EP2251524A1 - Bohrlochbehandlung - Google Patents

Bohrlochbehandlung Download PDF

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Publication number
EP2251524A1
EP2251524A1 EP09251306A EP09251306A EP2251524A1 EP 2251524 A1 EP2251524 A1 EP 2251524A1 EP 09251306 A EP09251306 A EP 09251306A EP 09251306 A EP09251306 A EP 09251306A EP 2251524 A1 EP2251524 A1 EP 2251524A1
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EP
European Patent Office
Prior art keywords
wellbore
pressure
zone
formation
displacement fluid
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.)
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Application number
EP09251306A
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English (en)
French (fr)
Inventor
Mark Shelton Aston
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
BP Exploration Operating Co Ltd
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BP Exploration Operating Co Ltd
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 BP Exploration Operating Co Ltd filed Critical BP Exploration Operating Co Ltd
Priority to EP09251306A priority Critical patent/EP2251524A1/de
Publication of EP2251524A1 publication Critical patent/EP2251524A1/de
Withdrawn legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
    • E21B33/138—Plastering the borehole wall; Injecting into the formation
    • 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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/003—Means for stopping loss of drilling fluid

Definitions

  • the present invention relates to strengthening the wall of a wellbore, and more particularly to a method of increasing the resistance of the wellbore wall to fracturing.
  • drilling of a well into the earth by rotary drilling techniques involves the circulation of a drilling fluid from the surface of the earth down a drill string having a drill bit on the lower end thereof and through ports provided in the drill bit to the well bottom and thence back to the surface through the annulus formed about the drill string.
  • drilling fluids are employed that are either oil or water based. These fluids are treated to provide desired rheological properties which make the fluids particularly useful in the drilling of wells.
  • a problem often encountered in the drilling of a well is the loss of unacceptably large amounts of drilling fluid into subterranean formations penetrated by the well. This problem is often referred to generally as “lost circulation”, and the formations into which the drilling fluid is lost are often referred to as “lost circulation zones” or “thief zones”.
  • Various causes may be responsible for the lost circulation encountered in the drilling of a well. For example, a formation penetrated by the well may exhibit unusually high permeability or may contain fractures or crevices therein. In addition, a formation may simply not be sufficiently competent to support the pressure applied by the drilling fluid and may break down under this pressure and allow the drilling fluid to flow thereinto.
  • mud weight density of the drilling fluid
  • encroachment of formation fluids can occur, borehole collapse may occur due to insufficient support from the fluid pressure in the wellbore, and in extreme cases safety can be compromised due to the possibility of a well blowout.
  • International patent publication number WO 2005/012687 relates to controlling formation breakdown during drilling by using an ultra-low fluid loss mud with the pressure of the drilling mud maintained at above the initial fracture pressure of the formation wherein the fractures that are induced in the wellbore wall are bridged at or near the mouth thereof by a solid particulate material that is added to the drilling mud and the bridge is sealed by the accumulation of fluid loss additives in the voids between the bridging particles and/or the precipitation of fluid loss additives onto the bridging particles.
  • the presence of the fluid impermeable bridge at or near the mouth of the fracture strengthens the near wellbore region of the formation by generating a stress cage. Thereafter, the drilling of the wellbore is continued with the pressure of the drilling mud maintained at below the breakdown pressure of the strengthened formation.
  • bridging particles to prop open and seal fractures has been successful in permeable formations such as sandstone formations, it has now been found that the effect can be temporary in certain formations, such as shale formations. Without wishing to be bound by any theory, it is believed that the induced fractures in shale formations may not open sufficiently when pressure is applied to allow the solid particulate material to enter and become trapped within the fractures. In addition, owing to the impermeable nature of shale formations, fluid does not leak off from the fractures into the formation once a bridge has been formed at the mouths of the fractures.
  • the pressure within the fractures is substantially the same as the pressure that is being applied to the bridging particles at the fracture mouth such that the bridging particles are readily removed from the mouths of the fractures as a result of small pressure changes in the wellbore.
