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WO2014008191A1 - Solution améliorée de renforcement de puits de forage soluble dans de l'acide - Google Patents

Solution améliorée de renforcement de puits de forage soluble dans de l'acide Download PDF

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Publication number
WO2014008191A1
WO2014008191A1 PCT/US2013/048938 US2013048938W WO2014008191A1 WO 2014008191 A1 WO2014008191 A1 WO 2014008191A1 US 2013048938 W US2013048938 W US 2013048938W WO 2014008191 A1 WO2014008191 A1 WO 2014008191A1
Authority
WO
WIPO (PCT)
Prior art keywords
wellbore
fluid
fluid composition
formation
synthetic fiber
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.)
Ceased
Application number
PCT/US2013/048938
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English (en)
Inventor
Jorge ARIAS PRADA
Steven Philip YOUNG
Quanxin Guo
John D. MOFFITT
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.)
MI LLC
Original Assignee
MI LLC
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 MI LLC filed Critical MI LLC
Priority to MX2014016006A priority Critical patent/MX374639B/es
Priority to US14/412,642 priority patent/US10093845B2/en
Publication of WO2014008191A1 publication Critical patent/WO2014008191A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • 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
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/08—Fiber-containing well treatment fluids

Definitions

  • various fluids are typically used in the well for a variety of functions.
  • the fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through the wellbore to the surface.
  • the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
  • Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively.
  • the pore pressure the pressure in the formation pore space provided by the formation fluids
  • the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur.
  • the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore.
  • the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.
  • Fluid compositions may be water- or oil-based and may comprise weighting agents, surfactants, proppants, viscosifiers, fluid loss additives, and polymers.
  • weighting agents may be used for a wellbore fluid to perform all of its functions and allow wellbore operations to continue.
  • the fluid must stay in the borehole.
  • undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation.
  • wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole.
  • Lost circulation is a recurring drilling problem, characterized by loss of drilling mud into downhole formations.
  • lost circulation may remain an issue for other wellbore fluids such as including completion, drill-in, production fluid, etc.
  • Fluid loss can occur naturally in earthen formations that are fractured, highly permeable, porous, cavernous, or vugular. These earth formations can include shale, sands, gravel, shell beds, reef deposits, limestone, dolomite, and chalk, among others.
  • Lost circulation may result from induced pressure during drilling. Specifically, induced mud losses may occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations.
  • induced mud losses may occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations.
  • a particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure weakens hydrocarbon-bearing rocks, but neighboring or inter-bedded low permeability rocks, such as shales, maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the mud weight required to support the shale exceeds the fracture resistance of nearby zones composed of weakly consolidated sands and silts.
  • Another unintentional method by which lost circulation can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove such solids, the fluid density can increase, thereby increasing the hole pressure, and
  • LCM lost circulation material
  • embodiments of the present disclosure are directed to wellbore fluid compositions containing a base fluid; at least one synthetic fiber; and a particulate solid; where one or more of the at least one synthetic fiber and the particulate solid are completely or substantially acid soluble.
  • embodiments of the present disclosure are directed to methods of reducing loss of wellbore fluid in a wellbore to a formation, including: introducing into the wellbore a fluid composition comprising one or more synthetic fibers and one or more particulate solids.
  • embodiments of the present disclosure are directed to methods of reducing loss of wellbore fluid in a wellbore to a formation, including: introducing into the wellbore a fluid composition comprising one or more synthetic fibers; and introducing a second fluid composition comprising one or more particulate solids.
  • Embodiments disclosed herein relate to engineered fluid loss control and wellbore strengthening compositions.
  • embodiments disclosed herein relate to fluid compositions that may enter weakly consolidated intervals of the formation, leaving behind a filtercake, plug, or seal that reduces the loss of fluids into the formation.
  • fluid compositions containing engineered combinations of fibrous materials may provide an immediate blockage, preventing further fluid loss and facilitating further drilling operations.
  • the materials may interact synergistically to form a seal that arrests the flow of wellbore fluids into the formation.
  • fiber and fibrous are used to denote a high aspect ratio molecular or macromolecular structure, which may have a length greater than either its diameter or width.
