CHARGE BASED STIMULATION OF ADJACENT WELLS TO FORM INTERCONNECTED FRACTURE NETWORK AND HYDROCARBON PRODUCTION THEREFROM

Abstract

Recovering hydrocarbons from a subterranean formation includes drilling first and second adjacent wells and detonating charges in each thereby causing fractures in the subterranean formation to extend from each well and interconnect in a fracture network. The charge detonations may include charges separated by delay units to create a pulse train at a resonant frequency of the subterranean formation. Sensors may be positioned within one or more of the wellbores and the surface, and the pulse train may be detected by the sensors to ensure the fracture network between the adjacent wellbores is sufficiently interconnected. The adjacent wells may be parallel to each other and separated by an optimal separation distance determined by testing different sections of test wellbores that diverge from an intersection point at a known angle. The charges may be propellant based. Fluids/gases may be injected into injection wells and production performed from interconnected production wells.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Application No. 62/482,591 filed Apr. 6, 2017 and U.S. Provisional Application No. 62/505,454 filed May 12, 2017. Each of these applications is incorporated herein by reference.

BACKGROUND OF THE INVENTION

(1) Field of the Invention

The invention pertains generally to recovering hydrocarbons from subterranean wells. More specifically, the invention relates to a method of utilizing propellant and/or explosives to establish communication by increasing the fracture face area between parallel wellbores or in single wells to thereby improve well production.

(2) Description of the Related Art

Hydraulic fracturing is a known method of stimulating wells. Vast volumes of fracking fluid such as water, chemicals and sand are pumped at high pressure into the wellbore to overcome the tensile strength of the surrounding rock. As the pressure builds, fractures are created extending outward from the wellbore. Sand or other proppants included in the fluid enter the fractures and hold the fractures open after the pressure is reduced.

FIG. 1 illustrates an isometric view of a typical hydraulic drilling site containing a plurality of wells 100, 110, 120. Each well 100, 110, 120 includes a plurality of bi-wing fractures 102, 112, 122 extending radially outward from horizontally orientated wellbores 104, 114, 124. FIG. 2 illustrates a top down view of a horizontal wellbore 104 of FIG. 1 and its associated bi-wing fractures 102.

Although effective, hydraulic fracturing suffers from a number of problems. For one, not all fractures 102, 112, 122 are effective at producing hydrocarbons, especially in rock with low permeability. Typically, up to thirty percent or more of fractures 102, 112, 122 in a shale field do not contribute to increased hydrocarbon recovery. Flow depletion is another problem where a well 100, 110, 120 will start at a high flow rate and then quickly taper off. For instance, after one to two years of starting production, production flow rate may have decreased by eighty percent or higher. Pollution is another concern. With the pumping of millions of gallons of water combined with various chemicals and proppants into the ground, environmentalists are concerned that this fracking fluid will make its way to the surface and contaminate ground water reservoirs. Propellant based stimulation utilizing a horizontal stimulation tool (HST) or the StimGun® or another propellant tool assembly (PTA) is an alternative technique for creating fractures without using large amounts of fracking fluid. PTA involves detonating/deflagrating combustible charges and propellants within the wellbore such that radially extending fractures (including “off plane” fractures) are created therefrom. For example, FIG. 22 illustrates a plurality of propellant charge sections ready for installation, FIG. 23 illustrates a propellant charge section being loaded into an assembly, and FIG. 24 illustrates a plurality of propellant charge assemblies (PTAs) ready for installation into a wellbore. However, PTA techniques create fractures that are shorter in length than those created by hydraulic fracturing. Shorter length fractures are fine for production in higher permeability rock but are not ideal for use in low permeability environments such as shale fields.

BRIEF SUMMARY OF THE INVENTION

In hydraulic fracturing, production is limited by restricted rock face area for production along with rapid depletion of reservoir pressure. The low rates of fracture effectiveness and rapid depletion of a hydraulically fracked well result in inefficient reservoir utilization. An object of some embodiments of the present invention is therefore to increase the exposed sand face area and fracture effectiveness by creating a network of interconnected fractures between adjacent wellbores or in single wells.

An object of some embodiments of the present invention is to increase efficiency of shale field hydrocarbon production while reducing or eliminating the volume of fracking fluids that need to be pumped in to the ground.

An object of some embodiments of the present invention is to map the subterranean features and ensure fracture interconnections by providing sensors in one or more well(s) adjacent to a well in which charge blasts are being detonated.

An object of some embodiments of the present invention is to map the subterranean features and ensure fracture interconnections by detonating a plurality of charge blasts in a wellbore at a predetermined frequency thereby creating an impulse train for detection by one or more surface and/or in-well sensors in adjacent well(s).

An object of some embodiments of the present invention is to increase fracture distance and volumes by detonating a plurality of charge blasts in a wellbore at a predetermined frequency selected according to characteristics of the subterranean formation in which the wellbore is located.

An object of some embodiments of the present invention is to reduce well depletion by injecting production facilitators into a first well and recovering hydrocarbons from adjacently interconnected wells or from other sections of the first well.

An object of some embodiments of the present invention is to use frequency enhanced fracture growth so that propellant created multiple radial fracture creation is much more extensive and more efficient.

An object of some embodiments of the present invention is to detonate/deflagrate at resonant frequency in order initiate/enhance off plane fracturing. Multiple fracturing is easier and more efficient.

According to an exemplary embodiment of the invention there is disclosed a method of recovering hydrocarbons from a subterranean formation. The method includes drilling a first well, drilling a second well adjacent to the first well, and detonating a first charge in the first well thereby causing first fractures in the subterranean formation to extend from the first well toward the second well. The method further includes detonating a second charge in the second well thereby causing second fractures in the subterranean formation to extend from the second well toward the first well, ensuring that at least some of the first fractures interconnect with at least some of the second fractures, and recovering hydrocarbons from at least one of the first well and the second well.

