WO2014039216A1 - Procédés et systèmes de traitement de puits - Google Patents

Procédés et systèmes de traitement de puits Download PDF

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Publication number
WO2014039216A1
WO2014039216A1 PCT/US2013/054599 US2013054599W WO2014039216A1 WO 2014039216 A1 WO2014039216 A1 WO 2014039216A1 US 2013054599 W US2013054599 W US 2013054599W WO 2014039216 A1 WO2014039216 A1 WO 2014039216A1
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WIPO (PCT)
Prior art keywords
proppant
fluid
treatment fluid
fracture
less
Prior art date
Application number
PCT/US2013/054599
Other languages
English (en)
Inventor
Yiyan Chen
Matthew J. Miller
Anthony Loiseau
Hemant K. J. Ladva
Leland RAMSEY
Rod Shampine
Hongren Gu
Partha Ganguly
Humair Shaikh
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
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Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2014039216A1 publication Critical patent/WO2014039216A1/fr

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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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents

Definitions

  • Many hydraulic fracturing techniques e.g., slickwater techniques, use an excessive amount of water, energy and on-site equipment to entrain and deliver proppant at high pumping rates into the subterranean formation fracture, leading to excessive water treatment costs, formation damage, undesirable fracture geometries in heterogeneous formations, high flowback fluid volumes, delayed production following treatment, waste disposal issues, public concerns about potential potable aquifer contamination, and other problems.
  • Other techniques e.g., viscosified proppant carrier fluids, require excessive amounts of viscosifiers that can damage the formation, e.g., as by impairing conductivity, or may be incompatible with downhole conditions such as pH, temperature, the presence of reactive chemicals, etc. In either case, high pump rates are frequently needed to maintain entrainment of the proppant and to maintain a sufficient downhole pressure for fracture initiation and propagation, i.e., fracture creation.
  • Figure 1 illustrates a wellsite configuration 10 that is typically used in current land-based fracturing operations.
  • the proppant is contained in sand trailers 10A, 10B.
  • Water tanks 12A, 12B, 12C, ...12N are arranged along one side of the operation site.
  • Hopper 14 receives sand from the sand trailers 10A, 10B and distributes it into the mixers 16A, 16B.
  • Blenders 18A, 18B are provided to blend the carrier medium (such as brine, viscosified fluids, etc.) with the proppant and then the slurry is discharged to manifolds 20A, 20B.
  • the final mixed and blended slurry also called frac fluid, is then transferred to the pump trucks 22A, 22B, 22C....22N, and routed at treatment pressure through treating lines 24A, 24B to wellhead 26, and then pumped downhole.
  • the treatment methods or systems employ a stabilized treatment slurry (STS) wherein the solid phase, which may include proppant, is inhibited from gravitational settling in the fluid phase.
  • STS stabilized treatment slurry
  • treatment methods, fluids, equipment and/or systems in general or in fracturing in particular have, or provide, or are associated with, one or more of the following characteristics, namely: use of less water, improvement of energy efficiency, use of less energy, reduction of emissions of dust, NOx, CO, HC, and/or C0 2 , use of less equipment (e.g., fewer trucks or pumps), use of a relatively lower pumping rate, use of a lower pressure drop through perforations, use of a lower friction pressure, use of a relatively lower pump discharge pressure, a smaller wellsite footprint, improvement of solids transport, improvement of distribution of solids among a plurality of transverse flow paths, improvement of stimulation of reservoir fluid production (in oil and gas well treatments), use of a slurry with a longer settling time, allowing pumping or flow of the fluid to be stopped and started or re-started without significant solids settling, allow adjustment of the treatment fluid density, allowing the use of a fluid with controllable bri
  • Figure 2 shows a schematic of a horizontal well with perforation clusters according to some embodiments of the current application.
  • Figure 3 shows the leakoff property of a low viscosity, high proppant treatment fluid (lower line) according to some embodiments of the current application compared to conventional crosslinked fluid (upper line).
  • Figure 4 shows a schematic representation of the wellsite equipment configuration with onsite mixing according to some embodiments of the current application.
  • Figure 6 shows a schematic slurry state progression chart for a treatment fluid according to some embodiments of the current application.
  • Figure 7 illustrates fluid stability regions for a treatment fluid according to some embodiments of the current application.
  • Figure 8 shows the treating pressure and slurry rate for a fracture operation according to some embodiments of the current application.
  • subproppant refers to particle size modes having a smaller size than the proppant modes (including colloidal and submicron particles); references to “proppant” exclude subproppant particles and vice versa;
  • solids” and “solids volume” refer to all solids present in the slurry, including proppant and subproppant particles (including particulate thickeners such as colloids and submicron particles);
  • treatment fluid or “fluid” (in context) refers to the entire treatment fluid, including any proppant, subproppant particles, liquid, gas etc.;
  • fluid phase or “liquid phase” refers to the entire treatment fluid, including any proppant, subproppant particles, liquid, gas etc.;
  • a cased and cemented horizontal well 100 is configured to receive a treatment stage for simultaneously introducing treatment fluid through a plurality of perforations 102, creating at least one fracture or a plurality of fractures, or multiple fractures 104A, 104B, 104C, 104D.
  • the treatment stage in these embodiments is provided with four corresponding cluster sets 106A, 106B, 106C, 106D to form the respective fractures 104A, 104B, 104C, 104D.
  • Four cluster sets are shown for purposes of illustration and example, but the invention is not limited to any particular number of cluster sets in the stage.
  • Vfluid/Vprop is equal to or less than 0.3. In embodiments, Vfluid/Vprop is equal to or less than 0.2. In embodiments, the method further comprises stabilizing the treatment fluid. In embodiments, the treatment fluid comprises a viscosity less than 300 mPa-s (170 s "1 , 25°C) and a yield stress between 1 and 20 Pa (2.1 -42 lb f /ft 2 ).
  • the treatment fluid comprises a viscosity less than 300 mPa-s (170 s "1 , 25°C), a solids phase having a packed volume fraction (PVF) equal to or greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1 - 2.1 * (PVF - 0.72).
  • a method comprises: injecting a proppant- containing treatment fluid into a low mobility subterranean formation; creating a fracture in the subterranean formation containing a first volume (V1 ) of the proppant-containing treatment fluid; and allowing the fracture to close on the proppant to form a proppant- supported fracture having a second volume (V2) of packed proppant support, wherein a ratio of the second volume (V2) to the first volume (V1 ) is at least 0.5.
  • the second volume (V2) to the first volume (V1 ) is at least 0.6.
  • the second volume (V2) to the first volume (V1 ) is at least 0.7.
  • the low mobility formation comprises a carbonate or siltstone formation. In embodiments, the low mobility formation comprises permeability less than 0.1 mD and further comprising producing hydrocarbon liquid from the formation. In embodiments, the low mobility formation comprises permeability less than 1000 nD and further comprising producing hydrocarbon gas from the formation. In embodiments, the method further comprises forming the proppant-supported fracture to extend away from a wellbore for a distance of at least 30 m (98 feet) into the subterranean formation, at least 50 m (164 feet) into the subterranean formation, at least 100 m (328 feet) into the subterranean formation, or at least 150 m (492 feet) into the subterranean formation.
  • the method further comprises placing the packed proppant support in pillars and forming open channels in spaces between the pillars.
  • the proppant-containing treatment fluid comprises a viscosity less than 300 mPa-s (170 s "1 , 25°C) and a yield stress between 1 and 20 Pa (2.1-42 lb f /ft 2 ).
  • the proppant-containing treatment fluid comprises 0.36 liters (L) (0.95 gal or 0.023 bbl) or more of proppant volume per liter of proppant-containing treatment fluid (equivalent to 8 lbs proppant added per gallon of base fluid ("ppa") where the proppant has a specific gravity of 2.6), a viscosity less than 300 mPa-s (170 s "1 , 25°C), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1 - 2.1 * (PVF - 0.72).
  • the proppant-containing treatment fluid comprises 0.4 L or more of proppant volume per liter of proppant-containing treatment fluid (9 ppa where the proppant has a specific gravity of 2.6), or 0.45 L or more of proppant volume per liter of proppant-containing treatment fluid (10 ppa where the proppant has a specific gravity of 2.6).
  • a method comprises injecting a proppant- containing treatment fluid from a wellbore through a perforation at a sustained perforation velocity of less than 50 m/s (164 ft/s) for a continuous period of at least 5 minutes to create a fracture in a subterranean formation; and placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture for a distance of at least 30 meters (98 feet) away from the wellbore, at least 50 m (164 feet) away from the wellbore, at least 100 m (328 feet) away from the wellbore, or at least 150 m (492 feet) away from the wellbore.
  • the sustained perforation velocity over the continuous period is less than 30 m/s.
  • the method further comprises preparing the proppant-containing treatment fluid by combining at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid and stabilizing the proppant-containing treatment fluid.
  • a method comprises: combining at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid to form a proppant- containing treatment fluid; stabilizing the proppant-containing treatment fluid; injecting the proppant-containing treatment fluid into a subterranean formation; creating a fracture in the subterranean formation with the treatment fluid; stopping injection of the treatment fluid to interrupt the creation of the fracture thereby stranding the treatment fluid in the wellbore; and thereafter resuming injection of the treatment fluid to inject the stranded treatment fluid into the formation and continue the fracture creation.
  • a method comprises: combining at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid to form a proppant- containing treatment fluid; stabilizing the proppant-containing treatment fluid; injecting the proppant-containing treatment fluid into a subterranean formation; propagating a fracture in the subterranean formation with the treatment fluid; stopping injection of the treatment fluid to interrupt the propagation of the fracture thereby stranding the treatment fluid in the wellbore; and thereafter circulating the stranded treatment fluid out of the wellbore as an intact plug with a managed interface between the stranded treatment fluid and a displacing fluid.
  • a method comprises: injecting into a subterranean formation one or more treatment fluids comprising a volume of an aqueous phase (Vw) and a volume of proppant (Vprop) at an overall ratio of Vw/Vprop less than 2; creating and filling a fracture in the subterranean formation with at least one of the one or more treatment fluids comprising the volume of proppant distributed therein; allowing fracture closure on the proppant to form a proppant-supported fracture; transporting at least a fraction of the injected volume of the aqueous phase from the one or more treatment fluids into the subterranean formation; and producing a reservoir fluid comprising hydrocarbon (oil or gas) through the proppant-supported fracture free of any aqueous phase flowback or with an aqueous phase flowback recovery volume (Vflowback) at a flowback recovery ratio (Vflowback/Vw) less than 5% over an initial production period of 5 days (FRR5).