  • the fluid composition may include a synthetic fiber and a particulate solid.
  • fluid compositions may include a number of other additives known to those of ordinary skill in the art of wellbore fluid formulations, such as wetting agents, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, gelling agents, rheological additives and cleaning agents.
  • additives known to those of ordinary skill in the art of wellbore fluid formulations, such as wetting agents, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, gelling agents, rheological additives and cleaning agents.
  • wellbore fluid compositions in accordance with the instant disclosure may be applied to an interval of a wellbore as a fluid "pill.”
  • the term "pill” is used to refer to a relatively small quantity (typically less than 200 bbl) of a special blend of wellbore fluid to accomplish a specific task that the regular wellbore fluid cannot perform.
  • the fluid composition may be used to plug thief zones or other regions where circulating fluids are being lost into the formation.
  • a pill Upon emplacement within the wellbore, a pill may be defluidized and lose a substantial portion of the base fluid to the formation such materials present in the pill form a plug or seal having sufficient compressive and shear strength for the particular application.
  • the pill upon placing the pill in the wellbore, the pill may be defluidized to lose a substantial portion of the base fluid to the formation such that the fiber blend of the present disclosure may form a plug or seal having sufficient compressive strength for the particular application, and which may increase the tensile strength of the rock.
  • the wellbore fluid composition may be completely or at least partially acid soluble, allowing placement during drilling operations and then subsequently removed prior to completion operations, for example.
  • one or more of the components may be substantially acid soluble.
  • acid soluble refers to the ability of a material to dissolve in/upon contact with an acid
  • substantially acid soluble is defined to mean that at least 50%, at least 75%, or at least 85% of a given component will dissolve in/upon contact with an acid.
  • the selection of fibers may have a significant effect on the efficiency of the fluid compositions in both performance (e.g., defluidization rate and/or resulting plug strength) and acid solubility.
  • One or more embodiments may incorporate at least one synthetic fiber type into the fluid composition.
  • the synthetic fibers may include high aspect ratio polymeric fibers.
  • the diameter of the synthetic fiber has been identified as parameter that may determine both the performance of the synthetic fiber as a lost circulation material, and a variable that may be used to tune the rate of dissolution of the fiber upon exposure to acidic media.
  • the denier of the nylon fiber which is the mass in grams of 9,000 meters of a selected fiber, may be used as a guide for determining the acid solubility of the fiber.
  • a higher denier nylon may be more soluble than a lower denier nylon.
  • a denier of at least 2, 4, 6, or 8 may be selected.
  • the diameter of the synthetic fibers may fall within the range of 0.1 ⁇ to 60 ⁇ .
  • the fiber diameter may range from any lower limit selected from the group of 0.5 ⁇ , 1 ⁇ , 5 ⁇ , and 10 ⁇ to an upper limit selected from the group of 10 ⁇ , 15 ⁇ , 20 ⁇ , and 50 ⁇ .
  • Also affecting acid solubility may be temperature.
  • a sample may have a relatively low acid solubility at room temperature, but upon exposure to elevated temperatures, such as 100°C and greater, the solubility may be increased to substantially or completely soluble.
  • elevated temperatures such as 100°C and greater
  • the solubility may be increased to substantially or completely soluble.
  • whether a component is acid soluble may include acid solubility at elevated temperatures.
  • acid soluble synthetic fibers may include polyamides such as nylon 6, nylon 6,6, and combinations thereof.
  • the synthetic fibers may be selected from polyamides, polyesters, polyaramids, polyethylene terephthalate, polytriphenylene terephthalate, polybutylene terephthalate, polylactic acid, poly(lactic-co-glycolic acid), polyglycolic acid, poly(8-caprolactone) and combinations thereof.
  • the one or more synthetic fibers may be added to the fluid composition in an amount ranging from a lower limit selected from the group of 0.25 ppb, 0.5 ppb, 1 ppb, 3 ppb, and 5 ppb to an upper limit selected from the group of 5 ppb, 8 ppb, 10 ppb, 15 ppb, and 20 ppb. In some embodiments; however, more or less may be desired depending on the particular application and downhole conditions.
  • the length of the fibers may be kept below a length of 8 mm or the composition may become undesirably viscous and unpumpable through standard wellbore fluid delivery means.
  • the fibers may range in length from any lower limit selected from 0.5 mm, 1 mm, 3 mm, and 5 mm to any upper limit selected from 3 mm, 5 mm, 6 mm, and 7 mm.
  • Wellbore fluid formulations in accordance with the present disclosure include particulate solids that may interact in concert with the synthetic fiber to reduce fluid loss by incorporating into the interstitial spaces of a network created by the synthetic fiber.
  • Particulate solids that may be used in accordance with the present disclosure may include any material that may aid in weighting up a fluid to a desired density, including the use of particles frequently referred to in the art as weighting materials, as well as particulates known in the art as lost circulation materials.