According to an exemplary embodiment of the invention there is disclosed a method of recovering hydrocarbons from a subterranean formation. The method includes drilling a first well, drilling a second well adjacent to the first well, creating a plurality of first fractures extending from the first well and creating a plurality of second fractures extending from the first well. The method further comprises ensuring that at least some of the first fractures interconnect with at least some of the second fractures, and recovering hydrocarbons from at least one of the first well and the second well.

These and other advantages and embodiments of the present invention will no doubt become apparent to those of ordinary skill in the art after reading the following detailed description of preferred embodiments illustrated in the various figures and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in greater detail with reference to the accompanying drawings which represent preferred embodiments thereof:

FIG. 1 illustrates an isometric view of a typical hydraulic drilling site containing a plurality of horizontal wellbores.

FIG. 2 illustrates a top down view of a horizontal wellbore of FIG. 1 and its associated bi-wing fractures.

FIG. 3 illustrates an isometric view of a horizontal drilling site layout containing a plurality of adjacently located wells with interconnected fracture networks according an exemplary embodiment of the present invention.

FIG. 4 illustrates a top down view of the horizontal wellbores of FIG. 3 and their associated interconnected fracture networks.

FIG. 5 illustrates a top down view of a plurality of sensors in a first wellbore for detecting sufficiency of fracture interconnection of a fracture network with a second wellbore after detonating a plurality of charges in the second wellbore according to an exemplary embodiment.

FIG. 6 illustrates the view of FIG. 5 after the charges have been detonated and the fractures extending from the second wellbore toward the first wellbore have been created.

FIG. 7 shows a flowchart of a method of drilling and charge based stimulation of adjacent wells to form an interconnected fracture network therebetween according to an exemplary embodiment.

FIG. 8 shows a flowchart of a method of producing hydrocarbons from a plurality of wellbores having interconnected fracture networks therebetween according to an exemplary embodiment.

FIGS. 9-16 illustrate a plurality of sequential screenshots of a computer simulation for predicting effectiveness of charge intensity and delay units in a particular wellbore according to an exemplary embodiment.

FIG. 17 illustrates a side view of two wells having parallel horizontal wellbores prior to detonating a plurality of charges in a bottom one of the wellbores to create a fracture network according to an exemplary embodiment.

FIG. 18 illustrates the wells of FIG. 17 after the charges have been detonated.

FIG. 19 illustrates a plurality of vertical wellbores having interconnected fracture networks therebetween according to an exemplary embodiment.

FIG. 20 illustrates a plurality of horizontal wellbores in a gun barrel cylinder configuration each having fractures radially extending in all directions around the axle length of the wellbores to form an interconnected fracture network according to an exemplary embodiment.

FIG. 21 illustrates additional screenshots from the computer simulation for a working region of about 500 ft of the horizontal stimulation tool that may be utilized in conjunction with exemplary embodiments of the present invention.

FIG. 22 illustrates a plurality of propellant charge sections ready for installation according to the prior art.

FIG. 23 illustrates a propellant charge section of FIG. 22 being loaded into an assembly.

FIG. 24 illustrates a plurality of propellant charge assemblies (PTAs) loaded and ready for installation into a wellbore according to the prior art.

FIG. 25 illustrates a plurality of horizontal wellbores each having fractures radially extending in all directions around the axle length of the wellbores to form an interconnected fracture network taking advantage of permeability of the subterranean formation according to an exemplary embodiment.

FIG. 26 illustrates wellbore pressure changing over time during a timed ignition according to an exemplary embodiment.

FIG. 27 illustrates a plan view of two adjacent horizontal wellbores having an angle A between their bore directions according to an exemplary embodiment.

FIG. 28 illustrates a projection view of a plurality of a plurality of adjacent horizontal wellbores having an angle between their bore directions according to an exemplary embodiment.

DETAILED DESCRIPTION

FIG. 3 illustrates an isometric view of a horizontal drilling site layout containing a plurality of adjacently located wells 300, 310, 320 according an exemplary embodiment of the present invention. Each well 300, 310, 320 includes a plurality of bi-wing and/or radial fractures 302, 312, 322 extending radially outward from horizontally orientated wellbores 304, 314, 324. Unlike the layout of the hydraulic drilling site of FIG. 1, in FIG. 3 the wellbores 304, 314, 324 are drilled closer together such that the intermediate fractures 302, 312, 322 between the wellbores 304, 314, 324 interconnect with each other and create fracture networks 306, 316. The number of intersecting fractures and intra fracture communication is maximized by shortening the distance between bi-wing fractures 302, 312, 322 from each wellbore 304, 314, 324 such that more fractures extend radially from each wellbore 304, 314, 324 for unit distance than do for a similar distance along the wellbores 104, 114, 124 of FIG. 1. In this way, the layout of the drilling site of FIG. 3 is compressed in area in comparison assuming a same number of wellbores 304, 314, 324 and bi-wing fractures 302, 312, 321 are created. Alternatively, the same area can be covered by the layout of FIG. 3 by increasing both the number of wellbores 304, 314, 324 and the number of bi-wing fractures 302, 312, 321 extending from each wellbore 304, 314, 324.

FIG. 4 illustrates a top down view of the horizontal wellbores 304, 314, 324 of FIG. 3 and their associated interconnected fracture networks 306, 316. As illustrated, the fractures 302 extending outward from a first wellbore 304 interconnect with counterpart fractures extending outward from a second, adjacent wellbore 314. In this example, the first wellbore 304 and the second wellbore 314 run parallel to each other through a target subterranean formation such as a shale field. Fractures 302, 312 are created along an adjacent length of each of the first and second wellbores 304, 314. The fractures 302, 312 extend outward from each wellbore 304, 314 toward the other of the first and second wellbores 304, 314. Between the two wellbores 304, 314 a first interconnected fracture network 306 is created. The fracture network 306 is interconnected meaning that a plurality of the respective fractures 302, 312 from each wellbore 304, 314 are communicatively coupled such that pressure changes in a first of the wellbores 304, 314 will cause pressure changes in the other of the wellbores 304, 314 and vice versa.

