FRACTURING PROCESS WITH FRICTION REDUCTION COATING

Abstract

A method to provide a fractured subterranean formation is provided, the method including the steps of: providing a wellbore from a surface location to the subterranean formation; applying a friction reduction treatment to at least a portion of an inside surface of a casing; cementing the casing with the applied friction reduction treatment into at least a portion of the wellbore; and pumping into the wellbore a fluid at a pressure that exceeds a fracture pressure of the subterranean formation thereby forming at least one fracture within the subterranean formation wherein the fluid is in contact with at least a portion of the inside surface of the casing with the applied friction reduction treatment.

Description

RELATED APPLICATIONS

This application claims priority to U.S. provisional patent application No. 61/976,858, filed on Apr. 8, 2014, the contents of which is incorporated herein by reference.

BACKGROUND

Hydraulic fracturing is used to increase the area of a formation that is in communication with a wellbore and therefore increasing either production of fluids from the wellbore, or increasing the amount of fluids that may be injected into the formation from the wellbore. Hydraulic fracturing has been in commercial use for many decades, but gradual improvements in the size of fractures that can be created and the cost effectiveness of the fractures, along with developments like improved horizontal drilling, have resulted in hydraulic fracturing enabling production of hydrocarbons from formations such as source rocks or other very low permeability formations, that were previously not thought to be economically producible.

Typically, gas and/or oil, referred to as light tight oil, is produced from low permeability formations such as source rocks, by providing horizontal wells in the formations for distances of a mile or more. The formation is then fractured from the wellbores in as many as twenty or thirty places, with the fractures placed every 50 to 150 meters along the horizontal wellbore. The fractures are provided by pumping fracturing fluids into an isolated section of the wellbore that is in communication with formation at pressures that exceed the pressure that causes the formation to break, and open up. This allows fracturing fluids to enter the formation through into the fracture and further propagate the fracture until the rate at which fluids go into the formation, via the rock faces of the fracture, equals the rate at which fluids can be pumped into the fracture.

Fractures are either propped open after they are formed by including in the fracturing fluids materials such as finely sized sands or ceramic particles, or in carbonate formations, permeability through fractures may be created by including acids in the fracturing which dissolve some minerals at the face of the fracture to create wormholes along the rock surfaces of the fractures. Proppants may be held in suspension within the fracturing fluids by including additives to increase the viscosity of the fracturing fluids, to decrease the settling rate of the proppants. Alternatively, or in addition, proppants may be utilized with lower densities to decrease the rate at which they settle in the fracture fluids,

Polymers used to increase the viscosity of fracturing fluids may be detrimental to permeability in the vicinity of the fractures, so techniques referred to as slick water fracturing have been developed. These techniques do not utilize thickening polymers, but instead rely on rapid injection of fracturing fluids.

Fracturing methods are disclosed in, for example, U.S. Pat. Nos. 8,183,179, and 7,451,820, the disclosures of which are incorporated herein by reference.

Although significant improvements in technology for fracturing formations have been made, fracturing remains an expensive operation. Fracturing typically costs about half of the total cost to provide a producing horizontal wellbore in a tight gas target formation. Large volumes of water are needed for hydraulic fracturing, and for propped fractures, large volumes of sand need to be combined with the water, and pumped to pressures of, for example, 10,000 to 12,000 Psia at the surface, at rates of 2000 to 5000 gallons per minute. Service companies have been known to charge for fracturing service according to a scale that depends upon the pressure to which the fracturing fluid must be pumped. For example, a fracturing operation requiring that fracturing fluids be pumped to 12,500 psig at the surface will cost significantly more than if a surface pressure of only 11,000 psig were required.

An additional significant cost of providing a fractured well is the cost of friction reduction chemicals for the fracturing fluid. Without these friction reducing chemicals the flow rates achievable would be significantly limited, or surface pressures would be excessive.

