WO2010027366A1 - Fluides de puits de forage pour des opérations de déplacement au ciment - Google Patents

Fluides de puits de forage pour des opérations de déplacement au ciment Download PDF

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Publication number
WO2010027366A1
WO2010027366A1 PCT/US2008/075588 US2008075588W WO2010027366A1 WO 2010027366 A1 WO2010027366 A1 WO 2010027366A1 US 2008075588 W US2008075588 W US 2008075588W WO 2010027366 A1 WO2010027366 A1 WO 2010027366A1
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WIPO (PCT)
Prior art keywords
fluid
wellbore
cement
weighting agent
pumping
Prior art date
Application number
PCT/US2008/075588
Other languages
English (en)
Inventor
Doug Oakley
Mike Hodder
Original Assignee
M-I 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 M-I Llc filed Critical M-I Llc
Priority to PCT/US2008/075588 priority Critical patent/WO2010027366A1/fr
Publication of WO2010027366A1 publication Critical patent/WO2010027366A1/fr

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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
    • C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B20/00—Use of materials as fillers for mortars, concrete or artificial stone according to more than one of groups C04B14/00 - C04B18/00 and characterised by shape or grain distribution; Treatment of materials according to more than one of the groups C04B14/00 - C04B18/00 specially adapted to enhance their filling properties in mortars, concrete or artificial stone; Expanding or defibrillating materials
    • C04B20/10—Coating or impregnating
    • C04B20/1018—Coating or impregnating with organic materials
    • C04B20/1029—Macromolecular compounds
    • C04B20/1033—Macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
    • 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
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • C09K8/48—Density increasing or weighting additives
    • 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
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • C09K8/487—Fluid loss control additives; Additives for reducing or preventing circulation loss
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes

Definitions

  • Embodiments disclosed here generally relate to wellbore fluids for use in cement displacement applications and methods of using such fluids.
  • a borehole is formed in the earth with a drill bit typically mounted at the end of a string of relatively small diameter tubing or drill string.
  • the wellbore is typically prepared for its completions phase by isolating formations transversed by the wellbore with a casing string. Specifically, the bit and drill string are removed from the well, and a larger diameter string of casing or liner is inserted therein.
  • the annulus between the casing and the borehole wall or between the liner and casing is filled with a cement slurry which will permanently seal the annulus and provide structural support for the casing or liner.
  • a cement slurry which will permanently seal the annulus and provide structural support for the casing or liner.
  • the cement slurry is formed at the well site prior to cementing, by mixing a dry cementious material such as fly ash with water to form a thin, watery mixture that is easy to pump.
  • cement is critical for not only supporting and protecting casing but also for sealing formation pressures hydraulically.
  • cementing operations are used to provide zonal isolation, a means to prevent wellbore fluids from contaminating sensitive zones such as freshwater aquifers and production intervals.
  • An important factor for successful cementing is adequate drilling fluid removal, or "mud displacement.”
  • mud displacement To enhance mud removal, a primary technique used is to pump a displacement and/or spacer fluid with modified rheology ahead of the cement slurry to improve mud displacement.
  • pump pressures and ECD may need to be reduced to prevent the formation from being fractured and inducing fluid losses.
  • the flow rate and pump pressure are reduced. By reducing the flow rate, the time required to complete the cement operation and to place the cement into the annulus is lengthened.
  • a critical property of a cement slurry is the 'thickening time.
  • the thickening time is a relative indication of the hardening process of the cement slurry and is a measure of the time required for the cement slurry to become too viscous to be pumpable. It is thus essential that the time required to place and pump the cement slurry into the annulus is less than the thickening time of the cementing slurry. Being able to pump a cement slurry in the annulus, with flow rates as high as possible, preferably under turbulent flow conditions, in the shortest possible time, within the constraints of formation pore and fracture pressures is highly desirable.
  • wellbore fluids may 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 wellbore fluid 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 wellbore fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.
  • Drilling fluids having tailored rheological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the casing string to become stuck, among other issues.
  • the fluid must be easy to pump so only a small amount of pressure is required to force it through restrictions in the circulating fluid system, such as bit nozzles, down-hole tools, or narrow wellbore annuli. In other words, the fluid must have the lowest possible viscosity under high shear conditions.
  • Wellbore fluids used during drilling operations may if properly designed, also be used as displacement and/or as spacer fluids prior to pumping the cement slurry into the borehole.
