US20100243242A1

US20100243242A1 - Method for completing tight oil and gas reservoirs

Info

Publication number: US20100243242A1
Application number: US12/724,456
Authority: US
Inventors: Curtis L. Boney; Marie Noelle Dessinges; Bruno Drochon; Don Williamson; Philip F. Sullivan; Francois M. Auzerais; John W. Still; Gregory Kubala; Bruce A. MacKay; Ryan Hartman; Austin Boyd; Rod Shampine
Original assignee: Individual
Current assignee: Schlumberger Technology Corp
Priority date: 2009-03-27
Filing date: 2010-03-16
Publication date: 2010-09-30
Also published as: RU2010111774A; AU2010201068A1; CA2697210A1; MX2010003218A

Abstract

A method and apparatus for processing a subterranean formation comprising stimulating and fracturing a subterranean formation, and drilling the subterranean formation wherein the drilling and fracturing occurs without removing equipment for drilling from the formation. A method and apparatus for drilling and fracturing a subterranean formation, comprising a drill string assembly and a hydraulic fracturing system, wherein the drill string and fracturing system are in communication with a wellbore and wherein the drill string and a fracture formed by the hydraulic fracturing system are less than about 1000 feet apart. A method and apparatus for processing a subterranean formation comprising fracturing a subterranean formation using a hydraulic fracturing system and drilling the subterranean formation using a drill string assembly wherein the drilling and fracturing occurs without removing the drill string from the formation, and wherein the fracturing occurs via ports in the drill string assembly.

Description

PRIORITY

This application claims priority as a non provisional application of U.S. Provisional Patent Application No. 61/211,194, filed Mar. 27, 2009, which is hereby incorporated by reference in its entirety.

BACKGROUND

Many geological formations require hydraulic stimulation to produce hydrocarbons. Examples of formations that require hydraulic stimulation would be tight gas sands such as the Cotton Valley of East Texas, the Barnett Shale in Arkansas, and the Niobrara Sand in Colorado. Such formations are usually hydraulically fractured after the drilling process. The typical procedure would be to drill, then case and cement the well, and then perforate the desired intervals and hydraulically fracture them by injecting fluid into the perforated interval at high pressure.
Completing tight gas and oil wells using hydraulic fracturing and horizontal/deviated wellbores recovers the most reserves in a shorter period of time with less cost than conventional procedures and techniques. Conventional completions normally have a wellbore that is drilled, the drilling assembly is then removed from the wellbore, and the completion assembly is run in the wellbore. After this, the completion or stimulation takes places at each zone of interest. This process is very costly and time consuming. Also, in fracturing operations, proppant is placed in the fracture in order to keep the fracture open after pumping is stopped. Efforts in the past have been made to ease the fracturing operations such as modifying fluid or proppant properties to optimize proppant placement. In any event, a system for increasing the production of a subterranean formation with reduced process steps is needed.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a sectional view of an embodiment of a drill string assembly and subterranean formation.

FIG. 2 is a schematic view of an embodiment of surface equipment and wellbore configured for hydraulic fracturing.

FIG. 3 is a sectional view of a an embodiment of a drill string assembly and a fracture in the subterranean formation.

FIG. 4 is a dimensional view of an embodiment of a wellbore positioned through several fractures in the subterranean formation.

FIG. 5 is a dimensional view of an embodiment of wellbores positioned through several fractures in the subterranean formation.

FIG. 6 is a dimensional view of an alternative embodiment of wellbores in a subterranean formation.

FIG. 7 is a plot of pressure versus time during an embodiment of a hydraulic fracturing operation.

FIG. 8 is a dimensional view of an embodiment of a wellbore and drilling assembly positioned to fracture the subterranean formation.

FIG. 9 is a dimensional view of an alternative embodiment of a wellbore and drilling assembly positioned to fracture the subterranean formation.

FIG. 10 is a schematic diagram of an embodiment of a tangential well-bore stress.

SUMMARY

Embodiments of the invention relate to a method and apparatus for processing a subterranean formation comprising stimulating and fracturing a subterranean formation and drilling the subterranean formation, wherein the drilling and fracturing occurs without removing downhole drilling equipment from the formation. In some embodiments, the drilling and fracturing form a conductive fracture using acid. Some embodiments may benefit from forming a seal along a surface of the formation. In some embodiments, the seal is temporary and/or the seal is placed during drilling. In some embodiments, the drilling accurs using a fluid selected for its density, lubricity, frictional properties, sonic travel properties, carry proppant, formation damage and its ability to modify fluid temperature.
Some embodiments may benefit from introducing a composition along the surface of the subterranean formation. In some embodiments, the composition stabilizes the surface of the subterranean formation. In some embodiments, the composition has a stability that is tailored to degrade over time. In some embodiments, the composition comprises carbon dioxide or nitrogen. In some embodiments, the composition is electrosensitive or magneto sensitive. In some embodiments, the composition comprises a material that melts below formation temperature. In some embodiments, the composition comprises crosslinked polymers.
In some embodiments, the fracturing comprises proppant. In some embodiments, the proppant comprises material to make it swell, shrink, or form acid. In some embodiments, the proppant comprises proppant with multiple diameters.
In some embodiments, a filter cake is formed along a surface of the subterranean formation. In some embodiments, the filter cake comprises a breaker material. In some embodiments, the material is encapsulated. In some embodiments, the filter cake comprises a material to decrease cake permeability. In some embodiments, the material comprises latex or an emulsion. In some embodiments, the filter cake is tailored to prevent or allow fracture. In some embodiments, the filter cake is self-diverting.
In some embodiments, the equipment comprises a drill string. Some embodiments may benefit from controlling and/or blocking the fluid return system. In some embodiments, a pressure on the outer surface of a drill bit is controlled. Some embodiments may benefit from pumping fluid through a bypass, annulus, or a drill string. Some embodiments may benefit from collecting cuttings via a drillstring or annulus. Some embodiments may benefit from introducing a packer into the wellbore. Some embodiments may benefit from triggering the fracturing by dropping a ball into the drillstring. Some embodiments may benefit from using electrical line or optical fibers to provide feedback to control the fracturing.
In some embodiments, the drilling occurs horizontally, vertically, and/or with multiple branches. Some embodiments may benefit from measuring microseismic, temperature, and/or sonic information and controlling the fracturing and/or drilling using the information. Some embodiments may benefit from introducing afoam or an energized fluid into the wellbore.
In some embodiments, the fracturing occurs as the drill string assembly is traveling away from a wellhead. In some embodiments, the fracturing occurs as the drill string assembly is traveling toward a wellhead.
Embodiments of the invention relate to a method and apparatus for drilling and fracturing a subterranean formation comprising a drill string assembly and a hydraulic fracturing system, wherein the drill string and fracturing system are in communication with a wellbore and wherein the drill string and a fracture formed by the hydraulic fracturing system are less than about 1000 feet apart. Some embodiments may benefit from a packer. In some embodiments, drill string is configured to withstand exposure to hydraulic fracturing. In some embodiments, the hydraulic fracturing system is configured to fracture one stage at a time. Some embodiments may benefit from a seal that encompasses a wellbore, drill string assembly, and a hydraulic fracturing fluid inlet port. In some embodiments, the drill string assembly is configured to deliver hydraulic fracturing fluid.
Embodiments of the invention relate to a method and apparatus for processing a subterranean formation comprising fracturing a subterranean formation using a hydraulic fracturing system and drilling the subterranean formation using a drill string assembly, wherein the drilling and fracturing occurs without removing the drill string from the formation, and wherein the fracturing occurs via ports in the drill string.

DETAILED DESCRIPTION

A method for fracturing while drilling is desirable for increased efficiency and reduced costs. Creating subterranean fractures without removing the drilling equipment from a wellbore eliminates individual process steps such as drilling, casing, completing, and perforating. This technique enables fracturing operations and uses less hardware for completion in the wellbores. Throughout this application, reference is made to fracturing a formation. In this application, unless indicated otherwise, fracturing may encompass stimulating a formation or providing a matrix treatment to the formation as well as fracturing a formation.