  • Vw aqueous phase
  • the improvement comprises: (a) preparing the proppant-containing treatment fluid to comprise at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s "1 , 25°C); (b) stabilizing the proppant-containing treatment fluid to form a stabilized treatment slurry (STS) meeting at least one of the following conditions: (1 ) the slurry has a Herschel-Buckley or Bingham plastic yield stress equal to or greater than 1 Pa; or (2) the largest particle mode in the slurry has a static settling rate less than 0.01 mm/hr; or the depth of any free fluid at the end of a 72-hour static settling test condition or an 8h@15Hz/10d-static dynamic settling test condition (4 hours vibration followed by 20 hours static followed by 4 hours vibration followed finally by 10 days of static conditions) is no more than 2% of total depth; or (3) the apparent dynamic viscosity (25°C, 1
  • the proppant-supported fracture extends for a distance of at least 30 meters (98 feet) away from the wellbore, at least 50 m (164 feet) away from the wellbore, at least 100 m (328 feet) away from the wellbore, or at least 150 m (492 feet) away from the wellbore.
  • the STS is pumped to surface treatment pressure with a proppant pumping energy efficiency of at least 2 L of proppant pumped per MJ of pumping energy (1.4 gal/hp-h).
  • the depth of any free fluid at the end of the 8h@15Hz/10d-static dynamic settling test condition is no more than 2% of total depth
  • the apparent dynamic viscosity (25°C, 170 s-1 ) across column strata after the 8h@15Hz/10d-static dynamic settling test condition is no more than +/- 20% of the initial dynamic viscosity
  • the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 8h@15Hz/10d-static dynamic settling test condition is no more than 5% greater than the initial SVF
  • the density across the column strata below any free water layer after the 8h@15Hz/10d- static dynamic settling test condition is no more than 1 % of the initial density.
  • the STS is formed by at least one of: (1 ) decreasing the density difference between particles and liquid phase in the treatment fluid by introducing into the treatment fluid particles having a density less than 2.6 g/mL, carrier fluid having a density greater than 1.05 g/mL or a combination thereof; (2) increasing a yield stress of the treatment fluid to at least 1 Pa; (3) increasing apparent viscosity of the treatment fluid to at least 50 mPa-s (170 s "1 , 25°C); (4) introducing a viscosifier selected from viscoelastic surfactants and hydratable gelling agents (optionally including crosslinked gelling agents) into the treatment fluid in an amount ranging from 0.01 up to 2.4 g/L of fluid phase; (5) introducing colloidal particles into the treatment fluid; (6) introducing sufficient particles into the treatment fluid to increase the SVF of the treatment fluid to at least 0.4; (7) introducing particles into the treatment fluid having an aspect ratio of at least 6, such as, for example, fiber, flakes
  • the improvement further comprises maintaining a relatively low perforation pressure drop (relative to the pressure drop of the treating fluid passing through the perforation at a higher velocity) corresponding to a sustained velocity of the treatment fluid through the perforations below 50 m/s.
  • the improvement further comprises lowering friction pressure drop in the wellbore by maintaining a sustained flow rate of treatment fluid in the wellbore below 1 .6 m 3 /min (10 BPM).
  • the improvement further comprises increasing liquid head in the wellbore and reducing the treatment pressure by increasing the density of the treatment fluid to at least 2 g/mL.
  • the STS comprises particles having a density greater than 2.8 g/mL, brine having a density greater than 1 .2 g/mL, or a combination thereof.
  • a method comprises: (1 ) preparing a treatment plan for fracturing a subterranean formation penetrated by a wellbore, wherein the treatment plan comprises a schedule for pumping into the wellbore one or more treatment fluids specified in the treatment plan including a stabilized proppant-containing treatment fluid comprising at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid, a packed volume fraction (PVF) greater than a slurry solids volume fraction (SVF), and a viscosity less than 300 mPa-s (170 s "1 , 25°C), and wherein a spurt loss (Vspurt) is less than 10 vol% of a fluid phase of the stabilized proppant-containing treatment fluid or less than 50 vol% of an excess fluid phase (Vspurt ⁇ 0.50 * (PVF-SVF), where the "excess fluid phase” is taken as the amount of fluid in excess of the amount present at the
  • the method further comprises immediately producing hydrocarbons from the formation via the fracture wherein a fluid phase flowback recovery volume (Vflowback) at a flowback recovery ratio (Vflowback/Vw where Vw is the fluid phase volume of the treatment fluid) is less than 1 % over an initial production period of 5 days (FRR5).
  • Vflowback fluid phase flowback recovery volume
  • Vw the fluid phase volume of the treatment fluid
  • a method of managing risk in a fracturing operation comprises: (1 ) preparing a treatment plan for fracturing a subterranean formation penetrated by a wellbore with surface access at a wellsite location, wherein the treatment plan comprises a schedule for pumping into the wellbore one or more treatment fluids specified in the treatment plan including a stabilized proppant-containing treatment fluid comprising at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s "1 , 25°C); (2) installing at the wellsite a pumping system having a maximum available pumping power capacity matching the sum of a maximum pumping power required to implement the pumping schedule plus a reserve pumping power capacity available in case of a pumping deviation event requiring additional power, wherein the reserve pumping power capacity comprises less than 50% of the maximum available pumping power capacity; (3) activating the pumping system with the reserve pumping
  • the pumping system has a maximum pump discharge pressure for safe operation and wherein the pumping schedule comprises pumping the proppant-containing treatment fluid into the wellbore at a rate exceeding 1600 L/min (10 bpm) at a pump discharge pressure below the safe operation pressure, and the method further comprises: (a) pumping of the proppant- containing treatment fluid according to at least a portion of the pumping schedule to create a fracture; (b) thereafter reducing the pumping rate of the proppant-containing treatment fluid to less than 1600 L/min to control the pump discharge pressure in response to a pumping deviation event comprising a pump discharge pressure approaching or exceeding the safe operation pressure; and (c) pumping a volume of the proppant-containing treatment fluid to complete the treatment plan according to a total volume of proppant-containing treatment fluid specified in the treatment plan.
  • a pumping deviation event comprises shutdown of the pumping system after pumping of the proppant-containing treatment fluid according to at least a portion of the pumping schedule to create a fracture, thereby stranding the proppant-containing treatment fluid in the wellbore under static conditions, and the method further comprises thereafter restoring the pumping system to operational status; and resuming pumping of the stranded proppant-containing treatment fluid from the wellbore into the fracture to continue the treatment substantially according to a remainder of the treatment plan.
  • a pumping deviation event comprises shutdown of the pumping system after pumping of the proppant-containing treatment fluid according to at least a portion of the pumping schedule to create a fracture, thereby stranding the proppant-containing treatment fluid in the wellbore under static conditions, and the method further comprises circulating the stranded proppant- containing treatment fluid out of the wellbore as an intact plug, optionally with a managed interface between the stranded treatment fluid and a displacing fluid.
  • a method comprises: injecting a multimodal proppant-containing treatment fluid from a wellbore through a perforation to create a fracture in a subterranean formation, wherein the treatment fluid comprises at least 0.36, at least 0.4 or at least 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s "1 , 25°C), and wherein a ratio of a diameter of the perforation to a diameter of the proppant is less than 6; and placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture for a distance of at least 30 meters (98 feet) away from the wellbore, at least 50 m (164 feet) away from the wellbore, at least 100 m (328 feet) away from the wellbore, or at least 150 m (492 feet) away from the wellbore.
  • the proppant may be said to go where the fracture grows, i.e., the proppant is generally reliably placed where the fracture is created, without forming appreciable proppant-free zones within the fracture so that the entire fracture is propped open with proppant, e.g., not more than 5 volume percent or more than 2 volume percent or more than 1 volume percent of the propagated fracture prior to closure comprises proppant-free zones.
  • a proppant-free zone in a propagated fracture is one having a volume equal to or greater than 10,000 proppant particle volumes in which the proppant concentration is less than 50 percent of the proppant concentration in the treatment fluid.
  • treatment fluid or "wellbore treatment fluid” are inclusive of “fracturing fluid” or “treatment slurry” and should be understood broadly. These may be or include a liquid, a solid, a gas, and combinations thereof, as will be appreciated by those skilled in the art.
  • a treatment fluid may take the form of a solution, an emulsion, slurry, or any other form as will be appreciated by those skilled in the art.
  • slurry refers to an optionally flowable mixture of particles dispersed in a fluid carrier.
  • flowable or “pumpable” or “mixable” are used interchangeably herein and refer to a fluid or slurry that has either a yield stress or low- shear (5.1 1 s "1 ) viscosity less than 1000 Pa and a dynamic apparent viscosity of less than 10 Pa-s (10,000 cP) at a shear rate 170 s "1 , where yield stress, low-shear viscosity and dynamic apparent viscosity are measured at a temperature of 25°C unless another temperature is specified explicitly or in context of use.
  • Viscosity refers to the apparent dynamic viscosity of a fluid at a temperature of 25°C and shear rate of 170 s '
  • Low- shear viscosity refers to the apparent dynamic viscosity of a fluid at a temperature of 25°C and shear rate of 5.1 1 s ' Yield stress and viscosity of the treatment fluid are evaluated at 25°C in a Fann 35 rheometer with an R1 B5F1 spindle, or an equivalent rheometer/spindle arrangement, with shear rate ramped up to 255 s "1 (300 rpm) and back down to 0, an average of the two readings at 2.55, 5.1 1 , 85.0, 170 and 255 s "1 (3, 6, 100, 200 and 300 rpm) recorded as the respective shear stress, the apparent dynamic viscosity is determined as the ratio of shear stress to shear rate ( ⁇ /
  • the Herschel- Buckley fluid is known as a Bingham plastic.
  • Yield stress as used herein is synonymous with yield point and refers to the stress required to initiate flow in a Bingham plastic or Herschel-Buckley fluid system calculated as the y-intercept in the manner described herein.
  • a "yield stress fluid” refers to a Herschel-Buckley fluid system, including Bingham plastics or another fluid system in which an applied non-zero stress as calculated in the manner described herein is required to initiate fluid flow.
  • Treatment fluid or “fluid” (in context) refers to the entire treatment fluid, including any proppant, subproppant particles, liquid, gas etc.
  • Whole fluid,” “total fluid” and “base fluid” are used herein to refer to the fluid phase plus any subproppant particles dispersed therein, but exclusive of proppant particles.