  • such fluids having this rheological compatibility may be used in both the drilling and completion of a wellbore.
  • a tailored wellbore fluid having low rheology properties of plastic viscosity, yield point, viscometer 6 rpm dial readings, and gel strengths may be displaced into the wellbore prior to cementing to reduce pump pressure and equivalent circulating density (ECD) while cementing.
  • ECD equivalent circulating density
  • Another highly desirable feature of the drilling fluid which is being displaced from the annulus by the spacers, pre-flushes, chemical washes that are pumped ahead of the cementing fluid, is the ability to remove residual drilling fluid from the wellbore and casing/liner to effect a good cement bond between the cement slurry and the casing/liner. If residual drilling fluid remains the casing and/or wellbore before the cement slurry is placed, a micro-annulus or channel may result, thereby favouring interzonal intercommunication and an incomplete bond between the cement and casing or wellbore that may, at some later date, require remedial treatment.
  • Drilling fluids that are viscous, with high gel strengths are particularly problematic to the ultimate success of a cementing operation and in some cases, as mentioned above, it is necessary to reduce the rheology of the drilling fluid prior to the cementing operation.
  • reducing the rheology of a drilling fluid may induce settlement of the drilling fluid weight material which may then be difficult to remove by the cementing fluid, cause channeling and ultimately an incomplete bond between the cementing fluid and casing.
  • the embodiments disclosed herein relate to a method of cementing a pipe into a wellbore filled with a drilling fluid that includes displacing the drilling fluid with the displacement fluid which includes a base fluid, a micronized weighting agent; suspending a pipe in the wellbore; and pumping cement into the wellbore to substantially fill the annulus formed between the outer surface of the pipe and the wellbore.
  • the embodiments disclosed herein relate to a method of drilling and cementing a wellbore that includes drilling the wellbore with a drilling fluid; displacing the drilling fluid with a displacement fluid comprising: a base fluid; and a micronized weighting agent; suspending a pipe in the well; and pumping cement into the well so as to fill the annulus formed between the outer surface of the pipe and the we ⁇ bore.
  • FIG. 1 shows a schematic of one embodiment of a drilling operation or system.
  • FIG. 2 shows a schematic of one embodiment of a cement displacement operation.
  • micronized weighting agents in wellbore fluids used in cement displacement operations.
  • Such fluids may include micronized weighting agents mixed into a base fluid which may be any of a number of fluids including water, seawater, brine, mineral oil, diesel, and synthetic oils.
  • a base fluid which may be any of a number of fluids including water, seawater, brine, mineral oil, diesel, and synthetic oils.
  • Use of these fluids may provide for a fluid to be present in the annulus prior to the cementing operation that possesses a low rheology and low gel strength, which may improves the effectiveness/efficiency of cement spacers, washes and pre- flushes to remove residual drilling fluid prior to the cementing operation, and which in turn may improve the quality of the cement bond between casing and wellbore and overall quality of the cementing operation.
  • Such fluids may also have improved rheology and ECD properties to simultaneously reduce wellbore pressures and minimize both fluid loss and increases in pressure in the wellbore during cement operations.
  • the wellbore fluids of the present disclosure may, as disclosed herein, be pumped prior to the cement displacement operation, in which a cement slurry is displaced into the annulus between a pipe and the walls of the borehole.
  • the wellbore fluids may be referred to as a displacement fluid because they are used to displace the fluids used in drilling from the wellbore prior to cementing.
  • displacement fluids may also be used to displace fluid or a cement slurry out of the casing string and into the annulus to complete the cement displacement operation.
  • pipe may include any "casing,” “liner,” “tubular,”
  • casing string is known in art to be cemented in place in the wellbore, to provide structural integrity to the wellbore.
  • FIG. 1 one embodiment of a typical drilling system is shown.
  • a drilling rig 11 is disposed atop a borehole 12.
  • a drill bit 22 is located at the lower end of the drill string 18 and carves a borehole 12 through the earth formation 24.
  • Drilling mud 26 is pumped from a storage reservoir pit 27 near the wellhead 28, down an axial passage (not shown) through the drill string 18, out of apertures in the bit 22 and back to the surface through the annular region 16, generally referred to as the annulus.
  • Casing 29 is positioned in the borehole 12 above the drill bit 22 for maintaining the integrity of the upper portion of the borehole 12.
  • Segments of casing 29 are placed in borehole 12.