  • Particulate solids may be selected from one or more of the materials including, for example, barium sulfate (barite), ilmenite, hematite or other iron ores, olivine, siderite, and strontium sulfate.
  • barium sulfate barium sulfate
  • ilmenite hematite or other iron ores
  • olivine olivine
  • siderite siderite
  • strontium sulfate Other examples include graphite, calcium carbonate (preferably, marble), dolomite (MgC03.CaC03), celluloses, micas, proppant materials such as sands, ceramic particles, diatomaceous earth, calcium silicates, nut hulls, and combinations thereof.
  • proppant materials such as sands, ceramic particles, diatomaceous earth, calcium silicates, nut hulls, and combinations thereof. It is also envisaged that a portion of the particulate solids may comprise drill cuttings having an average particle
  • the particulate weighting agent may be composed of an acid soluble material such as calcium carbonate (calcite), magnesium oxide, dolomite, and the like.
  • an acid soluble material such as calcium carbonate (calcite), magnesium oxide, dolomite, and the like.
  • Particulate solids may comprise substantially spherical particles; however, particulate solids may also comprise elongate particles, for example, rods or ellipsoids, as well as flat or sheet-like particles. Where the particulate solids comprise elongate particles, the average length of the elongate particles should be such that the elongate particles are capable of entering the induced fractures at or near the mouth thereof. Typically, elongate particles may have an average length in the range 25 to 3000 microns, or 50 to 1500 microns in some embodiments, and 250 to 1000 microns in yet other embodiments.
  • the particle size of the particulate solids may be selected depending on the particular application, the level of fluid loss, formation type, and/or the size of fractures predicted for a given formation. The size may also depend on the other particles selected for use in the fluid composition.
  • the particulate solids may have an average diameter that ranges from a lower limit selected from the group of 100 ⁇ , 250 ⁇ , 500 ⁇ , and 750 ⁇ to an upper limit selected from the group of 400 ⁇ , 500 ⁇ , 750 ⁇ , 1000 ⁇ , 1500 ⁇ , and 2000 ⁇ , and 3000 ⁇ .
  • combinations of particulate solids having different average size ranges may be combined in a single fluid composition.
  • the amount of particulate solid present in the fluid composition may also depend on the fluid loss levels, the anticipated fractures, the density limits for a given wellbore and/or pumping limitations, etc.
  • the particulate solids may be added to the wellbore fluid compositions such that the final density of the fluid may range from 9 ppg up to 23 ppg in some embodiments; however, more or less may be desired depending on the particular application.
  • the ratio of the synthetic fibers to particulate solids may be controlled such that the fluid compositions have a comparative weigh percent (wt%) of synthetic fibers to particulate solids [100X(weight synthetic fibers/weight particulate solids)] that ranges from a lower limit selected from the group of 0.25 wt%, 0.5 wt%, and 1 wt% to an upper limit selected from the group of 1 wt%, 3 wt%, 5 wt%, and 7 wt%.
  • wt% weight percent
  • the base fluid may be an aqueous fluid or an oleaginous fluid.
  • the aqueous fluid may include at least one of fresh water, sea water, brine, mixtures of water and water- soluble organic compounds and mixtures thereof.
  • the aqueous fluid may be formulated with mixtures of desired salts in fresh water.
  • Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.
  • the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water.
  • Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, and lithium, salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, and fluorides.
  • Salts that may be incorporated in a brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts.
  • brines that may be used in the pills disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
  • the density of the pill may be controlled by increasing the salt concentration in the brine (up to saturation).
  • a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.
  • the oleaginous fluid may be a liquid, more preferably a natural or synthetic oil, and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof.
  • diesel oil diesel oil
  • mineral oil such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alky
  • Selection between an aqueous fluid and an oleaginous fluid may depend, for example, the type of drilling fluid being used in the well when the lost circulation event. Use of the same fluid type may reduce contamination and allow drilling to continue upon plugging of the formation fractures / fissures, etc.
  • fluid compositions may stop losses when drilling a well, they may also introduce limitations that hinder operations later at the production stage.
  • wellbore fluid compositions may be formulated from acid soluble components such that the compositions may form a seal having high shear strength in a downhole fracture, but be removed at a later time with the application of an acidic treatment such as a breaker fluid.
  • an acidic treatment such as a breaker fluid.
  • the filtercake or seal formed on the wellbore walls may be removed by an acid wash.
  • the formulation of the present disclosure may be particularly desirable for use when drilling through a producing region of the well and fluid losses are experienced.