  • Carrier refers to the fluid or liquid that is present, which may comprise a continuous phase and optionally one or more discontinuous fluid phases dispersed in the continuous phase, including any solutes, thickeners or colloidal particles only, exclusive of other solid phase particles; reference to “water” in the slurry refers only to water and excludes any particles, solutes, thickeners, colloidal particles, etc.; reference to “aqueous phase” refers to a carrier phase comprised predominantly of water, which may be a continuous or dispersed phase.
  • the measurement or determination of the viscosity of the liquid phase may be based on a direct measurement of the solids-free liquid, or a calculation or correlation based on a measurement(s) of the characteristics or properties of the liquid containing the solids, or a measurement of the solids-containing liquid using a technique where the determination of viscosity is not affected by the presence of the solids.
  • solids-free for the purposes of determining the viscosity of the liquid phase means in the absence of non-colloidal particles larger than 1 micron such that the particles do not affect the viscosity determination, but in the presence of any submicron or colloidal particles that may be present to thicken and/or form a gel with the liquid, i.e., in the presence of ultrafine particles that can function as a thickening agent.
  • a "low viscosity liquid phase” means a viscosity less than about 300 mPa-s measured without any solids greater than 1 micron at 170 s "1 and 25°C.
  • the treatment fluid may include a continuous fluid phase, also referred to as an external phase, and a discontinuous phase(s), also referred to as an internal phase(s), which may be a fluid (liquid or gas) in the case of an emulsion, foam or energized fluid, or which may be a solid in the case of a slurry.
  • the continuous fluid phase may be any matter that is substantially continuous under a given condition. Examples of the continuous fluid phase include, but are not limited to, water, hydrocarbon, gas, liquefied gas, etc., which may include solutes, e.g. the fluid phase may be a brine, and/or may include a brine or other solution(s).
  • the fluid phase(s) may optionally include a viscosifying and/or yield point agent and/or a portion of the total amount of viscosifying and/or yield point agent present.
  • Some non- limiting examples of the fluid phase(s) include hydratable gels (e.g. gels containing polysaccharides such as guars, xanthan and diutan, hydroxyethylcellulose, polyvinyl alcohol, other hydratable polymers, colloids, etc.), a cross-linked hydratable gel, a viscosified acid (e.g. gel-based), an emulsified acid (e.g.
  • an energized fluid e.g., an N 2 or C0 2 based foam
  • a viscoelastic surfactant (VES) viscosified fluid e.g., an oil outer phase
  • an oil-based fluid including a gelled, foamed, or otherwise viscosified oil.
  • the discontinuous phase if present in the treatment fluid may be any particles (including fluid droplets) that are suspended or otherwise dispersed in the continuous phase in a disjointed manner.
  • the discontinuous phase can also be referred to, collectively, as “particle” or “particulate” which may be used interchangeably.
  • the term “particle” should be construed broadly.
  • the particle(s) of the current application are solid such as proppant, sands, ceramics, crystals, salts, etc.; however, in some other embodiments, the particle(s) can be liquid, gas, foam, emulsified droplets, etc.
  • the particle(s) of the current application are substantially stable and do not change shape or form over an extended period of time, temperature, or pressure; in some other embodiments, the particle(s) of the current application are degradable, dissolvable, deformable, meltable, sublimeable, or otherwise capable of being changed in shape, state, or structure.
  • the particle(s) is substantially round and spherical. In some certain embodiments, the particle(s) is not substantially spherical and/or round, e.g., it can have varying degrees of sphericity and roundness, according to the API RP- 60 sphericity and roundness index.
  • the particle(s) may have an aspect ratio, defined as the ratio of the longest dimension of the particle to the shortest dimension of the particle, of more than 2, 3, 4, 5 or 6.
  • aspect ratio defined as the ratio of the longest dimension of the particle to the shortest dimension of the particle, of more than 2, 3, 4, 5 or 6.
  • non-spherical particles include, but are not limited to, fibers, flakes, discs, rods, stars, etc. All such variations should be considered within the scope of the current application.
  • the particles in the slurry in various embodiments may be multimodal.
  • multimodal refers to a plurality of particle sizes or modes which each has a distinct size or particle size distribution, e.g., proppant and fines.
  • the terms distinct particle sizes, distinct particle size distribution, or multi-modes or multimodal mean that each of the plurality of particles has a unique volume-averaged particle size distribution (PSD) mode. That is, statistically, the particle size distributions of different particles appear as distinct peaks (or "modes") in a continuous probability distribution function.
  • PSD volume-averaged particle size distribution
  • a mixture of two particles having normal distribution of particle sizes with similar variability is considered a bimodal particle mixture if their respective means differ by more than the sum of their respective standard deviations, and/or if their respective means differ by a statistically significant amount.
  • the particles contain a bimodal mixture of two particles; in certain other embodiments, the particles contain a trimodal mixture of three particles; in certain additional embodiments, the particles contain a tetramodal mixture of four particles; in certain further embodiments, the particles contain a pentamodal mixture of five particles, and so on.
  • references disclosing multimodal particle mixtures include US 5,518,996, US 7,784,541 , US 7,789, 146, US 8,008,234, US 8, 1 19,574, US 8,210,249, US 2010/0300688, US 2012/0000641 , US 2012/0138296, US 2012/0132421 , US 2012/01 1 1563, WO 2012/054456, US 2012/0305245, US 2012/0305254, US 2012/0132421 , PCT/RU201 1/000971 and US 13/415,025, each of which are hereby incorporated herein by reference.
  • Solids and solids volume refer to all solids present in the slurry, including proppant and subproppant particles, including particulate thickeners such as colloids and submicron particles.
  • Solids-free and similar terms generally exclude proppant and subproppant particles, except particulate thickeners such as colloids for the purposes of determining the viscosity of a "solids-free" fluid.
  • Proppant refers to particulates that are used in well work-overs and treatments, such as hydraulic fracturing operations, to hold fractures open following the treatment, of a particle size mode or modes in the slurry having a weight average mean particle size greater than or equal to about 100 microns, e.g., 140 mesh particles correspond to a size of 105 microns, unless a different proppant size is indicated in the claim or a smaller proppant size is indicated in a claim depending therefrom.
  • "Gravel” refers to particles used in gravel packing, and the term is synonymous with proppant as used herein.
  • Sub-proppant refers to particles or particle size or mode (including colloidal and submicron particles) having a smaller size than the proppant mode(s); references to “proppant” exclude subproppant particles and vice versa.
  • the sub-proppant mode or modes each have a weight average mean particle size less than or equal to about one-half of the weight average mean particle size of a smallest one of the proppant modes, e.g., a suspensive/stabilizing mode.
  • the proppant when present, can be naturally occurring materials, such as sand grains.
  • the proppant when present, can also be man-made or specially engineered, such as coated (including resin-coated) sand, modulus of various nuts, high-strength ceramic materials like sintered bauxite, etc.
  • the proppant of the current application when present, has a density greater than 2.45 g/mL, e.g., 2.5 - 2.8 g/mL, such as sand, ceramic, sintered bauxite or resin coated proppant.
  • the proppant of the current application when present, has a density less than or equal to 2.45 g/mL, such as less than about 1 .60 g/mL, less than about 1.50 g/mL, less than about 1.40 g/mL, less than about 1 .30 g/mL, less than about 1.20 g/mL, less than 1.10 g/mL, or less than 1.00 g/mL, such as light/ultralight proppant from various manufacturers, e.g., hollow proppant.
  • 2.45 g/mL such as less than about 1 .60 g/mL, less than about 1.50 g/mL, less than about 1.40 g/mL, less than about 1 .30 g/mL, less than about 1.20 g/mL, less than 1.10 g/mL, or less than 1.00 g/mL, such as light/ultralight proppant from various manufacturers, e.g., hollow proppant.
  • the treatment fluid comprises an apparent specific gravity greater than 1 .3, greater than 1.4, greater than 1 .5, greater than 1.6, greater than 1.7, greater than 1.8, greater than 1.9, greater than 2, greater than 2.1 , greater than 2.2, greater than 2.3, greater than 2.4, greater than 2.5, greater than 2.6, greater than 2.7, greater than 2.8, greater than 2.9, or greater than 3.
  • the treatment fluid density can be selected by selecting the specific gravity and amount of the dispersed solids and/or adding a weighting solute to the aqueous phase, such as, for example, a compatible organic or mineral salt.
  • the aqueous or other liquid phase may have a specific gravity greater than 1 , greater than 1.05, greater than 1.1 , greater than 1.2, greater than 1 .3, greater than 1.4, greater than 1 .5, greater than 1.6, greater than 1.7, greater than 1 .8, greater than 1 .9, greater than 2, greater than 2.1 , greater than 2.2, greater than 2.3, greater than 2.4, greater than 2.5, greater than 2.6, greater than 2.7, greater than 2.8, greater than 2.9, or greater than 3, etc.
  • the aqueous or other liquid phase may have a specific gravity less than 1 .
  • the weight of the treatment fluid can provide additional hydrostatic head pressurization in the wellbore at the perforations or other fracture location, and can also facilitate stability by lessening the density differences between the larger solids and the whole remaining fluid.
  • a low density proppant may be used in the treatment, for example, lightweight proppant (apparent specific gravity less than 2.65) having a density less than or equal to 2.5 g/mL, such as less than about 2 g/mL, less than about 1.8 g/mL, less than about 1 .6 g/mL, less than about 1 .4 g/mL, less than about 1.2 g/mL, less than 1.1 g/mL, or less than 1 g/mL.
  • the proppant or other particles in the slurry may have a specific gravity greater than 2.6, greater than 2.7, greater than 2.8, greater than 2.9, greater than 3, etc.
  • Stable or “stabilized” or similar terms refer to a stabilized treatment slurry (STS) wherein gravitational settling of the particles is inhibited such that no or minimal free liquid is formed, and/or there is no or minimal rheological variation among strata at different depths in the STS, and/or the slurry may generally be regarded as stable over the duration of expected STS storage and use conditions, e.g., an STS that passes a stability test or an equivalent thereof.
  • stability can be evaluated following different settling conditions, such as for example static under gravity alone, or dynamic under a vibratory influence, or dynamic-static conditions employing at least one dynamic settling condition followed and/or preceded by at least one static settling condition.
  • the static settling test conditions can include gravity settling for a specified period, e.g., 24 hours, 48 hours, 72 hours, or the like, which are generally referred to with the respective shorthand notation "24h-static", “48h-static” or "72h-static”.
  • Dynamic settling test conditions generally indicate the vibratory frequency and duration, e.g., 4h@15Hz (4 hours at 15Hz), 8h@5Hz (8 hours at 5Hz), or the like. Dynamic settling test conditions are at a vibratory amplitude of 1 mm vertical displacement unless otherwise indicated.