  • the drill string 18 is pulled out of the borehole, a string of casing 29 (or liner) is run into the well at least down to the formation 24 which is believed to contain oil and/or gas hydrocarbons. Greater details of such placements are shown in FIG. 2.
  • FIG. 2 a close-up view of the placement and cementing of a liner
  • liner 46 is shown. As shown in FIG. 2, borehole 42 drilled into a subterranean formation 24 from an offshore or onshore rig has suspended therein a length of liner 46 to be cemented in place. The liner 46 is suspended by a hanger 80 positioned in the lower portion of the casing 44. The casing 44 is shown in the upper portion of the wellbore and a further extension of the wellbore as defined by wellbore walls 42 is shown.
  • the term "liner” as used herein relates generally to a well casing whose upper end does not extend all the way to the surface, but is hung down hole from a larger diameter casing string. Thus, one skilled in the art would appreciate that the techniques described with respect to a liner would be the same or similar for cementing a casing or other pipe. Thus, embodiments of the present disclosure relate to both placement of casing and liners or other pipes.
  • centralizers 48 center the liner 46.
  • a landing collar 50 having an annular shoulder 52.
  • Float shoes 64 or landing collars 50 are attached to the lower end of the liner 46 and include an upwardly closing check valve 60 to prevent reverse flow of cement slurry 68 once it has been pumped through the check valves 60 and into the annulus 78 that is formed between the outer diameter of the liner 46 and the walls of the borehole 42.
  • the purpose of the cementing operation is to fill the annulus 78 so that fluids in the formation 24 that have been penetrated by the borehole 42 can not migrate therethrough.
  • a portion of the liner 46 may be perforated to bring the well into production, or a smaller diameter borehole may be drilled below the borehole 42 and then lined and cemented to deepen the well.
  • borehole 42 is filled with a weighted wellbore mud 72 or "mud" that has hydrostatic head which overbalances the formation fluid pressure to prevent a blowout.
  • Mud 72 is circulated to remove cuttings produced by the rotary drilling process.
  • the mud 72 located in annulus 78 is displaced by a cement slurry 68 and removed from the well.
  • a spacer fluid (not shown) may be pumped prior to the cement slurry 68 to separate the mud 72 from the cement slurry 68.
  • a cementing head (not shown) is mounted on the top joint of the casing 44 hanging in the mast or derrick.
  • a wiper plug 76 is positioned at the lower end of the cement slurry 68 to maintain separation of the cement slurry 68 from mud 72 present in the casing or liner.
  • the outer edge of each plug 76 is sized to sealingly engage the inner walls of the liner 46 while sliding downward.
  • the bottom plug 76 separates the cement slurry 68 from any mud 72 inside the casing 44 and prevents the mud 72 from contaminating the cement 68.
  • the cement slurry 68 forwards the bottom plug 76 down the casing 44.
  • a top plug 58 is placed on top of the cement slurry 68.
  • the top plug 58 separates the last of the cement slurry 68 to go into the casing 44 from displacement fluid 56 pumped on top of the cement slurry 68.
  • Displacement fluid 56 which is usually salt water or a specially formulated drilling mud, moves or displaces, the cement slurry 68 from the casing 44 as the cement pump applies pressure to move the cement slurry 68, the top plug 58, and the displacement fluid 56 down the casing.
  • the bottom plug 76 continues to travel down the string of pipe until it stops or seats in the landing collar 50. Continued pumping is then used to rupture a membrane on the bottom plug 76 and open a passage therein. Cement slurry 68 then proceeds through the bottom plug 76 and continues down the last few joints of casing 44. The cement slurry 68 flows through an opening in the guide shoe 64 and up the annulus 78 between the casing 44 and the borehole 42. Pumping continues until the cement slurry 68 fills the annulus 78. As the last of the cement slurry 68 enters the casing 44 pumped therethrough, the top plug 58 is released from the cementing head. The top plug 58 is similar to the bottom plug 76 with the exception that it has no membrane or passage.
  • cement slurry 68 displaces mud 72 from the annulus 78; however, in accordance with the present disclosure, mud 72 being displaced by cement slurry 68 may be a fluid formulated with micronized barite (or other weighting agents). Such micronized barite fluid may be used to displace the fluid having drilled the interval, and thus it is this micronized barite fluid which is displaced during cementing.