  • the fluid composition may be pumped into the well to seal off the formation, so that further drilling and/or completion operations may continue.
  • an acid washes known in the art such as hydrochloric acid, sulfuric acid, citric acid, formic acid, acetic acid, or mixtures thereof may be used to at least partially dissolve some of the filtercake remaining on the wellbore walls.
  • the well may then be converted to production.
  • Wellbore fluids compositions may be added in a discrete amount, for example as a pill, or added continuously until lost circulation is reduced to an acceptable level.
  • the wellbore fluid compositions are preferably spotted adjacent to the location of the lost circulation using methods known in the art. Spotting may be accomplished by methods known in the art.
  • the permeable formation will often be at or near the bottom of the wellbore because when the permeable formation is encountered the formation will immediately begin to take drilling fluid and the loss of drilling fluid will increase as the permeable formation is penetrated eventually resulting in a lost circulation condition.
  • the wellbore fluid compositions may be spotted adjacent the permeable formation by pumping a slug or pill of the slurry down and out of the drill pipe as is known in the art. It may be, however, that the permeable formation is at a point farther up in the wellbore, which may result, for example, from failure of a previous seal. In such cases, the drill pipe may be raised as is known in the art so that the pill or slug of the wellbore fluid composition may be deposited adjacent the permeable formation.
  • the volume of the slug or pill that is spotted adjacent the permeable formation may range from less than that of the open hole to more than double that of the open hole. In some instances, it may be necessary to use more than one pill.
  • Such need may arise when the first pill was insufficient to plug the fissures and thief zone or was placed incorrectly. Further, in some instances, the first pill may have sufficiently plugged the first lost circulation zone, but a second (or more) lost circulation zone also exists needed treatment.
  • wellbore fluid compositions may be added and the wellbore may be sealed and pressurized to defluidize the compositions.
  • Defluidization may be accomplished either by hydrostatic pressure or by exerting a low squeeze pressure as is known in the art. Hydrostatic pressure will complete the seal; however, a low squeeze pressure may be desirable because incipient fractures or other areas of high permeability can be thereby opened and plugged immediately, thus reinforcing the zone and reducing or avoiding the possibility of later losses.
  • the drilling fluid may be re-circulated through the wellbore to deposit a filtercake on the formation seal, and drilling may be resumed.
  • Injection of the particles into the formation may be achieved by an overbalance pressure (i.e., an overbalance pressure greater than the formation pressure). While in particular embodiments, the injection pressure may range from 100 to 400 psi, any overbalance pressure level, including less than 100 psi or greater than 400 psi may alternatively be used. The selection of the injection pressure may simply affect the level of injection of the wellbore fluid compositions into the formation.
  • an overbalance pressure i.e., an overbalance pressure greater than the formation pressure.
  • the fibers and particulate solids are added to the treatment fluid, such as a water- or oil-based wellbore fluid, in any order with any suitable equipment to form the fluid composition.
  • the synthetic fiber and particulate solids may be added to the fluid while pumping using specialized shakers.
  • Wellbore fluid compositions formulated with a synthetic fiber and particulate solids may be mixed before pumping downhole in some embodiments.
  • a wellbore fluid containing the synthetic fiber may be introduced into the wellbore before a second wellbore fluid containing the particulate solids or vice versa in yet other embodiments.
  • spacer pills may be used in conjunction with the pills of the present disclosure.
  • a spacer is generally characterized as a thickened composition that functions primarily as a fluid piston in displacing fluids present in the wellbore and/or separating two fluids from each other.
  • G-Seal-PlusTM Coarse GSPC
  • Nut-PlugTM Coarse NPC
  • Nut-Plug FineTM NPF
  • Tests were performed in a modified lost circulation cell.
  • the cell was equipped with a cylinder approximately 50 mm high having a 5 mm slot.
  • the experimental apparatus consisted essentially of a high-pressure, high-temperature fluid loss cell equipped with a cylinder at the bottom. Pressure was applied from the top of the cell onto sample formulations placed within the cell (as in a standard fluid loss experiments known in the art). A valve at the bottom was closed, and a cylinder having a slot was placed inside the cell. 500 mL of fiber-laden fluid was poured into the test cell, and the cell was closed and pressurized to 100 psi. Once the cell was pressurized, the bottom valve was opened quickly enough to eliminate filtration of fibers through the bottom pipe.
  • the applicant has identified materials that are both capable of reducing or eliminating fluid loss in a subterranean formation.
  • the selected fiber materials may also be dissolved upon exposure to acid to such a degree that the seal formed by fiber blend may be partially or completely removed prior to production operations.