Friction reduction coatings or treatments are important in many fields, for example, reducing drag on hulls of ships or airplanes. U.S. Pat. No. 5,054,412 discloses a system for reducing friction by creating a layer of gas between a liquid and the wall of, for example, a vessel. SPE paper SPE 77687 “Case History: Internally Coated Completion Workstring Successes” by Pourciau describes coating of a completion workstring with a “modified epoxy-phenolic” internal coating for abrasion control for a fracturing completion. U.S. Pat. Nos. 6,994,045, 5,445,995, 5,133,519 and 4,932,612, the disclosures of which are incorporated herein by reference, suggest super-hydrophobic surface preparations.

BRIEF SUMMARY OF THE INVENTION

A method to provide a fractured subterranean formation is provided, the method comprising: providing a wellbore from a surface location to the subterranean formation; applying a friction reduction treatment to at least a portion of an inside surface of a casing; cementing the casing with the applied friction reduction treatment into at least a portion of the wellbore; and pumping into the wellbore a fluid at a pressure that exceeds a fracture pressure of the subterranean formation thereby forming at least one fracture within the subterranean formation wherein the fluid is in contact with at least a portion of the inside surface of the casing with the applied friction reduction treatment.

The fractures produced by the present invention may be propped using proppants, or the fracturing fluid may include reactants to react with the surface of the rock faces to result in permeability along the fracture. The fractures of the present invention may be utilized in vertical or horizontal wells, to produce natural gas, light tight oil, or for injection of fluids into the formation.

In one embodiment of the present invention, the fractures are provided in formations known as tight gas formations. These formations are sometimes referred to as shale gas formations, tight sands, source rock formations or basin center formations. When the maturity of the kerogens in such formations has not advanced to gas, and the formations still contain oils, the oils are generally relatively light, and are referred to as light tight oil. When tight gas or light tight oil are produced by the present invention, the wellbores provided according to the present invention are generally long and generally horizontal wellbores. The wellbores could be, for example, four thousand to eight thousand feet long, and could be fractured at intervals of, for example, every one hundred to two hundred feet.

Coatings are known for wellbore tubular. These coatings, such as various blends of phenolic resins sold by Tubescope, are used for corrosion control, and are known to improve “hydraulic efficiency”, but are usedin production tubings rather than casings.

BRIEF DESCRIPTION OF FIGURES

FIGS. 1 and 2 are plots of surface pressures as a function of stages for two adjacent wells where one of the two wells has a casing that has been internally coated with a phenolic resin.

DETAILED DESCRIPTION OF THE INVENTION

Wellbores may be provided for the practice of the present invention by known means of drilling and completion of wells. The wellbore for the present invention may be vertical, but the present invention is more beneficial when applied to horizontal wells because the hydraulic pressure drop of the fracturing fluid is more significant when the fluid needs to be transported a relatively long distance through the wellbore. Horizontal laterals may be provided by directional drilling techniques that utilize accelerometers to integrate movement to establish a present position, or by utilizing logging while drilling techniques to maintain the well near a target location within a formation, or within a predetermined distance and direction from a reference wellbore. Techniques are being developed to extend the distance which horizontal wells may be provided, because generally, a longer horizontal section will enable access to a larger volume of a formation more economically because the expense of providing wellheads and wellbores through the overburden are reduced with respect to a volume of formation to be accessed. Techniques such as neutrally buoyant drill pipes or tractors to supplement the weight on the drill bit may be useful.

After a wellbore is provided, it may be completed, for example, by known means of providing casing and cementing the casing in the wellbore. The casing will generally need to be perforated prior to the operation of fracturing the formation. Perforations are generally provided by placing shaped charges in tools that are positioned in the wellbore and the shaped charges detonated. The shaped charges force open holes in the casing, through any cement in the annulus around the casing and into the formation. Thus, communication is established between the inside of the casing and the formation.