  • the wellbore fluids of the present disclosure may be used in cement displacement operations, where a casing string is to be sealed and/or bonded in the annular space between the walls of the borehole and the outer diameter of the casing with a cementing bonding material.
  • the wellbore fluid may include a base fluid and a micronized weighting agent.
  • such a fluid may not be the fluid used to drill the well. Rather, following drilling of a given interval, once placement of a casing or liner is desired, the drilling fluid may be displaced by a micronized barite fluid. The drill bit and drill string may be pulled from the well and a casing or liner string may be suspended therein.
  • a cement slurry may be pumped through the interior of the casing, optionally separated from the micronized barite displacement fluid with one or more spacer fluids or plugs, as known in the art of cementing.
  • a second displacement fluid for example, the fluid with which the next interval will be drilled or a fluid similar to the first displacement fluid
  • the cement slurry may be pumped through the interior of the casing, optionally separated from the micronized barite displacement fluid with one or more spacer fluids or plugs, as known in the art of cementing.
  • a second displacement fluid for example, the fluid with which the next interval will be drilled or a fluid similar to the first displacement fluid
  • drilling of the next interval may continue.
  • the interior of the casing or liner may be cleaned and perforated, as known in the art of completing a wellbore.
  • the flow rate (and hence pump pressure) is reduced.
  • the time taken to complete the cement operation and place the cement in the annulus is lengthened such that it is less than the thickening time property of the cementing fluid, and the cement sets prior to being pumped into the correct location (as the cementing fluid thickens it will become so viscous it is unpumpable).
  • greater pump rates for a given ECD ceiling may be achieved, thus allowing for better placement of the cement slurry to avoid premature thickening.
  • micronized barite fluids of the present disclosure may, as an alternative, be used as drilling fluids, and be displaced by a cement slurry, without the use of an additional displacement fluid.
  • FIG. 2 described one embodiment of cement displacement; one skilled in the art would appreciate that the embodiment shown in, FIG. 2 is just one example of a cementing displacement operation and that there may be variations and/or different types of equipment and specific techniques used which do not depart from the scope of the invention as disclosed herein.
  • Fluids used in embodiments disclosed herein may include micronized weighting agents.
  • the micronized weighting agents may be uncoated.
  • the micronized weighting agents may be coated with a dispersant.
  • fluids used in some embodiments disclosed herein may include dispersant coated micronized weighting agents.
  • the coated weighting agents may be formed by either a dry coating process or a wet coating process.
  • Weighting agents suitable for use in other embodiments disclosed herein may include those disclosed in U.S. Patent Application Publication Nos. 20040127366, 20050101493, 20060188651, U.S. Patent Nos. 6,586,372 and 7,176,165, and U.S. Provisional Application Serial No. 60/825,156, each of which is hereby incorporated by reference,
  • Micronized weighting agents used in some embodiments disclosed herein may include a variety of compounds well known to one of skill in the art.
  • the weighting agent may be selected from one or more of the materials including, for example, barium sulphate (barite), calcium carbonate (calcite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate.
  • barium sulphate barite
  • calcium carbonate calcite
  • dolomite ilmenite
  • hematite or other iron ores olivine
  • siderite manganese oxide
  • strontium sulphate strontium sulphate.
  • selection of a particular material may depend largely on the density of the material as typically, the lowest wellbore fluid viscosity at any particular density is obtained by using the highest density particles.
  • other considerations may influence the choice of product such as cost, local availability, the power required for grinding, and whether the residual solid
  • the micronized weighting agent may have a d % ranging from 1 to 25 microns and a dso ranging from 0.5 to 10 microns, hi another embodiment, the micronized weighting agent includes particles having a dgo ranging from 2 to 8 microns and a dso ranging from 0.5 to 5 microns.
  • the weighting agent may have a particle size distribution other than a monomodal distribution. That is, the weighting agent may have a particle size distribution that, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.
  • weighting agent particles must be sufficiently small to avoid issues of sag, but not so small as to have an adverse impact on rheology.
  • weighting agent (barite) particles meeting the particle size distribution criteria disclosed herein may be used without adversely impacting the rheological properties of the wellbore fluids.
  • a micronized weighting agent is sized such that: particles having a diameter less than 1 microns are 0 to 15 percent by volume; particles having a diameter between 1 microns and 4 microns are 15 to 40 percent by volume; particles having a diameter between 4 microns and 8 microns are 15 to 30 by volume; particles having a diameter between 8 microns and 12 microns are 5 to 15 percent by volume; particles having a diameter between 12 microns and 16 microns are 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are 0 to 10 percent by volume; particles having a diameter greater than 20 microns are 0 to 5 percent by volume.