  • a settable fluid such as a resin, gel or cement composition is used in an attempt to retain the bridging particulate solids in place within the fractures of the wellbore, the bridging particulate solids may still not penetrate into the fracture and would also impede the flow of the settable fluid into the fractures.
  • a settable fluid such as a resin, cement or crosslinkable polymeric gel composition may be squeezed into the fractures that are induced in the wall of the wellbore, in the absence of particulate bridging solids. It has also been found that by using a composition that has a prolonged setting time, the width of the induced fractures may be increased during setting of the composition such that further settable composition may be squeezed into the fractures thereby increasing the hoop stress in the near wellbore region of the wellbore.
  • the hoop stress may be increased by performing a hesitation squeeze, in which the pressure in the wellbore is increased stepwise during the setting period for the composition thereby widening the fracture and ensuring the fracture is ultimately filled and sealed by the set composition.
  • a method of strengthening a wellbore wall in a zone of a wellbore that penetrates through a formation that is susceptible to formation breakdown comprising:
  • fracture pressure is meant the minimum fluid pressure in the zone of the wellbore at which a fracture is created in the wellbore wall.
  • squeeze pressure The pressure that is applied in the zone of the wellbore when the settable composition is flowing into the fractures.
  • weak formation The formation that is susceptible to formation breakdown is referred to herein as "weak formation”.
  • a spacer fluid may be pumped into the wellbore before the displacement fluid.
  • the spacer fluid may be a solids free fluid (for example, base oil or water) while the displacement fluid may be a drilling fluid.
  • the space fluid may be viscosified (thickened) to prevent fingering of the settable composition through the spacer fluid.
  • the settable composition is initially a pumpable fluid, that may be delivered to the wellbore zone by being pumped down the wellbore from the surface.
  • the settable fluid has an initial viscosity (prior to being delivered to the zone of the wellbore) in the range of 1 to 1000 centipoise (cP).
  • the setting time of the settable composition is at least 1 hour, preferably, at least 2 hours, for example, at least 5 hours.
  • the setting period for the settable composition is in the range of 1 to 20 hours.
  • the rate of increase in viscosity of the settable composition over the setting period may be linear or non-linear.
  • the viscosity against time profile follows a curve with the rate of increase in viscosity increasing over the setting period. Accordingly, the period of time during which pumping is interrupted may be reduced in later stages of the hestitation squeeze process.
  • the pumping may be interrupted for less than 5 minutes, for example, 1 to 2 minutes while towards the beginning of the setting period the pumping may be interrupted for up to 1 hour, for example, 15 to 30 minutes.
  • the squeeze pressure may be increased by between 25-500 psi, preferably, 50 to 250 psi, in particular, 50 to 100 psi for each successive pumping stage of the hesitation squeeze treatment.
  • step (b) of the present invention once fractures have started to form in the wellbore wall in the zone of the wellbore that penetrates through a formation that is susceptible to formation breakdown (hereinafter "weak formation"), there will be a deviation in the downhole pressure (or pumped volume) against time curve. Thus, there is a decrease in the downhole pressure in the zone of the wellbore where the wellbore wall is to be strengthened. After this deviation has been observed, pumping is continued to allow the settable fluid to enter the fracture(s) until the downhole pressure is substantially constant. This is referred to as the fracture propagating pressure. Typically, 0.01 to 1 barrels, preferably 0.1 to 1 barrels of the settable composition enters the fractures.
  • Pumping is then interrupted (stopped) for a sufficient period of time for there to be a significant increase in viscosity of the settable composition.
  • pumping is initially interrupted for at least 15 minutes, preferably, at least 0.5 hour, for example, 0.5 to 1 hour.
  • the settable composition may flow back out of the fracture into the wellbore as the fracture closes.
  • Pumping of the displacement fluid is then resumed until the pressure in the zone in the wellbore remains substantially constant at a higher fracture propagating pressure as determined by the downhole pressure (or pumped volume) against time curve.
  • the amount of settable composition that enters the fractures is typically 0.01 to 1 barrels, preferably 0.1 to 1 barrels.