The casing may be provided in a series of decreasing sizes. This is because the difference between the fracturing pressure of the formation, and the pore pressure of the formation, permits only a certain distance to be drilled before a single drilling fluid density will not be sufficient to keep the pressure within the wellbore above the pore pressure of the formation being drilled, and below the pressure which will fracture the formation, plus a margin of safety. Thus, at that point, the wellbore will need to be provided with a casing, typically cemented into the wellbore, to isolate the wellbore from the formation and permit continued drilling. Thus, wells are typically provided with a series of casings cemented into the wellbore with the largest diameter casing first, and each subsequent casing having a slightly smaller diameter.

Fracturing, or fracking, of formations is generally accomplished by injection of a slurry of fracturing fluid and proppant into the formation at pressures sufficiently great to exceed the tensile strength of the formation and cause the formation to separate at the point of the perforations. Formations will generally have a direction where the formation is under the least amount of stress, and the fracture will initially propagate in a plane perpendicular to the direction of such least stress. In deep formations, such as is generally the case in formations containing what is known as light tight oil, shale gas, or tight sands formation, the weight of the overburden will generally assure that the direction of minimal stress is a horizontal direction. It is generally the goal to provide horizontal wellbores in such formation in the direction of the minimal formation stress so that fractures from the wellbore will tend to be perpendicular to the wellbore. This allows access to the maximum possible volume of formation from a horizontal wellbore of a limited length.

Methods for hydraulic fracturing of formations are suggested, in for example, U.S. Pat. No. 5,074,359 to Schmidt and U.S. Pat. No. 5,487,831, to Hainey et al.

Propagation of fractures is typically halted or at least inhibited by interfaces between formations because the force exerted at the tip of the fracture can be dispersed at the interface of the formations. Larger fractures may therefore tend to have more rectangular shapes rather than disk shapes as the dimensions of the fracture exceed the height of the formation, and the fracture therefore grows laterally rather than continuing to grow vertically.

Fracking processes are generally initiated by a slug of fluids referred to as a pad, which initiates the fracture, followed by fluids that contain proppants. The proppants are generally finely sized sands. Generally the sands are referred to by the size of mesh which the sand will pass through, and the size of mesh which the sand will not pass through. Typically, a 20-40 mesh sand is used but other sizes, such as 40-50 or 40-60, may be utilized. Sand is also characterized by the “roundness” of the sand particles. Generally rounder sand is utilized in order to create more uniform void spaces between the particles and therefore better permeability within the propped fracture. Fracturing fluids also contain, for example, viscosifiers to slow the rate at which sand will separate from the fluids and permit the sand to be carried farther into the fractures.

Other types of proppants are also known and may be useful in the practice of the present invention. For example, ceramic proppants are known. Coated proppants such as the proppants suggested in U.S. Pat. No. 7,730,948 to Grood et al. may be useful. The coatings suggested by U.S. Pat. No. 7,730,948 are coatings with low coefficients of friction in order to reduce erosion caused by the fracturing fluid. The coatings also are said to make the sand particles more round. Examples of such coatings include antimony trioxide, bismuth, boric acid, calcium barium fluoride, copper, graphite, indium, fluoropolymers (FTFE), lead oxide, lead sulfide, molybdenum disulfide, niobium dielenide, polytetrafluoroethylene, silver, tin, or tungsten disulfideor zinc oxide. Ceramic proppants are suggested, for example, in U.S. Pat. No. 4,555,493 to Watson et al., and low density ceramic proppants are suggested in U.S. Pat. No. 8,420,578 to Usova et al., and such proppants may be useful in the practice of the present invention.

Formations may also be fractured with fracturing fluids that contain a component that reacts with at least some components of the formation, and thereby removing some of the formation at the face of the fracture. Alternatively, the component may react with the formation in a way that creates solids, and the solids could hold the rock faces of the formation apart after pressures are reduced within the fracture. The component that reacts with the formation may be acidic, and the acid may dissolve carbonate rocks on the surface of the fractures, leaving unmatched rock surfaces that close up with paths for fluids to traverse through the fracture to the wellbore. Acid fracturing may be used in conjunction with proppants, or could be used without proppants.