In this example, the second wellbore 314 and a third wellbore 324 also run parallel to each other through the target subterranean formation. Fractures 312, 322 are created along a similar adjacent length of each of the second and third wellbores 314, 324 and extend outward from each toward the other of the second and third wellbores 314, 324. Between the two wellbores 314, 324, a second interconnected fracture network 316 is created. Again, the second fracture network 316 is interconnected meaning that a plurality of respective fractures 312, 314 are communicatively coupled such that pressure changes transfer from the second wellbore 314 to the third wellbore 324 and vice versa.

FIG. 5 illustrates a top down view of a plurality of sensors 500 in a first wellbore 304 for detecting sufficiency of fracture interconnection of a fracture network 306 with a second wellbore 314 after detonating a plurality of charges 502 in a second wellbore 314. The view of FIG. 5 is taken after a plurality of fractures 302 have already been created extending radially from the first wellbore 304 toward the second wellbore 314. The fractures 312 of the second wellbore 314 will be created after the charges 502 in the second wellbore 314 are detonated. During the detonation process, the sensors 500 in the first wellbore detect changes in various attributes measured by the sensors 500 as a result of fracture interconnections within fracture network 306.

In some embodiments, the in-well sensors 500 include pressure sensors. At the time illustrated in FIG. 5 prior to the detonation of the charges 502 and prior to the creation of the fractures 312 extending from the second wellbore 314, the sensors 500 will not detect any pressure changes within the first wellbore 304 caused by pressure changes in the second wellbore 314. This is because the existing fractures 302 extending from the first wellbore 304 do not reach the second wellbore 314 and the first wellbore 304 is therefore not in communication with the second wellbore 314.

FIG. 6 illustrates the view of FIG. 5 after the charges 502 have been detonated and the fractures 312 extending from the second wellbore 314 toward the first wellbore 304 have been created. As illustrated, the first wellbore 304 is now in communication with the second wellbore 314 via the interconnected fracture network 306.

During the detonation of the charges 502, the sensors 500 will begin to detect pressure changes as soon as the newly forming fractures 312 extending from the second wellbore 314 interconnect with the previously existing fractures 302 extending from the first wellbore 304. Pressure data captured by the sensors 500 may therefore be utilized to confirm the sufficiency of the interconnections within the fracture network 306. For example, if no pressure changes (or minimal pressure changes) are detected by the sensors 500 during and immediately after the detonation of charges 502, this indicates that the fracture network 306 is not sufficiently interconnected. Larger intensity charges 502 may need to be employed in this case in order to ensure the first and second fractures 302, 312 extend far enough into the fracture network 306 to ensure proper wellbore communication.

In addition to pressure sensors, the in-well sensors 500 may include other types of sensors such as seismic sensors and/or electrical sensors. Seismic sensors in particular may be beneficial to generate three dimensional (3D) maps and gather other data about the various subterranean rock layer formations between the first wellbore 304 and the second wellbore 314. As illustrated in FIG. 5, a plurality of charges 502 may be connected in series with a corresponding plurality of delay units 504 interspaced therebetween. The charges 502 may be a plurality of propellant, PTA, HST, StimGun®, and/or other any other desired explosive or propellant sections with millisecond delay devices acting as delay units 504 between each charge section 502. The delay units 504 each add a predetermined delay time before causing the next charge section 502 to detonate. For example, in the case where one thousand charges 502 are interconnected in series along the wellbore 314 and are separated by a one millisecond delay unit, the detonation of the charges 502 will cause a one kilohertz 1KHz pulse train to be generated along the length of the wellbore 314. In some embodiments, at least ten separate charge sections 502 are coupled in series and detonated at slightly different times (e.g., on the order of millisecond delays) in order to provide a pulse train long enough for seismic analysis.

The pulse train caused by detonating the series of charges 502 are detected by each of the in-well seismic sensors 500 in the first wellbore 304 and data representing the detected seismic vibrations is transmitted back to the surface. Since the position of each charge section 502 and its respective detonation time are known in advance, information regarding the subterranean formation between the first wellbore 304 and the second wellbore 314 can be determined according to the seismic data. Likewise, a plurality of surface sensors 1700 (see FIG. 17), may also detect the pulse train generated by detonating the charges 502, and the data captured by the surface sensors 1700 can be utilized to determine information regarding the various subterranean layers between the surface and the second wellbore 314. This is similar to existing methods of utilizing spaced out surface charges and surface sensors in order to determine characteristics of subterranean formations according to bounce vibrations detected back at the surface. However, in the method described herein, either the sensors 500 and/or the charges 502 may be located within respective wellbores 304, 314, 324. As methods of generating 3D maps and determining characteristics of subterranean formations according to seismic data are well-known in the art, further explanation of specific calculations is omitted herein for brevity.

In some applications, the delay value associated with the delay units 504 may be selected in advance according to a type of the subterranean formation in which fractures 312 are desired to be created. For instance, different types of rock layers have different natural resonance frequencies at which they are easier to vibrate. At these frequencies, the rock's tensile strength may be reduced and fractures easier to create. If the frequency of the pulse train is adjusted to be within a threshold range of the rock's natural resonance frequency, the fractures 312 created by the charge detonation may extend further than they otherwise would. In other words, through experimentation of charge detonation with different delay times between charges in order to create impulse trains of different frequencies, it may be determined that certain delay times between charge pulses achieves a more extensive and better interconnected fracture network 306. Fracture efficiency may thereby be increased by selecting appropriate delay units 504 between a plurality of charges 502 according to the subterranean formation type.

A predicted resonant frequency of the surrounding material may also be determined utilizing other methods and then charge detonations at frequencies near the predicted resonant frequency may be tried. For instance, adding energy to a system will cause the material of the system to vibrate at the resonant frequency. Because resonant frequency may change slightly over time or as the material changes in structure such as fractures are formed, the charge delays may also be set in some embodiments such that the detonation pulse train will have a slightly changing frequency in order to follow or more closely match the actual resonant frequency of the surrounding subterranean formation material. Taking shale with a predicted natural resonance frequency of 1 kHz as an example, the delay units 504 may be adjusted such that the charge sections 502 are detonated and form a detonation pulse train frequency sweeping from 0.9 kHz to 1.1 kHz. The delay unit 504 timings may be pre-set in advance or dynamically adjusted by one or more computer processors during the charge sequence detonation according to sensor 500 feedback.