  • the micronized weighting agent is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 microns; less than 25 percent are in the range of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns to 6 microns; less than 75 percent are in the range of 6 microns to 10 microns; and less than 90 percent are in the range of 10 microns to 24 microns.
  • Particles having these size distributions may be obtained by several means.
  • sized particles such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially purchased.
  • a coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size.
  • Such techniques include jet-milling, ball milling, high performance wet and dry milling techniques, or any other technique that is known in the art generally for milling powdered products.
  • appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API-grade barite grinding operation. Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API-grade barite. However, in accordance with the present disclosure, these by-product fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein.
  • the micronized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
  • the micronized weighting agents include solid colloidal particles having a deflocculating agent or dispersant coated or sprayed onto the surface of the particle.
  • colloidal refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application.
  • the micronized particle size generates high density suspensions or slurries that show a reduced tendency to sediment or sag, while the dispersant on the surface of the particle controls the inter-particle interactions resulting in lower rheological profiles.
  • the combination of high density, fine particle size, and control of colloidal interactions by surface coating the particles with a dispersant reconciles the objectives of high density, lower viscosity and minimal sag.
  • a dispersant may be coated onto the particulate weighting additive during the comminution (grinding) process. That is to say, coarse weighting additive is ground in the presence of a relatively high concentration of dispersant such that the newly formed surfaces of the fine particles are exposed to and thus coated by the dispersant. It is speculated that this allows the dispersant to find an acceptable conformation on the particle surface thus coating the surface. Alternatively, it is speculated that because a relatively higher concentration of dispersant is in the grinding fluid, as opposed to that in a drilling fluid, the dispersant is more likely to be absorbed (either physically or chemically) to the particle surface.
  • coating of the surface is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art.
  • dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult. Therefore, by necessity, reliance is made on a results oriented definition.
  • one can control the colloidal interactions of the fine particles by coating the particle with dispersants prior to addition to the drilling fluid. By doing so, it is possible to systematically control the rheological properties of fluids containing in the additive as well as the tolerance to contaminants in the fluid in addition to enhancing the fluid loss (filtration) properties of the fluid.
  • the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d 5 o) of less than 10 microns that are coated with a polymeric deflo collating agent or dispersing agent. In other embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (dso) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in yet other embodiments.
  • the fine particle size will generate suspensions or slurries that will show a reduced tendency to sediment or sag, and the polymeric dispersing agent on the surface of the particle may control the inter-particle interactions and thus will produce lower rheological profiles. It is the combination of fine particle size and control of colloidal interactions that reconciles the two objectives of lower viscosity and minimal sag. Additionally, the presence of the dispersant in the comminution process yields discrete particles which can form a more efficiently packed filter cake and so advantageously reduce filtration rates.
  • Coating of the micronized weighting agent with the dispersant may also be performed in a dry blending or spray drying process such that the process is substantially free of solvent.
  • the process includes blending the weighting agent and a dispersant at a desired ratio to form a blended material.
  • the weighting agent may be un-sized initially and rely on the blending process to grind the particles into the desired size range as disclosed above.
  • the process may begin with sized weighting agents.
  • the blended material may then be fed to a heat exchange system, such as a thermal desorption system.
  • the mixture may be forwarded through the heat exchanger using a mixer, such as a screw conveyor. Upon cooling, the polymer may remain associated with the weighting agent.
  • the polymer/weighting agent mixture may then be separated into polymer coated weighting agent, unassociated polymer, and any agglomerates that may have formed.
  • the unassociated polymer may optionally be recycled to the beginning of the process, if desired.
  • the dry blending process alone may serve to coat the weighting agent without heating.
  • a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process.
  • a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react monomelic dispersant onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent.
  • one may use a catalyzed process to form the polymer in the presence of the sized weighting agent.
  • the polymer may be preformed and may be thermally adsorbed or spray dried onto the sized weighting agent.
  • the micronized weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3; at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other embodiments; and at least 2.68 in yet other embodiments.
  • a weighting agent formed of particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density requirements yet have a particulate volume fraction low enough for the fluid to be pumpable.
  • embodiments of the micronized weighting agent may include a deflocculating agent or a dispersant.
