US20160230515A1

US20160230515A1 - Systems and methods for increasing fracture complexity using acoustic energy

Info

Publication number: US20160230515A1
Application number: US15/023,024
Authority: US
Inventors: Timothy Holiman Hunter; Travis Wayne Cavender; Mark Allen Parker
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2013-12-16
Filing date: 2013-12-16
Publication date: 2016-08-11
Also published as: WO2015094159A1

Abstract

A system is configured to fracture a formation surrounding a subterranean wellbore. In one example, the system includes a tool string configured to be deployed in the wellbore, and an acoustic pulse generator connected to the tool string and configured to transmit acoustic pressure pulses into the formation. The acoustic pulse generator is configured to generate acoustic pressure pulses with a magnitude of at least 1000 pounds per square inch.

Description

BACKGROUND

This disclosure relates to generally subterranean wells, and more specifically to hydraulic fracturing systems employed in subterranean wells.
A fracturing system commonly includes pumps that pressurize fracturing fluid, which may be communicated downhole via the central passageway of a string of conduits disposed within a wellbore. The fracturing system pumps the fracturing fluid downhole and communicates the fluid from the wellbore to a zone of the formation in which the wellbore is formed. The pressurized fracturing fluid functions to form cracks in the formation from which useful gases and fluids can be extracted. The complexity of the fractured formation can affect the amount of useful products that can be extracted from the formation.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 schematically depicts an example fracturing system in accordance with this disclosure.

FIGS. 2-4 schematically depict an example acoustic generator, which can be employed in a fracturing system in accordance with this disclosure.

FIG. 5 depicts another example fracturing system in accordance with this disclosure.

FIG. 6 illustrates an example method of fracturing a subterranean formation.