  • Dynamic-static settling test conditions will indicate the settling history preceding analysis including the total duration of vibration and the final period of static conditions, e.g., 4h@15Hz/20h-static refers to 4 hours vibration followed by 20 hours static, or 8h@15Hz/10d-static refers to 8 hours total vibration, e.g., 4 hours vibration followed by 20 hours static followed by 4 hours vibration, followed by 10 days of static conditions.
  • the designation "8h@15Hz/10d-static” refers to the test conditions of 4 hours vibration, followed by 20 hours static followed by 4 hours vibration, followed by 10 days of static conditions.
  • the settling condition is 72 hours static.
  • the stability settling and test conditions are at 25°C unless otherwise specified.
  • one stability test is referred to herein as the "8h@15Hz/10d-static STS stability test", wherein a slurry sample is evaluated in a rheometer at the beginning of the test and compared against different strata of a slurry sample placed and sealed in a 152 mm (6 in.) diameter vertical gravitational settling column filled to a depth of 2.13 m (7 ft), vibrated at 15 Hz with a 1 mm amplitude (vertical displacement) two 4-hour periods the first and second settling days, and thereafter maintained in a static condition for 10 days (12 days total settling time).
  • the 15 Hz/1 mm amplitude condition in this test is selected to correspond to surface transportation and/or storage conditions prior to the well treatment.
  • the depth of any free water at the top of the column is measured, and samples obtained, in order from the top sampling port down to the bottom, through 25.4-mm sampling ports located on the settling column at 190 mm (6'3"), 140 mm (47"), 84 mm (2'9") and 33 mm (1 ⁇ "), and Theologically evaluated for viscosity and yield stress as described above.
  • the stabilized slurry is formed by at least three of the slurry stabilization operations, such as, for example, increasing the SVF, increasing the low- shear viscosity and introducing the multimodal solids phase, and optionally one or more of increasing the yield stress, increasing the apparent viscosity, introducing the solids phase having the PVF greater than 0.7, introducing the viscosifier, introducing the colloidal particles, reducing the particle-fluid density delta, introducing the particles having the aspect ratio of at least 6, introducing the ciliated or coated proppant or a combination thereof.
  • the slurry stabilization operations such as, for example, increasing the SVF, increasing the low- shear viscosity and introducing the multimodal solids phase, and optionally one or more of increasing the yield stress, increasing the apparent viscosity, introducing the solids phase having the PVF greater than 0.7, introducing the viscosifier, introducing the colloidal particles, reducing the particle-fluid density delta, introducing the particles having the aspect ratio of at least
  • increasing the volume fraction of the particles in the treatment fluid can also hinder movement of the carrier fluid. Where the particles are not deformable, the particles interfere with the flow of the fluid around the settling particle to cause hindered settling.
  • the addition of a large volume fraction of particles can be complicated, however, by increasing fluid viscosity and pumping pressure, and increasing the risk of loss of fluidity of the slurry in the event of carrier fluid losses.
  • a ratio of SVF/PVF may be less than 1 - 2.1 * (PVF - 0.81 ) for mixability (flowability).
  • Adding thickening or suspending agents, or solids that perform this function such as calcium carbonate or colloids, i.e., to increase viscosity and/or impart a yield stress in some embodiments allows fluids otherwise in the settling area 714 embodiments (where SVF/PVF is less than or equal to about 1 - 2.1 * (PVF - 0.72)) to also be useful as an STS or in applications where a non-settling, slurriable/mixable slurry is beneficial, e.g., where the treatment fluid has a viscosity greater than 10 mPa-s, greater than 25 mPa-s, greater than 50 mPa-s, greater than 75 mPa-s, greater than 100 mPa-s, greater than 150 mPa- s,
  • the leakoff of embodiments of a treatment fluid of the current application was an order of magnitude less than that of a conventional crosslinked fluid. It should be noted that the leakoff characteristic of a treatment fluid is dependent on the permeability of the formation to be treated. Therefore, a treatment fluid that forms a low permeability filter cake with good leakoff characteristic for one formation may or may not be a treatment fluid with good leakoff for another formation. Conversely, certain embodiments of the treatment fluids of the current application form low permeability filter cakes that have substantially superior leakoff characteristics such that they are not dependent on the substrate permeability provided the substrate permeability is higher than a certain minimum, e.g., at least 1 mD.
  • a certain minimum e.g., at least 1 mD.
  • the treatment fluid comprises an STS also having a very low leakoff rate.
  • the total leakoff coefficient may be about 3X10 "4 m/min 1/2 (10 "3 ft/min 1/2 ) or less, or about 3X10 "5 m/min 1/2 (10 "4 ft/min 1/2 ) or less.
  • Vspurt and the total leak-off coefficient Cw are determined by following the static fluid loss test and procedures set forth in Section 8-8.1 , "Fluid loss under static conditions," in Reservoir Stimulation, 3 Edition, Schlumberger, John Wiley & Sons, Ltd., pp.
  • the treatment fluid has a fluid loss value of less than 10g in 30 min when tested on a core sample with 1000 mD porosity. In some embodiments of the current application, the treatment fluid has a fluid loss value of less than 8 g in 30 min when tested on a core sample with 1000 mD porosity.
  • Fluid loss agents can if desired also include or be used in combination with acrylamido-methyl- propane sulfonate polymer (AMPS).
  • the leak-off control agent comprises a reactive solid, e.g., a hydrolysable material such as PGA, PLA or the like; or it can include a soluble or solubilizable material such as a wax, an oil-soluble resin, or another material soluble in hydrocarbons, or calcium carbonate or another material soluble at low pH; and so on.
  • the leak-off control agent comprises a reactive solid selected from ground quartz, oil soluble resin, degradable rock salt, clay, zeolite or the like.
  • the treatment fluid may additionally or alternatively include, without limitation, friction reducers, clay stabilizers, biocides, crosslinkers, breakers, corrosion inhibitors, and/or proppant flowback control additives.
  • the treatment fluid may further include a product formed from degradation, hydrolysis, hydration, chemical reaction, or other process that occur during preparation or operation.
  • the treatment fluid may be prepared on location, e.g., at the wellsite when and as needed using conventional treatment fluid blending equipment.
  • Figure 4 shows a wellsite equipment configuration 10 for a fracture treatment job according to some embodiments using the principles disclosed herein, for a land-based fracturing operation.
  • the proppant is contained in sand trailers 1 1 A, 1 1 B.
  • Water tanks 12A, 12B, 12C, 12D are arranged along one side of the operation site.
  • Hopper 14 receives sand from the sand trailers 10A, 10B and distributes it into the mixer truck 16.
  • Blender 18 is provided to blend the carrier medium (such as brine, viscosified fluids, etc.) with the proppant, i.e., "on the fly," and then the slurry is discharged to manifold 20.
  • carrier medium such as brine, viscosified fluids, etc.
  • the final mixed and blended slurry also called frac fluid
  • the final mixed and blended slurry is then transferred to the pump trucks 22A, 22B, 22C, 22D, and routed at treatment pressure through treating line 24 to rig 26, and then pumped downhole.
  • This configuration eliminates the additional mixer truck(s), pump trucks, blender(s), manifold(s) and line(s) normally required for slickwater fracturing operations, and the overall footprint is considerably reduced.
  • the STS comprises proppant and a fluid phase at a volumetric ratio of the fluid phase (Vfluid) to the proppant (Vprop) equal to or less than 3.
  • Vfluid/Vprop is equal to or less than 2.5.
  • Vfluid/Vprop is equal to or less than 2.
  • Vfluid/Vprop is equal to or less than 1.5.
  • Vfluid/Vprop is equal to or less than 1 .25.
  • Vfluid/Vprop is equal to or less than 1 .
  • Vfluid/Vprop is equal to or less than 0.75.
  • Vfluid/Vprop is equal to or less than 0.7. In embodiments, Vfluid/Vprop is equal to or less than 0.6. In embodiments, Vfluid/Vprop is equal to or less than 0.5. In embodiments, Vfluid/Vprop is equal to or less than 0.4. In embodiments, Vfluid/Vprop is equal to or less than 0.35. In embodiments, Vfluid/Vprop is equal to or less than 0.3. In embodiments, Vfluid/Vprop is equal to or less than 0.25. In embodiments, Vfluid/Vprop is equal to or less than 0.2. In embodiments, Vfluid/Vprop is equal to or less than 0.1 .
  • the treatment fluid comprises more than 1 .1 kg proppant added per liter of whole fluid including any sub-proppant particles (9 ppa), or more than 1.2 kg proppant added per liter of whole fluid including any sub-proppant particles (10 ppa), or more than 1 .44 kg proppant added per liter of whole fluid including any sub- proppant particles (12 ppa), or more than 1 .68 kg proppant added per liter of whole fluid including any sub-proppant particles (14 ppa), or more than 1.92 kg proppant added per liter of whole fluid including any sub-proppant particles (16 ppa), or more than 2.4 kg proppant added per liter of fluid including any sub-proppant particles (20 ppa), or more than 2.9 kg proppant added per liter of fluid including any sub-proppant particles (24 ppa).
  • the water content in the fracture treatment fluid formulation is low, e.g., less than 30% by volume of the treatment fluid, the low water content enables low overall water volume to be used, relative to a slickwater fracture job for example, to place a similar amount of proppant or other solids, with low to essentially zero fluid infiltration into the formation matrix and/or with low to zero flowback after the treatment, and less chance for fluid to enter the aquifers and other intervals.
  • the low flowback leads to less delay in producing the stimulated formation, which can be placed into production with a shortened clean up stage or in some cases immediately without a separate flowback recovery operation.
  • the solid pack As well as on formation surfaces and in the formation matrix, water can be retained due to a capillary and/or surface wetting effect.
  • the solids pack obtained from an STS with multimodal solids can retain a larger proportion of water than conventional proppant packs, further reducing the amount of water flowback.
  • the water retention capability of the fracture- formation system can match or exceed the amount of water injected into the formation, and there may thus be no or very little water flowback when the well is placed in production.
  • the STS is prepared by combining the proppant and a fluid phase having a viscosity less than 300 mPa-s (170 s "1 , 25C) to form the proppant-containing treatment fluid, and stabilizing the proppant-containing treatment fluid. Stabilizing the treatment fluid is described above.
  • the proppant-containing treatment fluid is prepared to comprise a viscosity between 0.1 and 300 mPa-s (170 s "1 , 25C) and a yield stress between 1 and 20 Pa (2.1-42 lb f /ft 2 ).