Mechanical Equipment

Drilling
Any drilling equipment could be used for the drilling aspect of embodiments of this invention. The equipment may be selected for its resilient properties over a high pressure regime and upon exposure to a variety of chemical processes, mechanical stress created by drilling, fracturing, and proppant placement, and/or high temperatures. At a minimum, the drilling equipment should include a drillbit. Further, the drilling equipment may include protective shields and/or electrical components designed to withstand harsh conditions. For example, some embodiments may benefit from the couplers described in U.S. Pat. Nos. 6,866,306 and 6,641,434, which are hereby incorporated by reference. Also, the drilling equipment may contain nozzles or other fluid delivery mechanisms to deliver drilling fluid and/fracturing fluid and/or other fluids.
FIG. 1 includes a downhole drilling assembly that includes downhole drilling equipment and illustrates a wellsite system in which embodiments of the present invention may be employed. The wellsite can be onshore or offshore. In this exemplary system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments of the invention can also use directional drilling, as will be described hereinafter.
A drill string 12 is suspended within the borehole 11 and has a bottomhole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11, the assembly 10 including a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook. A top drive system could alternatively be used.
In the example of some embodiments, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this manner, the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation. The drilling fluid may also be cooled by injecting cooling liquids, fluids, or gases near the pump 29 or the port in the swivel 19.
The bottom hole assembly 100 of the illustrated embodiment a logging-while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a roto-steerable system and motor, and drill bit 105.
The LWD module 120 is housed in a special type of drill collar and can contain one or a plurality of logging tools. More than one LWD and/or MWD module can be employed, e.g. as represented at 120A (References throughout to a module at the position of 120 can alternatively mean a module at the position of 120A as well.). The LWD module includes measuring, processing, and storing information capabilities, as well as the ability to communicate with the surface equipment. In some embodiments, the LWD module includes a pressure measuring device.
The MWD module 130 is also housed in a special type of drill collar and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In some embodiments, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
The placement of wires in drill pipes for carrying signals has been studied. Some early approaches to a wired drill string are disclosed in U.S. Pat. Nos. 4,126,848, 3,957,118, and 3,807,502 and in the publication “Four Different Systems Used for MWD,” W. J. McDonald, The Oil and Gas Journal, pages 115-124, Apr. 3, 1978.
Using inductive couplers located at the pipe joints has also been studied. The following disclose use of inductive couplers in a drill string: U.S. Pat. No. 4,605,268; Russian Federation published patent application 2140527, filed Dec. 18, 1997; Russian Federation published patent application 2040691, filed Feb. 14, 1992; and WO Publication 90/14497A2. Also, see U.S. Pat. Nos. 5,052,941, 4,806,928, 4,901,069, 5,531,592, 5,278,550; and 5,971,072.
U.S. Pat. Nos. 6,641,434 and 6,866,306, are both hereby incorporated by reference and describe a wired drill pipe joint that is for reliably transmitting measurement data in high-data rates, bidirectionally, between a surface station and locations in the borehole. The '434 and '306 patents disclose a low-loss wired pipe joint in which conductive layers reduce signal energy losses over the length of the drill string by reducing resistive losses and flux losses at each inductive coupler. The wired pipe joint is robust in that the wired pipe joint remains operational in the presence of gaps in the conductive layer.
A particularly advantage is controlled steering or “directional drilling.” In this embodiment, a roto-steerable subsystem 150 is provided. Directional drilling is the intentional deviation of the wellbore from the path it would naturally take. In other words, directional drilling is the steering of the drill string so that it travels in a desired direction. Directional drilling is advantageous in offshore drilling because it enables many wells to be drilled from a single platform. Directional drilling also enables horizontal drilling through a reservoir. Horizontal drilling enables a longer length of the wellbore to traverse the reservoir, which increases the production rate from the well. A directional drilling system may also be used in vertical drilling operation as well. Often the drill bit will veer off of a planned drilling trajectory because of the unpredictable nature of the formations being penetrated or the varying forces that the drill bit experiences. When such a deviation occurs, a directional drilling system may be used to put the drill bit back on course.
Directional drilling includes the use of a rotary steerable system (“RSS”). The RSS includes rotating the drill string from the surface and downhole devices cause the drill bit to drill in the desired direction. Rotating the drill string greatly reduces the likelihood of the drill string getting hung up or stuck during drilling. Rotary steerable drilling systems for drilling deviated boreholes into the earth may be generally classified as either “point-the-bit” systems or “push-the-bit” systems.
In the point-the-bit system, the axis of rotation of the drill bit is deviated from the local axis of the bottom hole assembly in the general direction of the new hole. The hole is propagated in accordance with a three point geometry defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the bottom hole assembly close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. In its idealized form, the drill bit is not required to cut sideways because the bit axis is continually rotated in the direction of the curved hole. Examples of point-the-bit type rotary steerable systems, and how they operate are described in United States Patent Application Publication Number 2001/0052428 and U.S. Pat. Nos. 6,401,842, 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and 5,113,953, which are all hereby incorporated by reference.
In the push-the-bit rotary steerable system there is usually no specially identified mechanism to deviate the bit axis from the local bottom hole assembly axis. Instead, the requisite non-collinear condition is achieved by causing either or both of the upper or lower stabilizers to apply an eccentric force or displacement in a direction that is preferentially orientated with respect to the direction of hole propagation. Again, there are many ways in which this may be achieved, including non-rotating (with respect to the hole) eccentric stabilizers (displacement based approaches) and eccentric actuators that apply force to the drill bit in the desired steering direction. Steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. In its idealized form the drill bit is required to cut sideways in order to generate a curved hole. Examples of push-the-bit type rotary steerable systems and how they operate are described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated by reference.
In some embodiments, the drilling motor may be top drive (from a rotary table). In some embodiments, the motor may be driven at the bit and feature some modification such as using a static screen isolating tools from the wear and tear of hydraulic fracturing. In some embodiments, the drill string may be partially rotating. In some embodiments, the drill components may need to be specially configured to resist being lodged into the wellbore during drilling or fracturing, which may be especially important during directional drilling.
Coiled Tubing
Coiled tubing has long been used in well operations in order to place desirable fluids such as acids, cement and the like in a well utilizing a relatively simple apparatus comprising a long length of tubing, often as long as 25,000 feet, wound onto a large spool or reel. In coiled tubing operations, tubing from the reel is fed into the wellbore utilizing an injector mechanism which is well known in the art. Fluids can be fed through a fitting on the tubing reel, through the tubing to a tool disposed on the inserted end of the coiled tubing within the well. In some embodiments, coiled tubing with drilling capabilities may be used in addition to or in place of drilling equipment.
Fracturing
Fracturing a subterranean formation with a drilling string in the wellbore requires equipment that has been tailored for use with a wellbore that may not include casing or completion. For example, some surface equipment at the well head or wellbore casing or cement may not be present. A choke line, bleedoff, and/or pressure seal may be configured to protect the drill string. High pressure pumps, blending equipment, proppant storage and delivery, and other components of the system may need to be streamlined or aligned to provide individual stages of treatment instead of multiple stages. That is, less pumps or other equipment may be needed for some embodiments of the invention. FIG. 2 provides a schematic diagram of how the equipment may be arranged. Especially, FIG. 2 illustrates that the number of pumps and other surface equipment may be reduced to provide one stage at a time fracturing treatments instead of multiple stages at one time.
Fracture tanks 201, transfer tanks 202, proppant feeders 203, proppant conveyer 204, hopper 205, liquid transport trailer 206, fluid blending unit 207, proppant blender 208, job monitoring unit 209, pumpers 210, manifold trailer 211, nitrogen pumpers 212, carbon dioxide transports 213, booster 214, and pumper 215, densitometer 216, flowmeter 217, pressure transducer 218, and pumper 219 may all be configured to provide fracturing while drilling to the well 220. At the well 220, the wellhead (not pictured) may be configured to administer drill equipment and fracturing equipment simultaneously.
Packers
In some embodiments, packers may be used to isolate sections of the wellbore. The packer may be mechanical, inflatable, or swellable. To provide a seal, the packer may mechanically squeeze, expand upon exposure to a fluid pressure, and/or contain a material that swells upon exposure to a fluid or other conditions. The packers may be mechanical or chemical or both. They may have a means of activation and/or release that is mechanical or chemical or both. In some embodiments, the packers may be temporary packers. In alternative embodiments, the packers may remain in place until mechanically removed. In some embodiments, the packers may be deployed to isolate regions of the wellbore or wellhead from flow backup from a hydraulic fracturing operation or from a drilling operation. In some embodiments, the packers may have mechanisms to keep from getting stuck in undesired regions of the wellbore.
Ball.
In some embodiments, a ball may be introduced into the wellbore to trigger drilling or fracturing. Aspects of the use of a ball are described in more detail below.