DETAILED DESCRIPTION

Examples according to this disclosure are directed to systems and methods for applying acoustic pulses to a fractured subterranean formation to increase the complexity of the fracture. In some cases, the acoustic pulses employed to affect the character of the fractured formation can also be used to determine one or more characteristics of the fracture.
In one example according to this disclosure, a system is configured to fracture a formation surrounding a subterranean wellbore. The system includes a tool string configured to be deployed in the well bore, and an acoustic pulse generator connected to the tool string and configured to transmit acoustic pressure pulses into the formation. The acoustic pulse generator is configured to generate acoustic pressure pulses with a magnitude that is in a range from approximately 1000 to approximately 16,000 pounds per square inch (psi). In one example, the acoustic pressure pulses generated by the acoustic pulse generator can have a magnitude that is at least approximately 1000 psi. In another example, the acoustic pressure pulses generated by the acoustic pulse generator can have a magnitude that is at least approximately 6000 psi. In another example, the acoustic pressure pulses generated by the acoustic pulse generator can have a magnitude that is at least approximately 12,000 psi. The foregoing magnitudes of the pressure pulses generated by the pulse generator are independent of any ambient pressure in the wellbore, and would be additive to the pressure within the wellbore area in which the pulse generator is disposed.
Augmenting hydraulic fracturing with high-energy acoustic pressure pulses can have a number of benefits. The acoustic energy can increase the energy available to create fracture geometry, which can act to increase primary and secondary fracture network complexity. The acoustic pulses can also provide indirect benefits to the hydraulic fracturing treatment by enabling alteration of job parameters such as higher rate, increased sand concentration, larger stages, reduced material and treating liquids, and advantageous modification of other hydraulic fracturing parameters. Additionally, hydraulic treatment pumping pressures may be reduced while achieving similar fractures when acoustic energy is applied downhole as a supplemental pressure source affecting the fractured formation. This can enable the creation of more complexity with less capital and operational expenditures, fewer emissions, smaller environmental footprint, and other benefits related to the costs and complexity of fracturing formations to extract useful gases and fluids.
Systems and methods for transmitting acoustic pressure pulses in accordance with this disclosure can have a number of additional benefits. For example, acoustic energy can be used to prevent or mitigate screen-out in casing perforations at targeted formation zones. Acoustic energy can also be employed in a secondary stimulation process as a standalone, or supplemental stimulation technology to re-fracture existing mature wells. In some cases, applying acoustic energy to fractured formations can remove the need for costly processes directed at improving fracture complexity. One such method is sometimes referred to as Altered Sequence Fracturing (or the “Texas Two-Step”), in which the fracturing sequence in a horizontal wellbore is altered. For example, stage 1 is completed and the next adjacent stage (stage 2) is skipped. Stage 3 is completed and then the next treatment stage occurs at the stage 2 location between stages 1 and 3.
FIG. 1 schematic depicts example fracturing system 100 including tool string 102 arranged within wellbore 104, which passes through a number of layers of formation 106 of the well. Wellbore 104 is lined with a casing 108. However, in another example, wellbore 104 can be unlined. Tool string 102 includes an acoustic pulse generator 110 in accordance with this disclosure and an acoustic isolator 112 arranged above pulse generator 110.
Tool string 102 can include a coiled or jointed pipe string. Pulse generator 110 and isolator 112 can be coupled to a portion of tool string 102 and then lowered into wellbore 104 using appropriate equipment on the surface. Additionally, in another example, pulse generator 110 can be suspended within wellbore 104 via a wire line system. In some cases, the tool string that deploys acoustic generator 110 is separate from the tool string that pumps fracturing fluid down wellbore 104 and into formation 106.
Fracturing system 100 is configured to fracture formation 106 to allow for extraction of useful products from the formation, e.g., gas and petroleum products. Fracturing system 100 is a hydraulic fracturing system that is augmented by acoustic fracturing achieved by pulse generator 110. System 100 is configured to pump a fracturing fluid from the surface down wellbore 104. In some cases, system 100 pumps fracturing fluid from the surface into formation 106 via the annulus between string 102 and casing 108. In some cases, system 100 pumps fracturing fluid from the surface into formation 106 via the annulus of tool string 102. The fracturing fluid can include water mixed with sand and can be a gel, foam or slickwater-based fracturing fluid.
Tool string 102 can include valves, baffles, or other components that allow selective communication of the fracturing fluid into formation 106 through perforations in casing 108. In the example of FIG. 1, casing 108 includes perforations 114 adjacent to a particular location of formation 106, which can correspond to a zone of the formation targeted for fracturing.
In some cases, tool string 102 can also include a number of packer devices (not shown). The packers can be employed to seal, or partially obstruct the annulus formed radially between tool string 102 and casing 108. Packers in the example of FIG. 1 would be designed for engagement with cased wellbore 104. However, if the wellbore is uncased or unlined, then uncased or open hole packers can be used instead. Swellable, inflatable, expandable, and other types of packers can be used, as appropriate for the well conditions, or no packers may be used.
In the example of FIG. 1, formation 106 has or is being fractured by fracturing fluid transmitted through tool string 102. Tool string 102 includes acoustic pulse generator 110, which is configured to augment the hydraulic fracturing operations of system 100. In the example of FIG. 1, acoustic pulse generator 110 is generally aligned with perforations 114 and the fractured portion of formation 106. However, in another example, pulse generator 110 can also be arranged further downhole below or uphole above the fractured portion of a formation.