  • This sequence of pumping and interrupting pumping is repeated one or more times until the settable composition has increased in viscosity (thickened) to such as extent that a desired target wellbore pressure can be applied to the open fractures without propagation of the fractures.
  • target wellbore pressure is meant the increased pressure of step (f).
  • This desired target wellbore pressure is then maintained until the settable composition has completely set in the zone of the wellbore (within the fractures and within the wellbore).
  • the displacement fluid is pumped into the wellbore during the pumping steps of the hesitation squeeze process of the present invention at a rate of 0.25 to 0.5 bbls/minute.
  • the stepwise increase in pressure at each successive stage of the hesitation squeeze process results in a stepwise increase in the width of the fractures that are induced in the wellbore wall.
  • the increase in the fracture width results in additional settable composition being squeezed into the fractures before the fluid has completely set in the wellbore. Accordingly, the fractures become filled with a set composition which maintains the rock displacement caused by the fractures.
  • the rock displacement caused by the fracture places the rock in the near wellbore region of the formation (for example, within a radial distance of up to 1 metre from the wellbore wall) in a state of compression, thereby increasing the "hoop stress" and generating a "stress cage".
  • hoop stress is meant the increased compressive stress in the near wellbore region of the weak formation that arises from the induced fractures being propped open by the set composition.
  • This increased compressive stress in the near wellbore region of the weak formation results in the wall of the wellbore having a greater resistance to further fracturing.
  • the method of the present invention therefore allows a drilling mud of higher density to be employed in drilling a further section of the wellbore than could be used in the absence of strengthening of the weak formation.
  • the method also has a further beneficial effect of reducing loss of fluid from the drilling mud into the formation owing to the sealing of the fractures with the fluid impermeable settable composition.
  • An advantage of the present invention is that by accurately monitoring the pressure in the zone of the wellbore that penetrates the weak formation (or by accurately monitoring the surface pumping pressure), the amount of settable composition that enters the fractures can be controlled so as to limit fracture propagation.
  • pumping of displacement fluid is either stopped or the amount of displacement fluid that is pumped into the wellbore is substantially reduced once the pressure in the wellbore is at or above the fracture propagation pressure for each stage of the hesitation squeeze treatment. Interruption of pumping reduces the propagation of the fractures and allows the viscosity of the settable composition to increase. This increase in viscosity of the settable composition results in an increase in the fracture propagating pressure.
  • a further advantage of the present invention is that the prolonged setting time of the settable composition avoids premature setting of the settable fluid in the wellbore before sufficient fracture width has developed to achieve the desired increase in "hoop stress".
  • the fracture width increases with each successive stage of the hestitation squeeze process of the present invention owing to: (a) the progressive increase in viscosity of the settable composition that enters the fractures, and/or (b) the progressively higher squeeze pressure that is applied to the formation.
  • the settable composition is designed to sustain sufficient applied pressure across the fracture width as the settable fluid sets in the fracture.
  • the mouth of a fracture that is induced in the wall of the wellbore will have a diameter (fracture width) substantially less than that of the wellbore, for example, in the range 0.1 to 5 mm, in particular, 1 to 2 mm. Accordingly, when the viscosity of the settable composition has increased to such an extent that it is no longer capable of flowing into the fractures, the composition remains flowable within the wider diameter wellbore.
  • the settable composition is therefore capable of transmitting an applied pressure to the mouth of the fractures as the composition sets within the fractures.
  • the wellbore wall is therefore strengthened owing to an increase in the hoop stress in the near wellbore region of the formation arising from the fractures being propped open by the set composition.
  • the width of the fractures that are filled with the set composition and hence the increase in the hoop stress in the near wellbore region of the formation is dependent upon, amongst other factors, the strength (stiffness) of the formation rock, and the squeeze pressure that is achieved in the final stage of the hesitation squeeze.
  • a negative feedback control system is especially useful in the final stages of the hesitation squeeze process when the viscosity of the settable fluid may be rapidly increasing within the zone of the wellbore.