Chemistry

Embodiments of the invention may relate to several chemical processes that enhance the effectiveness of fracturing or drilling or both. Drilling fluid, fracturing fluid, pills, filter cake, proppant, tracers, annular protection fluid, and cooling systems may be employed to facilitate embodiments of the invention. In some embodiments, acid fracturing may be employed, such as the fracturing described in U.S. Pat. No. 7,644,761, 7,306,041 and 6,828,280, which are all three incorporated by reference herein in their entirety.
Drilling fluid may comprise components to significantly increasing the mud weight or otherwise controlling the drilling fluid density. As drilling proceeds (especially for a horizontal well), some embodiments may create zones of various permeability along the newly generated well faces by weighing the drilling mud with additives. The concentration of additives (from 0 to a certain percentage by weight of the drilling mud) would form a filter cake of increasing permeability. The drilling fluid is cooled by injecting liquid CO₂, nitrogen, or other liquid gas at the surface to cool the drilling fluid sufficiently to create thermally induced fractures in the desired geological formations near the drill bit.
Adding a material to the drilling fluid that melts at some temperature above ambient and below formation temperatures would significantly increase the impact on the formation by allowing the drilling fluid to carry significantly more energy. When the drilling fluid with these materials reaches the formation area the materials would melt, absorbing significant energy and cooling the formation more than would be possible with fluids alone. Further, these materials could be chosen such that the liquids generated by melting the materials would provide other useful chemical activity downhole (such as producing liquid acid, gelling, breaking, crystallization of something in the fluid, or other processes).
The hydraulic fractures may be created using water, acid, oil, hydrocarbon gas, carbon dioxide, nitrogen gas, and any combination of these. The carrier fluid can generally be any liquid carrier suitable for use in oil and gas producing wells. One such liquid carrier is water. The liquid carrier can comprise water, can consist essentially of water, or can consist of water. Water will typically be a major component by weight of the fluid. The water can be potable or non-potable water. The water can be brackish or contain other materials typical of sources of water found in or near oil fields.
A salt may be present in the fluid carrier. The salt can be present naturally if brine is used, or can be added to the fluid carrier. For example, it is possible to add to water; any salt, such as an alkali metal or alkali earth metal salt (NaCO₃, NaCl, KCl, etc.). The salt is generally present in weight percent concentration between about 0.1% to about 5%, from about 1% to about 3% by weight. One useful concentration is about 2% by weight. Salt maybe used in higher concentrations to make a more dense fluid and thus enabling higher pressures at the fracturing point and lower pressures at the surface. This makes for less hydraulic horsepower and expensive pressure control equipment.
The crosslinked polymer can generally be any crosslinked polymers. The polymer viscosifier can be a metal-crosslinked polymer. Suitable polymers for making the metal-crosslinked polymer viscosifiers include, for example, polysaccharides such as substituted galactomannans, such as guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl guar (CMG), hydrophobically modified guars, guar-containing compounds, and synthetic polymers. Crosslinking agents based on boron, titanium, zirconium or aluminum complexes are typically used to increase the effective molecular weight of the polymer and make them better suited for use in high-temperature wells.
Other suitable classes of polymers effective as viscosifiers include polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates, and ammonium, alkali metal, and alkaline earth salts thereof. More specific examples of other typical water soluble polymers are acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkyleneoxides, other galactomannans, heteropolysaccharides obtained by the fermentation of starch-derived sugar and ammonium and alkali metal salts thereof.
Cellulose derivatives are used to a smaller extent, such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC) and carboxymethycellulose (CMC), with or without crosslinkers. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to have excellent proppant-suspension ability even though they are more expensive than guar derivatives and therefore have been used less frequently, unless they can be used at lower concentrations.
In other embodiments, the crosslinked polymer is made from a crosslinkable, hydratable polymer and a delayed crosslinking agent, wherein the crosslinking agent comprises a complex comprising a metal and a first ligand selected from the group consisting of amino acids, phosphono acids, and salts or derivatives thereof. Also the crosslinked polymer can be made from a polymer comprising pendant ionic moieties, a surfactant comprising oppositely charged moieties, a clay stabilizer, a borate source, and a metal crosslinker. Said embodiments are described in U.S. Patent Publications US2008-0280790 and US2008-0280788 respectively, each of which are incorporated herein by reference.
Linear (not cross-linked) polymer systems may be used. However, in some cases, may not achieve the full benefits because they may require more concentration. Any suitable crosslinked polymer system may be used, including for example, those which are delayed, optimized for high temperature, optimized for use with sea water, buffered at various pH's, and optimized for low temperature. Any crosslinker may be used, for example boron, titanium, zirconium, aluminum and the like. Suitable boron crosslinked polymers systems include by non-limiting example, guar and substituted guars crosslinked with boric acid, sodium tetraborate, and encapsulated borates; borate crosslinkers may be used with buffers and pH control agents such as sodium hydroxide, magnesium oxide, sodium sesquicarbonate, and sodium carbonate, amines (such as hydroxyalkyl amines, anilines, pyridines, pyrimidines, quinolines, and pyrrolidines, and carboxylates such as acetates and oxalates) and with delay agents such as sorbitol, aldehydes, and sodium gluconate. Suitable zirconium crosslinked polymer systems include by non-limiting example, those crosslinked by zirconium lactates (for example sodium zirconium lactate), triethanolamines, 2,2'-iminodiethanol, and with mixtures of these ligands, including when adjusted with bicarbonate. Suitable titanates include by non-limiting example, lactates and triethanolamines, and mixtures, for example delayed with hydroxyacetic acid. Any other chemical additives may be used or included provided that they are tested for compatibility with the viscoelastic surfactant. For example, some of the standard crosslinkers or polymers as concentrates usually contain materials such as isopropanol, n-propanol, methanol or diesel oil.
The viscoelastic surfactant can generally be any viscoelastic surfactant. The surfactant is present in a low weight percent concentration. Some suitable concentrations of surfactant are about 0.001% to about 1.5% by weight, from about 0.01% to about 0.75% by weight, or even about 0.25%, about 0.5% or about 0.75% by weight.
The VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic and combinations thereof. Some non-limiting examples are those cited in U.S. Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et al.), each of which are incorporated herein by reference. The viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous environment that contribute to the increased viscosity of the fluid (also referred to as “viscosifying micelles”). These fluids are normally prepared by mixing in appropriate amounts of VES suitable to achieve the desired viscosity. The viscosity of VES fluids may be attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting viscous and elastic behavior.
Non-limiting examples of suitable viscoelastic surfactants useful for viscosifying some fluids include cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, nonionic surfactants, and combinations thereof.
In general, particularly suitable zwitterionic surfactants have the formula:
RCONH—(CH₂)_a(CH₂CH₂O)_m(CH₂)_b—N⁺(CH₃)₂—(CH₂)_a′(CH₂CH₂O)_m′(CH₂)_b′COO⁻
in which R is an alkyl group that contains from about 11 to about 23 carbon atoms which may be branched or straight chained and which may be saturated or unsaturated; a, b, a′, and b′ are each from 0 to 10 and m and m′ are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and (a+b) is from 2 to 10 if m is 0; a′ and b′ are each 1 or 2 when m′ is not 0 and (a′+b′) is from 1 to 5 if m is 0; (m+m′) is from 0 to 14; and CH₂CH₂O may also be OCH₂CH₂.