Acoustic pulse generator 110 is a high-energy pulse generator that is configured to generate acoustic pressure pulses with a magnitude in a range from approximately 1000 to approximately 16,000 psi. In one example, the acoustic pressure pulses generated by pulse generator 110 can have a magnitude that is at least 1000 psi. In another example, the acoustic pressure pulses generated by pulse generator 110 can have a magnitude that is at least 6000 psi. In another example, the acoustic pressure pulses generated by pulse generator 110 can have a magnitude that is at least 12,000 psi. The foregoing magnitudes of the pressure pulses generated by pulse generator 110 are independent of any ambient pressure in wellbore 104 and/or fractured formation 106, and would be additive to the ambient pressure within the area in which pulse generator 110 is disposed.
Pulse generator 110 is configured to generate a plurality of acoustic pulses in succession to form an acoustic pressure wave that can be transmitted into fractured formation 106. The energy level of the pressure wave generated by pulse generator 110 can be sufficient to affect the character of the fracture including increasing fracture complexity and also to travel across a large amount of the fracture before being dissipated. As used in this disclosure, increasing fracture complexity can include increasing the number of secondary fractures, often at various azimuths that differ from that of the primary fracture.
In considering the creation of fracture geometry the earth stresses are often considered. The greatest principle earth stress is usually the vertical stress due to the weight of the rock column. The least principle stress is in a horizontal direction and it is overcome when hydraulic fractures are created. The intermediate stress is also a horizontal stress but it is difficult to determine and generally not considered. It is accepted that the hydraulic fracture plane is oriented perpendicular to the least principle earth stress. For example, if the least principle earth stress is oriented N-S, then the created fracture orientation will be E-W. The difference in the horizontal stresses can affect the simplicity or complexity of created fractures. A large difference in horizontal stresses or a high degree of stress anisotropy, will generally result in simple planar fractures. In one condition, stress anisotropy can be overcome as the fracturing process develops and net pressure increases over and above the least principle stress such that it is greater than the intermediate principle stress. Another condition is where there are natural fractures or fissures that can be intersected by the created hydraulic fracture. If pressure increases enough to open these accessory fractures, complexity will be created or enhanced. Systems and methods in accordance with this disclosure can alter the stress anisotropy condition by increasing the pressure in the fracture to overcome the intermediate principle stress and allow complex fracturing to occur.
In one example, fractured formation 106 includes what is sometimes referred to as a “penny” shaped crack. The fracture in formation 106 emanates from wellbore 104 in substantially all directions and forms, from above, a circular shaped crack with a crack radius, r, that spans from the root of the crack at wellbore 104 to the tip in formation 106. Acoustic pulse generator 110 can generate an acoustic pressure wave of sufficient energy to increase the complexity of fractured formation 106 from wellbore 104 radially into the formation by a substantial distance. In one example, the radius of the crack in formation 106 is approximately 1000 feet. In such a case, pulse generator 110 can generate an acoustic pressure wave that will travel approximately 700 feet across fractured formation before becoming dissipated to levels that will not affect the character of formation 106.
As noted above, acoustic pulse generator 110 is a high-energy pulse generator that is configured to generate acoustic pressure pulses with a range of magnitudes, including, e.g., at least 1000 psi, at least 6000 psi, or at least 12,000 psi independent of the pressure within wellbore 104. The output of pulse generator 110 can also be expressed relative to the conditions downhole within wellbore 104 and formation 106. During or after hydraulic fracturing operations executed by system 100, the pressure within wellbore 104 and fractured formation 106 can reach relatively high levels. In one example, the ambient pressure within wellbore 104 and fractured formation is approximately 10,000 psi. The output of pulse generator 110 can be expressed relative to the pressure within wellbore 104 and formation 106.
For example, pulse generator 110 can be configured to increase the ambient pressure within wellbore 104 and fractured formation 106 by 8-10 times. Thus, in the example in which the downhole pressure is approximately 10,000 psi, pulse generator 110 can transmit an acoustic pressure wave including a series of acoustic pulses that will increase the fracture pressure to in a range from approximately 80,000 psi to approximately 100,000 psi. In such examples, the increase in pressure within wellbore 104 and fractured formation 106 due to the pulses generated by pulse generator may be a temporary substantial increase in pressure, which may be referred to as a pressure spike or an instantaneous pressure spike.
In some cases, the path of the acoustic pressure pulses generated by pulse generator 110 or another example pulse generator according to this disclosure can be controlled to direct the energy into formation 106. For example, the number, geometry, location, and size of perforations 114 in casing 108 can be configured to control the azimuth of acoustic pulses generated by pulse generator 110. In another example, an additional downhole tool can be deployed in conjunction with acoustic pulse generator 110 to direct the pulses into formation 106 at a target azimuth.
The energy output level of pulse generator 110 may necessitate isolation of the acoustic pulses from being transmitted up the wellbore. As such, tool string 102 includes acoustic isolator 112, which is configured to damp acoustic pulses transmitted by pulse generator 110 up wellbore 104. Containing acoustic energy downhole within wellbore 104 can be important for several reasons including, e.g., to prevent damage of wellbore tubulars, wellhead, and surface treating equipment, and to concentrate the acoustic energy imparted to formation 106.
Acoustic isolator 112 is arranged along tool string 102 above pulse generator 110. Acoustic isolator 112 can include a number of different types of isolation devices or mechanisms. In one example, acoustic isolator 112 includes a compressible media such as gas or a gas-energized (foamed) fluid in wellbore 104 above the treatment zone to cushion the acoustic pressure wave and significantly reduce the amount of energy that travels up hole above isolator 112. In another example, isolator 112 can include an array of dynamic directional flow restrictors or baffles, which can be configured to allow fracturing fluid flow within wellbore and simultaneously isolate acoustic energy from pulse generator 110. In such example, isolator 112 includes a dynamic flow control devises like conical baffles oriented in such a manner to enable downward flow with minimal restrictions while significantly restricting upward flow/pressure pulse transmission. Examples of acoustic isolators that can be employed with examples according to this disclosure are described in Patent Cooperation Treaty Application No. PCT/US2013/056484 (Attorney Docket No. 17697-0045W01/2013-IP-070884U1), filed Aug. 23, 2013, and entitled “DAMPING PRESSURE PULSES IN A WELL SYSTEM.”