  • pumping of the displacement fluid is continued as long as the pressure that is being monitored at the wellhead or at the surface continues to rise. Once the pressure is substantially constant, pumping is interrupted. It is envisaged that the pressure may be continuously monitored or may be intermittently monitored, for example, every 1 to 2 minutes. Where there is intermittent monitoring of the pressure, pumping is preferably interrupted when successive pressure readings, for example, two or three successive pressure readings, are the same.
  • pumping is preferably interrupted when the pressure is substantially constant for a period of 1 to 2 minutes. Pumping may then be restarted after a predetermined time period. As discussed above, this time period may decrease during the setting period of the composition. If the pressure measured at the wellhead or at the surface does not increase (after recommencing pumping of the displacement fluid), pumping is again interrupted for a period of time during which there is a further increase in the viscosity of the settable fluid.
  • a pill of settable composition (a controlled amount of the settable composition) is injected into the wellbore wherein the amount of the pill is at least sufficient to fill the zone of the wellbore that is to be strengthened and to fill the fractures that are induced in the wellbore wall in the zone of the wellbore that penetrates the weak formation.
  • a displacement fluid is then injected into the wellbore behind the pill of settable composition.
  • the amount of settable composition that is injected into the wellbore is minimized such that displacement fluid is present in the wellbore above the zone of the wellbore that penetrates the weak formation.
  • the displacement fluid is a non-settable fluid, for example, an aqueous fluid or an organic fluid, for example, a drilling fluid.
  • the settable composition may contain a particulate material provided that the average particle size of the particulate material is less than 100 microns, preferably, less than 50 microns.
  • the use of a particulate material of limited particle size mitigates the risk that the particulate material may bridge the fractures at or near the mouths thereof as this may prevent the settable composition from flowing into the fractures.
  • the particulate material that may be optionally included in the settable composition as a filler includes graphite, calcium carbonate (preferably, marble), dolomite (MgCO 3 .CaCO 3 ), celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof. These materials are very inert and are environmentally acceptable.
  • the concentration of particulate material in the settable composition is in the range of 0 to 200 pounds per barrel, preferably, 1 to 100 pounds per barrel.
  • the settable composition for use in the method of the present invention is selected from the group consisting of (a) cement compositions, (b) thermosetting resin compositions selected from epoxy resin compositions, furan resin compositions, and polyester resin compositions, and (c) cross-linkable polymeric compositions.
  • the cement composition may be any slurry of a cement in a carrier fluid, preferably, an aqueous carrier fluid, wherein the average particle size of the cement is less than 100 microns, such as 0.1-50 microns, preferably 0.5-10 microns, especially 1-5 microns.
  • the cement is a Portland cement, and may be made by methods well known to the person skilled in the art.
  • the cement composition may contain 10-80% cement, in particular 20-70% cement.
  • the cement composition for use in the present invention is designed to have a gradual set time under the conditions of temperature and pressure prevailing in the zone of the wellbore that spans the weak formation that is to be consolidated. Accordingly, the viscosity of the cement composition increases gradually in a controlled manner as it sets. In particular, the cement should not have a so-called "right-angle" set, which makes it distinctive from commonly used oil field cement compositions.
  • the setting time for the cement and the rate at which the viscosity of the cement composition increases during the setting period may be controlled by using additives such as accelerators or retarders that are added to the aqueous carrier fluid.
  • Suitable setting accelerators include calcium chloride, for example, in an amount of 0.1-10% by weight based on the weight of the aqueous medium.
  • Suitable setting retarders include sugars such as sucrose.
  • the setting time and the viscosity rate increase of the cement composition may be controlled by using extenders that are added to the cement composition.
  • Suitable extenders include clays such as bentonite or soluble silicates such as sodium silicate.
  • the cement composition for use in the present invention should harden, at the temperature encountered in the zone of the wellbore that penetrated the weak formation, over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours. It is within the common general knowledge of the person skilled in the art to select a cement composition having the desired setting characteristics.
  • thermosetting resin composition for use in the present invention may be a thermosetting epoxy resin, furan resin or polyester resin composition.
