stimulating a subterranean formation via a wellbore fluid passage of a wellbore comprising; injecting treatment fluid, via the wellbore fluid passage, from a treatment fluid source to a first zone within the subterranean formation such that fracturing of the first zone is effected; effecting fluid communication, via the wellbore fluid passage, between a second zone within the subterranean formation and the treatment fluid source; while both of the first zone and the second zone are disposed in fluid communication, via the wellbore fluid passage, with the treatment fluid source, injecting treatment fluid from the treatment fluid source and into the wellbore fluid passage with effect that at least a fraction of the injected treatment fluid is directed to the second zone such that fracturing of the second zone is effected.
  • a process of stimulating a subterranean formation via a wellbore fluid passage of a cased wellbore comprising; with a perforating gun, perforating at least casing to form at least one or more perforations effecting fluid communication, via the wellbore fluid passage, between a first zone of the subterranean formation and a treatment fluid source; injecting treatment fluid, via the wellbore fluid passage, from the treatment fluid source to the first zone such that fracturing of the first zone is effected; suspending the injecting of the treatment fluid; deploying a perforating gun within the wellbore fluid passage; perforating at least casing to form at least one or more perforations effecting fluid communication, via the wellbore fluid passage, between a second zone of the subterranean formation and the treatment fluid source; while both of the first zone and the second zone are disposed in fluid communication, via the wellbore fluid passage, with the treatment fluid source, injecting treatment fluid from the treatment fluid source and
  • a process of stimulating a subterranean formation including a pre-existing cased wellbore having a fluid passage that is disposed in fluid communication with uphole and downhole zones within the subterranean formation, wherein, for each one of the zones, one or more openings or ports extend through the casing for effecting fluid communication with the zone, the process comprising: sealing, or substantially sealing fluid communication, via the wellbore fluid passage, between a source of treatment fluid and the downhole zone; after the fluid communication, via the wellbore fluid passage, between the source of treatment fluid and the downhole zone is sealed or substantially sealed, injecting treatment fluid, via the wellbore fluid passage, from the source to the uphole zone; suspending the injection of the treatment fluid; unsealing fluid communication between the source and the downhole zone; and after the unsealing of the fluid communication, and while both of the uphole and downhole zones are disposed in fluid communication with the source via the wellbore fluid passage, injecting treatment fluid from the source and into the wellbore fluid
  • Figure 1 is a schematic illustration of a subterranean formation within which a cased wellbore is disposed for effecting an embodiment of a process of the present disclosure
  • Figure 2 is a schematic illustration of the subterranean formation of Figure 1 , with the cased wellbore having been perforated for effecting stimulation of a first zone;
  • Figure 3 is a schematic illustration of the subterranean formation of Figure 1 , with the first zone having been fractured via the perforation illustrated in Figure 2;
  • Figure 4 is a schematic illustration of the subterranean formation of Figure 1 , with the cased wellbore having been perforated, uphole of the first zone, for effecting stimulation of a first zone, after fracturing of the first zone;
  • Figure 5 is a schematic illustration of the subterranean formation of Figure 1 , with the second zone having been fractured via the perforation illustrated in Figure 4;
  • Figure 6 is a schematic illustration of a subterranean formation within which a cased wellbore is disposed for effecting another embodiment of a process of the present disclosure
  • Figure 7 is a schematic illustration of a subterranean formation within which a cased wellbore is disposed, with a first zone of the subterranean formation receiving injection of treatment fluid through the cased wellbore, while the second zone is isolated with a mechanical diverter.
  • Figure 8 is a schematic illustration of the system illustrated in Figure 7, with the injection of treatment fluid having been suspended, and with the mechanical diverter, effecting the isolation of the second zone from the first zone, being removed;
  • Figure 9 is a schematic illustration of the system illustrated in Figure 7, with a second zone of the subterranean formation receiving injection of treatment fluid through the cased wellbore, after the second zone has been isolated from a downhole zone by a mechanical diverter, and while the first zone still remains disposed in fluid communication with the wellbore.
  • Figure 1 illustrates an exemplary wellbore installation.
  • a wellbore 10 penetrates a surface 80 of, and extends through, a subterranean formation 12.
  • the subterranean formation 12 may be onshore or offshore.