Another additive generally present in fracturing fluids is friction reduction chemicals. U.S. Pat. No. 8,105,985, to Wood et al, for example, discloses acceptable combinations of water soluble fiction reducing polymers useful in fracturing fluids gelled with viscoelastic surfactants. Such friction reduction chemicals may be utilized with the present invention, but optimal amounts of such chemicals may be reduced as a result of the coatings provided to the wellbore tubular.

Fracturing fluids may also contain other components, such as acids for breaking the thickening polymers, salts such as calcium chlorides to increase the density of the fluids, corrosion inhibitors or other additives known to be useful in fracturing fluids.

Fracturing is generally done prior to production tubular being installed in the wellbores. Thus, the full cross sectional area of the well bore is available for fluid flow down the well. The coating of the present invention therefore could be applied to the inside of the casing.

Hydraulic pressure drop due to friction in a pipe in fully turbulent flow increases with the “roughness factor”, which is the effective height of pipe wall irregularities. Thus, providing a friction reduction treatment may, by application of a smoother surface to the inside of a tubular, reduce the hydraulic pressure drop for flow of fluids through the tubular. Providing well bore tubular having a low roughness factor may be accomplished by machining of the tubular, or by providing a coating that would dry, cure, or otherwise result in a smooth surface.

Alternatively, the friction reduction treatment may be accomplished by reduction of the effective roughness factor by providing textures that create, for example, super hyperbolic characteristics such as those suggested in U.S. Pat. Nos. 6,994,045, 5,445,995, 5,133,519 and 4,932,612.

Coatings that are useful to reduce the roughness factor for wellbore tubular, including the inside surface of casings, include, for example, phenolic resins, epoxy, epoxy novolac, nylon, fluorinated and microstructured coatings.

The present invention could be utilized to produce, for example, natural gas, light tight oil, or carbon doxide. The present invention could also be used to provide the ability to inject fluids into the formation. For example, carbon dioxide could be injected for sequestration, or for carbon dioxide flooding to produce hydrocarbons. The present invention could also be utilized to produce fractures for injection of waste water streams.

EXAMPLE 1

Two adjacent horizontal wells were fractured using similar conditions wherein one of the two wells included a casing which was internally coated with a commercially available coating sold as Tuboscope TK805. This product is an oven-baked phenolic resin coating. Friction reduction additives were used for both, with a target concentration of 1500 ppm, but the first twelve stages in the well with uncoated casing required additional friction reduction chemicals to maintain desired pressures and flow rates. The average hydrofracturing pressure at the surface was 11,000 psig. The average flow rate for fracture fluid injection was 63 bpm. FIG. 1 shows the average treating pressure by stage number for 26 stages fractured. Twenty six stages were fractured in both wells. Line 1 is the average pressure at the wellhead for the well without coating on the casing. Line 2 is the average pressure at the wellhead for the well with coating on the casing.

It can be seen that even with additional friction reduction chemicals, the surface pressures with the uncoated casings exceeded the surface pressure with coated casing. Although for stages eleven and greater, the performance was not different, for the initial stages, the coated casing resulted in lower surface pressures.

EXAMPLE 2

In another example, a five inch casing for a horizontal well was coated internally with Tuboscope TK805 and a similar adjacent horizontal well was not. The wells were fractured with the same amount of friction reduction chemicals. The well with the coated casing was fractured at higher flow rates and higher pressures. This resulted in additional fracture fluids being injected, and larger fractures in the well with the coated casing. FIG. 2 is a plot of the fracturing pressure for each of the twenty three stages of the two wells for the well with coated casing (line 3) and the uncoated casing (line 4) along with the average flow rates for fracturing fluids, in barrels per minute, shown on the figure. In this example, all but three of the stages resulted in lower fracturing pressures for the well with the internally coated casing. The difference between the energy costs to pump the fracturing fluids for the two wells was $385,000, and the cost for providing the internal coating was about $250,000, but it is expected that this cost could be significantly reduced by having the service provided on a larger scale. The lower energy cost was lower in spite of having pumped about seven percent more fracturing fluid and proppant than the wellbore having uncoated pipe. The benefits from having been able to inject more proppant could be significant. By having larger fractures, optimal well spacing would be marginally larger, resulting in reduced drilling and completion costs, and increased fracture area for production. This re-optimized pattern would result in additional cost effectiveness in addition to energy savings from reduced pumping power requirements.