FIG. 1 depicts fracturing system 100 including acoustic pulse generator 110 in accordance with this disclosure in use in a substantially vertical well. However, other examples in accordance with this disclosure can be employed in horizontal wells and wells including wellbores that deviate from vertical and horizontal by a variety of degrees.
FIGS. 2-4 schematically depict example acoustic pulse generator 200. In FIG. 2, pulse generator 200 includes pipe 202, disperser 204, combustion chamber 206, oxidizer tank 208, fuel tank 210, pressurant tanks 212 and 214, and controller 216. In one example, pulse generator 200 is a high-pressure, moving-piston, pulse engine, which is configured to generate a plurality of acoustic pulses that are at least 1000 psi in magnitude and/or configured to increase the pressure within a wellbore and a fractured formation by 8-10 times.
An example of such an engine is the High-Pressure Pulse Engine (HIPPE) designed for motive use in space vehicles by the Rockwell International Corporation, Rocketdyne Division, Canoga Park, Calif., which is described in U.S. Pat. No. 4,258,546, issued Mar. 31, 1981, to Harold S. Stratton. The HIPPE engine described in U.S. Pat. No. 4,258,546 can be modified by removing its nozzle and replacing it with a pipe which is fastened to the combustion chamber of the engine. A disperser can be fastened to the rear of the pipe in such a manner that at least a portion of the disperser extends into the pipe leaving an annular space between the disperser surface and the inside wall of the pipe. The combustion chamber and a volume of the pipe can be injected with a pressurized gas before firing the engine to provide a water-free volume in which controlled combustion can occur. The gaseous pulse discharge of the engine can occur transversely to the longitudinal axis of the engine without any propulsive effect. The gas discharge tube is acoustically tuned by varying the structural dimensions of the pipe exit by either fixed or adjustable devices. A modified HIPPE engine that functions as an acoustic pulse generator in an underwater marine environment is described in U.S. Pat. No. 7,145,836, issued Dec. 5, 2006 to William J. Christoff et al.
In FIG. 2, components of pulse generator 200 are connected to the device by fuel, oxidizer and pressurant lines 218, 220, 222, and 224. Pulse generator 200 can operate on a hypergolic fuel and oxidizer charge, the fuel and oxidizer being fed to the charging chambers of the piston section of combustion chamber 206 by self-opening of check valves 226 and 228 from the fuel and oxidizer tanks 210 and 208, respectively. Pressurant tank 212 feeds pressurized gas, e.g., an inert gas such as nitrogen or helium, to the fuel and oxidizer tanks 210 and 208 through a pair of pressure regulators 230 and 232, respectively, so that the fuel and oxidizer liquids are pressurized. In one example, the fuel and oxidizer liquids are pressurized at about 300 psi pressure above ambient.
The pressurant gas is also fed to the piston section of combustion chamber 206 of pulse generator 200 through a pressure regulator 234 under the control of a solenoid valve 236, which can be opened upon application to the valve 236 of a suitable electrical signal from controller 216. Pressurant gas is also fed to the combustion chamber 206 from a second pressurant tank 214 through a valve 238 connected by line 240 from controller means 50.
As illustrated in FIGS. 2 and 3, pulse generator 200 is modified for sonic use from the HIPPE configuration by removing the HIPPE nozzle and replacing the nozzle with pipe 202 the inside diameter of which is the same as the inside diameter of at least a portion of combustion chamber 206. Pressurant gas is fed to disperser 204 attached to the end of the pipe 202 through line 242 and valve 244. Disperser 204 is attached to the end of pipe 202 by any suitable mechanism, such as a plurality of support members 300, as illustrated in FIG. 3. Support members 300 may be bolted to disperser 204 and welded around the outside of pipe 202. Shapes, other than as shown, may be used for support members 300. Support members 300 support the disperser 204 centrally on the axis of pipe 202.
As shown in FIG. 4, disperser 204 can house a single or double acting axial piston subassembly 400 actuated remotely by pneumatic, hydraulic or electric mechanism 402. In the example shown in FIG. 4 a disperser nose cone 404 is shown mounted to the piston subassembly 400 by a threaded attachment 406 which includes a piston rod roll pin 408, with the piston subassembly retained in the disperser by a snap ring 410. Actuating fluid is introduced to disperser 204 by fluid line 412 and directed by conduit plug 414.
When actuated, the piston subassembly 400 displaces the nose cone 404 a controlled distance toward pipe 202 as shown by phantom line 416. This displacement results in a predetermined, selected change in the area of the annular space between nose cone 404 and pipe 202. The lateral or transverse forces produced cancel each other out since they act equally in a 360° circumference around the axis of pulse generator 200. Additionally, little or no axial propulsive force is produced and the acoustic pulse(s) are propagated substantially equally in all directions around the axis of pipe 202.
In operation, the check valves 226 and 228 (FIG. 2) are opened to allow the charging chambers of the piston section of combustion chamber 206 to be filled with fuel and oxidizer. An electrical signal from the controller means 216 is sent to the solenoid valve 236 allowing gas under pressure to be applied to lift the propellant seals in the piston, permitting propellants to flow into combustion chamber 206 and self-ignite (combust) after gas has been injected into chamber 206 to free it of water. Combustion raises the chamber pressure which moves the piston backward and the backward movement injects propellants into combustion chamber 206 at increasing pressure. Combustion chamber 206 pressure rises rapidly due to the continued injection of propellants and the restricted water exit of the water pipe 202. The piston is moved back rapidly, with continually increasing injection pressure resulting in increasing combustion chamber pressure, until the propellants in the engine-charging chambers are expended and, therefore, after the water is expelled from pipe 202, the combustion gases exit. These combustion gases flow around disperser 204 forming a predetermined, shaped cavity in the surrounding water.