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  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Chemical Or Physical Treatment Of Fibers (AREA)
  • Curing Cements, Concrete, And Artificial Stone (AREA)
  • Solid-Sorbent Or Filter-Aiding Compositions (AREA)
  • Artificial Filaments (AREA)

Abstract

Compositions de fluide de puits de forage contenant un fluide de base, au moins une fibre synthétique, et un solide particulaire, une ou plusieurs desdites fibres synthétiques et le solide particulaire étant complètement ou sensiblement solubles dans l'acide. Selon un autre aspect de l'invention, des procédés permettant de réduire les pertes de fluide dans puits de forage qui s'échappent dans une formation, consistent à introduire, dans le puits de forage, une composition de fluide comprenant une ou plusieurs fibres synthétiques et un ou plusieurs solides particulaires.
PCT/US2013/048938 2012-07-02 2013-07-01 Solution améliorée de renforcement de puits de forage soluble dans de l'acide Ceased WO2014008191A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
MX2014016006A MX374639B (es) 2012-07-02 2013-07-01 Solucion mejorada de refuerzo de pozos solubles en ácido.
US14/412,642 US10093845B2 (en) 2012-07-02 2013-07-01 Enhanced acid soluble wellbore strengthening solution

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US201261667179P 2012-07-02 2012-07-02
US61/667,179 2012-07-02
US201361787807P 2013-03-15 2013-03-15
US201361789263P 2013-03-15 2013-03-15
US61/787,807 2013-03-15
US61/789,263 2013-03-15

Publications (1)

Publication Number Publication Date
WO2014008191A1 true WO2014008191A1 (fr) 2014-01-09

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PCT/US2013/048934 Ceased WO2014008190A1 (fr) 2012-07-02 2013-07-01 Comprimés de défluidisation solubles dans l'acide
PCT/US2013/048938 Ceased WO2014008191A1 (fr) 2012-07-02 2013-07-01 Solution améliorée de renforcement de puits de forage soluble dans de l'acide
PCT/US2013/048940 Ceased WO2014008193A1 (fr) 2012-07-02 2013-07-01 Solution améliorée de renforcement de puits de forage

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WO2016163996A1 (fr) * 2015-04-07 2016-10-13 Halliburton Energy Services, Inc. Procédé d'ingénierie pour le traitement de zones de perte grave avec un système de ciment thixotrope
CN109233765A (zh) * 2018-10-09 2019-01-18 中国石油集团渤海钻探工程有限公司 用于大孔隙度易漏油气层固井的碳酸钙隔离液

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AU2015299742B2 (en) * 2014-08-05 2019-07-18 Mohammad As'ad Drilling fluid additive
WO2016019415A1 (fr) * 2014-08-05 2016-02-11 Ryanto Husodo Additif pour fluide de forage
US10723935B2 (en) 2015-11-05 2020-07-28 Halliburton Energy Services, Inc. Calcium carbonate lost circulation material morphologies for use in subterranean formation operations
WO2024238185A1 (fr) * 2023-05-17 2024-11-21 Baker Hughes Oilfield Operations Llc Matériaux biodégradables et solubles dans l'acide pour la régulation de la perte de circulation dans des opérations de forage de réservoir

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WO2016163996A1 (fr) * 2015-04-07 2016-10-13 Halliburton Energy Services, Inc. Procédé d'ingénierie pour le traitement de zones de perte grave avec un système de ciment thixotrope
GB2550313A (en) * 2015-04-07 2017-11-15 Halliburton Energy Services Inc Engineering methodology to treat severe loss zones with thixotropic cement system
AU2015390232B2 (en) * 2015-04-07 2019-02-07 Halliburton Energy Services, Inc. Engineering methodology to treat severe loss zones with thixotropic cement system
US10344544B2 (en) 2015-04-07 2019-07-09 Halliburton Energy Services, Inc. Engineering methodology to treat severe loss zones with thixotropic cement system
GB2550313B (en) * 2015-04-07 2022-02-09 Halliburton Energy Services Inc Engineering methodology to treat severe loss zones with thixotropic cement system
CN109233765A (zh) * 2018-10-09 2019-01-18 中国石油集团渤海钻探工程有限公司 用于大孔隙度易漏油气层固井的碳酸钙隔离液
CN109233765B (zh) * 2018-10-09 2020-11-03 中国石油集团渤海钻探工程有限公司 用于大孔隙度易漏油气层固井的碳酸钙隔离液

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WO2014008190A1 (fr) 2014-01-09
MX369323B (es) 2019-11-05
MX2014016010A (es) 2015-04-13
MX2014016005A (es) 2015-04-13
MX374639B (es) 2025-03-06
MX2014016006A (es) 2015-04-13
MX374658B (es) 2025-03-06

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