Classifications

• • 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
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/06—Arrangements for treating drilling fluids outside the borehole
• • 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
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/06—Arrangements for treating drilling fluids outside the borehole
  • E21B21/062—Arrangements for treating drilling fluids outside the borehole by mixing components
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
  • B01F25/00—Flow mixers; Mixers for falling materials, e.g. solid particles
  • B01F25/20—Jet mixers, i.e. mixers using high-speed fluid streams
  • B01F25/25—Mixing by jets impinging against collision plates
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
  • B01F25/00—Flow mixers; Mixers for falling materials, e.g. solid particles
  • B01F25/40—Static mixers
  • B01F25/45—Mixers in which the materials to be mixed are pressed together through orifices or interstitial spaces, e.g. between beads
  • B01F25/452—Mixers in which the materials to be mixed are pressed together through orifices or interstitial spaces, e.g. between beads characterised by elements provided with orifices or interstitial spaces
  • B01F25/4521—Mixers in which the materials to be mixed are pressed together through orifices or interstitial spaces, e.g. between beads characterised by elements provided with orifices or interstitial spaces the components being pressed through orifices in elements, e.g. flat plates or cylinders, which obstruct the whole diameter of the tube

Definitions

• Embodiments disclosed herein relate generally to mixing drilling fluids.
• embodiments disclosed herein relate generally to devices, systems, and methods for conditioning drilling fluids.
• drill bit cutting surfaces When drilling or completing wells in earth formations, various fluids may be used in the well for a variety of reasons.
• Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling- in (i.e. , drilling in a targeted petroliferous formation), transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
• drilling fluids should be pumpable under pressure down through strings of drilling pipe, then through and around the drilling bit head deep in the earth, and then returned back to the earth surface through an annulus between the outside of the drill stem and the hole wall or casing.
• drilling fluids should suspend and transport solid particles to the surface for screening out and disposal.
• the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the mud), generally finely ground barites (barium sulfate ore), and transport clay and other substances capable of adhering to and coating the borehole surface.
• Drilling fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drilling bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it contains to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry unwanted particulate matter from the bottom of the well bore to the surface. The drilling fluid formulation should also allow the cuttings and other unwanted particulate material to be removed or otherwise settle out from the liquid fraction.
• a drilling operator selects between a water-based drilling fluid and an oil-based or synthetic drilling fluid.
• Each of the water-based fluid and oil-based fluid typically include a variety of additives to create a fluid having the rheological profile necessary for a particular drilling application.
• a variety of compounds are typically added to water- or brine-based well fluids, including viscosifiers, corrosion inhibitors, lubricants, pH control additives, surfactants, solvents, thinners, thinning agents, and/or weighting agents, among other additives.
• Some typical water- or brine-based well fluid viscosifying additives include clays, synthetic polymers, natural polymers and derivatives thereof such as xanthan gum and hydroxyethyl cellulose (HEC).
• clays synthetic polymers, natural polymers and derivatives thereof such as xanthan gum and hydroxyethyl cellulose (HEC).
• HEC hydroxyethyl cellulose
• a variety of compounds are also typically added to a oil-based fluid including weighting agents, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents.
• Rheological properties of certain drilling fluids may change when the shearing action is halted for extended periods of time. Many such periods exist during typical deepwater drilling projects due to other operational requirements. Because the fluid properties change during times of low shear, drilling operations may be delayed or restricted until the fluid has again been sheared sufficiently to recover original properties. Recirculating the drilling fluid through a drill string may help to restore the original rheological properties of the drilling fluid; however, circulating the entire volume of drilling fluid through the drill string until desired rheological properties are achieved may take from a few hours to more than a day. Because drilling cannot proceed until the drilling fluid has been reconditioned, drilling operations are halted while the drilling fluid is recirculated.
• inventions disclosed herein relate to a system for conditioning drilling fluid including a pump configured to pump drilling fluid from a drilling fluid source to a conditioning device, and a second conduit fluidly connected to the second chamber, wherein the second conduit is configured to transport the drilling fluid from the second chamber to conditioned drilling fluid storage area.
• the conditioning device may include a first conduit configured to receive the drilling fluid, a flow restriction disposed adjacent the first conduit, the flow restriction comprising a fluid inlet and a fluid outlet, an impact plate disposed downstream of the flow restriction, a first chamber disposed between the flow restriction and the impact plate, and a second chamber disposed downstream of the impact plate, wherein the first chamber is fluidly connected to the second chamber.
• embodiments disclosed herein relate to a method for conditioning drilling fluid using a conditioning device, the method including pumping a drilling fluid through a flow restriction, accelerating the drilling fluid into a mixing chamber, subjecting the drilling fluid to elongational shearing, decelerating the drilling fluid against an impact plate, subjecting the drilling fluid to impact shearing, and emptying drilling fluid from the mixing chamber.