FIG. 7 shows a flowchart of a method of drilling and charge based stimulation of adjacent wells to form an interconnected fracture network therebetween according to an exemplary embodiment. The steps of the flowchart of FIG. 7 are not restricted to the exact order shown, and, in other configurations, shown steps may be omitted or other intermediate steps added. In this embodiment, the drilling and stimulation process includes the following steps:

A drilling and stimulation phase of operations begins at step 700. This may occur when starting to drill a first well or may occur when adding an additional well to a group of already-drilled wells.

At step 702, an initial well is drilled. For example, with reference to FIG. 3, the initial well drilled at this step may be the first well 300. As illustrated in FIG. 3, the initial well 300 may include a horizontal wellbore 304 drilled through a target subterranean rock formation such as a shale field from which hydrocarbons are to be recovered.

At step 704, charges 502 and their associated delay units 504 are calculated according to simulation data representing the type of subterranean formation. For example, during the drilling process of step 702, data may be gathered representing the subterranean formation. Simulation parameters are updated according to all known data in order to simulate what charge intensities and delay values will optimize the fracture lengths and numbers.

At step 706, a series of charge sections 502 interconnected by delay units 504 according to the values calculated at step 704 are set within the initial wellbore 304. The charges may be set within any desired tool for charge deployment including HST and StimGun® tools or any other propellant tool assembly (PTA) or explosive charge. The enclosure pipe casing (if used) may include holes in any desired patterns to cause fractures to extend outward in said patterns. Bi-wing, off-plane fractures, or any desired charge direction and shape may be utilized in different embodiments. For instance, the prior art casing on PTA assemblies of FIG. 24 will create fractures radiating in all directions. Other user-selectable values may also be calculated or estimated at this step in a similar manner including wellbore fluid types and amounts.

At step 708, surface sensors 1700 are placed in order to detect the pulse train generated by detonation of the plurality of charges 502 set at step 706.

At step 710, the series of charge sections 502 set at step 706 are detonated within the initial wellbore 304 to create fractures 302 extending outward from the initial wellbore 304.

At step 712, the sensor data is reviewed in order to evaluate rock layers around the subterranean formation and in an attempt to determine the distance and coverage of the fractures 302. Other data may also be collected at this step such as to determine whether a desired level of flow capacity is present within the wellbore 304 after the fractures 302 are created.

At step 714, a determination is made as to whether the initial fractures 302 and subterranean formation are as expected. For instance, if little flow capacity is detected, the fractures 302 are found to extend less than an expected distance, and/or the subterranean rock layers are different than expected, these negative results may mean that the simulation parameters need to be updated to better reflect the actual situation. Control proceeds to step 716 in this case. On the other hand, if everything is as expected, control proceeds to step 718 to start work on drilling a next well.

At step 716, the simulation parameters are updated according to the sensor data collected at step 712. Control then returns to step 704 to calculate a better intensity of charges 502 and/or time delays of the delay units 504 to hopefully get better fracture efficiency on a subsequent attempt at detonation.

At step 718, a next well is drilled adjacent to the initial well. For example, the next well may be the second well 310 shown in FIG. 3 including its horizontal wellbore 314 portion running parallel to the horizontal wellbore 304 of the initial well 300. The distance of the newly drilled wellbore 314 from the initial wellbore 304 should be less than double the typical length of the fractures 302, 312 from their respective wellbores 304, 314. For instance, if the simulation results and sensor data reviewed at step 712 indicate that the initial fractures 302 are extending on average about eighty feet from the initial wellbore 304, the new wellbore 314 should be less than one hundred and sixty feet from the initial wellbore 304. In this way, assuming the new fractures 312 extend about the same distance (i.e., on average eighty feet in this example), the new fractures 312 and the initial fractures 302 will have an overlapping portion where interconnection/cross fracture flow can occur. Depending on rock formations, it is expected that new wellbores 314 will be drilled a distance apart from one another in a range from one hundred to five hundred feet apart, which would accommodate fractures and/or cross fracture flow extending about fifty to two hundred and fifty feet. However, the distance of the new wellbore 314 from the adjacent wellbore(s) 302, 324 can be determined and adjusted on a site by site basis according to the actual fracture distances and interconnections predicted according to simulations and/or achieved in actual experimentation.

At step 720, charges 502 and their associated delay units 504 along with possible changes to wellbore fluid types and amounts are calculated according to the simulation data. This step is similar to step 704; however, the simulation data parameters may now be verified to be within a threshold desired accuracy as a result of determining how closely the previous simulated results matched actual results at step 714.

At step 722, a series of charge sections 502 interconnected by delay units 504 according to the values calculated at step 720 are set within the newly drilled wellbore 314.

At step 724, surface sensors 1700 are again placed in order to detect the pulse train generated by detonation of the plurality of charges 502 set in the new wellbore 314 at step 722.

At step 726, in-well sensors 500 are placed within the previously drilled adjacent wellbore(s) such as the initial wellbore 304 for example. In some embodiments, the sensors 500 are placed in one or more adjacent wellbores 304 that already have fractures 302 extending toward the newly drilled wellbore 314. In this way, the in-well sensors 500 can be utilized to detect sufficiency of the interconnection between these adjacent wellbores 304, 314 after detonation of the charges 502. The in-well sensors 500 may include a plurality of different types of sensors such as pressure sensors and seismic sensors as desired to collect different types of data. In this way, the in-well sensors 500 can detect pressure or other changes within the initial wellbore 304 upon detonating charges in the new wellbore 314.

At step 728, the series of charge sections 502 set at step 722 are detonated within the new wellbore 314 in order to create fractures 314 extending outward from the new wellbore 314 toward the one or more adjacent wellbores 304, 324.