  • the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons, such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefm sulphonic acids, phospholipids such as lecithin, including salts thereof and including mixtures thereof.
  • Synthetic polymers may also be used, such as HYPERMER OM-I (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example.
  • Such polyacrylate esters may include polymers of stearyl methacrylate and/or butylacrylate. In another embodiment, the corresponding acids methacrylic acid and/or acrylic acid may be used.
  • acrylate or other unsaturated carboxylic acid monomers or esters thereof may be used to achieve substantially the same results as disclosed herein.
  • a water soluble polymer of molecular weight of at least 2000 Daltons may be used in a particular embodiment.
  • water soluble polymers may include a homopolymer or copolymer of any monomer selected from acrylic acid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido 2-propane sulphonic acid, acrylamide, styrene sulphonic acid, acrylic phosphate esters, methyl vinyl ether and vinyl acetate or salts thereof.
  • the polymeric dispersant may have an average molecular weight from about
  • the polymeric dispersant be polymerized prior to or simultaneously with the wet or dry blending processes disclosed herein.
  • Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization, initiated polymerization or combinations thereof.
  • weighting agent may be included.
  • additional components may be mixed with the weighting agent to modify various macroscopic properties.
  • anti-caking agents, lubricating agents, and agents used to mitigate moisture build-up may be included.
  • solid materials that enhance lubricity or help control fluid loss may be added to the weighting agents and drilling fluid disclosed herein.
  • finely powdered natural graphite, petroleum coke, graphitized carbon, or mixtures of these are added to enhance lubricity, rate of penetration, and fluid loss as well as other properties of the drilling fluid.
  • Another illustrative embodiment utilizes finely ground polymer materials to impart various characteristics to the fluid. In instances where such materials are added, it is important to note that the volume of added material should not have a substantial adverse impact on the properties and performance of the wellbore fluids.
  • polymeric fluid loss materials comprising less than 5 percent by weight are added to enhance the properties of the wellbore fluid.
  • suitably sized graphite and petroleum coke are added to enhance the lubricity and fluid loss properties of the fluid.
  • less than 5 percent by weight of a conventional anti-caking agent is added to assist in the bulk storage of the weighting materials.
  • the particulate materials as described herein may be added to a wellbore fluid as a weighting agent in a dry form or concentrated as slurry in either an aqueous medium or as an organic liquid.
  • an organic liquid should have the necessary environmental characteristics required for additives to oil-based drilling fluids.
  • the oleaginous fluid may have a kinematic viscosity of less than 10 centistokes (10 mm 2 /s) at 40 0 C and, for safety reasons, a flash point of greater than 60 0 C.
  • Suitable oleaginous liquids are, for example, diesel oil, mineral or white oils, n-alkanes or synthetic oils such as alpha-olefin oils, ester oils, mixtures of these fluids, as well as other similar fluids known to one of skill in the art of drilling or other wellbore fluid formulation.
  • the desired particle size distribution is achieved via wet milling of the courser materials in the desired carrier fluid.
  • the micronized weighting agent may be used in a wellbore fluid formulation.
  • the wellbore fluid may be a water-based fluid, an invert emulsion, or an oil-based fluid.
  • Water-based wellbore fluids may have an aqueous fluid as the base fluid and a micronized weighting agent.
  • 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 drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
  • the density of the drilling fluid 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 oil-based/invert emulsion wellbore fluids may include an oleaginous continuous phase, a non-oleaginous discontinuous phase, and a micronized weighting agent.
  • a micronized weighting agent may be modified in accordance with the desired application. For example, modifications may include the hydrophilic/hydrophobic nature of the dispersant.
  • 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
  • the concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion.
  • the amount of oleaginous fluid is from about 30% to about 95% by volume and more preferably about 40% to about 90% by volume of the invert emulsion fluid.
  • the oleaginous fluid in one embodiment, may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.
  • the non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein is a liquid and may be an aqueous liquid.
  • the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds, and combinations thereof.
  • the amount of the non- oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion.
  • the amount of non-oleaginous fluid is less that about 70% by volume, and preferably from about 1% to about 70% by volume.
  • the non-oleaginous fluid is preferably from about 5% to about 60% by volume of the invert emulsion fluid.
  • the fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof.
  • coated barite or other micronized weighting agents may be included in a wellbore fluid having an aqueous fluid that includes at least one of fresh water, sea water, brine, and combinations thereof.