In an embodiment of the invention, a zwitterionic surfactants of the family of betaine is used. Two suitable examples of betaines are BET-0 and BET-E. The surfactant in BET-O-30 is shown below; one chemical name is oleylamidopropyl betaine. It is designated BET-O-30 because as obtained from the supplier (Rhodia, Inc. Cranbury, N.J., U.S.A.) it is called Mirataine BET-O-30 because it contains an oleyl acid amide group (including a C₁₇H₃₃alkene tail group) and contains about 30% active surfactant; the remainder is substantially water, sodium chloride, and propylene glycol. An analogous material, BET-E-40, is also available from Rhodia and contains an erucic acid amide group (including a C₂₁H₄₁alkene tail group) and is approximately 40% active ingredient, with the remainder being substantially water, sodium chloride, and isopropanol. VES systems, in particular BET-E-40, optionally contain about 1% of a condensation product of a naphthalene sulfonic acid, for example sodium polynaphthalene sulfonate, as a rheology modifier, as described in U.S. Patent Application Publication No. 2003-0134751. The surfactant in BET-E-40 is also shown below; one chemical name is erucylamidopropyl betaine. As-received concentrates of BET-E-40 were used in the experiments reported below, where they will be referred to as “VES”. BET surfactants, and other VES's that are suitable for the embodiments according to the invention, are described in U.S. Pat. No. 6,258,859. According to that patent, BET surfactants make viscoelastic gels when in the presence of certain organic acids, organic acid salts, or inorganic salts; in that patent, the inorganic salts were present at a weight concentration up to about 30%. Co-surfactants may be useful in extending the brine tolerance, and to increase the gel strength and to reduce the shear sensitivity of the VES-fluid, in particular for BET-O-type surfactants. An example given in U.S. Pat. No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS), also shown below. Other suitable co-surfactants include, for example those having the SDBS-like structure in which x=5-15; other co-surfactants are those in which x=7-15. Still other suitable co-surfactants for BET-O-30 are certain chelating agents such as trisodium hydroxyethylethylenediamine triacetate. The rheology enhancers of the embodiments according to the invention may be used with viscoelastic surfactant fluid systems that contain such additives as co-surfactants, organic acids, organic acid salts, and/or inorganic salts.
Some embodiments use betaines; for example BET-E-40. Although experiments have not been performed, it is believed that mixtures of betaines, especially BET-E-40, with other surfactants are also suitable. Such mixtures are within the scope of embodiments of the invention.
Other betaines that are suitable include those in which the alkene side chain (tail group) contains 17-23 carbon atoms (not counting the carbonyl carbon atom) which may be branched or straight chained and which may be saturated or unsaturated, n=2-10, and p=1-5, and mixtures of these compounds. Some betaines are those in which the alkene side chain contains 17-21 carbon atoms (not counting the carbonyl carbon atom) which may be branched or straight chained and which may be saturated or unsaturated, n=3-5, and p=1-3, and mixtures of these compounds. These surfactants are used at a concentration of about 0.5 to about 10%, or from about 1 to about 5%, or even from about 1.5 to about 4.5%.
Exemplary cationic viscoelastic surfactants include the amine salts and quaternary amine salts disclosed in U.S. Pat. Nos. 5,979,557, and 6,435,277 which have a common Assignee as the present application and which are hereby incorporated by reference. Examples of suitable cationic viscoelastic surfactants include cationic surfactants having the structure:
R₁N⁺(R₂)(R₃)(R₄)X⁻
in which R₁has from about 14 to about 26 carbon atoms and may be branched or straight chained, aromatic, saturated or unsaturated, and may contain a carbonyl, an amide, a retroamide, an imide, a urea, or an amine; R₂, R₃, and R₄are each independently hydrogen or a C₁to about C₆aliphatic group which may be the same or different, branched or straight chained, saturated or unsaturated and one or more than one of which may be substituted with a group that renders the R₂, R₃, and R₄group more hydrophilic; the R₂, R₃and R₄groups may be incorporated into a heterocyclic 5- or 6-member ring structure which includes the nitrogen atom; the R₂, R₃and R₄groups may be the same or different; R₁, R₂, R₃and/or R₄may contain one or more ethylene oxide and/or propylene oxide units; and X⁻ is an anion. Mixtures of such compounds are also suitable. As a further example, R₁is from about 18 to about 22 carbon atoms and may contain a carbonyl, an amide, or an amine, and R₂, R₃, and R₄are the same as one another and contain from 1 to about 3 carbon atoms.
Cationic surfactants having the structure R₁N⁺(R₂)(R₃)(R₄)X⁻ may optionally contain amines having the structure R₁N(R₂)(R₃). It is well known that commercially available cationic quaternary amine surfactants often contain the corresponding amines (in which R₁, R₂, and R₃in the cationic surfactant and in the amine have the same structure). As received commercially available VES surfactant concentrate formulations, for example cationic VES surfactant formulations, may also optionally contain one or more members of the group consisting of alcohols, glycols, organic salts, chelating agents, solvents, mutual solvents, organic acids, organic acid salts, inorganic salts, oligomers, polymers, co-polymers, and mixtures of these members. They may also contain performance enhancers, such as viscosity enhancers, for example polysulfonates, for example polysulfonic acids, as described in U.S. Pat. No. 7,084,095 which is hereby incorporated by reference.
Another suitable cationic VES is erucyl bis(2-hydroxyethyl) methyl ammonium chloride, also known as (Z)-13 docosenyl-N-N-bis(2-hydroxyethyl) methyl ammonium chloride. It is commonly obtained from manufacturers as a mixture containing about 60 weight percent surfactant in a mixture of isopropanol, ethylene glycol, and water. Other suitable amine salts and quaternary amine salts include (either alone or in combination in accordance with the invention), erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; erucylamidopropyltrimethylamine chloride, octadecyl methyl bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl) ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl) ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl) ammonium iodide; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl) ammonium iodide; and cetylamino, N-octadecyl pyridinium chloride.
Many fluids made with viscoelastic surfactant systems, for example those containing cationic surfactants having structures similar to that of erucyl bis(2-hydroxyethyl) methyl ammonium chloride, inherently have short re-heal times and the rheology enhancers of the embodiments according to the invention may not be needed except under special circumstances, for example at very low temperature.
Amphoteric viscoelastic surfactants are also suitable. Exemplary amphoteric viscoelastic surfactant systems include those described in U.S. Pat. No. 6,703,352, for example amine oxides. Other exemplary viscoelastic surfactant systems include those described in U.S. Pat. Nos. 6,239,183; 6,506,710; 7,060,661; 7,303,018; and 7,510,009 for example amidoamine oxides. These references are hereby incorporated in their entirety. Mixtures of zwitterionic surfactants and amphoteric surfactants are suitable. An example is a mixture of about 13% isopropanol, about 5% 1-butanol, about 15% ethylene glycol monobutyl ether, about 4% sodium chloride, about 30% water, about 30% cocoamidopropyl betaine, and about 2% cocoamidopropylamine oxide.
The viscoelastic surfactant system may also be based upon any suitable anionic surfactant. In some embodiments, the anionic surfactant is an alkyl sarcosinate. The alkyl sarcosinate can generally have any number of carbon atoms. Alkyl sarcosinates can have about 12 to about 24 carbon atoms. The alkyl sarcosinate can have about 14 to about 18 carbon atoms. Specific examples of the number of carbon atoms include 12, 14, 16, 18, 20, 22, and 24 carbon atoms. The anionic surfactant is represented by the chemical formula:
R₁CON(R₂)CH₂X
wherein R₁is a hydrophobic chain having about 12 to about 24 carbon atoms, R₂is hydrogen, methyl, ethyl, propyl, or butyl, and X is carboxyl or sulfonyl. The hydrophobic chain can be an alkyl group, an alkenyl group, an alkylarylalkyl group, or an alkoxyalkyl group. Specific examples of the hydrophobic chain include a tetradecyl group, a hexadecyl group, an octadecentyl group, an octadecyl group, and a docosenoic group.
To provide the ionic strength for the desired micelle formation, in some cases, the treatment fluids of the embodiments according to the invention may comprise a water-soluble salt. Adding a salt may help promote micelle formation for the viscosification of the fluid in some instances. In some embodiments, the aqueous base fluid may contain the water-soluble salt, for example, where saltwater, a brine, or seawater is used as the aqueous base fluid. Suitable water-soluble salts may comprise lithium, ammonium, sodium, potassium, cesium, magnesium, calcium, or zinc cations, and chloride, bromide, iodide, formate, nitrate, acetate, cyanate, or thiocyanate anions. Examples of suitable water-soluble salts that comprise the above-listed anions and cations include, but are not limited to, ammonium chloride, lithium bromide, lithium chloride, lithium formate, lithium nitrate, calcium bromide, calcium chloride, calcium nitrate, calcium formate, sodium bromide, sodium chloride, sodium formate, sodium nitrate, potassium chloride, potassium bromide, potassium nitrate, potassium formate, cesium nitrate, cesium formate, cesium chloride, cesium bromide, magnesium chloride, magnesium bromide, zinc chloride, and zinc bromide.
All thicknened fluids may contain a breaker to reduce fracture formation damage or to facilitate the return of the fracturing fluids from the fracture as normally used.