  • the proppant-containing treatment fluid comprises 0.36 L or more of proppant volume per liter of proppant-containing treatment fluid (8 ppa proppant equivalent where the proppant has a specific gravity of 2.6), a viscosity between 0.1 and 300 mPa-s (170 s "1 , 25C), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1 - 2.1 * (PVF - 0.72).
  • the ratio of V2/V1 is at least 0.6. In some embodiments, the ratio of V2/V1 is at least 0.65. In some embodiments, the ratio of V2/V1 is at least 0.7. In some embodiments, the ratio of V2/V1 is at least 0.75.
  • the subterranean formation treated according to the embodiments wherein the ratio V2/V1 is as specified may comprise a permeability less than 100 mD. In some embodiments, the subterranean formation comprises a permeability less than 10 mD. In some embodiments, the subterranean formation comprises a permeability less than 1 mD. In some embodiments, the subterranean formation comprises a permeability less than 100 ⁇ . In some embodiments, the subterranean formation comprises a permeability less than 10 ⁇ .
  • the subterranean formation comprises a permeability less than 1 ⁇ , e.g., less than 300 nD or less than 100 nD.
  • the wellbore is substantially horizontal.
  • a substantially horizontal well bore is generally plus or minus 15 degrees from horizontal.
  • the subterranean formation treated according to the embodiments wherein the ratio V2/V1 is as specified the subterranean formation may be a low mobility formation.
  • a low mobility formation as used herein has a low ratio of permeability to reservoir fluid viscosity, i.e., less than or equal to 0.5 mD/mPa-s. Permeability herein can be determined according to RP40, Recommeded Practices for Core Analysis.
  • Viscosity of reservoir hydrocarbons herein can be determined at reservoir conditions (temperature and pressure) according to testing procedures known to the ordinarlily skilled artisan, such as, for example, by Brookfield viscometer, capillary viscometer, and the like, or may be estimated using an appropriate predictive models, correlations or nomographs based on known properties or composition of the fluid.
  • Low mobility oil-bearing formations may have a permeability down in the microdarcy range, e.g., less than 1 mD or less than 200 ⁇ or less than 100 ⁇ , whereas petroleum may have a viscosity at reservoir conditions in the range of 0.3 to 3 mPa-s.
  • Low mobility gas-bearing formations may have a permeability down in the nanodarcy range, e.g., less than 1 microdarcy or less than 300 nD or less than 100 nD, whereas natural gas may have a viscosity at reservoir conditions in the range of 0.05 to 0.4 mPa-s.
  • the subterranean formation may be any low permeability formation, such as, for example, a shale, carbonate or siltstone formation.
  • the method comprises forming the proppant-supported fracture to extend away from a wellbore into the subterranean formation for a distance of at least 15 m (49 feet), or at least 30 m (98 feet), or at least 50 m (160 feet) , or at least 75 m (250 feet) , or at least 100 m (330 feet) , or at least 125 m (410 feet) , or at least 150 m (490 feet).
  • the treatment method comprises placing the packed proppant support in pillars and forming open channels in spaces between the pillars.
  • Various techniques are available for forming proppant clusters in the fracture as posts or islands that prevent complete fracture closure and rely on the formation of proppant-lean flow channels to impart conductivity for reservoir fluid or injection fluid to flow through the fracture between the wellbore and the formation. Examples of these techniques are disclosed in US 6,776,235, US Application Serial No. 13/073458, and US Application Serial No. 13/153529, which are hereby incorporated herein by reference.
  • the method comprises combining the proppant and a fluid phase having a viscosity less than 300 mPa-s (170 s "1 , 25C) to form the proppant-containing treatment fluid, and stabilizing the proppant-containing treatment fluid. Stabilizing the treatment fluid is described above.
  • the proppant-containing treatment fluid is prepared to comprise a viscosity between 0.1 and 300 mPa-s (170 s "1 , 25C) and a yield stress between 1 and 20 Pa (2.1-42 lb f /ft 2 ).
  • the proppant-containing treatment fluid comprises 0.36 L or more of proppant volume per liter of proppant-containing treatment fluid (8 ppa proppant equivalent where the proppant has a specific gravity of 2.6), a viscosity between 0.1 and 300 mPa-s (170 s "1 , 25C), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1 - 2.1 * (PVF - 0.72).
  • the proppant stage treatment fluid comprises a volumetric proppant/treatment fluid ratio (including proppant and sub-proppant solids) in a main stage of at least 0.27 L/L (6 ppg at sp.gr.
  • ppg here refers to the ratio of proppant solids only to the entire treatment fluid volume including proppant and subproppant particles, whereas ppa generally refers to the ratio of proppant added to the base fluid), or at least 0.36 L/L (8 ppg), or at least 0.44 L/L (10 ppg), or at least 0.53 L/L (12 ppg), or at least 0.58 L/L (13 ppg), or at least 0.62 L/L (14 ppg), or at least 0.67 L/L (15 ppg), or at least 0.71 L/L (16 ppg).
  • the hydraulic fracture treatment may comprise an overall volumetric proppant/water ratio of at least 0.13 L/L (3 ppg at sp. gr. 2.7; nota bene: ppg here refers to the ratio of proppant solids only to water only, excluding proppant and subproppant particles, whereas ppa generally refers to the ratio of proppant added to the base fluid including subproppant particles), or at least 0.18 L/L (4 ppg), or at least 0.22 L/L (5 ppg), or at least 0.26 L/L (6 ppg), or at least 0.38 L/L (8 ppg), or at least 0.44 L/L (10 ppg), or at least 0.53 L/L (12 ppg), or at least 0.58 L/L (13 ppg), wherein the treatment optionally comprises one or more of a pre-pad stage, a pad stage, a front-end stage, a flush stage, and a post-flush stage, in addition to the proppant
  • the pad stage is present in advance of the front- end stage and comprises viscosifier in an amount to provide a viscosity in the pad stage of greater than 300 mPa-s, determined on a whole fluid basis at 170 s "1 and 25°C.
  • the flush stage is present and comprises a proppant-free slurry comprising a stabilized solids mixture comprising a particulated leakoff control system (which may include solid and/or liquid particles, e.g., submicron particles, colloids, micelles, PLA dispersions, latex systems, etc.) and a solids volume fraction (SVF) of at least 0.4.
  • a particulated leakoff control system which may include solid and/or liquid particles, e.g., submicron particles, colloids, micelles, PLA dispersions, latex systems, etc.
  • SVF solids volume fraction
  • the flush stage comprises a first substage comprising viscosifier and a second substage comprising slickwater.
  • the viscosifier may be selected from viscoelastic surfactant systems, hydratable gelling agents (optionally including crosslinked gelling agents), and the like.
  • the flush stage comprises an overflush equal to or less than 3200 L (20 42-gal bbls), equal to or less than 2400 L (15 bbls), or equal to or less than 1900 L (12 bbls).
  • the proppant stage comprises a continuous single injection free of spacers.
  • the method comprises combining proppant and a fluid phase at a volumetric ratio of the fluid phase to the proppant (Vf
  • Uid /Vp r0 p is equal to or less than 3. In some embodiments, the ratio Vf
  • Uid /Vprop is equal to or less than 0.7. In some embodiments, the ratio Vf
  • Uid /Vprop is equal to or less than 0.2. In some embodiments, the ratio Vf
  • Uid /Vprop is equal to or greater than 0.05, equal to or greater than 0.1 , equal to or greater than 0.15, equal to or greater than 0.2, equal to or greater than 0.25, equal to or greater than 0.3, equal to or greater than 0.35, equal to or greater than 0.4, equal to or greater than 0.5, or equal to or greater than 0.6, or within a range from any lower limit to any higher upper limit mentioned above.
  • a volumetric ratio of the proppant mode(s) to aqueous phase is greater than about 1 .0. In some embodiments, a volumetric ratio of the proppant mode(s) to aqueous phase is greater than about 1 .5. In some embodiments, a volumetric ratio of the proppant mode(s) to aqueous phase is greater than about 2.0. In some embodiments, a volumetric ratio of the proppant mode(s) to aqueous phase is greater than about 2.5.
  • the aqueous phase refers to the solids-free liquid in the absence of any solid particles regardless of size and in the absence of non-aqueous liquids.
  • the total proppant volume injected is at least 800 liters. In some embodiments, the total proppant volume injected is at least 1600 liters. In some embodiments, the total proppant volume injected is at least 3200 liters. In some embodiments, the total proppant volume injected is at least 8000 liters. In some embodiments, the total proppant volume injected is at least 80,000 liters. In some embodiments, the total proppant volume injected is at least 800,000 liters. The total proppant volume injected is typically not more than 16 million liters.
  • the methods and systems of the current application allow for fewer pumps to be used for fracture treatment because the injection rate, either overall or per restrictive flow area cross section or per perforation relative to slickwater, is reduced, or because the surface pressure requirements are reduced and/or the proppant loading is increased relative to high viscosity treatment fluid.
  • the concentrated proppant loading, as well as water displacement by the sub-proppant particles allow less treatment fluid to be used and especially less water (or other fluid phase fluid) to be used, either overall or per volume of proppant placed or per volume of propped fracture created. This in turn can lead to a reduced footprint owing to fewer pumping trucks, less energy required, reduced C0 2 and other emissions, fewer water trucks, etc.
  • the rate of fluid and/or proppant through each perforation depends on (1 ) the pressure difference between the fluid in the wellbore and in the formation at the perforation and (2) the perforation friction.
  • the treatment pressure of a hydraulic fracture at surface is a sum of multiple pressures and stress as shown in Eq. 1.
  • P s is surface treating pressure (pump discharge)
  • a mm is the minimum stress of the formation
  • P ne t is the net pressure required to initiate and propagate hydraulic pressure
  • P perf is the pressure drop pumping through any perforations
  • P hy d is the hydrostatic pressure created by the fluid
  • P f nction is the pipe friction pressure drop while pumping.
  • a mm is a formation property
  • P hyd is a property of the fluid
  • both can be regarded as constants once a fluid and a formation are selected.
  • the ideal operation is to maximize the surface treating pressure transformation to P ne t-
  • Both Pper f and P f nction are pressure losses and increase with an increase of the pumping rate. So pumping slow according to embodiments can be beneficial in improving the energy efficiency in hydraulic fracture and reducing the surface pressure required of the pumps delivering the fracture fluid.