EXAMPLE—ALTERNATIVE COATINGS

To compare some additional coating options with the phenolic resin Tuboscope TK805, roughness factors were determined for coupons with a variety of coatings. The surface roughness of the coating samples were evaluated by KEYENCE VK-X200 3D laser scanning microscope. Roughness was measured at three different locations on each sample and the average data were listed in the table. For each measurement, the Wide-Scan mode, which can eliminate field-of-view limitation at high magnification by high-speed and high-precision image stitching, was used to get more accurate values. Relative pressure drops for the same flow-rates compared to an uncoated carbon steel wellbore tubular were measured on a flow channel setup. This measurement was based on water as the fluid. These results are useful to rank order possible coating candidates and demonstrate that significant reductions in pressure drops may be achieved by the use of such coatings.

The table below contains a description of the coating, the measured roughness factor, and the expected pressure drop reduction as a percentage of the pressure drop expected for carbon steel casing. In this table, the coatings are all commercially available.

		Roughness	Pressure drop
	Coating description	factor	reduction percent
	TK805	0.16	33%
	Phenolic resin from
	Tubescope
	TK236 Epoxy Novolac	0.30	59%
	resin from Tubescope
	TK70 powder epoxy from	0.17	49%
	Tubescope
	TK70XT powder epoxy	0.33	65%
	from Tubescope
	Tuboscope TK99 Nylon	0.16	65%
	Curralon fluorinated resin	5.43	46%
	from Curran
	Chemline 2400 from	1.89	17%
	Advanced Polymer Coatings
	AM-C-O 430 from Atometal	2.83	43%
	Polyond-1.5 mil from	6.73	16%
	Polyplating
	Aculon plating w/treatment	3.64	43%
	Aculon plating w/o	3.65	48%
	treatment
	Ni plating by US Plating	7.59	18%

Claims

1. A method to provide a fractured subterranean formation comprising:

providing a wellbore from a surface location to the subterranean formation;

applying a coating selected from the group consisting of epoxy coatings and nylon coatings to at least a portion of an inside surface of a casing;

cementing the casing into at least a portion of the wellbore with the applied coating; and

pumping into the wellbore a fluid at a pressure that exceeds a fracture pressure of the subterranean formation thereby forming at least one fracture within the subterranean formation wherein the fluid is in contact with at least a portion of the inside surface of the casing with the coating.

2. (canceled)

3. (canceled)

4. (canceled)

5. The method of claim 1 further comprising the step of producing hydrocarbons from the subterranean formation

6. (canceled)

7. The method of claim 1 wherein the fluid comprises a proppant.

8. The method of claim 1 wherein the fluid comprises a component that reacts with at least one component of the subterranean formation to cause that component to be at least temporarily dissolved and transported from the surface of the fracture.

9. The method of claim 7 wherein the proppant is sand.

10. The method of claim 7 wherein the proppant comprises ceramic particles.

11. The method of claim 1 wherein at least a portion of the wellbore within the subterranean formation is essentially horizontal.

12. The method of claim 11 wherein fractures are produced at a plurality of locations within the essentially horizontal section of the wellbore.

13. The method of claim 1 wherein the subterranean formation has a permeability of less than 1 millidarcy.

14. The method of claim 5 wherein the hydrocarbon produced comprises natural gas.

15. The method of claim 14 wherein the hydrocarbon produced consists essentially of natural gas.

16. The method of claim 5 wherein the hydrocarbon produced comprises light tight oil.

17. The method of claim 5 wherein the subterranean formation is a hydrocarbon source rock formation.