The composition also typically contains proppants. The selection of a proppant involves many compromises imposed by economical and practical considerations. Criteria for selecting the proppant type, size, and concentration is based on the needed dimensionless conductivity, and can be selected by a skilled artisan. Such proppants can be natural or synthetic (including but not limited to glass beads, ceramic beads, sand, and bauxite), coated, or contain chemicals; more than one can be used sequentially or in mixtures of different sizes or different materials. The proppant may be resin coated, or pre-cured resin coated, provided that the resin and any other chemicals that might be released from the coating or come in contact with the other chemicals of the Invention are compatible with them. Proppants and gravels in the same or different wells or treatments can be the same material and/or the same size as one another and the term “proppant” is intended to include gravel in this discussion. In general the proppant used will have an average particle size of from about 0.15 mm to about 2.39 mm (about 8 to about 100 U.S. mesh), more particularly, but not limited to 0.25 to 0.43 mm (40/60 mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20), 0.84 to 1.68 mm (12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh) sized materials. Normally the proppant will be present in the slurry in a concentration of from about 0.12 to about 0.96 kg/L, or from about 0.12 to about 0.72 kg/L, or from about 0.12 to about 0.54 kg/L. The fluid may also contain other enhancers or additives.
In other embodiments, the composition may further comprise an additive for maintaining and/or adjusting pH (e.g., pH buffers, pH adjusting agents, etc.). For example, the additive for maintaining and/or adjusting pH may be included in the treatment fluid so as to maintain the pH in, or adjust the pH to, a desired range and thereby maintain, or provide, the necessary ionic strength to form the desired micellar structures. Examples of suitable additives for maintaining and/or adjusting pH include, but are not limited to, sodium acetate, acetic acid, sodium carbonate, potassium carbonate, sodium bicarbonate, potassium bicarbonate, sodium or potassium diacetate, sodium or potassium phosphate, sodium or potassium hydrogen phosphate, sodium or potassium dihydrogen phosphate, sodium hydroxide, potassium hydroxide, lithium hydroxide, combinations thereof, derivatives thereof, and the like. The additive for adjusting and/or maintaining pH may be present in the treatment fluids of the embodiments according to the invention in an amount sufficient to maintain and/or adjust the pH of the fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate additive for maintaining and/or adjusting pH and amount thereof to use for a chosen application.
In some embodiments, the composition may optionally comprise additional additives, including, but not limited to, acids, fluid loss control additives, gas, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction reducers, combinations thereof and the like. For example, in some embodiments, it may be desired to foam the composition using a gas, such as air, nitrogen, or carbon dioxide. In one certain embodiment, the composition may contain a particulate additive, such as a particulate scale inhibitor.
In some embodiments of the invention, the composition may be used for carrying out a variety of subterranean treatments, where a viscosified treatment fluid may be used, including, but not limited to, drilling operations, fracturing treatments, and completion operations (e.g., gravel packing) In some embodiments, the treatment fluids may be used in treating a portion of a subterranean formation. In certain embodiments, the composition may be introduced into a well bore that penetrates the subterranean formation. Optionally, the treatment fluid further may comprise particulates and other additives suitable for treating the subterranean formation. For example, the treatment fluid may be allowed to contact the subterranean formation for a period of time sufficient to reduce the viscosity of the treatment fluid. In some embodiments, the treatment fluid may be allowed to contact hydrocarbons, formations fluids, and/or subsequently injected treatment fluids, thereby reducing the viscosity of the treatment fluid. After a chosen time, the treatment fluid may be recovered through the well bore.
In certain embodiments, the treatment fluids may be used in fracturing treatments. In the fracturing embodiments, the composition may be introduced into a well bore that penetrates a subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in a portion of the subterranean formation. Generally, in the fracturing embodiments, the composition may exhibit viscoelastic behavior which may be due. Optionally, the treatment fluid further may comprise particulates and other additives suitable for the fracturing treatment. After a chosen time, the treatment fluid may be recovered through the well bore.
The composition according to the invention provides the following benefits when fracturing permeable formations in the 50 to 90 degC temperature range, or even the 54 to 82 degC temperature range: higher viscosity at a given temperature with lower polymer concentration (71.1 degC at a shear rate of 100 s/s and 25 minutes at temperature—prior art fluid 130 cp, fluid according to the invention 210 cp); improved fluid loss control (static leakoff test in an 80 mD core at71.1 degC—prior art fluid spurt loss 4.81, C_w=0.006088, fluid according to the invention spurt loss 2.61, C_w=0.001598); improved shear recovery (viscosity at 100/s after 2 minutes shear at 100/s—prior art fluid 100 cp, fluid according to the invention 175 cp); less sensitive to the presence of surfactants and de-emulsifiers.
The methods of the invention are also suitable for gravel packing, or for fracturing and gravel packing in one operation (called, for example frac and pack, frac-n-pack, frac-pack, StimPac treatments, or other names), which are also used extensively to stimulate the production of hydrocarbons, water and other fluids from subterranean formations. These operations involve pumping a slurry of “proppant” (natural or synthetic materials that prop open a fracture after it is created) in hydraulic fracturing or “gravel” in gravel packing In low permeability formations, the goal of hydraulic fracturing is generally to form long, high surface area fractures that greatly increase the magnitude of the pathway of fluid flow from the formation to the wellbore. In high permeability formations, the goal of a hydraulic fracturing treatment is typically to create a short, wide, highly conductive fracture, in order to bypass near-wellbore damage done in drilling and/or completion, to ensure good fluid communication between the rock and the wellbore and also to increase the surface area available for fluids to flow into the wellbore.
Gravel is also a natural or synthetic material, which may be identical to, or different from, proppant. Gravel packing is used for “sand” control. Sand is the name given to any particulate material from the formation, such as clays, that could be carried into production equipment. Gravel packing is a sand-control method used to prevent production of formation sand, in which, for example a steel screen is placed in the wellbore and the surrounding annulus is packed with prepared gravel of a specific size designed to prevent the passage of formation sand that could foul subterranean or surface equipment and reduce flows. The primary objective of gravel packing is to stabilize the formation while causing minimal impairment to well productivity. Sometimes gravel packing is done without a screen. High permeability formations are frequently poorly consolidated, so that sand control is needed; they may also be damaged, so that fracturing is also needed. Therefore, hydraulic fracturing treatments in which short, wide fractures are wanted are often combined in a single continuous (“frac and pack”) operation with gravel packing For simplicity, in the following we may refer to any one of hydraulic fracturing, fracturing and gravel packing in one operation (frac and pack), or gravel packing, and mean them all.
In a particular embodiment, fluids that comprise emulsions may be selected. The invert emulsion may be of the reversible type, whereby the invert emulsion may be converted from a water-in-oil type emulsion to an oil-in-water type emulsion upon exposure to acid, for example. Such reversible oil-based fluids include those described in U.S. Pat. Nos. 6,218,342, 6,806,233 6,790,811, 7,527,097, 7,238,646, 6,989,354, 7,178,550, 6,608,006, 7,152,697, 7,178,594, 7,222,672, 7,238,646 and 7,3777,721, for example, which are herein incorporated by reference in their entirety.
In some embodiments, a degradable material such as polylactic or polyglycolic acid may be used. More information about degradable materials may be found in U.S. Pat. Nos. 7,380,600, 7,565,929, and 7,581,590 which are all three incorporated by reference herein.
Any fracture connecting to the wellbore (either a natural fracture or a created fracture) may be temporarily sealed during some part of the process. Otherwise the open fractures will “steal” fluid from the wellbore and hinder further progress in either drilling or fracturing. Some embodiments relate to ways to chemically seal the fractures, reverse the sealing to make the fractures reconnect to the wellbore, and chemical tracers to verify that the process is occurring as desired downhole.
Solutions to seal at least temporarily the fractures created are:

- Use swellable proppant: once placed in the fracture the proppant would swell and decrease the permeability of the proppant pack. Once the drilling tool is pumped out the hole, a pill could be used to shrink back the proppant to its original shape. The pill could dissolve the swellable proppant by pH or by any other chemical means.
- Use proppant that would automatically slowly release a chemical that would shrink the proppant. It could be a slowly dissolvable material that coat the proppant such as PVA or PVOH. With the time and temperature the coated layer would dissolve and leave the core of the proppant intact. The proppant pack conductivity would be resumed.
- An alternative is to use a double layer coating made of an internal oxidizer and an external oxidizable material. With temperature and time the oxidizer could be triggered to oxidize the external layer and leave the core of the proppant intact.
- Another elegant approach would be to use different size of proppant and use the CRETE concept: weight the proppant stages with a smaller size particle proppant that is entirely dissolvable (particles of PVA or particles of oxidizers or particles of a slowly soluble salt) but which size completely plugs the fracture faces by invading the pores left by the bigger size proppant. This would be specifically manageable with oil based mud where the presence of the oil would decrease significantly the solubility of the small size particles. When drilling is complete the particles would dissolve and the proppant pack conductivity would be resumed.
- Use swellable proppant: once placed in the fracture the proppant would swell and decrease the permeability of the proppant pack. Once the drilling tool is pumped out the hole, a pill could be used to shrink back the proppant to its original shape. The pill could dissolve the swellable proppant by pH or by any other chemical means. Alternatively, unswelling or degradation can be triggered by dissolution of solid acid in the proppant pack or wellbore.
- Use proppant that would automatically slowly release a chemical that would shrink the proppant. it could be a slowly dissolvable material that coat the proppant such as PVA or PVOH. With the time and temperature the coated layer would dissolve and leave the core of the proppant intact. The proppant pack conductivity would be resumed.
- An alternative is to use a double layer coating made of an internal oxidizer and an external oxidizable material. With temperature and time the oxidizer could be triggered to oxidize the external layer and leave the core of the proppant intact.
- Another elegant approach would be to use different size of proppant and use a concept based on the CRETE™ system available from Schlumberger Technology Corporation of Sugar Land, Tex.: weight the proppant stages with a smaller size particle proppant that is entirely dissolvable (particles of PVA or particles of oxidizers or particles of a slowly soluble salt) but which size completely plugs the fracture faces by invading the pores left by the bigger size proppant. This would be specifically manageable with oil based mud where the presence of the oil would decrease significantly the solubility of the small size particles. When drilling is complete the particles would dissolve and the proppant pack conductivity would be resumed.
- In one approach, CleanSEAL™ technology, which is a technology platform that may be commercial obtained from Schlumberger Technology Corporation of Sugar Land, Tex., may be used as a temporary sealant that is acid degradable. CleanSEAL™ is comprised of crosslinked HEC, which breaks rapidly on contact with acid or slowly over time by degradation. A CleanSEAL™ squeeze pill could be placed to seal a fracture entrance at the wellbore. CleanSEAL™ could be placed in conjunction with solid acid. Such a squeeze treatment can also temporarily fill natural fractures connected to the wellbore or created fractures. Systems can be developed both for breaking with dissolved acid either by an acid-breaking polymer or by an internal trigger that is acid-responsive. An effective seal with CleanSEAL™ would allow us to clean up the wellbore by swabbing and circulating acid.