At step 730, the sensor data is reviewed in order to evaluate rock layers around the subterranean formation and between the adjacent wellbores 304, 314, and to determine the sufficiency of interconnection between the fractures 302, 312 of these wellbores 304, 314. Other data may also be collected at this step including determining whether a desired level of flow capacity is present within any one of more of the adjacent wellbores 304, 314 after the fractures 302, 312 are in communication with each other.

At step 732, a determination is made as to whether the initial fractures 302 and the newly formed fractures 312 are sufficiently interconnected. Sufficiently interconnected means that cross wellbore flow achieved between adjacent wellbores 304, 314 is greater than a predetermined threshold. For instance, if the in-well sensors 500 do not detect any pressure changes in the initial wellbore 304 when detonating the charges 502 in the second wellbore 314, these negative results may mean that the simulation parameters need to be updated to better reflect the actual situation. Control proceeds to step 734 in this case. On the other hand, if everything is as expected and interconnection of fracture network 306 has been confirmed such as by positive changes in pressure data detected by the in-well sensors 500, control proceeds to step 736 to determine whether work on drilling a next well should be performed.

At step 734, the simulation parameters are updated according to the sensor data collected at step 730. Control then returns to step 720 to calculate a better intensity of charges 502 and/or time delays of the delay units 504 to hopefully get better fracture efficiency and interconnection of the fracture network 306 on a subsequent attempt at detonation.

At step 736, a determination is made of whether there are any more adjacent wells to drill. For instance, after finishing drilling the second wellbore 314 and ensuring the fracture network 306 between the first wellbore 304 and the second wellbore 314 is sufficiently interconnected, work may begin on the third well 320 and its parallel running horizontal wellbore 324. When work is to continue on a new adjacent well, control returns back to step 718. The loop of step 718 to step 736 can repeat as many times as necessary to build as many interconnected wellbores 304, 314, 324 as desired. Likewise, any number of interconnected fracture networks 306, 316 can be formed between the plurality of wellbores 304, 314, 324. Although only three wellbores 306, 316, 324 and two interconnected fracture networks 306, 316 are shown in the attached figures, this is for simplicity of explanation and it is to be understood that these numbers may be increased in actual field deployments.

Once the desired number of wellbores 306, 316, 324 and interconnected fracture networks 306, 316 therebetween are completed, control proceeds from step 736 to step 738 to end the drilling and stimulation phase.

At step 738, the drilling and stimulation phase is now complete and one or more production phases may be started.

FIG. 8 shows a flowchart of a method of producing hydrocarbons from a plurality of wellbores having interconnected fracture networks therebetween according to an exemplary embodiment. The steps of the flowchart of FIG. 8 are not restricted to the exact order shown, and, in other configurations, shown steps may be omitted or other intermediate steps added. In this embodiment, the production process includes the following steps:

The production phase of operations begins at step 800. In some embodiments, this step occurs anytime after the completion of step 738 of FIG. 7.

At step 802, the plurality of wells 300, 310, 320 are partitioned into two different groups: injection wells and production wells. For example, assuming three wells 300, 310, 320 as illustrated in FIG. 3, the middle well 310 may be selected as an injection well and the two adjacent wells 300, 320 on either side may be selected as production wells. Injection wells such as middle well 310 may be selected due to their central location and high connectivity via their fracture network(s) 306, 316 with adjacent production wells 300, 320.

At step 804, an injection process is started by beginning to pump fluids and/or gases into the one or more injection well(s) selected at step 802. Again, taking the example shown in FIG. 3 and assuming the middle well 310 is selected as the injection well, fluids/gases such as methane, salt water, carbon dioxide, solvents, etc. are pumped in to the injection well 310.

At step 806, the fluids and/or gases injected into the injection well 314 at step 804 travel through the interconnected fracture networks 306, 316 toward the production wellbores 304, 324. This causes pressure to be maintained within the production wellbores 304, 324 to facilitate production. Because the wellbores 304, 314, 324 are interconnected via their fracture networks 306, 316, the fluid injection is continued on an ongoing basis during production to keep pressure on the fractures 302, 312, 314 and help hydrocarbons within these fractures 302, 312, 314 make their way back to the one or more production wellbores 304, 314. The continuous fluid injection helps prevent the rapid depletion phenomenon experienced in typical hydraulically fractured wells such as that shown in FIG. 1. The fluids may also be designed to act as solvents to increase mobility of hydrocarbons in place increasing production rates and ultimate total production.

At step 808, hydrocarbons are recovered from the one or more production wellbore(s) 304, 324.

Normal production techniques may be employed at this step so a detailed description is omitted herein for brevity. However, it is worthwhile to note that feedback from the production wells 300, 320 can be utilized to control the fluid injection at the injection well(s) 300. For instance, if production flow rate begins to dip, then injection flow rate may be correspondingly increased. Again, dynamically changing the fluid injection rates at step 804 according to production flow rates at step 808 helps prevent the rapid depletion phenomenon experienced in typical hydraulically fractures wells such as that shown in FIG. 1.

At step 810, a determination is made as to whether production is finished. This step may be performed in any desired manner, but typically will involve determining whether the level of hydrocarbons currently being recovered is sufficient to warrant continued production. Once production is finished, control proceeds to step 812; otherwise, control returns to step 808 to continue recovering hydrocarbons from the production well(s) 300, 320.

At step 812, fluid injection into the injection well(s) 310 is stopped.

At step 814, hydrocarbon production from the production well(s) 300, 320 is stopped. In order to claim any residual hydrocarbons left in the wells 300, 310, 320, this step may be performed a predetermined time duration after injection fluids are stopped at step 812.

At step 816, the production phase is finished.

After step 818, clean up and reclamation procedures may begin. However, in some embodiments, the production process of FIG. 8 may be restarted and different selection of injection wells and production wells may be performed at step 802. Repeating the production process with different injection and production wells may be beneficial to ensure that all recoverable hydrocarbons are produced from the wells 300, 310, 320. Likewise, additional wellbores may be drilled and additional fracture networks created by returning to step 718 of FIG. 7.