The rate and size of the cavity growth and collapse determine the acoustic energy output by pulse generator 200. The period of the subsequent oscillations of the cavity determine the acoustic spectrum. Moving disperser 204 further into pipe 202 affects the energy level and frequency characteristics of the cavity. Further rapid combustion is nearly in the form of an explosion, producing a pulse of high pressure and therefore an acoustic wave through the medium surrounding pulse generator 200, e.g., fracturing fluid within a wellbore and adjacent fractured formation. After combustion is completed, the piston is pushed forward by propellant tank pressure and the charging chambers then refill with oxidizer and fuel to await the next signal from controller 216. Controller 216 can be operated manually as a simple manual switch or may be an electronic unit which can be programmed to emit a series of switching signals in a sequence so that controlled acoustic signals may be propagated by the HIPPE engine and disperser.
It may be necessary before ignition to remove the water from combustion chamber 206; otherwise, the combustion of the propellants is quenched too quickly. As such, in one example, the water can be replaced by air or other gas from the pressurant tank 214 by opening the valve 236. The water in the forward part of pipe 202 next to combustion chamber 206 can also be replaced by gas supplied from pressurant tank 214
In one example, a modified HIPPE engine including combustion chamber, water pipe, and disperser appropriate for use in fracturing systems according to this disclosure may weigh approximately 80 pounds. The other components (e.g. gas, oxidizer, and pressurant tanks) without propellants may weigh up to about 100 pounds. Propellant weight is determined by the number of pulses desired. Even if an integrated pulse generator with tanks is deployed in a wellbore, the pulse generator (less propellants) is still under 200 pounds. In this example, the fuel, oxidizer, and pressurants can be supplied downhole in a wellbore by one or more supply lines connected to pulse generator 200.
In another example, however, the propellants are included in pulse generator 200. In one example, pulse generator 200 includes enough fuel and oxidizer to generate and deliver at least 20 acoustic pulses without the need for separate supply lines. In one example, pulse generator 200 includes enough fuel and oxidizer to generate and deliver in a range from approximately 20 to 30 acoustic pulses without the need for separate supply lines. In this manner, pulse generator 200 or another acoustic pulse generator in accordance with this disclosure can provide a portable, easily handled, high-pressure, acoustic source which generates a controllable, repeatable and variable pulse output that can be used to increase the complexity of a fractured formation.
In some cases, the acoustic pulses employed to affect the character of a fractured formation can also be used to determine one or more characteristics of the fracture. FIG. 5 schematic depicts example fracturing system 500 including tool string 502 arranged within wellbore 504, which passes through a number of layers of formation 506 of the well. Wellbore 504 is lined with a casing 508. However, in another example, wellbore 504 can be unlined. Tool string 502 includes an acoustic pulse generator 510 in accordance with this disclosure and an acoustic isolator 512 arranged above pulse generator 510.
Fracturing system 500 also includes an array of acoustic sensors 516 suspended from wire lines in wellbores adjacent wellbore 504. Sensors 516 are configured to detect acoustic pulses generated by pulse generator 510. Sensors 516 can also transmit information related to the acoustic pulses to a computing device, e.g., at the surface. The computing device can collect the information from all of the sensors 516 and determine one or more characteristics of fractured formation 506 based on the information related to the acoustic pulses.
Tool string 502 can include a coiled or jointed pipe string. Pulse generator 510 and isolator 512 can be coupled to a portion of tool string 502 and then lowered into wellbore 504 using appropriate equipment on the surface. Additionally, in another example, pulse generator 510 can be suspended within wellbore 504 via a wire line system. In some cases, the tool string that deploys acoustic generator 510 is separate from the tool string that pumps fracturing fluid down wellbore 504 and into formation 506.
Tool string 502 can include valves, baffles, or other components that allow selective communication of the fracturing fluid from tool string 502 into formation 506 through perforations in casing 508. In the example of FIG. 5, casing 508 includes perforations 514 adjacent a particular location of formation 506, which can correspond to a zone of the formation targeted for fracturing. In order to carry out a fracturing operation on a particular one of the zones of formation 506, an associated valve can be opened to allow communication between the central passageway of tool string 502 and the associated zone through perforations, e.g. perforations 514 in casing 508.
In the example of FIG. 5, formation 506 has or is being fractured by fracturing fluid transmitted through tool string 502. Acoustic pulse generator 510 is configured to augment the hydraulic fracturing operations of system 500. In the example of FIG. 5, acoustic pulse generator 510 is generally aligned with perforations 514 and the fractured portion of formation 506. However, in another example, pulse generator 510 can also be arranged further downhole below the fractured portion of a formation.
In this example, acoustic pulse generator 110 is a high-energy pulse generator that is configured to generate acoustic pressure pulses that are at least 1000 psi in magnitude and/or configured to increase the pressure within a wellbore and a fractured formation by 8-10 times. Pulse generator 510 is configured to generate a plurality of acoustic pulses in succession to form an acoustic pressure wave that can be transmitted into fractured formation 506. The energy level of the pressure wave generated by pulse generator 510 can be sufficient to affect the character of the fracture including increasing fracture complexity. Additionally, the pressure wave generated by pulse generator 510 can be capable of traveling across a large amount of the fracture before being dissipated. Pulse generator 510 can be configured and function in substantially similar manner as pulse generators 110 and 200 described above with reference to FIGS. 1-4.
In FIG. 5, two acoustic sensors 516 are shown. However, in another example, fracturing system 500 or another system in accordance with this disclosure can include more than two acoustic sensors configured to detect acoustic signals generated by an acoustic pulse generator suspended in a wellbore adjacent a fractured formation. In one example, more than two acoustic sensors 516 are arranged in wellbores surrounding wellbore 504 such that the sensors 516 are circumferentially disposed about wellbore 504. In such an example, sensors 516 can be configured to detect acoustic pulses from pulse generator 510 in order to determine characteristics of fractured formation 506 at a plurality of locations around wellbore 504.
In the example of FIG. 5 sensors 516 are illustrated as suspended downhole in wellbores adjacent wellbore 504. However, in another example, acoustic sensors could also be located closer to or at the surface adjacent and/or surrounding wellbore 504.