  • a curing agent (catalyst) is added to the thermosetting resin composition.
  • the thermosetting resin composition hardens over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours, at the temperature prevailing in the zone of the wellbore that penetrates the weak formation. It is within the common general knowledge of the skilled person to select a thermosetting resin composition having the desired setting characteristics.
  • the settable polymeric composition for use in the present invention may comprise an aqueous or organic liquid, a crosslinkable polymer, a crosslinking agent and optionally a gelation delaying agent.
  • the crosslinkable polymers suitable for use in this invention include but are not limited to biopolysaccharides, cellulose ethers and acrylamide-containing polymers.
  • the polymers contain crosslinkable groups such as carboxylate, phosphonate or hydroxyl groups.
  • the person skilled in the art will understand that the polymer should contain sufficient crosslinkable groups to form a rigid cross-linked polymer.
  • biopolysaccaride, cellulose ether or acrylamide-containing polymer for the crosslinkable polymeric composition that has sufficient crosslinkable groups to form a rigid crosslinked polymer.
  • Further polymers for use in the present invention include graft copolymers prepared by reacting hydrophilic polymers with certain allyl or vinyl monomers having a crosslinkable substituent.
  • graft copolymers of hydrophilic polymers and vinyl phosphonate are disclosed in US 5,701,956 .
  • the crosslinking agent that is included in the settable polymeric composition may comprise any of the well known polyvalent metal compounds which are capable of creating a cross-linked structure with the particular polymer utilized, for example, a metal compound selected from the group consisting of zirconium compounds, titanium compounds, aluminium compounds, iron compounds, chromium compounds, hafnium compounds, niobium compounds and antimony compounds.
  • the polymeric composition may also contain a gelation delaying agent in order to mitigate the risk of the composition setting prematurely before the hesitation squeeze can be completed.
  • a gelation delaying agent is defined herein as a chemical or mixture of chemicals which delays the rate of gelation.
  • a delaying agent useful for the retardation of the rate of gelation may be a carboxylic acid or a salt thereof.
  • a further commonly known gelation delaying agent is an amine that has more than one functional group and contains one or more hydroxyls and that can chelate the polyvalent metal moiety of the polyvalent metal compound
  • the set composition (cement, resin or polymeric composition) has a sufficient compressive strength to withstand the closure stresses exerted on the fracture.
  • the compressive strength of the composition when set, is less than that of the strengthened formation in order to mitigate the risk of accidentally deviating from the original wellbore when drilling out the set composition.
  • the settable composition has a compressive strength (UCS strength) when set which is 10-90% of the compressive strength of the formation, more preferably, 50-80%.
  • the strength of the set composition may be controlled in a number of ways depending on the system.
  • the slurry density is typically used to control the set strength.
  • UCS strengths may typically vary from 500 psi to 10,000 psi for set cements, depending on the slurry design.
  • the compressive strength of the set composition will be dependent on the molecular weight of the polymer, the concentrations of cross-linking agent and of polymer employed in the settable polymeric composition, and on the concentration and type of the optional filler material that may be included in the settable polymeric composition.
  • the compressive strength of the set resin will be dependent on the number of active groups (for example, epoxy or unsaturated groups) of the resin prior to curing of the resin and on the concentration and type of the optional filler material that may be included in the settable resin composition.
  • formation pressure generally increases with increasing depth of the wellbore. It is therefore generally necessary to continuously increase the pressure of a drilling mud during a drilling operation, for example, by increasing the density of the drilling mud. A problem arises when the increased pressure of the drilling mud exceeds the initial fracture pressure of a previously drilled formation ("weak formation").
  • the method of the present invention may therefore be used to strengthen such weak formations thereby allowing the pressure of the drilling mud that is employed for completing the drilling operation to be increased to above the initial fracture pressure of the weak formation.
  • a method of reducing formation breakdown during the drilling of a wellbore through a weak formation with a circulating drilling mud which method comprises:
  • breakdown pressure of the strengthened formation is meant the maximum fluid pressure that can be sustained within the wellbore without creating a fracture in the strengthened formation.