Simultaneous execution of drilling, stimulation, injection, and production steps in FIG. 7 and FIG. 8 may also take place in other embodiments. For instance, after drilling and stimulation is completed for a first two wells, injection and/or production may begin on those two wells while drilling and stimulation work continues to form additional interconnected wells. The injection process maintains pressure as the fractures of the new wells interconnect with existing fracture networks and create new fracture networks. Additionally, because the plurality of wells are interconnected and in communication via their fracture networks, even if some hydrocarbons flow out of existing production wells into newly drilled wells, these hydrocarbons will eventually be recovered when production starts on the new wells. In some embodiments, a plurality of wells are simultaneously drilled and then simultaneous stimulation is performed on each.

FIGS. 9-16 illustrate screenshots of a computer simulation for predicting effectiveness of charge 502 intensity and delay units 504 in a particular wellbore 304, 314, 324 according to an exemplary embodiment. The computer simulation screenshots in the examples of FIGS. 9-16 were performed utilizing a dynamic event modeling computer software program called PulsFrac™ by Baker Hughes. However, it should be noted that any desired propellant tool assembly simulation program may be utilized in other applications.

FIG. 9 shows a first screenshot of the computer simulation prior to beginning the charge detonation. The simulation output is generally divided into three graphical rows: a top row 900 shows a plurality of charges on a stimulation tool string located within a wellbore, a middle row 902 shows the pressure within the wellbore, and a bottom row 904 shows the fluid velocity within the wellbore. The legend 906 on the right-hand side from top to bottom indicates the colors for the various data that will be displayed during the simulation. In particular, the data indicating pressure includes the following measurable elements:

TABLE 1
Pressure data
Tool      Tool gas 910
Interior  Tool gas 912
          Air 914
          KCI water 916
          Light oil 918
Annulus 1 Tool gas 920
          Air 922
          KCI water 924
          Light oil 926

Likewise, the data indicating fluid velocity for the bottom row 904 includes the following elements:

• • Tool 928
  • Interior 930
  • Annulus 1 932

After inputting the various simulation parameters, the play/run button 908 is pressed to start the simulation.

FIG. 10 illustrates a second screenshot of the computer simulation after the charge detonation simulation is started. As illustrated in the middle pressure row 902, the interior pressure 914 immediately begins to increase. Likewise, as shown in the bottom fluid velocity row 904, the interior 930 begins to drop and the tool 928 begins to rise.

FIG. 11 illustrates a third screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 10. As illustrated, the interior tool gas 912 and annulus 1 air 922 continue to rise. Fluid pressures of each of the tool 928, interior 930, and annulus 932 are changing.

FIG. 12 illustrates a fourth screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 11. At this point several of the charges 502 have been detonated.

FIG. 13 illustrates a fifth screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 12. At this point the last of the charges 502 is about to be detonated.

FIG. 14 illustrates a fifth screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 13. At this point all charges 502 have been fired and the pressures are beginning to stabilize while the fluid velocities are still highly turbulent.

FIG. 15 illustrates a fifth screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 14. At this point the fluid velocities are beginning to stabilize.

FIG. 16 illustrates a fifth screenshot of the computer simulation while the charge detonation simulation continues from that shown in FIG. 15. The simulation is about to end and both the pressures and the fluid velocities have stabilized.

Tool gas 920 refers to the middle graphic row 902 and illustrates the tool gas pressure resulting from the combustion developed during the burn. The tool gas 910 and the air 922 in the middle graphic row 902 refer to the pressure of the fluids in the wellbore, the lighter shaded tool gas 910 the water commonly used to fill the hole before the job and the black air 922 is formation fluid surrounding the tool before ignition.

It should be noted that the animation format illustrated in FIGS. 9-16 is set up to handle several different scenarios. Different scenarios may not employ all the measurable elements in the legend 906. Likewise, the measurable in the legend 906 may actually refer to a different measurable than is labeled in the legend as is normal behavior of the simulation software package. For example, in the illustrated example, air 914 in the interior as labeled in the legend 906 actually refers to interior fluid since there is no air for this type of tool. Similarly, the light oil 918 measurable in the legend 906 is unused in the above illustrated examples but can be used in other types of tools and simulations.

FIG. 21 illustrates additional screenshots from the computer simulation for a working region 2106 of about 500 ft (from 7500 ft to 8000 ft) of the horizontal stimulation tool 2108. Again, the computer simulation screenshot in the example of FIG. 21 is performed utilizing the PulsFrac™ software by Baker Hughes; however, any desired simulation tool/software may be employed in other examples. As shown, the propellant weight starts off about 2400 lbs and achieves fractures of approximately 150 ft.

Parameters that were inputted into the simulation according to the site formation features include:

Formation             Type: Shale
                      Permeability: 0.01md
                      Porosity: 0.01
Fluid                 Type: KCI Water
                      Density: 1.01 g/cm{circumflex over ( )}3
                      Sound Speed: 5000 ft/s
Existing Perfs        Top: na
                      Bottom: na
                      Hole Density: na
Tool (Multi-Tool)     Type: HST
Propellant (Multi-    Diameter: 3.0 in
Tool)                 Loading: na
Perf Gun (Multi-Tool) Diameter: na
                      Hole Density: na
                      Phasing: na

Key information for the working region 2106 include:

	Propellant Length:	490.0	ft
	Peak Pressure:	9257	psi
	Min Pressure:	2940	psi
	Frac Length Max:	146.79	ft

Concerning the simulation data that is utilized to calculate and estimate charge weight/intensity and fracture lengths at steps 704 and 720 of FIG. 7 (and also adjustments that can be made at steps 716 and 734), multiple simulations may be run in order to achieve desired fracture length and or to determine the required propellant weight etc. Appendix A provides an example of various simulation parameters and values also utilizing the PulsFrac™ software package for reference. Any desired combination of simulation parameters may be adjusted to both estimate and verify charge weights and intensity, fracture lengths, wellbore fluid levels, pressures, etc.