Acoustic sensors 516 can include any of a wide variety of pressure sensors appropriate for sensing signals transmitted through formation 506 across relatively large distances (e.g. on the order of 1000 feet). For example, sensors 516 can include piezoresistive strain gauges, or capacitive, electromagnetic, piezoelectric, or optical pressure sensors. In one example, an acoustic sensor 516 includes an electromagnetic sensor that is configured to measure displacement of a diaphragm of the sensor by, e.g., detecting changes in inductance, Hall Effect, or eddy currents. In one example, acoustic sensor 516 includes an electromagnetic sensor that is configured to measure displacement of a diaphragm of the sensor using a linear variable differential transformer (LVDT).
The acoustic pulses generated by pulse generator 510 can be used to determine one or more characteristics of fractured formation 506. For example, the information related to the acoustic pulses detected and transmitted by the array of circumferentially disposed sensors 516 can be analyzed by a computing device and used to generate a one or multi-dimensional map of the complexity of fractured formation 506. For example, the speed of travel of acoustic pulses generated by pulse generator 510 through the fluid-filled fracture will be slower than through formation 506. The difference in travel speed of the pulses through the fluid filled fracture versus through formation 506 can provide a detectable contrast to determine, e.g., fracture geometry, complexity, and placement.
In one example, sensors 516 and the computing device interpreting/analyzing the signals detected by sensors 516 can determine characteristics of fractured formation 506 by determining deviations from a baseline measurement.
For example, pulse generator 510 can be deployed before or early in the process of hydraulically fracturing formation 506 and sensors 516 can be used to detect and record baseline pulses generated by pulse generator 510 at this stage of operations on the formation. Sometime after this initial measurement of the acoustic pulses passing through formation 506, pulse generator 510 can generate a plurality of high-energy acoustic pulses configured to increase the complexity of fractured formation 506. Sensors 516 can detect these or subsequently generated pulses from pulse generator 510. The detected pulses can be compared to the baseline measurement to determine the difference in the character of fractured formation 506 caused by the high-energy acoustic pulses generated by pulse generator 510.
In another example, acoustic pulses generated by pulse generator 510 can be detected by sensors 516 prior to fracturing of formation 506 to determine a number of parameters by which to carry out hydraulic fracturing. For example, pulse generator can be deployed in wellbore 504 before formation 506 has been fractured. Pulse generator can generate a series of pulses that are then detected by sensors 516. Acoustic sensors can communicate information related to the detected acoustic pulses to a computing device, which can determine one or more characteristics of formation 506 based on the information. Based on the characteristic(s) of formation 506 determined based on the information related to the detected acoustic pulses, hydraulic fracturing parameters, including, e.g., rate, pressure, fracturing fluid properties, and stage durations can be set for hydraulic fracturing.
In one example, acoustic pulses generated by pulse generator 510 can be detected by sensors 516 during fracturing of formation 506 to adaptively modify fracturing parameters by which to carry out hydraulic fracturing. For example, pulse generator can be deployed in wellbore 504 during fracturing of formation 506. Pulse generator can generate a series of pulses that are then detected by sensors 516. Acoustic sensors can communicate information related to the detected acoustic pulses to a computing device, which can determine one or more characteristics of formation 506 based on the information. Based on the characteristic(s) of formation 506 determined based on the information related to the detected acoustic pulses, hydraulic fracturing parameters, including, e.g., rate, pressure, fracturing fluid properties, and stage durations can be modified during hydraulic fracturing to improve the extent to which the fracturing fluid affects the formation.
FIG. 6 depicts of an example method of fracturing a subterranean formation. The example method of FIG. 6 includes pumping a pressurized fluid down a wellbore (600), communicating the pressurized fluid to a surrounding formation to fracture the formation (602), and transmitting a plurality of acoustic pressure pulses into the fractured formation (604). The amplitude of at least one of the acoustic pressure pulses is at least 1000 psi. In some cases, the method of FIG. 6 can also include damping the acoustic pressure pulses in the wellbore above the fractured formation. Additionally, the method of FIG. 6 can include sensing the acoustic pressure pulses transmitted into the fractured formation and determining at least one property of the fractured formation based on the sensed acoustic pressure pulses.
In one example, a fracturing system including a jointed or coiled tubing tool string pumps a fracturing fluid from the surface down a wellbore through the annulus between the wellbore and the tool string or through the annulus of the tool string. The fracturing fluid can include water mixed with sand and can be a gel, foam or slickwater-based fracturing fluid. The fracturing fluid is transmitted downhole to selected locations to fracture the formation surrounding the wellbore. In some cases, the wellbore is cased and the casing includes perforations that allow the fracturing fluid be transmitted through the casing and into the formation. In other cases, the wellbore is uncased or unlined, in which case the fracturing fluid can be transmitted directly into the surrounding formation.
Before, after, or while the formation is hydraulically fractured using fracturing fluid, a plurality of acoustic pressure pulses are transmitted into the formation. In one example, the acoustic pulses are transmitted into the fractured formation by a high-energy acoustic pulse generator during or after hydraulic fracturing. The energy level of the pressure wave generated by the pulse generator is sufficient to affect the character of the fracture including increasing fracture complexity. Additionally, the pulses generated by the pulse generator can travel across a large amount of the fracture before being dissipated to a magnitude that is no longer sufficient to affect the character of the formation.
In some cases, the path of the acoustic pressure pulses generated by the pulse generator can be controlled to direct the energy into the formation. For example, the number, geometry, location, and size of perforations in a casing lining the wellbore can be configured to control the azimuth of acoustic pulses generated by the pulse generator.