  • the ratio of the pumping energy to the proppant volume (V pro p) to be injected into the formation is equal to or less than 0.5 MJ/L (0.35 hp-h/gal). In some embodiments, the ratio of the pumping energy to the proppant volume (Vp r0 p) to be injected into the formation is equal to or less than 0.2 MJ/L (0.14 hp-h/gal).
  • the ratio of the pumping energy to the proppant volume (Vp r0 p) to be injected into the formation is equal to or less than 0.1 MJ/L. In some embodiments, the ratio of the pumping energy to the proppant volume (Vp r0 p) to be injected into the formation is equal to or less than 0.05 MJ/L (0.07 hp-h/gal).
  • the ratio of the C0 2 emission to the proppant volume (Vp r0 p) where the pump engines use diesel fuel is equal to or less than 40 g/L, equal to or less than 15 g/L, equal to or less than 10 g/L, equal to or less than 5 g/L, or equal to or less than 1 g/L, and a proportional reduction in nitrogen oxides, carbon monoxide, sulfur compounds, fine particles (2.5 micron) and hydrocarbons, is also obtained due to reduced fuel combustion for pumping.
  • the ratio of the C0 2 emission to the proppant volume (V pro p) is equal to or less than 32 g/L, equal to or less than 12 g/L, equal to or less than 8 g/L, equal to or less than 4 g/L, or equal to or less than 0.8 g/L, with a proportional reduction in concomitant air pollutants.
  • Figure 4 shows a wellsite equipment configuration for a fracture treatment job according to some embodiments using the principles disclosed herein, for a fracture treatment job of similar in scope to that of Figure 1.
  • the number of pump trucks 22 is reduced to just four, three for active pumping and one as a spare, and the number of water trailers 12 is similarly reduced to just four.
  • the water trailers 12E - 12N from Figure 1 are not needed, as are the mixer truck 16B, pump trucks 22E to 22N, blender 18B, manifold 20B and lines 24B, and the overall footprint is considerably reduced.
  • Figure 5 shows further embodiments of the wellsite equipment configuration with the additional feature of delivery of pump-ready treatment fluid delivered to the wellsite in trailers 10A to 10D and further elimination of the mixer 26A, hopper 14, and/or blender 18B.
  • proppant can be maldistributed, e.g., with less proppant going to the initial clusters/perforations and more to the end clusters/perforations. This is because proppant typically has a higher density and more momentum while the treatment fluid is viscoelastic, both of which tend to concentrate the proppant in the center of the wellbore, carrying the proppant past the initial perforation clusters and concentrating the proppant in the treatment fluid injected into the end cluster(s).
  • the presently disclosed hydraulic fracture treatment methods or systems are capable of producing a generally uniform overall per-perforation proppant placement in the formation.
  • a "generally uniform overall per-perforation proppant placement" means that the total volume of proppant injected in any one perforation is within 50% of the quotient of the total volume of proppant injected in all the perforations of the stage divided by the number of perforations in the stage.
  • the total volume of proppant injected at each perforation or other restrictive flow passage in the stage is within +1- 50% of the per perforation average, or within +/- 40% of the per perforation average, or within +/- 35% of the per perforation average, or within +/- 30% of the per perforation average, or within +/- 25% of the per perforation average, or within +/- 20% of the per perforation average, or within +/- 15% of the per perforation average, or within +/- 10% of the per perforation average.
  • the per- perforation average is normalized by the flow area of each perforation, e.g., a perforation in a ten-perforation stage having 10% of the total flow area through the perforations would count as 1 .0 perforation whereas a perforation having 5% of the total flow area as 0.5 perforations, or having 20% as 2.0 perforations.
  • the flow velocities of the treatment fluid flowing simultaneously into a plurality of perforations is within +/- 50% of the average perforation velocity, or within +/- 40% of the per perforation average velocity, or within +/- 35% of the average perforation velocity, or within +/- 30% of the average perforation velocity, or within +/- 25% of the average perforation velocity, or within +/- 20% of the average perforation velocity, or within +/- 15% of the average perforation velocity, or within +/- 10% of the average perforation velocity.
  • a "generally uniform overall per-perforation (or per- restrictive flow passage) proppant injection” means that the total volume of proppant injected in any one perforation is within 50% of the quotient of the total volume of proppant injected in all the perforations of the stage divided by the number of perforations in the stage.
  • the total volume of proppant injected at each perforation or other restrictive flow passage in the stage is within +/- 50% of the per perforation average, or within +/- 40% of the per perforation average, or within +/- 35% of the per perforation average, or within +/- 30% of the per perforation average, or within +/- 25% of the per perforation average, or within +/- 20% of the per perforation average, or within +/- 15% of the per perforation average, or within +/- 10% of the per perforation average.
  • a volumetric proppant loading in the fluid injected into each perforation in the stage is within +/- 50%, 40%, 35%, 30%, 25%, 20% or 15%, of an overall volumetric proppant loading in the proppant stage treatment fluid injected into the wellbore. In some embodiments, a volumetric proppant loading in the fluid injected into each perforation cluster in the stage is within +/- 50%, 40%, 35%, 30%, 25%, 20% or 15%, of an overall volumetric proppant loading in the proppant stage treatment fluid injected into the wellbore.
  • a method comprises injecting a proppant-containing treatment fluid from a wellbore through a perforation at a sustained perforation velocity of less than 200 m/s to create a proppant-supported fracture in a subterranean formation, and propagating the fracture into the subterranean formation for a distance of at least 30 meters (98 feet) away from the wellbore.
  • the sustained perforation velocity in the injection and propagation is less than 100 m/s, less than 75 m/s, less than 50 m/s, less than 30 m/s or less than 25 m/s.
  • the method may further comprise preparing the proppant-containing treatment fluid by combining at least 0.36, at least 0.4, or at least 0.45 L of proppant per liter of base fluid and stabilizing the proppant-containing treatment fluid.
  • Circulating the treatment fluid out of the wellbore can be achieved optionally using coiled tubing or a workover rig, if desired, but in embodiments the treatment fluid will itself suspend and convey all the proppant out of the wellbore with high efficiency.
  • the method may include managing the interface between the treatment fluid and any displacing fluid, such as, for example, matching density and viscosity between the treatment and displacing fluids, using a wiper plug or pig, using a gelled pill or fiber pill or the like, to prevent density and viscous instabilities.
  • Subterranean formations are heterogeneous, with layers of high, medium, and low permeability strata interlaced.
  • a hydraulic fracture that grows to the extent that it encounters a high permeability zone will suddenly experience a high leakoff area that will attract a disproportionately large fraction of the injected fluid significantly changing the geometry of the created hydraulic fracture possibly in an undesireable manner.
  • a hydraulic fracturing fluid that would automatically plug a high leakoff zone is useful in that it would make the fracture execution phase more reliable and probably ensure the fracture geometry more closely resembles the designed geometry (and thus production will be closer to that expected).
  • One feature of embodiments of an STS is that it will dehydrate and become an immobile mass (plug) upon losing more than 25% of the water it is formulated with.
  • an STS in embodiments only contains up to 50% water by volume, then it will only require a loss of a total of 12.5% of the STS treatment fluid volume in the high fluid loss affected area to become an immobile plug and prevent subsequent fluid loss from that area; or in other embodiments only contains up to 40% water by volume, requiring a loss of a total of 10% of the STS treatment fluid volume to become immobile.
  • a slick water system would need to lose around 90% or 95% of its total volume to dehydrate the proppant into an immobile mass.
  • Sp can be within a range of from about 10 to about 50 ml/m 2 , or from about 15 to about 40 ml/m 2 , or from about 20 to about 35 ml/m 2 , or from about 24 to about 32 ml/m 2 .
  • Vspurt represents the wetting water loss from the initial contact between the freshly exposed fracture faces and the fracturing fluid, and in some embodiments may be much less than the volume of water present in the fracturing fluid, e.g., less than 10% or less than 8% or less than 5% or less than 4% or less than 3% or less than 2% or less than 1.5% or less than 1 % of the volume of water present in the fracturing fluid.
  • Vspurt is less than about 50% of the free water in the fracturing fluid, i.e., PVF-SVF, or less than about 30%, or less than about 25% or less than about 20% or less than about 15% of the free water, where the free water is calculated as the product of the volume of fracturing fluid introduced into the formation and the difference between the PVF and SVF of the fracturing fluid.
  • free water assumes that when all the solids touch each other, i.e., when the water volume equals (1-PVF), the water loss mechanism changes from hydraulic pressure due to pumping during the injection operation and/or overburden during post-injection shut-in, to one of drainage and/or capillary action.
  • the total water present in the volume of the fracturing fluid introduced into the formation depends on the overall or average SVF of the fluid introduced into the fracture, whereas for small water losses the fracture volume, i.e., fracture width W times fracture surface area, can be taken as an estimate of the volume of fracturing fluid.
  • the fracture width may be within a range of from about 2.5 mm (0.1 in.) to about 12.5 mm (0.5 in.).
  • the Vspurt would be about 6% of the total water and about 14% of the free water in the fracturing fluid, which should be sufficient to maintain fluidity of the fracturing fluid upon initial contact.
  • Vw 2 * 2 * A * Cw * t ° 5
  • Vw is the continuous water loss to the matrix
  • Cw is the loss coefficient
  • t- ⁇ is the duration of the fluid treatment injection operation into the formation.
  • the loss coefficient Cw is determined by following the static fluid loss test and procedures set forth in Section 8-8.1 , "Fluid loss under static conditions," in Reservoir Stimulation, 3 rd Edition, Schlumberger, John Wiley & Sons, Ltd., pp.
  • Cw may be within the range from about 0.06 to about 0.15 mm/min " 0 5 (0.0002 to 0.0005 ft/min "0 5 ).
  • the calculated value of Vw is such that the sum of the calculated values of Vspurt plus Vw is equal to or greater than the volume of free water, or much greater than the volume of free water, for example, (Vspurt + Vw)/(A * W) > (SVF-PVF), or (Vspurt + Vw)/(A * W) > 2 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 5 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 10 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 20 * (SVF-PVF), wherein the product of A times W is taken as the total volume of fracturing fluid injected into the formation during fracture initiation and propagation.
  • the calculated value of Vw is such that the sum of Vspurt plus Vw is equal to or greater than the volume of total water in the treatment fluid injected into the fracture, or much greater than the total water in the treatment fluid injected into the fracture, for example, (Vspurt + Vw)/(A * W) > (1 -SVF), or (Vspurt + Vw)/(A * W) > 2 * (1-SVF), or (Vspurt + Vw)/(A * W) > 5 * (1-SVF), or (Vspurt + Vw)/(A * W) > 10 * (1 -SVF), based on calculated values wherein the product of A times W is taken as the total volume of fracturing fluid injected into the formation during fracture initiation and propagation.