FIG. 17 illustrates a side view of two wells 1710, 1720 having parallel horizontal wellbores 1714, 1724 prior to detonating a plurality of charges in the bottom wellbore 1724 to create a fracture network according to an exemplary embodiment. Unlike FIG. 3 where the horizontal wellbores 304, 314, 324 were beside each other at a same depth, in the embodiment of FIG. 17 the first wellbore 1714 is above the second wellbore 1724 at a different depth.

FIG. 17 illustrates the wells 1710, 1720 at a point in time corresponding to just prior to detonating/the charges 502 at step 728 of FIG. 7. At this point in time, fractures 1712 have already been created extending from the first wellbore 1714 toward the second wellbore 1724. Likewise, a plurality of charges 502 separated by appropriate delay units 504 have been set in the second wellbore 1724. In-well sensors 500 are positioned in the first wellbore 1714 to detect changes in pressure and/or other characteristics within the first wellbore 1714 as a result of detonating the charges 502 in the second wellbore. Surface sensors 1700 are placed above ground in order to gather infor-mation of the subterranean formation layers utilizing seismic vibrations caused by detonating the charges 502 and creating a corresponding pressure pulse train as a result of each charge impulse in the pulse train being separated by an appropriate delay unit 504.

FIG. 18 illustrates the wells 1710, 1720 of FIG. 17 after the charges 502 have been detonated. This point in time corresponds to sometime after step 728 of FIG. 7 has been performed. As illustrated in FIG. 18, new formed fractures 1722 extending upward from the second wellbore 1724 interconnect with the previously existing fractures 1712 extending downward from the first wellbore 1714 In this way, an interconnected fracture network 1716 is formed between the first wellbore 1714 and the second wellbore 1724.

FIG. 19 illustrates a plurality of vertical wellbores 1900, 1920, 1930 having interconnected fracture networks 1906, 1916 therebetween according to an exemplary embodiment. In addition to horizontal and vertical wellbores, sloping adjacent wellbores may also have interconnected fracture networks formed therebetween in a similar manner according to yet further embodiments.

FIG. 20 illustrates a plurality of horizontal wellbores 20, 22, 24, 26, 28, 30, 32 in a gun barrel cylinder configuration, each wellbore having fractures 50 radially orientated in all directions around the axle length of the wellbores 20, 22, 24, 26, 28, 30, 32 according to an exemplary embodiment. The fractures 50 together create a large interconnected fracture network such that pressure changes within a center wellbore 20 will cause associated pressure changes in all the other surrounding wellbores 22, 24, 26, 28, 30, 32. During the production phase, fluids or gases may be injected into the center wellbore 20 and then production may simultaneously occur from all the other surrounding wellbores 22, 24, 26, 28, 30, 32. The drilling configuration of FIG. 20 may be particularly useful for thick shale fields and any number of additional interconnected horizontal wellbores may be added as necessary to produce from the entire field.

According to various exemplary embodiments, multiple horizontal wellbores are drilled parallel to each other within an optimum distance of each other (the optimum distance is usually 100-500 ft and can be determined using computer simulations). Propellants (liquid or solid or gas) and/or explosives (liquid or solid or gas) are then placed and ignited in the wellbores. This results in high pressure pulse which overcomes the rock tensile strength and drives cracks/fractures away from the wellbore to establish multiple connections with adjacent wellbore(s). The ignition timing can be altered by placing short delays along the stimulation tool length to produce a resonant frequency designed to maximize rock breakdown and crack/fracture extension. The resonant frequency ignition will also facilitate the creation “off plane” fractures (fracture growth in directions not perpendicular to the least principal stress). Something which is difficult if not impossible to do with traditional hydraulic fracturing techniques. The entire length of the horizontal sections of the wellbore can be stimulated at one time or shorter sections may be stimulated sequentially. Instrumentation including but not limited to high speed pressure recorders and seismic sensors can be placed in adjacent wellbore(s) to record the event for subsequent analysis and optimization of the process. Seismic recording arrays may also be placed at surface to enhance analysis and improvement.

After the drilling and stimulation, the wellbore production is initiated by producing hydrocarbons from some wellbores while simultaneously injecting fluids or gases into others. The injection will maintain reservoir pressure and production rates. The fluid or gases injected (examples—methane, propane, carbon dioxide, water, etc.) will replace the hydrocarbons as they are produced and can act as solvents to enhance mobility and ultimate production of reservoir hydrocarbons in place.

Multiple wellbores can be continuously added to the network over time. Single wellbores may use the same process by stimulating lengths of the wellbore and then isolating part of the stimulated length and injection into it while producing from other sections of the well.

Exemplary benefits of some embodiments include eliminating the requirement for hydraulic fracturing (and its common use of massive quantities of fracking fluids) and the potential for contaminating ground water with fracking fluids. Hydrocarbon reservoir utilization and efficiency may also be increased by multiple wellbores connected to each other with a huge network of fractures to produce hydrocarbons and simultaneously replace the produced volumes by injecting other fluids/gases/solvents to maintain reservoir pressure and maximize total production volumes.

According to some exemplary embodiments, multiple parallel wells with interconnected fracture networks utilizing injection to enhance production are combined with propellant/explosive stimulation techniques to vastly increase the producing area (exposed shale face) thereby increasing production, sweep efficiency and ultimate recovery.

In an exemplary embodiment, a method of recovering hydrocarbons from a subterranean formation includes drilling first and second adjacent wells and detonating charges in each of the wells thereby causing fractures in the subterranean formation to extend from each well and interconnect with each other in a fracture network. The method further includes ensuring that at least some of the first fractures interconnect with at least some of the second fractures in the fracture network. Hydrocarbons are then recovered from at least one of the first well and the second well. The charge detonations may include a plurality of charges separated by delay units to create a pulse train selected according to a type of subterranean formation. The pulse train may be detected by sensors to ensure the fracture network between the adjacent wellbores is sufficiently interconnected. Fluids may be injected into injection wells and while production is performed from interconnected production wells.