  • the subterranean formation 12 includes a plurality of zones, such as zones 14, 16.
  • the distance across which a zone may span is determined by the anticipated effectiveness of a frac (or stimulation) within such zone. Amongst other things, this is dictated by the injection rate that is available from the pump.
  • the wellbore 10 can be straight, curved, or branched.
  • the wellbore can have various wellbore portions.
  • a wellbore portion is an axial length of a wellbore.
  • a wellbore portion can be characterized as “vertical” or “horizontal” even though the actual axial orientation can vary from true vertical or true horizontal, and even though the axial path can tend to "corkscrew” or otherwise vary.
  • the wellbore 10 may be cased, such as with casing 20 that is disposed within the wellbore 10.
  • the casing 20 includes a wellbore fluid passage 23 configured to conduct fluids to and from the zones 14, 16 of the subterranean formation 12, as is explained below.
  • the casing 20 is cemented to formation 12 with cement 22 disposed within the annular region between the casing 20 and the formation 12.
  • a wellhead 50 is coupled to and substantially encloses the wellbore 10 at the surface 2.
  • the wellhead 50 includes conduits and valves to direct and control the flow of fluids to and from the wellbore 10.
  • treatment fluid is injected into the wellbore 10 from the source 40 of treatment fluid, and is conducted through the fluid passage 23 defined within the casing 20.
  • the conducted treatment fluid is directed into the formation 12 through ports or openings 24 that penetrate through the casing 20 (and, in some embodiments, for example, the cement 22) and into the formation, thereby effecting fluid communication between the fluid passage 23 and the formation 12.
  • the treatment fluid includes hydraulic fracturing fluid.
  • Suitable hydraulic fracturing fluid includes water, water with various additives for friction reduction and viscosity such as polyacrylamide, guar, derivitized guar, xyanthan, and crosslinked polymers using various crosslinking agents, such as borate, metal salts of titanium, antimony, alumina, for viscosity improvements, as well as various hydrocarbon both volatile and non-volatile, such as lease crude, diesel, liquid propane, ethane and compressed natural gas, and natural gas liquids.
  • various compressed gases such as nitrogen and/or C0 2
  • the treatment fluid may also include proppant.
  • the process includes effecting fluid communication, via the wellbore fluid passage 23, between the first zone 12 and a source 40 of treatment fluid (see Figure 2).
  • treatment fluid is injected, via the wellbore fluid passage 23, from the source 40 to the first zone 14 within the subterranean formation 12 such that fracturing of the first zone 14 is effected (see Figure 3), resulting in the formation of fractures 32.
  • the injecting of the treatment fluid is then suspended.
  • fluid communication, via the wellbore fluid passage 23, between the second zone 16 and the source 40 is effected (see Figure 4). While both of the first zone 14 and the second zone 16 are disposed in fluid communication, via the wellbore fluid passage 23, with the source 40, treatment fluid is injected from the source 40 and into the wellbore fluid passage 23 with effect that at least a fraction of the injected treatment fluid is injected into the second zone 16 such that fracturing of the second zone 16 is effected (see Figure 5), resulting in the formation of fractures 34.
  • the pressure of the treatment fluid being injected to the second zone 16 exceeds the fracture initiation pressure of the second zone 16.
  • the first zone 14 is not mechanically isolated from the wellbore fluid passage 23 while treatment fluid is being injected to the second zone 16 via the wellbore fluid passage 23.
  • the cost, time and risk associated with setting and drilling plugs may be mitigated or eliminated.
  • production may be improved by eliminating the damage associated drill out fluid and drill cuttings losses associated with removing drillable bridge plugs.
  • eliminating drill outs may also reduce near wellbore damage to conductivity.
  • avoiding the drilling out of bridge plugs may improve productivity, as the drilling out of bridge plugs involves the injection of fluid with additives which could otherwise compromise productivity.
  • avoiding the drilling out of bridge plugs would also eliminate the introduction of drill cuttings into the wellbore, which may otherwise cause the plugging of perforations in the casing.
  • laterals may be completed.
  • completion issues resulting from casing deformation, may be avoided.
  • an additional monitoring tool may be provided in terms of observing frac hits from offset wells.