In some cases, high-energy acoustic pulses may be employed in wells previously fractured using fracturing fluids. For example, acoustic energy can be employed in a secondary stimulation process as a standalone, or supplemental stimulation technology to re-fracture existing mature wells.
In one example, the acoustic pulse generator generates acoustic pressure pulses with a magnitude in a range from approximately 1000 to approximately 16,000 psi. In one example, the acoustic pulse generator generates acoustic pressure pulses with a magnitude of at least 1000 psi. In another example, the acoustic pulse generator generates acoustic pressure pulses with a magnitude of at least 6000 psi. In another example, the acoustic pulse generator generates acoustic pressure pulses with a magnitude of at least 12,000 psi. The pulse generator is configured to generate the acoustic pulses in succession to form an acoustic pressure wave that is transmitted into fractured formation. Additionally, the pulse generator can be configured to control the amplitude and the frequency of the acoustic pulses.
In one example, the fractured formation includes a “penny” shaped crack. The fracture in the formation emanates from the wellbore in substantially all directions and forms a circular shaped crack with a crack radius, r, that spans from the root of the crack at the wellbore to the fracture tip in the formation. The acoustic pulse generator can generate an acoustic pressure wave of sufficient energy to increase the complexity of the fractured formation from the wellbore radially into the formation by a substantial distance. In one example, the radius of the crack in the formation is approximately 1000 feet. In such a case, the pulse generator can generate an acoustic pressure wave that will travel approximately 700 feet across fractured formation before becoming dissipated to levels that will not affect the character of the formation.
The output of the pulse generator can also be expressed relative to the conditions downhole within the wellbore and formation. During or after hydraulic fracturing operations are executed, the pressure within the wellbore and the surrounding fractured formation can reach relatively high levels. In one example, the pressure within the wellbore and fractured formation is approximately 10,000 psi. In one example, the pulse generator can increase the pressure within the wellbore and fractured formation by 8-10 times. Thus, in the example in which the downhole pressure is approximately 10,000 psi, the pulse generator can transmit an acoustic pressure wave including a series of acoustic pulses that will increase the fracture pressure to in a range from approximately 80,000 psi to approximately 100,000 psi.
In one example, the acoustic pulse generator includes a high-pressure, moving-piston, pulse engine, which is configured to generate a plurality of acoustic pulses that are at least 1000 psi in magnitude and/or configured to increase the pressure within a wellbore and a fractured formation by 8-10 times. In one example, the acoustic pulse generator includes a modified High-Pressure Pulse Engine (HIPPE), such as is described in U.S. Pat. No. 4,258,546, issued Mar. 31, 1981, to Harold S. Stratton, as described above with reference to FIGS. 2-4
The energy output level of the pulse generator may necessitate isolation of the acoustic pulses from being transmitted up the wellbore. As such, the method of FIG. 6 can include damping the acoustic pressure pulses in the wellbore above the fractured formation. The acoustic pulses can be damped by a number of acoustic isolation devices. In one example, a compressible media such as gas or a gas-energized (foamed) fluid can be deployed in the wellbore above the treatment zone to cushion the acoustic pressure wave and significantly reduce the amount of energy that travels up hole above the isolator. In another example, an array of dynamic directional flow restrictors or baffles can be arranged above the acoustic pulse generator to allow fracturing fluid flow within the wellbore and simultaneously isolate acoustic energy from the pulse generator from traveling up the wellbore toward the surface. In one example, conical baffles are included in the tool string and oriented in such a manner to enable downward flow with minimal restrictions while significantly restricting upward flow/pressure pulse transmission. Examples of acoustic isolators that can be employed with examples according to this disclosure are described in Patent Cooperation Treaty Application No. PCT/US2013/056484 (Attorney Docket No. 17697-0045W01/2013-IP-070884U1), filed Aug. 23, 2013, and entitled “DAMPING PRESSURE PULSES IN A WELL SYSTEM.”
In some cases, the method of FIG. 6 include sensing the acoustic pressure pulses transmitted into the fractured formation and determining at least one property of the fractured formation based on the sensed acoustic pressure pulses. The acoustic pulses generated by the pulse generator can be used to determine one or more characteristics of the fractured formation. For example, the information related to the acoustic pulses detected and transmitted by an array of sensors circumferentially disposed around the wellbore can be analyzed by a computing device communicatively coupled to the sensors. The computing device can then generate a one or multi-dimensional map of the complexity of the fractured formation based on the acoustic signals detected by the sensors.
In one example, the sensors and the computing device interpreting/analyzing the signals detected by the sensors can determine characteristics of the fractured formation by determining deviations from a baseline measurement. For example, the pulse generator can be deployed before or early in the process of hydraulically fracturing of the formation and the sensors can be used to detect and record baseline pulses generated by the pulse generator at this stage of operations on the formation. Sometime after this initial measurement of the acoustic pulses passing through the formation, the pulse generator can generate a plurality of high-energy acoustic pulses configured to increase the complexity of the fractured formation. The sensors can detect these or subsequently generated pulses from the pulse generator. The detected pulses can be compared to the baseline measurement by the computing device to determine the difference in the character of the fractured formation caused by the high-energy acoustic pulses generated by the pulse generator.
Acoustic pulses generated by the pulse generator can also be detected by the sensors prior to fracturing of the formation. Such pulse generation and detection can be used to determine a number of parameters by which to carry out hydraulic fracturing, e.g., rate, pressure, fracturing fluid properties, and stage durations. Additionally, in one example, acoustic pulses generated by the pulse generator can be detected by the sensors during fracturing of the formation to adaptively modify fracturing parameters by which to carry out hydraulic fracturing.
Various examples have been described. These and other examples are within the scope of the following claims.