  • the displacement fluid may be a drilling fluid (often referred to as drilling mud). If necessary, for compatibility reasons, a spacer fluid could be placed between the pill of settable composition and the drilling mud.
  • the spacer fluid may be a base oil or water.
  • the settable composition may be introduced into the wellbore as a "pill" and may be passed to the weak formation where it is squeezed in stages into the weak formation as described above so that the composition sets in the open fractures.
  • the pill is squeezed into the weak formation by raising the drill string until it lies immediately above the zone of the wellbore that extends through the weak formation, sealing the annulus between a drill string and the wellbore wall, and pumping the pill into the wellbore via the drill string.
  • a displacement fluid is then pumped into the wellbore until the pressure in the vicinity of the weak formation is greater than the fracture pressure of the formation. If the wellbore extends below the weak formation, it is preferred to seal off the wellbore below the zone that penetrates through the weak formation so as to reduce the amount of the pill of settable composition that is introduced into the wellbore and to prevent the composition from setting in the wellbore below the weak zone i.e. in a zone of the wellbore that does not require strengthening. This reduces the length of the wellbore that needs to be drilled out to remove the set composition prior to recommencing drilling of the wellbore. After strengthening the weak formation, drilling of the wellbore may be continued using a drilling mud with the proviso that the pressure in the wellbore in the vicinity of the strengthened formation is maintained below the breakdown pressure of the strengthened formation.
  • the method of the present invention has been described above, in relation to a vertical well, the method of the present invention may also be applied to deviated wells (inclined or horizontal wells).
  • aqueous cement composition (300 ml) comprising 73% wt/wt of Portland cement was placed in a 500 ml beaker that was fitted with a stirrer paddle.
  • the cement composition was heated at a temperature of 50°C whilst the stirrer paddle was rotated at a rate of 6 revolutions per minute (rpm).
  • the torque of the composition was measured as the cement thickened.
  • Figure 1 shows a "right angled" set for the initial cement composition and a gradual set for the composition that contained the bentonite clay.
  • a polyester resin composition (Norester 854 TM , supplied by Nord Composites, France) had an initial viscosity of 1500 mPa.s at a temperature of 20°C.
  • a methyl ethyl ketone peroxide catalyst (2% Butanox M50 TM ) was added to the resin composition which was then found to set gradually over a period of 400 minutes.
  • the person skilled in the art could readily provide a composition that sets gradually at the higher temperatures prevailing in a wellbore by reducing the concentration of the catalyst.
  • Figure 2 shows the calculated pressure required to initiate flow in a number of theoretical fractures having a constant width of 1mm and a height of 30 metres where the fractures extend different distances into the rock (fracture lengths of 0.5, 1, 2, 3 and 5 metres).
EP09251306A 2009-05-13 2009-05-13 Bohrlochbehandlung Withdrawn EP2251524A1 (de)

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Cited By (6)

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WO2015164078A3 (en) * 2014-04-25 2015-12-17 Weatherford Techology Holdings, Llc System and method for managed pressure wellbore strengthening
CN106226217A (zh) * 2016-07-11 2016-12-14 中国石油大学(北京) 一种确定地下裂缝张开度的方法、装置及其应用
US9803475B2 (en) 2014-04-09 2017-10-31 Weatherford Technology Holdings, Llc System and method for integrated wellbore stress, stability and strengthening analyses
CN110761765A (zh) * 2018-07-27 2020-02-07 中国石油化工股份有限公司 一种大范围激活天然裂缝的体积压裂方法
US20210079288A1 (en) * 2019-09-18 2021-03-18 Southwest Petroleum University Process for preparing metal-chelate retarder by sol-gel method
US11661815B1 (en) 2022-06-06 2023-05-30 Halliburton Energy Services, Inc. Resins for repair of well integrity issues

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Cited By (12)

* Cited by examiner, † Cited by third party
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US9803475B2 (en) 2014-04-09 2017-10-31 Weatherford Technology Holdings, Llc System and method for integrated wellbore stress, stability and strengthening analyses
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