  • the well may enjoy a larger inside diameters, thereby mitigating restriction to post completion interventions such as production logging and scale cleanouts.
  • the avoidance of bridge plugs shortens cycle times between completion and production.
  • the effecting fluid communication (as between one or both of: (a) the first zone 14 and the source 40, and (b) the second zone 16 and the source 40) includes effecting creation of one or more ports or openings 24 through the casing 20.
  • the ports or openings 24 are created by perforating through the casing 20 to form perforations 24A, 24B.
  • the perforating is effected by a perforating gun.
  • the perforating gun is deployed downhole via wireline, such as by, for example, being pumped downhole with fluid flow.
  • the perforating gun is not capable of being deployed downhole of the first zone, as the fluid flow which is carrying the perforating gun becomes is conducted into the first zone through the previously created ports or openings 24 (such as, for example, perforations), and is unavailable to assist in deploying the perforating gun further downhole relative to the first zone 14 such that the next zone (i.e. second zone 16) to be treated is one that is uphole relative to the first zone 14.
  • the perforating gun is deployed downhole via coiled tubing. In some embodiments, for example, the perforating gun is deployed using a tractor.
  • the lithology of both the first and second zones 14, 16 is the same or substantially the same.
  • a first interface 92 is disposed between the first zone 14 and the wellbore 10
  • a second interface 94 is disposed between the second zone 16 and the wellbore 10
  • the lithology of the first zone 14 at the first interface 92 is the same, or substantially the same, as the lithology of the second zone 16 at the second interface 94.
  • the identifiable stratigraphy of both the first and second zones 14, 16 is the same or substantially the same.
  • a first interface 92 is disposed between the first zone 14 and the wellbore 10
  • a second interface 94 is disposed between the second zone 16 and the wellbore 10
  • the identifiable stratigraphy of the first zone 14 at the first interface 92 is the same, or substantially the same, as the identifiable stratigraphy of the second zone 16 at the second interface 94.
  • the stress magnitude of both the first and second zones 14, 16 is the same or substantially the same.
  • a first interface 92 is disposed between the first zone 14 and the wellbore 10
  • a second interface 94 is disposed between the second zone 16 and the wellbore 10
  • the stress magnitude of the first zone 14 at the first interface 92 is the same, or substantially the same, as the stress magnitude of the second zone 16 at the second interface 94.
  • the first and second zones 14, 16 are disposed at the same or substantially the same depth.
  • the depth of the first interface 92 is within a maximum distance of less than 50 metres (such as, for example, less than 20 metres, such as, for example, less than five (5) metres) of the depth of the second interface 94.
  • the minimum distance between the first and second zones 14, 16 is at least five (5) metres (such as, for example at least 25 metres).
  • the minimum distance between the set of one or more first zone ports or openings 24 and the set of one or more second zone ports or openings 24 is at least five (5) metres (such as, for example, at least 25 metres).
  • the first and second zones 14, 16, respectively are disposed within a shale formation.
  • the injection of treatment fluid to the second zone 16 is induced at least by both of: (i) stress that is induced within the formation by the injecting of the treatment fluid to the first zone 14, and (ii) stress effected by water imbibition into the one or more fractures effected within the first zone 14.
  • the well is flowed back such that production of hydrocarbons from the subterranean formation 12 may be initiated.
  • Figure 6 illustrates another exemplary wellbore installation within a subterranean formation 12 includes a plurality of zones, such as zones 1 14, 1 16, 1 18, in which, in another aspect, another process is provided for stimulating the plurality of zones within the subterranean formation 12 by supplying treatment fluid to the zones via a wellbore fluid passage (such as, for example, fluid passage 23) of the cased wellbore 10.
  • a wellbore fluid passage such as, for example, fluid passage 23
  • the zones may be ones which have not been previously stimulated, such that the opening or ports 126 are newly created.
  • one or more of the zones may have been previously treated such that the process is, in effect, a re-stimulation or a "refrac".
  • a re-stimulation or a "refrac” prior to the stimulation by supplying treatment fluid to the zones, for each one of the zones to be stimulated, corresponding openings or ports 126, for effecting fluid communication between the wellbore fluid passage 24 and the zone, are already provided.