Claims

I claim:

1. An system for fracturing a formation surrounding a subterranean wellbore, the system comprising:

a tool string configured to be deployed in the wellbore;

an acoustic pulse generator connected to the tool string and configured to transmit a plurality of acoustic pressure pulses into the formation, wherein the acoustic pulse generator is configured to generate acoustic pressure pulses comprising a magnitude that is at least approximately 1000 pounds per square inch (psi).

2. The system of claim 1, wherein the acoustic pulse generator is configured to generate acoustic pressure pulses comprising a magnitude that is at least approximately 6000 psi.

3. The system of claim 1, wherein the acoustic pulse generator is configured to generate acoustic pressure pulses comprising a magnitude that is at least approximately 12000 psi.

4. The system of claim 1, wherein the acoustic pulse generator is configured to generate acoustic pressure pulses comprising a magnitude in a range from approximately 1000 to approximately 16,000 psi.

5. The system of claim 1, wherein the acoustic pulse generator comprises a high-pressure, moving-piston, pulse engine comprising:

a combustion chamber;

a pipe comprising a first end connected to the combustion chamber; and

a disperser connected to a second end of the pipe.

6. The system of claim 5, wherein the combustion chamber is configured to combust an oxidized fuel and transmit combustion gases through the pipe and around the disperser to generate an acoustic pressure pulse.

7. The system of claim 1, further comprising a plurality of acoustic sensors arranged adjacent the wellbore and configured to detect the acoustic pressure pulses transmitted by the acoustic pulse generator.

8. The system of claim 7, wherein the acoustic sensors comprise at least one of a piezoresistive strain gauge, or a capacitive, electromagnetic, piezoelectric, or optical pressure sensor.

9. The system of claim 7, further comprising a computing device communicatively coupled to the acoustic sensors, wherein the computing device is configured to:

receive information from the acoustic sensors related to the acoustic pressure pulses; and

determine at least one property of the formation based on the received information.

10. The system of claim 1, further comprising an acoustic isolator connected to the tool string above the acoustic pulse generator, wherein the acoustic isolator is configured to dampen the acoustic pressure pulses.

11. The system of claim 1, wherein the acoustic pulse generator is configured to be connected to the tool string.

12. The system of claim 1, further comprising a wire line configured to be deployed into the wellbore, wherein the acoustic pulse generator is configured to be suspended in the wellbore by the wire line.

13. The system of claim 1, wherein the acoustic pulse generator comprises at least one tank configured to house at least one of an oxidizer, a fuel, or a pressurant.

14. The system of claim 13, wherein the at least one tank is configured to house sufficient fuel and oxidizer to allow the acoustic pulse generator to generate at least 20 acoustic pressure pulses.

15. The system of claim 1, further comprising a supply line connected to and configured to supply at least one of an oxidizer, a fuel, or a pressurant to the pulse generator.

16. The system of claim 1, wherein the acoustic pressure pulses are configured to increase the pressure within at least a portion of the formation by approximately 8-10 times.

17. A method comprising:

pumping a pressurized fluid down a wellbore;

communicating the pressurized fluid to a surrounding formation to fracture the formation; and

transmitting a plurality of acoustic pressure pulses into the fractured formation, wherein an amplitude of at least one of the acoustic pressure pulses is at least approximately 1000 psi.

18. The method of claim 17, wherein the acoustic pressure pulses are transmitted into the fractured formation after the pressurized fluid is communicated to the formation.

19. The method of claim 17, wherein the acoustic pressure pulses are transmitted into the fractured formation while the pressurized fluid is being communicated to the formation.

20. The method of claim 17, wherein the acoustic pressure pulses are transmitted by an acoustic pulse generator arranged adjacent the fractured formation on the tool string.

21. The method of claim 20, wherein the acoustic pulse generator comprises sufficient oxidizer and fuel to generate the plurality of acoustic pressure pulses.

22. The method of claim 21, wherein the acoustic pulse generator comprises sufficient oxidizer and fuel to generate at least 20 acoustic pressure pulses.

23. The method of claim 20, further comprising transmitting an oxidizer and a fuel through at least one supply line connected to the acoustic pulse generator, wherein the acoustic pulse generator is configured to generate the plurality of acoustic pressure pulses using the oxidizer and the fuel transmitted through the at least one supply line.

24. The method of claim 20, further comprising controlling, by the acoustic pulse generator, at least one of an amplitude and a frequency of the plurality of acoustic pressure pulses.

25. The method of claim 17, further comprising:

sensing the plurality of acoustic pressure pulses transmitted into the fractured formation; and

determining at least one property of the fractured formation based on the sensed acoustic pressure pulses.

26. The method of claim 17, further comprising damping the plurality of acoustic pressure pulses in the wellbore above the fractured formation.

27. The method of claim 17, wherein an amplitude of at least one of the acoustic pressure pulses is at least approximately 6000 psi.

28. The method of claim 17, wherein an amplitude of at least one of the acoustic pressure pulses is at least approximately 12,000 psi.

29. The method of claim 16, wherein an amplitude of at least one of the acoustic pressure pulses is in a range from approximately 1000 to approximately 16,000 psi.

30. The method of claim 17, wherein the acoustic pressure pulses are configured to increase the pressure within at least a portion of the formation by approximately 8-10 times.