• FIGS. 1A and IB are schematic representations of an offshore drilling system.
• FIGS. 2 is a cross sectional view of a fluid conditioning device in accordance with embodiments disclosed herein.
• FIGS. 3A, 3B, 3C, and 3D are cross sectional views of flow restrictions in accordance with embodiments disclosed herein.
• FIG. 4 A is a perspective view of an impact plate in accordance with embodiments disclosed herein.
• FIGS. 4B and 4C are cross sectional views of an impact plate in accordance with embodiments disclosed herein.
• FIGS. 5A and 5B are perspective views of impact plate carriers in accordance with embodiments disclosed herein.
• embodiments disclosed herein relate to a device, system, and method for mixing drilling fluids.
• embodiments disclosed herein relate generally to devices, systems, and methods for conditioning drilling fluids.
• a floating platform 102 may be connected to an outer casing 104 disposed around an inner casing 106.
• a drill string 108 may be disposed through inner casing 106 and an annulus 110 may be formed between an outer surface of drill string 108 and an inner surface of inner casing 106.
• a drill bit 112 may be disposed on a distal end of drill string 108 as shown, and may extend into a wellbore 1 18 drilled into the surface of a sea floor 116.
• a blow out preventer (“BOP") stack 1 14 may be disposed on sea floor 1 16 around an outer surface of outer casing 104.
• a drilling riser 120 may extend from BOP stack 1 14 to platform 102, and may be configured to couple with outer casing 104 and inner casing 106.
• outer casing 104, inner casing 106, and drilling riser 120 may be continuous or may be an assembly of multiple casing segments.
• riser assembly 120 may extend from platform 102 for miles through sea water before reaching sea floor 1 16.
• drilling operations require drilling fluid to be pumped into drill string 108 and through drill bit 112 in order to lubricate and cool drill bit 1 12, and to remove cuttings from wellbore 1 18.
• procedures may be performed which require drilling operations to be stopped, e.g. , repairing a drill string component or replacing a bit.
• circulation of drilling fluid down through drill string 108 and up through annulus 110 is also stopped.
• SBM synthetic-based drilling fluid
• OBM oil-based drilling fluid
• gel strength may change, and the homogeneity of additives dispersed within the SBM and OBM may degenerate, resulting in a drilling fluid having undesirable rheological properties.
• drilling riser 120 may extend for miles, and thus, properties of the SBM and OBM disposed therein may vary significantly from platform 102 to sea floor 1 16, and may be considered unreliable due to uncertainty about the ability of the drilling fluid to lubricate and cool drill bit 112, to transport cuttings from well bore 1 18, and to control an amount of hydrostatic pressure applied to the bottom of well bore 1 18.
• the drilling fluid may require reconditioning to restore its desired rheological properties and homogeneity.
• one method of conditioning the drilling fluid is to pump the drilling fluid down drill string 108, through drill bit 1 12, and up annulus 1 10. It may be necessary to circulate the entire volume of drilling fluid through the drill string 108 multiple times before desired rheological properties are restored to the drilling fluid. Because the length of drill string 108 may extend for miles, circulating the drilling fluid multiple times may take hours or days, and thus, significant costs associated with rig downtime may be incurred. Embodiments disclosed herein may provide a more efficient device, system, and method of conditioning drilling fluid.
• Drilling fluid from a drilling fluid source 122 may be pumped to a conditioning device 126 using a pump 124.
• Drilling fluid source 122 may include a mud pit, which may be a large tank that holds drilling fluid, or a storage pit disposed in the body of platform 120.
• Pump 124 may be a pump specifically for the conditioning of drilling fluid or, alternatively, may be a pump that is used on board platform 120 for other purposes.
• pump 124 may be a kill pump used to supply a kill fluid if well control is required.
• a boost pump (not shown) may be used to accelerate the drilling fluid to conditioning device 126, which will be discussed in detail below.
• reconditioned drilling fluid may be directed back to drilling fluid source 122, as indicated by arrow A.
• reconditioned drilling fluid may be pumped to a drilling fluid storage area 128 or may be pumped into drill string 108, as indicated by arrow B and arrow C, respectively.
• a second system 100B for conditioning a drilling fluid is shown disposed on board platform 102.
• drilling fluid from annulus 1 10 may be pumped to conditioning device 126 using pump 122.
• Reconditioned drilling fluid may be pumped to a drilling fluid storage area 128, as indicated by arrow B, or may be pumped into drill string 108, as indicated by arrow C.
• Conditioning device 126 may include a first conduit 202 configured to receive drilling fluid. The drilling fluid may then enter a fluid inlet 206 of a flow restriction 204 and may exit through a fluid outlet 208 into a first chamber 212, as shown by arrow A.
• First chamber 212 may be defined as the area within a second conduit 224 disposed between fluid outlet 208 and an impact plate 210.
• Impact plate 210 may be secured to an impact plate carrier 211 using any fastening means known in the art such as, for example, mechanical fasteners, adhesives, welding, etc. Alternatively, impact plate 210 may be integrally formed with impact plate carrier 211.
• Impact plate 210 may include a surface feature 234 designed to provide a desired flow of drilling fluid through conditioning device 126.
• Surface feature 234 may include a planar or convex surface (not shown), or may include a concave surface 236 as shown.
• Drilling fluid may flow from first chamber 212 through a fluid passage 216 to a second chamber 214 where it may exit conditioning device 126 through outlet 218, as shown by arrow B.
• a flow restriction 204 in accordance with embodiments disclosed herein are shown.
• a flow restriction 204 is shown having a single nozzle 302a of variable diameter.
• nozzle 302a may include a decreasing diameter portion 304, a constant diameter portion 306, and an increasing diameter portion 308.
• flow restriction 204 may include a single nozzle 302b of constant diameter.
• Figure 3C shows three nozzles 302c of constant diameter