Annular protection fluid will have the properties to prevent the stimulation fluid from moving up the wellbore. These properties come from the combination of a heavy weight or hydrostatic pressure, high viscosity or yield strength, and or particulates that prevent flow into a permeable or thief zone. This fluid maybe captured and reused to lower waste and cost.
Tracers may be placed in the CleanSEAL™ material so one can chemically detect the cleanup process. This detection can even take place downhole with chemical detector instrumentation. Ways to exploit the use of solid acid as it eliminates the need to circulate live acid in a drilling system are also desirable.
In some embodiments, fracturing fluid may comprise lubricating ingredients to help remove the drill string.

Methods

FIG. 3 illustrates an embodiment of a drill string assembly 301 in a wellbore 302 in a subterranean formation 303. The drill string assembly 301 may contain a port or ports 304 that release fluid from the drill string assembly 301 at high pressure to fracture the formation 303, forming a fracture 305. In some embodiments, the port 304 may release an acid, solid latened slurry or other chemical to notch the formation 303 to facilitate fracturing in a later process step as the drill string moves through the wellbore or drills the wellbore. In some embodiments, the port 304 may provide a mechanical means such as a slip, dog, or bit to form a notch. In some embodiments, the port 304 may provide a perforating mechanism. In some embodiments, the port 304 may provide proppant to pack the fracture 305. In some embodiments, the port 304 may provide viscous material to seal the fracture 305 as described in more detail below. In some embodiments, the port 304 may be activated by dropping a ball (not pictured in FIG. 3) down the annulus (not pictured).
Initially, the drill string assembly 301 drills the wellbore 302 in the subterranean formation 303. As it reaches a region that may benefit from hydraulic fracturing, packers 306 and/or packers 307 may be deployed and fluid is introduced through the ports 304 to form a fracture 305. The packers 306 and 307 may be used to protect the wellbore 302 and/or the drill bit assembly 307 and/or mechanical, chemical, electrical, sonic, or other instrumentation and communication devices housed in the drill string assembly components 308. The drill string components 308 may also collect, administer, and direct the drill string assembly 301 via logging while drilling information. For example, the components 308 may be used to identify and direct the drill string assembly 301 to notch regions of the formation 302 that would benefit from fracturing. Additional process steps such as additional fracturing may be desired to fracture regions initially identified with a notch. The components 308 may also comprise microseismic measurement capability.
FIG. 3 illustrates an embodiment wherein the fracturing occurs after the drill string assembly 301, such as downhole drilling equipment, has formed a wellbore, but alternative embodiments are possible. That is, fracturing could occur ahead of the drilling assembly 308. Further, this process appears to be occurring as the drilling assembly 308 travels down the wellbore 302, but the process could also be occurring as the drilling assembly 308 returns from the depths of the wellbore 302 to the surface of the wellbore 308 toward the wellhead (not pictured in FIG. 3).
In fact, in some embodiments, the advantage of ports 304 is that the fracturing may occur above the drill bit assembly 308, providing high pressure and ease of operation down the annulus 309. That is, it may be desirable to continue drilling while fracturing. In some embodiments, the packers 306 may be formed of a degradable material selected to protect or seal the drill bit assembly 307. Alternatively, in some embodiments, a seal may be formed of degradable material that acts as packer 306 in place of or in addition to seal 306.
In some embodiments, fluid may be pumped through ports such as jets in the drill bit assembly 307. In some preferred embodiments, fluid may be pumped through ports 304 above the drill bit assembly 307. In some embodiments wherein the packers 307 may or may not be deployed, fluids may be pumped through the annulus 309 to produce the fracture 305. In some embodiments, coiled tubing and the annulus may be used to fracture and drill. In some embodiments, the drilling assembly and annulus may be used to fracture and drill.
In some embodiments, partial return of material may be selected to cool the bit and to remove tailings. In some embodiments, the fracture may not be sealed and it may be used for underbalanced drilling, that is, intentionally trying to get flow or not blocking flow may be desirable.
In some embodiments, one approach uses horizontal or highly deviated wellbore(s). The wellbore(s) is hydraulically fractured several times along its length. The fractures are made orthogonal to the wellbore and extend into the reservoir to at least near the boundary edge of the desired drainage. These long fractures, while very conductive as compared to the formation, are not conductive enough to meet the drainage goals of the reservoir. This makes these fractures more economical to create because they use fewer resources. After the fractures are created, additional wellbores or branches from the original well bore are added out further in the formation and intersecting the fractures. These additional wellbores can then drain the formation through the fractures that were created earlier.
The wellbore itself can be vertical or horizontal or highly deviated up or down and with or without multibraching wellbore(s). The wellbore(s) can be hydraulically fractured several times along its length. These fractures are connected directly to the wellbore and extend into the reservoir. This makes these fractures more economical to create as they can be created as soon as the wellbore is drilled lowering time and associated cost. One embodiment of the invention provides a means to generate preferential zones for future fractures as the horizontal well is drilled.
In some embodiments, thermal stress can be significant in high Young's modulus formations. Accordingly, embodiments of the invention provide a method to hydraulically stimulate “tight” high Young's Modulus formations while drilling by significantly cooling the drilling fluid. The method to cool the drilling fluid is to inject liquid CO₂into the drilling fluid while drilling in the formation that requires hydraulic stimulation Alternatively, the hydraulic fracture could be induced by significantly lowering the temperature of the drilling fluid in the zone of interest. If the drilling fluid is cooler the than the formation temperature, the hoop stresses at the well-bore can become tensile and the injection pressure required to initiate a fracture can be reduced by several thousand psi. Such fractures are created while drilling by cooling the drilling fluid which would induce an extra tensile force on the borehole wall, in proportion to the difference in temperature between borehole fluid and the geological formation.
An additional embodiment creates a self diverting filter cake while drilling in a horizontal well, in order to generate fractures in the entire drilled zone at the same time when the zone has been entirely drilled.
In some embodiments, as drilling is complete, the entire length of the horizontal well could be fractured, and the zones with the highest permeability would be preferentially fractured while the zone with the lowest permeability would not accept fracturing fluid. Given that the entire zone should be a pay zone, the exact placement of the mud cakes with the highest permeability should not be critical.
This process enables economical flow of hydrocarbon fluids or gas in reservoirs that have a combination of the reservoir pressure, fluid properties and formation permeability result in very low flow to the wellbore(s).
FIG. 4 is a dimensional view of an embodiment of a wellbore 401 positioned through several fractures 402 in a reservoir 403 in the subterranean formation. In a simple block reservoir, this process uses a primary wellbore 401 that would be horizontal on near horizontal through the actual reservoir 403. The wellbore 401 would then be hydraulically fractured many times (more than 2 fractures 402) using conventional techniques used in the industry to complete the well 404 and isolate the different fractures 402 while they are being made from each other. The fractures 402 would be left conductive to the reservoir fluids and gas as shown by fluid flow arrows 405 in FIG. 4, but not conductive enough to satisfactorily drain the reservoir 403 from volumes, time or economics.
FIG. 5 is a dimensional view of an embodiment of wellbores 501. The fractures 502 would then be accessed by another wellbore(s) 501 further into the reservoir 503. This additional wellbore 501 would enable the produced fluid less restriction to flow by shorting the distance down the fracture it must travel to a wellbore 501. The wellbore 501 would then open a high capacity venue for the fluid to flow out. The additional wellbore(s) 501 may come from another lateral leg from the same wellbore that is used to make the fractures 502 from or other wellbores in or near the reservoir 503. The vertical position of the extra wellbores 501 maybe positioned either up or down from the others to drain a different fluid or gas (as illustrated by the fluid flow lines 504) from the reservoir 503 than the other one(s). An example one be the lowest wellbore 501 would be water from the fracture and thus freeing up fracture conductivity for the gas to up and out.
These extra drain holes 501 can be completed without the cost of isolation completion as it will not be necessary to do so and this lowers cost. If it is desirable to drill the drain hole prior to fracturing, then they can be filled with polymer, drilling fluid, or any material that will help prevent the flow of frac fluid down the wellbore while fracturing. This process is best used in wells where the rock 505 around the wellbore is sufficient strength to produce the well without collapse.
FIG. 6 is a dimensional view of an alternative embodiment of wellbores 601 in a subterranean formation 602. That is, the vertical legs of the wellbores 601 may be selected to drain regions of the reservoir 603 based upon locations of the fractures 604 and/or flow patterns of the water, oil, or gas illustrated by the flow lines 605.
FIG. 7 shows a typical sequence of pressure versus time during a hydraulic fracturing operation. The fracture initiation pressure is the maximum pressure shown on the plot above and is determined by the hoop stresses on the formation, the tensile strength of the formation and the formation pore pressure. In low porosity, low permeability or “tight” formations the fracture initiation pressure may be so high that it would not be feasible to attempt fracturing while drilling. By cooling the drilling fluid so that it is significantly less than the formation temperature, the fracture initiation pressure could be reduced significantly as shown in the following diagram and equations and it would then be feasible to create a tensile fracture.
The tangential well-bore stress σ_θθ as illustrated in some embodiments by FIG. 10 is given by;
σ_θθ=σ_H+σ_h−2(σ_H−σ_h)cos 2θ−2P _o−(P _b −P _o) (1)
where σ_His the maximum horizontal stress,
σ_his the minimum horizontal stress,
θ is the angle relative to maximum horizontal stress
P_ois the formation pore pressure
P_bis the borehole hydraulic pressure
In the case where θ=0 or 180 which is where the tensile forces will be greatest and in formations where permeability is very low and we can neglect the formation pore pressure equation (1) reduces to
σ_θθ=3σ_h−σ_H −P _b (2)
If the borehole fluid temperature is less than the formation temperature there will be an extra tensile force
σ_T =−αEΔT/1−γ (3)
where σ_Tis the thermal stress
α is the linear coefficient of thermal expansion of the formation
E is the Young's Modulus of the formation
ΔT is the temperature difference between borehole fluid and formation
γ is the Poisson's ratio of the formation
Including equation 3 in equation 2 we now have
σ_θθ=3σ_h−σ_H+σ_T −P _b (4)
Where σ_Tis a negative or tensile force if the drilling fluid is cooler than the formation.
If the sum of all the terms on the right hand side of equation 4 are negative (tensile) and exceed the tensile strength of the formation, a fracture will initiate. The tensile strength of most rock formations is assumed to be 1/12 of the compressive strength. For example, in a formation with a compressive strength of 24000 psi we'd expect a tensile strength of 2000 psi. If the minimum horizontal stress were 5000 psi and the maximum horizontal stress were 6000 psi, and the hydraulic pressure from the drilling fluid were 4000 psi, a fracture could be initiated if the thermal stress exceeded 3000 psi. For formations with high Young's Modulus, the tensile forces due to thermal stress are of the order of 1000 psi for every 10 degrees Celsius the drilling fluid is cooler than the formation temperature. Thus if the mud could be cooled to 30 degrees Celsius cooler than formation temperature, a tensile fracture would be initiated.
The thermal stress is highest in zones of high Young's Modulus, and tight, low porosity zones which are difficult to conventionally hydraulically stimulate can have Young's moduli sufficiently high that the thermal stress would facilitate creating a tensile fracture. This could be achieved by significantly increasing the mud weight or the pump pressure while drilling through the interval requiring hydraulic fracturing.
In some embodiments, a packer may be placed above the drill bit. Judicial placement of a packer above the drill bit would improve the efficiency further. By cooling the borehole fluid sufficiently, a tensile fracture could be initiated without exceeding the pressure rating of the packer. In some embodiments, a packer may be activated when the drilling fluid is cooled sufficiently and/or before fracturing occurs.
An alternative therefore to fracturing while drilling is to drill the entire well and generate fractures from different zones at the end of the drilling operation all in once at the same time. The drilling and fracturing fluids can be different and the drilling equipment can be at least partially removed (in case of an horizontal well) and not damaged by the proppant stages. This implies, however, the use of a diversion technique in order to fracture all the zones at once.
An additional embodiment of a fracturing while drilling process is also provided. The process depends on the idea of drilling some distance in to the reservoir, fracturing a zone, temporarily sealing a zone, then resuming drilling. The process repeats until the desired length of the wellbore has been drilled and fractured.
The process, as illustrated in some embodiments by FIG. 8 and in some embodiments by FIG. 9, is as follows.
1) Once drilled through or partially through zone of interest or reservoir 801, circulate annular protection fluid to the annulus.
2) prop ball 802 and displace with cutting or formation breakdown fluid.
3) Open cutting ports (not shown) and cut or break down formation 805 to initiate the fracture 804.
4) propand displace larger ball 803 to open frac ports (not shown).
5) Fracture well.
6) Pull pipe 806 up to shear the annular protection fluid 807 and circulate or reverse out of the wellbore 808. Reverse balls 803, 802 to surface at this time.
7) Run drilling pipe 806 back to bottom to close ports.
8) Continue drilling to next interval 809.
9) Repeat steps 1 through 8 until all zones are stimulated. (FIG. 6)
10) Come out of the wellbore with the drilling assembly 810. Flow well to produce
In the above process, the drilling assembly maybe pulled back up the hole for up to 1000′ to insure the security of the assembly in case of wellbore collapse.
In an alternative embodiment, one could place an additive such as a latex or an emulsion that would replace temporarily the mud cake or that would be placed on the top of the mud cake and decrease locally the permeability of the mud cake. This additive would be placed in stages either of various concentrations or in an on and off manner. When the additive is present the mud cake would be of very low permeability since the additive would form an impermeable film of the surface of the mud cake, when the additive is not present the mud cake would be of standard permeability value encountered with standard mud cakes.
When the entire zone is drilled, the drilling equipment would be removed leaving a drilling well with zones of lowest permeability than others. As fracturing fluid would be pumped in the horizontal well at a pressure sufficient to crack the rock wherever the permeability is high enough different zones would be fractured. The zones of lowest permeability would not allow fluid entry and would not be fractured.
An alternative embodiment may place in the additive a responsive material such as a material that is electro-sensitive or magneto-sensitive. As the drilling equipment is removed from the horizontal well from the tip of the well to the wellbore, a signal would be sent through the drilling bit on the way out that would activate the additive wherever it is placed and for example degrade the mud cake for preferential fluid entry. The sequence described above would be inverted but the principle remains the same.