  • a process is provided for implementation within a subterranean formation 12 including a pre-existing cased wellbore 10 having a fluid passage that is disposed in fluid communication with a plurality of zones (such as, for example, in the illustrated embodiments, zones 1 14, 1 16, and 1 18, within the subterranean formation 12).
  • zones 1 14, 1 16, and 1 18, within the subterranean formation 12.
  • one or more openings or ports 126 extend through the casing 20 for effecting fluid communication with the zone.
  • Sealing, or substantial sealing, of fluid communication, via the wellbore fluid passage 23, between a source 40 of treatment fluid and the second zone 1 16 is effected.
  • the second zone 1 16 is a downhole zone disposed downhole relative to the first zone 1 14.
  • the sealing, or substantial sealing, of fluid communication is effected by a mechanical diverter, such as a ball 128.
  • the sealing or substantial sealing is necessary in order to effectively inject sufficient treatment fluid to an uphole zone, such as the zone 114.
  • treatment fluid is then injected via the wellbore fluid passage 23 to the first zone 1 14 such that fracturing of the first zone 1 14 is effected. Injecting of the treatment fluid is then suspended, and the sealing, or substantial sealing, of fluid communication, via the wellbore passage 23, between the second zone 1 16 and the source 40, becomes unsealed (see Figure 8) such that the second zone 1 16 is disposed in fluid communication with the source 40 via the wellbore fluid passage 23.
  • the unsealing of fluid communication is effected by flowing the ball 128A back to the surface 80.
  • the ball 128A is disintegratable under wellbore conditions such that, after a time interval, the ball 128A disintegrates such that the unsealing of fluid communication is thereby effected.
  • sealing, or substantial sealing, of fluid communication Prior to injecting of the treatment fluid into the wellbore 10, for effecting treatment of the second zone 1 16, sealing, or substantial sealing, of fluid communication, via the wellbore fluid passage 23, between a source 40 of treatment fluid and a zone downhole of the second zone (such as, for example, a third zone 1 18) is effected (see Figure 9).
  • the sealing, or substantial sealing, of fluid communication is effected by a mechanical diverter, such as a ball 128B (which may be characterized by a smaller diameter than ball 128A).
  • the sealing or substantial sealing is necessary in order to effectively inject sufficient treatment fluid to the zone 1 16.
  • treatment fluid is injected into the wellbore fluid passage 23 with effect that at least a fraction of the injected treatment fluid is directed to the second zone 1 16 such that fracturing of the second zone 1 16 is effected.
  • the process may be repeated for the zone 1 18, as well as, sequentially, for any number of zones disposed downhole of the second zone 1 16.
  • the process may be implemented for horizontal sections of deviated wellbores for stimulating a formation 12 from heel to toe.
  • the lithology of the first zone 1 14 is the same, or substantially the same, as the lithology of the second zone 1 16, and is also the same, or substantially the same, as the lithology of the third zone 1 18.
  • a first interface 192 is disposed between the first zone 14 and the wellbore 10
  • a second interface 194 is disposed between the second zone 16 and the wellbore 10
  • a third interface 196 is disposed between the third zone 1 18 and the wellbore 10
  • the lithology of the first zone 1 14 at the first interface 192 is the same, or substantially the same, as the lithology of the second zone 116 at the second interface 194, and is also the same, or substantially the same, as the lithology of the third zone 1 18 at the third interface 196.
  • the identifiable stratigraphy of the first zone is identifiable stratigraphy of the first zone
  • a first interface 192 is disposed between the first zone 14 and the wellbore 10
  • a second interface 194 is disposed between the second zone 16 and the wellbore 10
  • a third interface 196 is disposed between the third zone 1 18 and the wellbore 10
  • the identifiable stratigraphy of the first zone 1 14 at the first interface 192 is the same, or substantially the same, as the identifiable stratigraphy of the second zone 116 at the second interface 194, and is also the same, or substantially the same, as the identifiable stratigraphy of the third zone 1 18 at the third interface 196.
  • the stress magnitude of the first zone 1 14 is the same, or substantially the same, as the stress magnitude of the second zone 1 16, and is also the same, or substantially the same, as the stress magnitude of the third zone 1 18.