• Figure 3D shows four nozzles 302d of variable diameter.
• nozzles of varying sizes and geometries may be disposed in the same flow restriction.
• Flow restriction 204 may experience high wear, and thus, may be formed from a wear-resistant material such as, for example, tungsten carbide or ceramic.
• flow restriction 204 may be designed to removably assemble within conditioning device 126.
• flow restriction 204 may be assembled using, for example, mechanical fasteners such as clamps, bolts, screws, and threaded connections.
• flow restriction 204 may be disposed between two flanges 220, 222, with a first flange 220 disposed on first conduit 202 and a second flange 222 disposed on second conduit 224.
• Flow restriction 204 may be designed to accelerate a flow of drilling fluid therethrough, and may subject the drilling fluid to shear elongation as the drilling fluid passes therethrough. Shear elongation may reduce the gel strength of the drilling fluid, thereby helping to restore original rheological properties to the drilling fluid.
• drilling fluid may be pumped through flow restriction
• drilling fluid may be pumped through flow restriction 204 at a pressure between approximately 100 pounds per square inch (“psi”) and approximately 3000 psi.
• Impact plate 210a may include a first surface 402a having a surface feature 234 configured to contact a flow of drilling fluid exiting flow restriction 204. While flow restriction 204 is configured to accelerate drilling fluid therethrough, impact plate 210 may be configured to decelerate drilling fluid quickly, thereby subjecting the drilling fluid to an impact shear.
• Impact plate 210 may include at least one of a planar surface, a convex surface, and a concave surface.
• impact plate 210a may include a single convex protrusion 404 configured to impede accelerated drilling fluid from fluid outlet 208 of flow restriction 204 ( Figure 2).
• an impact plate 210b is shown having a plurality of surface features 234 including convex protrusions 404 separated by concave recesses 406.
• impact plate 210c may have a surface feature 234 including protrusion 408 with orthogonal surfaces.
• impact plate 210 may include a protrusion 404 centered with respect to fluid outlet 208 of flow restriction 204 ( Figure 2); however, protrusions 404 and/or recesses 406 may be offset with respect to fluid outlet 208. Additionally, protrusions 404 and/or recesses 406 may have any cross sectional shape such as, for example, circular, oval, triangular, square, etc. Those of ordinary skill in the art will appreciate that any number of protrusions and/or recesses having any desired geometry may be used.
• impact plate 210 may be subjected to high wear conditions, and as such, impact plate 210 may be made from a wear resistant material such as, for example, tungsten carbide or ceramic. Additionally, impact plate 210 may be designed as a replaceable component of conditioning device 126. In certain embodiments, impact plate 210 may be attached to impact plate carrier 211 using removable fasteners such as, for example, threaded connections, bolts, screws, rivets, etc. Those of ordinary skill in the art will appreciate that alternative removable couplings may be also used.
• the position of impact plate 210 with respect to fluid outlet 208 of flow restriction 204 may determine an amount of impact the drilling fluid experiences. In general, increasing a distance between fluid outlet 208 and impact plate 210 may decrease the amount of impact shear the drilling fluid experiences, while decreasing the distance between fluid outlet 208 and impact plate 210 may increase the amount of impact shear the drilling fluid experiences. [0034] Referring to Figure 2 and Figures 5 A and 5B, embodiments of an impact plate carrier 21 1 are shown.
• an impact plate carrier 21 1a may include an arcuate slot 502 having an upper arc 504 configured to align with a lower portion of a circumference of impact plate 210 such that drilling fluid may contact impact plate 210 and may flow through slot 502 disposed therebelow and may flow into second chamber 214 ( Figure 2).
• slot 502 may be sized to allow drilling fluid to exit first chamber 212 at a rate substantially equal to or greater than a rate at which the drilling fluid enters first chamber 212. In such an embodiment, drilling fluid may be prevented from building up within first chamber 212.
• Impact plate carrier 211b may include a plurality of holes 506 such that drilling fluid may exit through holes 506 into second chamber 214 ( Figure 2).
• holes 506 may be sized and positioned to allow drilling fluid to flow into second chamber 214 at a rate approximately equal to or greater than the rate at which drilling fluid flows into first chamber 212. In such an embodiment, fluid may be prevented from filling up first chamber 212.
• impact plate carriers 21 la, 21 lb may include a plurality of bores 508 disposed therethrough located around a periphery of the impact plate carriers 211a, 21 1b.
• impact plate carriers 211a, 21 1b may be assembled between a third flange 228 disposed around second conduit 224 and a fourth flange 230 disposed around a third conduit 226 ( Figure 2).
• Third and fourth flanges 228, 230 may include a plurality of bores (not shown) corresponding to bores 508, such that bolts 232 may be removably engaged therethrough.
• fluid may flow into a conduit (not shown) connected to second chamber 214 and may exit conditioning device 126 through outlet 218.
• chamber 214 and the conduit (not shown) connected to second chamber 214 may be sized to allow drilling fluid to exit from second chamber 214 at a rate approximately equal to the rate at which the drilling fluid enters second chamber 214. Thus, drilling fluid may be prevented from accumulating in second chamber 214.
• second chamber 214 may be positioned such that gravity drains drilling fluid from second chamber 214 through a connected conduit (not shown).
• reconditioned drilling fluid may be suitable for using during drilling.
• drilling operations may resume without having to recirculate drilling fluid through annulus 210 and drill string 208 multiple times.
• embodiments disclosed herein may provide for reconditioning a drilling fluid in a decreased time period, thereby providing time and cost savings. Additionally, because the conditioning system disclosed herein may use equipment that is already present on offshore drilling platforms, the conditioning system may have a relatively small footprint.