  • Conventional methods may be used to prepare the wellbore fluids disclosed herein in a manner analogous to those normally used, to prepare conventional water- and oil-based fluids.
  • a desired quantity of water-based fluid and a suitable amount of one or more micronized weighting agents, as described above, are mixed together and the remaining components of the drilling fluid added sequentially with continuous mixing.
  • a desired quantity of oleaginous fluid such as a base oil, a non-oleaginous fluid, and a suitable amount of one or more micronized weighting agents are mixed together and the remaining components are added sequentially with continuous mixing.
  • An invert emulsion may be formed by vigorously agitating, mixing, or shearing the oleaginous fluid and the non-oleaginous fluid.
  • additives that may be included in the wellbore fluids disclosed herein include, for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, and cleaning agents.
  • wetting agents for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, and cleaning agents.
  • the ECD of the micronized weighting agent fluid resulted in a displacement flow rate of 160 gal/min and a lower ECD of 14.1 allowing (use of and further below the ECD ceiling) a higher pump rate of 250 gal/min, which gives an ECD of 14.65 lb/gal, and no observable fluid losses to the formation.
  • use of the micronized displacement fluid allowed for keeping the ECD at a manageable level without viscosity settling prior to completion of the cementing operation, and without any measurable losses of the wellbore displacement fluid to the formation.
  • embodiments of the present disclosure provide for one or more of the following: reduced risk of weighting agent sag or settlement; improved ability to formulate thin fluids for reduced pumping pressures; improved ECD control; improved cement job quality, hi cement displacement, the reduction in annular space generally leads to increased ECD.
  • the fluids of the present disclosure may possess rheological properties such that increases in viscosity (and thus ECD) may be minimized while also allowing for reduction in sag and particle settlement. Further, by controlling ECD, bottomhole pressures, and thus, wellbore stability, may be controlled.
  • the fluids of the present disclose may advantageously allow for lower frictional pressures with less risk of fluid losses where pressures are close to the fracture pressure, thus resulting in higher flow rates for turbulent flow placement, and less pumping time required for placing the cement slurry in the annulus, thereby reducing the risk of the cement slurry prematurely hardening during cementing operations.

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Abstract

L'invention porte sur un procédé de cimentation d'une conduite dans un puits de forage rempli d'un fluide de forage qui comprend le déplacement du fluide de forage avec le fluide de déplacement qui comprend un fluide de base et un agent d'alourdissement micronisé ; la mise en suspension d'une canalisation dans le puits de forage ; et le pompage de ciment dans le puits de forage pour remplir en grande partie l'anneau formé entre la surface externe de la canalisation et le puits de forage.
PCT/US2008/075588 2008-09-08 2008-09-08 Fluides de puits de forage pour des opérations de déplacement au ciment WO2010027366A1 (fr)

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US8252729B2 (en) 2008-01-17 2012-08-28 Halliburton Energy Services Inc. High performance drilling fluids with submicron-size particles as the weighting agent
WO2012143687A1 (fr) * 2011-04-21 2012-10-26 Fumi Minerals Limited Agent de lestage pour utilisation dans des puits souterrains
NO333089B1 (no) * 2011-07-11 2013-02-25 Elkem As Oljebrønnborevæsker, oljebrønnsementsammensetning og slurry av vektmateriale
WO2014028804A1 (fr) * 2012-08-17 2014-02-20 Corsicana Technologies, Inc. Recyclage respectueux de l'environnement de saumures dans le procédé de réduction de frottement résultant d'un écoulement turbulent
AU2012254933B2 (en) * 2011-11-16 2015-04-09 Weatherford Technology Holdings, Llc Managed pressure cementing
EP2900781A4 (fr) * 2012-09-27 2016-06-22 Halliburton Energy Services Inc Agents de pondération particulaires comprenant des revêtements amovibles et ses procédés d'utilisation
WO2016144645A1 (fr) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Système d'écartement à base de ciment pour puits de forage, procédés de préparation et procédés d'utilisation