  • Vw 2 * 2 * A * Cw * (t 1 +t 2 )- 0 5
  • Vw is a shut-in period following the injection stage(s) and all other variables are as previously defined.
  • the calculated value of Vw is such that the sum of the calculated values of Vspurt plus Vw is equal to or greater than the volume of free water, or much greater than the volume of free water, for example, (Vspurt + Vw)/(A * W) > (SVF-PVF), or (Vspurt + Vw)/(A * W) > 2 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 5 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 10 * (SVF-PVF), or (Vspurt + Vw)/(A * W) > 20 * (SVF-PVF), wherein the product of A times W is taken as the total volume of fracturing fluid injected into the formation during fracture initiation and propagation and t2 > 0.
  • the well can be shut in for a period of time sufficient to inhibit water flowback where t2 is such that the calculated value of the sum of Vspurt plus Vw is equal to or greater than the volume of total water in the treatment fluid injected into the fracture, or much greater than the total water in the treatment fluid injected into the fracture, for example, (Vspurt + Vw)/(A * W) > (1-SVF), or (Vspurt + Vw)/(A * W) > 2 * (1 - SVF), or (Vspurt + Vw)/(A * W) > 5 * (1 -SVF), or (Vspurt + Vw)/(A * W)/(A * W)/(A * W)/(A * W)/(A * W)/(A * W)/(A * W)/(A * W)/(A * W) > 5 * (1 -SVF), or (Vspurt + Vw)/(A * W
  • FRR5 is less than 1 % and/or FRR90 is less than 2%.
  • any water produced from the reservoir after a period of continuous hydrocarbon production of at least 10 days comprises less than 1 % injected water and at least 99% connate water.
  • the production comprises a proppant placement/aqueous phase flowback ratio (Vprop/Vflowback) of at least 100 over the initial 5 day production period (PFR5), or PFR5 is at least 200 or at least 300 or at least 400 or at least 500.
  • Vprop/Vflowback proppant placement/aqueous phase flowback ratio
  • a method of managing risk in a fracturing operation comprises:
  • the surface treating pressure will approach the maximum pressure limit for safe operation.
  • the maximum pressure limit may be due to the safe pressure limitation of the wellhead, the surface treating lines, the casing, or some combination of these items.
  • One common response to reaching an upper pressure limit is to reduce the pumping rate.
  • the proppant suspension will be inadequate at low pumping rates, and proppant may fail to get placed in the fracture.
  • the stabilized fluids in some embodiments of this disclsoure which can be highly stabilized and practically eliminate particle settling, possess the characteristic of excellent proppant conveyance and transport even when static.
  • some risk of treatment failure is mitigated since a fracture treatment can be pumped to completion in some embodiments herein, even at very low pump rates should injection rate reduction be necessary to stay below the maximum safe operating pressure during a fracture treatment with the stabilized treatment fluid.
  • the pumping system has a maximum pump discharge pressure for safe operation and wherein the pumping schedule comprises pumping the proppant-containing treatment fluid into the wellbore at a rate exceeding 1600 L/min (10 bpm) at a pump discharge pressure below the safe operation pressure.
  • the risk management method further comprises: pumping of the proppant-containing treatment fluid according to at least a portion of the pumping schedule to create a fracture; thereafter reducing the pumping rate of the proppant-containing treatment fluid to less than 1600 L/min to control the pump discharge pressure in response to a pumping deviation event comprising a pump discharge pressure approaching or exceeding the safe operation pressure; and pumping a volume of the proppant-containing treatment fluid to complete the treatment plan according to a total volume of proppant-containing treatment fluid specified in the treatment plan.
  • a pumping deviation event comprises shutdown of the pumping system after pumping of the proppant-containing treatment fluid according to at least a portion of the pumping schedule to create a fracture, thereby stranding the proppant-containing treatment fluid in the wellbore under static conditions
  • the method further comprises thereafter restoring the pumping system to operational status and resuming pumping of the stranded proppant-containing treatment fluid from the wellbore into the fracture to continue the treatment substantially according to a remainder of the treatment plan.
  • the method further comprises circulating the stranded proppant-containing treatment fluid out of the wellbore as an intact plug, optionally with a managed interface between the stranded treatment fluid and a displacing fluid.
  • the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 1.0 m 3 /minute (6 bbl/min). In some embodiments, the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 0.5 m 3 /minute (3 bbl/min). In some embodiments, the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 0.4 m 3 /minute (2.4 bbl/min). In some embodiments, the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 0.3 m 3 /minute (1.8 bbl/min).
  • the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 0.2 m 3 /minute (1.2 bbl/min). In some embodiments, the overall proppant laden treatment fluid injection rate in the stage is equal to or less than an average of about 0.1 m 3 /minute (0.6 bbl/min).
  • the hydraulic fracture treatment comprises fracture propagation with injection of the proppant stage treatment fluid through the perforations at a velocity less than 135 m/s (2 BPM per perforation), or less than 100 m/s (1 .5 BPM per perforation), or less than 80 m/s (1 .2 BPM per perforation), or less than 65 m/s (1 BPM per perforation), or less than 50 m/s (0.8 BPM per perforation), or less than 40 m/s (0.6 BPM per perforation), or less than or equal to 25 m/s (0.4 BPM per perforation).
  • the injection of the treatment fluid of the current application can be stopped all together (i.e. at an injection rate of 0 bbl/min). Due to the excellent stability of the treatment fluid, very little or no proppant settling occurs during the period of 0 bbl/min injection. Well intervention, treatment monitoring, equipment adjustment, etc. can be carried out by the operator during this period of time. The pumping can be resumed thereafter.
  • a method comprising injecting a proppant laden treatment fluid into a subterranean formation penetrated by a wellbore, initiating or propagating a fracture in the subterranean formation with the treatment fluid, stopping injecting the treatment fluid for a period of time, restarting injecting the treatment fluid to continue the initiating or propagating of the fracture in the subterranean formation.
  • the proppant stage treatment fluid comprises an apparent specific gravity greater than 1 .3, greater than 1.4, greater than 1.5, greater than 1 .6, greater than 1 .7, greater than 1 .8, greater than 1.9, greater than 2, greater than 2.1 , greater than 2.2, greater than 2.3, greater than 2.4, greater than 2.5, greater than 2.6, greater than 2.7, greater than 2.8, greater than 2.9, or greater than 3.
  • the proppant stage treatment fluid density can be selected by selecting the specific gravity and amount of the dispersed solids and/or adding a weighting solute to the aqueous phase, such as, for example, a compatible organic or mineral salt.
  • a low density proppant may be used in the treatment, for example, lightweight proppant (apparent specific gravity less than 2.6) having a density less than or equal to 2.5 g/mL, such as less than about 2 g/mL, less than about 1 .8 g/mL, less than about 1.6 g/mL, less than about 1 .4 g/mL, less than about 1 .2 g/mL, less than 1.1 g/mL, or less than 1 g/mL.
  • the treatment and system may achieve the ability to fracture using a carbon dioxide proppant stage treatment fluid.
  • Carbon dioxide is normally too light and too thin (low viscosity) to carry proppant in a slurry useful in fracturing operations.
  • carbon dioxide may be useful in the liquid phase, especially where the proppant stage treatment fluid also comprises a particulated fluid loss control agent.
  • the liquid phase comprises at least 10 wt% carbon dioxide, at least 50 wt% carbon dioxide, at least 60 wt% carbon dioxide, at least 70 wt% carbon dioxide, at least 80 wt% carbon dioxide, at least 90 wt% carbon dioxide, or at least 95 wt% carbon dioxide.
  • the carbon dioxide-containing liquid phase may alternatively or additionally be present in any pre-pad stage, pad stage, front-end stage, flush stage, post-flush stage, or any combination thereof.
  • Jet perforating and jet slotting are embodiments for the STS, wherein the proppant is replaced with an abrasive or erosive particle.
  • Multi-zone fracturing systems using a locating sleeve/polished bore and jet cut opening are embodiments.
  • Drilling cuttings transport and cuttings stability during tripping are also improved in embodiments.
  • the STS can act to either fracture the formation or bridge off cracks, depending on the exact mixture used.
  • the STS can provide an extreme ability to limit fluid losses to the formation, a very significant advantage. Minimizing the amount of liquid will make oil based muds much more economically attractive.
  • the modification of producing formations using explosives and/or propellant devices in embodiments is improved by the ability of the STS to move after standing stationary and also by its density and stability.
  • Zonal isolations operations in embodiments are improved by specific STS formulations optimized for leakoff control and/or bridging abilities. Relatively small quantities of the STS radically improve the sealing ability of mechanical and inflatable packers by filling and bridging off gaps.
  • the pressure containing ability and ease of placement/removal of sand plugs in embodiments are significantly improved using appropriate STS formulations selected for high bridging capacity. Such formulations will allow much larger gaps between the sand packer tool and the well bore for the same pressure capability.
  • Another major advantage is the reversibility of dehydration in some embodiments; a solid sand pack may be readily re-fluidized and circulated out, unlike conventional sand plugs.
  • Permanent isolation of zones is achieved in some embodiments by bullheading low permeability versions of the STS into water producing formations or other formations desired to be isolated. Isolation in some embodiments is improved by using a setting formulation of the STS, but non-setting formulations can provide very effective permanent isolation.
  • Temporary isolation may be delivered in embodiments by using degradable materials to convert a non-permeable pack into a permeable pack after a period of time.
  • plug and abandon work may be improved using CRETE cementing formulations in the STS and also by placing bridging/leakoff controlling STS formulations below and/or above cement plugs to provide a seal repairing material.
  • CRETE cementing formulations are disclosed in US 6,626,991 , GB 2,277,927, US 6,874,578, WO 2009/046980, Schlumberger CemCRETE Brochure (2003), and Schlumberger Cementing Services and Products - Materials, pp.
  • a method comprising: (a) injecting a treatment fluid containing proppant into (i) a subterranean formation or (ii) a subterranean penetrated by a wellbore; and (b) creating a fracture in the subterranean formation with the fluid.
  • a method comprising: combining proppant and a fluid phase at a volumetric ratio of the fluid phase (Vfluid) to the proppant (Vprop) equal to or less than 1 .5 to form a treatment fluid; and injecting the treatment fluid into a subterranean formation to create a fracture in the subterranean formation.