  • a first interface 192 is disposed between the first zone 14 and the wellbore 10
  • a second interface 194 is disposed between the second zone 16 and the wellbore 10
  • a third interface 196 is disposed between the third zone 1 18 and the wellbore 10
  • the stress magnitude of the first zone 114 at the first interface 192 is the same, or substantially the same, as the stress magnitude of the second zone 1 16 at the second interface 194, and is also the same, or substantially the same, as the stress magnitude of the third zone 1 18 at the third interface 196.
  • the depth of the first interface 192, the depth of the second interface 194, and the depth of the third interface 196 are within a maximum distance of less than 50 metres (such as, for example, less than 20 metres, such as, for example, less than five (5) metres) of each other.
  • the minimum distance between the first and second zones 1 14, 1 16 is at least five (5) metres (such as, for example at least 25 metres).
  • the minimum distance between the set of one or more first zone ports or openings 24 and the set of one or more second zone ports or openings 24 is at least five (5) metres (such as, for example, at least 25 metres).
  • the minimum distance between the second and third zones 1 16, 1 18 is at least five (5) metres (such as, for example at least 25 metres).
  • the minimum distance between the set of one or more second zone ports or openings 24 and the set of one or more third zone ports or openings 24 is at least five (5) metres (such as, for example, at least 25 metres).
  • each one of the first, second and third zones 1 14, 1 16, 1 18 is disposed within a shale formation.
  • the injection of treatment fluid to the second zone 1 16 is induced at least by both of: (i) stress that is induced within the formation by the injecting of the treatment fluid to the first zone 1 14, and (ii) stress effected by water imbibition into the one or more fractures effected within the first zone 1 14.

Abstract

L'invention concerne un processus de stimulation d'une formation souterraine par un passage de fluide de puits de forage d'un puits de forage tubé. Le procédé consiste à perforer, avec un perforateur, au moins le tubage pour former au moins une ou plusieurs perforations réalisant une communication fluidique, par le passage de fluide, entre une première zone de la formation souterraine et une source de fluide de traitement. Du fluide de traitement est alors injecté par le passage de fluide, à partir de la source de fluide de traitement jusqu'à la première zone de façon à causer la fracturation de la première zone. L'injection du fluide de traitement est ensuite interrompue provisoirement. Un perforateur est alors déployé dans le passage de fluide de puits de forage par un câble de forage. Le tubage est ensuite perforé pour former une ou plusieurs perforations réalisant une communication fluidique, par le passage de fluide de puits de forage, entre une deuxième zone de la formation souterraine et la source de fluide de traitement. Pendant que la première zone et la deuxième zone sont toutes deux mises en communication fluidique, par le passage de fluide de puits de forage, avec la source de fluide de traitement, injecter du fluide de traitement à partir de la source de fluide de traitement et dans le passage de fluide de puits de forage pour engendrer l'envoi d'au moins une fraction du fluide de traitement injecté dans la deuxième zone de façon à causer la fracturation de la deuxième zone.
PCT/CA2016/000106 2015-04-02 2016-04-04 Processus de fracturation hydraulique WO2016154732A1 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
CA2887292A CA2887292A1 (fr) 2015-04-02 2015-04-02 Procedes de fracturation hydraulique
US14/677,298 US20160290112A1 (en) 2015-04-02 2015-04-02 Processes for hydraulic fracturing
CA2,887,292 2015-04-02
US14/677,298 2015-04-02

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WO2016154732A1 true WO2016154732A1 (fr) 2016-10-06

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CN113803016A (zh) * 2020-06-12 2021-12-17 中国石油化工股份有限公司 固井分段改造管柱和方法

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US6776238B2 (en) * 2002-04-09 2004-08-17 Halliburton Energy Services, Inc. Single trip method for selectively fracture packing multiple formations traversed by a wellbore
US7278486B2 (en) * 2005-03-04 2007-10-09 Halliburton Energy Services, Inc. Fracturing method providing simultaneous flow back
US20130228337A1 (en) * 2012-03-01 2013-09-05 Shell Oil Company Fluid injection in light tight oil reservoirs
WO2014053043A1 (fr) * 2012-10-04 2014-04-10 Nexen Energy Ulc Procédé amélioré de fracturation hydraulique pour forages déviés

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US20160290112A1 (en) 2016-10-06

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