WO2016144644A1 (fr) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Fluides d'isolation de ciment pour puits de forage, procédés de fabrication et procédés d'utilisation
US20170306727A1 (en) * 2014-12-31 2017-10-26 Halliburton Energy Services, Inc. Optimizing completion operations
US9994756B2 (en) 2015-03-10 2018-06-12 Baker Hughes, A Ge Company, Llc Segregating fluids, methods of making, and methods of use
US10253599B2 (en) 2014-12-31 2019-04-09 Halliburton Energy Services, Inc. Optimizing stimulation and fluid management operations
US10301913B2 (en) 2014-12-31 2019-05-28 Halliburton Energy Services, Inc. Optimizing running operations
US10577898B2 (en) 2015-04-02 2020-03-03 Halliburton Energy Services, Inc. Running fluid for use in a subterranean formation operation

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GB2315505A (en) * 1996-07-24 1998-02-04 Sofitech Nv Additive for increasing the density of wellbore fluids
GB2382363A (en) * 2001-11-13 2003-05-28 Schlumberger Holdings Low viscosity spacer fluid

Cited By (24)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8252729B2 (en) 2008-01-17 2012-08-28 Halliburton Energy Services Inc. High performance drilling fluids with submicron-size particles as the weighting agent
WO2012143687A1 (fr) * 2011-04-21 2012-10-26 Fumi Minerals Limited Agent de lestage pour utilisation dans des puits souterrains
CN103635560A (zh) * 2011-04-21 2014-03-12 弗米矿物有限公司 在地下井中使用的加重剂
NO333089B1 (no) * 2011-07-11 2013-02-25 Elkem As Oljebrønnborevæsker, oljebrønnsementsammensetning og slurry av vektmateriale
US8962537B2 (en) 2011-07-11 2015-02-24 Elkem As Oil well drilling fluids, oil well cement composition and slurry of weighting material
AU2012254933B2 (en) * 2011-11-16 2015-04-09 Weatherford Technology Holdings, Llc Managed pressure cementing
US9249646B2 (en) 2011-11-16 2016-02-02 Weatherford Technology Holdings, Llc Managed pressure cementing
US9951600B2 (en) 2011-11-16 2018-04-24 Weatherford Technology Holdings, Llc Managed pressure cementing
WO2014028804A1 (fr) * 2012-08-17 2014-02-20 Corsicana Technologies, Inc. Recyclage respectueux de l'environnement de saumures dans le procédé de réduction de frottement résultant d'un écoulement turbulent
US9404033B2 (en) 2012-08-17 2016-08-02 Ecolab Usa Inc. Environmentally beneficial recycling of brines in the process of reducing friction resulting from turbulent flow
EP2900781A4 (fr) * 2012-09-27 2016-06-22 Halliburton Energy Services Inc Agents de pondération particulaires comprenant des revêtements amovibles et ses procédés d'utilisation
US20170306727A1 (en) * 2014-12-31 2017-10-26 Halliburton Energy Services, Inc. Optimizing completion operations
US10253599B2 (en) 2014-12-31 2019-04-09 Halliburton Energy Services, Inc. Optimizing stimulation and fluid management operations
US10301913B2 (en) 2014-12-31 2019-05-28 Halliburton Energy Services, Inc. Optimizing running operations
US10329882B2 (en) * 2014-12-31 2019-06-25 Halliburton Energy Services, Inc. Optimizing completion operations
WO2016144644A1 (fr) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Fluides d'isolation de ciment pour puits de forage, procédés de fabrication et procédés d'utilisation
GB2553238A (en) * 2015-03-10 2018-02-28 Baker Hughes A Ge Co Llc Cement isolation fluids for wellbores, methods of making, and methods of use
GB2553696A (en) * 2015-03-10 2018-03-14 Baker Hughes A Ge Co Llc Cement spacer system for wellbores, methods of making, and methods of use
WO2016144645A1 (fr) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Système d'écartement à base de ciment pour puits de forage, procédés de préparation et procédés d'utilisation
US9951261B2 (en) 2015-03-10 2018-04-24 Baker Hughes, A Ge Company, Llc Cement spacer system for wellbores, methods of making, and methods of use
US9994756B2 (en) 2015-03-10 2018-06-12 Baker Hughes, A Ge Company, Llc Segregating fluids, methods of making, and methods of use
EA036934B1 (ru) * 2015-03-10 2021-01-18 Бейкер Хьюз, Э Джии Компани, Ллк Растворы для отделения цемента в стволах скважин, способы производства и способы применения
EA036986B1 (ru) * 2015-03-10 2021-01-25 Бейкер Хьюз, Э Джии Компани, Ллк Способ цементирования ствола скважины
US10577898B2 (en) 2015-04-02 2020-03-03 Halliburton Energy Services, Inc. Running fluid for use in a subterranean formation operation

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