  • a method comprising: injecting a proppant-containing treatment fluid into a low mobility subterranean formation; creating a fracture in the subterranean formation containing a first volume (V1 ) of the proppant-containing treatment fluid; and allowing the fracture to close on the proppant to form a proppant-supported fracture having a second volume (V2) of packed proppant support, wherein a ratio of the second volume (V2) to the first volume (V1 ) is at least 0.5.
  • the proppant-containing treatment fluid comprises 0.36 L or more of proppant volume per liter of proppant- containing treatment fluid (8 ppa proppant where specific gravity is 2.6), a viscosity less than 300 mPa-s (170 s "1 , 25°C), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1 - 2.1 * (PVF - 0.72).
  • any water produced from the reservoir after a period of continuous hydrocarbon production of at least 10 days comprises less than 1 % injected water and at least 99% connate water.
  • a method comprising: pumping a stabilized proppant-containing treatment fluid into a wellbore in fluid communication with a subterranean formation, wherein the stabilized proppant containing treatment fluid comprises at least 0.36, 0.4 or 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa (170 s "1 , 25°C), at a proppant pumping energy efficiency of at least 2 L of proppant pumped per MJ of pumping energy (1.4 gal/hp-h); injecting the stabilized proppant-containing treatment fluid from the wellbore into a subterranean formation to create a fracture, and placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture for a distance of at least 30 meters (98 feet) away from the wellbore.
  • a method to improve proppant pumping energy efficiency in a fracturing procedure comprising pumping a proppant-containing treatment fluid at a surface treatment pressure into a wellbore in fluid communication with a subterranean formation, injecting the proppant-containing treatment fluid from the wellbore into a subterranean formation to create a fracture, placing the proppant into the fracture and closing the fracture to form a proppant-supported fracture extending away from the wellbore and in fluid communication therewith, the improvement comprising: preparing the proppant- containing treatment fluid to comprise at least 0.36, 0.4 or 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s "1 , 25°C); stabilizing the proppant- containing treatment fluid to form a stabilized treatment slurry (STS) meeting at least one of the following conditions:
  • the largest particle mode in the slurry has a static settling rate less than 0.01 mm/hr;
  • the depth of any free fluid at the end of a 72-hour static settling test condition or an 8h@15Hz/10d-static dynamic settling test condition (4 hours vibration followed by 20 hours static followed by 4 hours vibration followed finally by 10 days of static conditions) is no more than 2% of total depth; or
  • the apparent dynamic viscosity (25°C, 170 s-1 ) across column strata after the 72-hour static settling test condition or the 8h@15Hz/10d-static dynamic settling test condition is no more than +/- 20% of the initial dynamic viscosity; or
  • the density across the column strata below any free water layer after the 72-hour static settling test condition or the 8h@15Hz/10d-static dynamic settling test condition is no more than 1 % of the initial density; and pumping the STS to the surface treatment pressure (at the wellhead) for introduction into the wellbore.
  • the depth of any free fluid at the end of the 8h@15Hz/10d-static dynamic settling test condition is no more than 2% of total depth
  • the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 8h@15Hz/10d-static dynamic settling test condition is no more than 5% greater than the initial SVF;
  • a method comprising: preparing a treatment plan for fracturing a subterranean formation penetrated by a wellbore, wherein the treatment plan comprises a schedule for pumping into the wellbore one or more treatment fluids specified in the treatment plan including a stabilized proppant-containing treatment fluid comprising at least 0.36, 0.4 or 0.45 L of proppant per liter of whole fluid, a packed volume fraction (PVF) greater than a slurry solids volume fraction (SVF), and a viscosity less than 300 mPa-s (170 s "1 , 25°C), and wherein a spurt loss (Vspurt) is less than 10 vol% of a fluid phase of the stabilized proppant-containing treatment fluid or less than 50 vol% of an excess fluid phase (Vspurt ⁇ 0.50 * (PVF-SVF)); injecting the stabilized proppant-containing treatment fluid into the subterranean formation according to the treatment plan to create a fracture, wherein the spurt loss is
  • a method of managing risk in a fracturing operation comprising: preparing a treatment plan for fracturing a subterranean formation penetrated by a wellbore with surface access at a wellsite location, wherein the treatment plan comprises a schedule for pumping into the wellbore one or more treatment fluids specified in the treatment plan including a stabilized proppant-containing treatment fluid comprising at least 0.36, 0.4 or 0.45 L of proppant per liter of whole fluid and a viscosity less than 300 mPa-s (170 s- ⁇ 25°C);
  • a pumping system having a maximum available pumping power capacity matching the sum of a maximum pumping power required to implement the pumping schedule plus a reserve pumping power capacity available in case of a pumping deviation event requiring additional power, wherein the reserve pumping power capacity comprises less than 50% of the maximum available pumping power capacity;
  • a pumping deviation event comprises shutdown of the pumping system after pumping of the proppant- containing treatment fluid according to at least a portion of the pumping schedule to create a fracture, thereby stranding the proppant-containing treatment fluid in the wellbore under static conditions, and further comprising circulating the stranded proppant-containing treatment fluid out of the wellbore as an intact plug, optionally with a managed interface between the stranded treatment fluid and a displacing fluid.
  • the total leakoff coefficient of STS was determined to be very low from the test.
  • the STS fluid loss did not appear to be a function of differential pressure. This unique low to no fluid loss property, and excellent stability (low rate of solids settling), allows the STS to be pumped at a low rate without concern of screen out.
  • Example 2 Stabilized Treatment Slurry.
  • Table 2 Another example of an STS is provided in Table 2 below, which has an SVF of 60%.
  • the fluid is very flowable and has been pumped into a subterranean formation with available field equipment.
  • Typical slickwater operation has an SVF up to about 8% only.
  • the fluid in the current example delivers proppant at a much higher efficiency.
  • the solids in these embodiments are conventional proppant, and the 40/70 mesh proppant and 100 mesh sand are conventionally referred to as proppant.
  • a low total water content in the STS results from both high proppant loading in the STS and the conversely relatively low amount of free water required for the slurry to be flowable/pumpable.
  • Low water volume injection embodiments certainly result in correspondingly low fluid volumes to flow back.
  • the PVF of that formulation is 69%. This means that only 31 % of the volume is fluid-filled voids.
  • a certain amount of water is retained due to capillary and/or surface wetting effects. The amount of retained water in this embodiment is higher than that of a conventional proppant pack, further reducing the amount of water flow back (in addition to inhibiting water infiltration into the matrix).
  • the flow back is less than 30% or less than 20% or less than 10% of the water injected in the STS stage and/or the total water injected (including any pre- pad, pad, front-end, proppant, flush, and post-flush stage(s)), and there is a good chance that there may even be zero flow back.
  • the STS in this embodiment is using only 3% of the water that is required using the slickwater fracturing technique. Even considering any requirements of a pad, a flush and other non-STS fluid, the amount of water used by STS in this embodiment is still at least an order of magnitude less than the comparable slickwater technique, e.g., less than 10 % of the water required for the slickwater technique.
  • the proppant stage placement v/v water efficiency (volume of proppant/volume of water) is at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 100%, at least 1 10%, or at least 120%, and in additional or alternative embodiments the aqueous phase in the high-efficiency proppant stage has a viscosity less than 300 mPa-s.
  • Example 3 STS Slurry Stability Tests. A slurry sample was prepared with the formulation given in Table 3.
  • the slurry was prepared by mixing the water, diutan and other additives, and SafeCARB particles in two 37.9-L (10 gallon) batches, one in an eductor and one in a RUSHTON turbine, the two batches were combined in a mortar mixer and mixed for one minute. Then the sand was added and mixed one minute, silica added and mixed with all components for one minute.
  • a sample of the freshly prepared slurry was evaluated in a Fann 35 rheometer at 25°C with an R1 B5F1 configuration at the beginning of the test with speed ramped up to 300 rpm and back down to 0, an average of the two readings at 3, 6, 100, 200 and 300 rpm (2.55, 5.10, 85.0, 170 and 255 s "1 ) recorded as the shear stress, and the yield stress ( ⁇ 0 ) determined as the y-intercept using the Herschel-Buckley rheological model.
  • the slurry was then placed and sealed with plastic in a 152 mm (6 in.) diameter vertical gravitational settling column filled with the slurry to a depth of 2.13 m (7 ft).
  • the column was provided with 25.4-mm (1 in.) sampling ports located on the settling column at 190 mm (6'3"), 140 mm (47"), 84 mm (2'9") and 33 mm (1 ⁇ ") connected to clamped tubing.
  • the settling column was mounted with a shaker on a platform isolated with four airbag supports. The shaker was a BUTTKICKER brand low frequency audio transducer.
  • the column was vibrated at 15 Hz with a 1 mm amplitude (vertical displacement) for two 4-hour periods the first and second settling days, and thereafter maintained in a static condition for 10 days (12 days total settling time, hereinafter "8h@15Hz/10d static").
  • the 15 Hz/1 mm amplitude condition was selected to correspond to surface transportation and/or storage conditions prior to the well treatment.
  • Examples 7 - 10 Additional Formulations. Additional STS formulations were prepared as shown in Table 2. Example 7 was prepared without proppant and exemplifies a high-solids stabilized slurry without proppant that can be used as a treatment fluid, e.g., as a spacer fluid, pad or managed interface fluid to precede or follow a proppant-containing treatment fluid. Example 8 was similar to Example 7 except that it contained proppant including 100 mesh sand. Example 9 was prepared with gelling agent instead of latex. Example 10 was similar to Example 9, but was prepared with dispersed oil particles instead of calcium carbonate. Examples 8 - 10 exemplify treatment fluids suitable for fracturing low mobility formations.

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Abstract

L'invention porte sur des procédés, sur des fluides, sur un équipement et/ou sur des systèmes pour traiter une formation souterraine dans laquelle pénètre un puits de forage, lesquels utilisent moins d'eau, moins d'énergie, moins d'équipement, ont une plus petite surface au sol sur le site du puits, une émission de dioxyde de carbone réduite, une distribution améliorée d'agent de soutènement parmi une pluralité de trajectoires d'écoulement, une stimulation améliorée de production de fluide de réservoir, un procédé de gestion de risque amélioré, ou analogue, ou toute combinaison de ceux-ci, par rapport à des procédés, à des fluides, à un équipement et/ou à des systèmes de traitement classiques comparables, tels que, par exemple, des traitements de fracturation hydraulique de formations souterraines utilisant de l'eau dite « glissante » et/ou des fluides de traitement à viscosité élevée.
PCT/US2013/054599 2012-09-05 2013-08-13 Procédés et systèmes de traitement de puits WO2014039216A1 (fr)

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