Landscapes

• Engineering & Computer Science (AREA)
• Geology (AREA)
• Mining & Mineral Resources (AREA)
• Life Sciences & Earth Sciences (AREA)
• Chemical & Material Sciences (AREA)
• Chemical Kinetics & Catalysis (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Mechanical Engineering (AREA)
• Physics & Mathematics (AREA)
• Geochemistry & Mineralogy (AREA)
• Fluid Mechanics (AREA)
• Environmental & Geological Engineering (AREA)
• Dispersion Chemistry (AREA)
• Earth Drilling (AREA)
• Perforating, Stamping-Out Or Severing By Means Other Than Cutting (AREA)

Priority Applications (5)

Applications Claiming Priority (2)

Publications (1)

Family

ID=44914636

Family Applications (1)

Country Status (6)

Cited By (4)

Citations (4)

Family Cites Families (5)

• 2011
  • 2011-03-29 US US13/637,933 patent/US20140174830A1/en not_active Abandoned
  • 2011-03-29 EP EP11780971A patent/EP2553208A1/en not_active Withdrawn
  • 2011-03-29 WO PCT/US2011/030309 patent/WO2011142894A1/en active Application Filing
  • 2011-03-29 BR BR112012024871A patent/BR112012024871A2/pt not_active IP Right Cessation
  • 2011-03-29 MX MX2012011343A patent/MX2012011343A/es not_active Application Discontinuation
  • 2011-03-29 EA EA201290967A patent/EA022156B1/ru not_active IP Right Cessation

Patent Citations (4)

Also Published As

Similar Documents

Legal Events