- As the well is drilled place in various amounts (or on/off sequence) an additive in the drilling mud that would be placed inside the mud cake whenever present.
- When the entire zone is drilled, the drilling bit on the way back would activate the additive by sending electric pulses (range of action short enough to be able to activate the additive) or pressure pulses. Wherever the additive is present the mud cake would be removed.
- Wherever the mud cake has been removed, the local permeability would be much higher enabling preferential entry of the fracturing fluids, ie. The additives would be diverting the fracturing fluid in the entire drilled well.

The responsive material could be a drilling mud cake breaker encapsulated in a pressure sensitive membrane or encapsulated in magnetic material that would revert or change conformation with a local magnetic field.
An important note is that the material does not have to invade the entire fracture but it could be used in the first few inches of the fracture length as long as the seal is strong enough to not be open again while the next fractures are open.
Another note is that the described inventions here could be used in other (and maybe more relevant) applications than fracturing while drilling such as means of diverting agents, or sand control issues.
An important note is that the material does not have to invade the entire fracture but it could be used in the first few inches of the fracture length as long as the seal is strong enough to not be open again while the next fractures are open.
In some embodiments, bypassed zones may be the target for combined drilling and fracturing. Instead of “starting over” with a new well from the surface, one option is to drill off horizontally from existing wells. This can be done either with coiled tubing drilling or with rotary steerable technology. Ideally, this horizontal section will be fractured in numerous places to maximize connectivity of the reservoir to the wellbore.
The above processes can be also used to stimulate the formation where acid or other chemical that will dissolve the rock, such as HCl with Carbonate formation, to stimulate will be injected below fracturing pressures. This etches the face of an already present fracture or wormhole a small channel some distance from the wellbore out into the formation.
Advantages
A technique that requires less fracturing operations and less hardware for completion in the wellbores will reduce cost of field development and speed up production. This will reduce cost of field development and speed up production.
This process enables economical flow of hydrocarbon fluids or gas in reservoirs that have a combination of the reservoir pressure, fluid properties and formation permeability result in very low flow to the wellbore(s).
The methods herein could be used in other applications than fracturing while drilling such as means of diverting agents, or resolving sand control issues.
In formations where an open hole completion is desired, such as horizontal wells in tight formations, fracturing while drilling would lead to significant savings in rig time and operational efficiency.
The preceding description has been presented with reference to presently preferred embodiments of the invention. Persons skilled in the art and technology to which this invention pertains will appreciate that alterations and changes in the described structures and methods of operation can be practiced without meaningfully departing from the principle, and scope of this invention. Accordingly, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

Claims

1. A method for processing a subterranean formation, comprising:

stimulating and fracturing a subterranean formation; and

drilling the subterranean formation,

wherein the drilling and fracturing occurs without removing downhole drilling equipment from the formation.

2. The method of claim 1, wherein the drilling and fracturing form a conductive fracture using acid.

3. The method of claim 1, further comprising forming a seal along a surface of the formation.

4. The method of claim 3, wherein the seal is temporary.

5. The method of claim 3, wherein the seal is placed during drilling.

6. The method of claim 1, wherein the drilling occurs using a fluid selected for its density and its ability to modify fluid temperature.

7. The method of claim 1, further comprising introducing a composition along the surface of the subterranean formation.

8. The method of claim 7, wherein the composition stabilizes the surface of the subterranean formation.

9. The method of claim 7, wherein the composition has a stability that is tailored to degrade over time.

10. The method of claim 7, wherein the composition comprises carbon dioxide or nitrogen.

11. The method of claim 7, wherein the composition is electrosensitive or magneto sensitive.

12. The method of claim 7, wherein the composition comprises a material that melts below formation temperature.

13. The method of claim 7, wherein the composition comprises crosslinked polymers.

14. The method of claim 1, wherein the fracturing comprises proppant.

15. The method of claim 14, wherein the proppant comprises material to make it swell, shrink, or form acid.

16. The method of claim 14, wherein the proppant comprises proppant with multiple diameters.

17. The method of claim 1, wherein a filter cake is formed along a surface of the subterranean formation.

18. The method of claim 17, wherein the filter cake comprises a breaker material.

19. The method of claim 18, wherein the material is encapsulated.

20. The method of claim 17, wherein the filter cake comprises a material to decrease cake permeability.

21. The method of claim 17, wherein the material comprises latex or an emulsion.

22. The method of claim 17, wherein the filter cake is tailored to prevent or allow fracture.

23. The method of claim 17, wherein the filter cake is self-diverting.

24. The method of claim 1, wherein the equipment comprises a drill string.

25. The method of claim 1, further comprising controlling and/or blocking the fluid return system.

26. The method of claim 1, wherein a pressure on the outer surface of a drill bit is controlled.

27. The method of claim 1, further comprising pumping fluid through a bypass, annulus, or a drill string.

28. The method of claim 1, further comprising collecting cuttings via a drillstring or annulus.

29. The method of claim 1, further comprising introducing a packer into the wellbore.

30. The method of claim 1, further comprising triggering the fracturing by dropping a ball into the drillstring.

31. The method of claim 1, further comprising using optical fibers to provide feedback to control the fracturing.

32. The method of claim 1, wherein the drilling occurs horizontally, vertically, and/or with multiple branches.

33. The method of claim 1, further comprising measuring microseismic, temperature, sonic, information and controlling the fracturing and/or drilling using the information.

34. The method of claim 1, wherein the fracturing comprises introducing a foam or an energized fluid into the wellbore.

35. The method of claim 1, wherein the fracturing occurs as a drill string assembly is traveling away from a wellhead.

36. The method of claim 1, wherein the fracturing occurs as a drill string assembly is traveling toward a wellhead.

37. An apparatus for drilling and fracturing a subterranean formation, comprising:

a drill string assembly; and

a hydraulic fracturing system,

wherein the drill string and fracturing system are in communication with a wellbore and wherein the drill string and a fracture formed by the hydraulic fracturing system are less than about 1000 feet apart.

38. The apparatus of claim 37, further comprising a packer.

39. The apparatus of claim 37, wherein the drill string is configured to withstand exposure to hydraulic fracturing.

40. The apparatus of claim 37, wherein the hydraulic fracturing system is configured to fracture one stage at a time.

41. The apparatus of claim 37, further comprising a seal that encompasses a wellbore, drill string, and a hydraulic fracturing fluid inlet port.

42. The apparatus of claim 37, wherein the drill string is configured to deliver hydraulic fracturing fluid.

43. A method for processing a subterranean formation, comprising:

fracturing a subterranean formation using a hydraulic fracturing system; and

drilling the subterranean formation using a drill string assembly,

wherein the drilling and fracturing occurs without removing the drill string from the formation, and

wherein the fracturing occurs via ports in the drill string assembly.