FIG. 25 illustrates a plurality of horizontal wellbores 20, 22, 24, 26, 28, 30, 32 each having fractures 50 radially extending in all directions around the axle length of the wellbores 20, 22, 24, 26, 28, 30, 32 to form an interconnected fracture network taking advantage of permeability of the subterranean formation according to an exemplary embodiment. The embodiment shown in FIG. 25 differs from the earlier embodiment illustrated in FIG. 20 by the wellbores 20, 22, 24, 26, 28, 30, 32 in FIG. 25 being further apart such that their fractures 50 do not directly intersect with the fractures 50 of the adjacent wellbores 20, 22, 24, 26, 28, 30, 32. However, despite the lack of direct intersection of fractures 50 in FIG. 25, the fractures 50 still together create a large interconnected fracture network 250 by taking advantage of permeability of the subterranean formation 252. As such, it is to be understood that the term “interconnect” and derivates such as utilized in the phrase “interconnected fracture network” include cases where the fractures 50 themselves do not directly intersect but are nonetheless interconnected via the permeability of the material of the subterranean formation. Fracture interconnection in this document generally refers to cross wellbore flow. Combinations of both directly connected (intersecting) fractures 50 and also fractures 50 that are close enough to establish sufficient cross wellbore flow may be utilized together. During step 732, the primary concern in some embodiments may be testing for sufficient wellbore flow between adjacent wellbores 20, 22, 24, 26, 28, 30, 32 in order to determine whether the fractures 50 are sufficiently interconnected.

FIG. 26 illustrates wellbore pressure changing over time during a timed ignition according to an exemplary embodiment. Timed ignition (e.g., millisecond delays) can be used for both (or either) seismic signal generation and for propellant burn control (to control burn pressure and burn time to produce best fracture length/pattern). By timing the ignition of different sections 502 of propellant, well overpressure can be avoided while at the same time the burn time can be extended thereby extending pressure time and fracture lengths. As shown by the pressure line 260 in FIG. 26, each burn ignition is in sequence and raises the pressure a bit more as time runs along the bottom axis of the graph. As illustrated, the maximum pressure is about 14,000 psi at around the 150 ms burn time. By having a plurality of propellant sections 502 ignited in sequence, the total burn time may range in some embodiments from 100 ms to 1000 ms. The pressure and burn times shown in FIG. 26 differ with what would happen in a typical propellant burn where all propellant sections 502 would be ignited at the same time. The graph for typical simultaneous ignition would have the pressure line 260 rapidly rise in a highly sloped essentially straight line up to around 20,000 psi, which represents an overpressure state where the pipe and/or other equipment within the wellbore may be destroyed by such a rapid and high increase in pressure. Timed ignition as illustrated in FIG. 26 allows more propellant to be put in the wellbore over a typical propellant application while avoiding overpressure situations. The timed ignition technique is particular beneficial for creating interconnected fractures as described above such as step 728 of FIG. 7; however, the same technique may also be applied in single wellbore applications.

FIG. 27 illustrates a plan view of two adjacent horizontal wellbores 270, 272 having an angle A between their bore directions according to an exemplary embodiment. In order to test and determine the optimal spacing and other parameters for fracture 274 interconnection, two adjacent well-bores 270, 272 such as illustrated in FIG. 27 may be drilled. The wellbores 270, 272 have different bore directions differing by angle A. In this way, as the position along the wellbore length moves from an initial position D0 to final position D9, the separation distance between the wellbores 270, 272 increases. At the initial positions between D0 and D1, the fractures 274 are not very extensive because there is not enough space for the fractures 274 to expand in different directions and there is not much space in the subterranean formations. Therefore, reduced hydrocarbon flow rates may result from interconnected fractures 274 this close to each other. Alternatively, in the range of D3-D5, the fractures 274 have enough room to spread in different directions while still achieving good interconnection with the fractures 274 from the adjacent wellbore 270, 272. Hydrocarbon flow rates in this section may be maximized for these reasons. Likewise, in the ranges of D7-D9, the fractures 274 are too far apart that there is very little cross wellbore flow. The fractures in the range of D7-D9 are simply not sufficiently interconnected to achieve acceptable hydrocarbon flow rates.

To determine optimal wellbore spacing, production/injection tests may be performed on the wellbores 270, 272. To this end, testing personnel may drill test wellbores 270, 272 starting from known positions and with a known angle A between them. Testing personnel may then perform fracture interconnection tests in different distance ranges D1-D9 within the adjacent wellbores 270, 272 in order to determine the distance range(s) D1-D9 that have the best cross wellbore flow rates. For example, by isolating and testing fracture interconnection results and flow rates within different sections D0-D1, D2-D3, D3-D4, etc., it may be determined which distance section(s) is/are optimal in a given environment. For example, assuming that hydrocarbon recovery rates are optimal in the D4-D5 distance section, future wells at this site may be drilled parallel to one another having a separation distance Dsep between them. The optimal separation distance Dsep is equivalent to the distance between the first and second test wellbores 270, 272 at the D4-D5 distance sections.

Because the wellbores 270, 272 are straight lines with an angle between them, there will be an intersection point. The intersection point may be an actual intersection such as an origin point at the initial position D1 of each wellbore 270, 272, or the intersection point may be a theoretical intersection point where the wellbores 270, 272 would intersect if they were drilled back further. Dsep can be calculated by the law of cosines because the distance of the sub-sections where the optimal test results are achieved from the intersection point are known and the angle between the wellbore lines is known. The test results showing that the D4-D5 distance sections are at the optimal distance Dsep may also be utilized to update simulation parameters to help better predict future adjacent wells.

A benefit of having at least two wellbores 270, 272 diverging from each other at an angle A is to perform fracture testing and flow rate testing at different wellbore distances without being required to drill separate wellbores at each distance. Instead, a fixed number of wellbores 270, 272 are drilled diverging at angle A from one another, and tests are done at different distances D0-D9 along those wellbores in order to test different separation distances Dsep. As tests are conducted along the lengthwise distances D0-D9, eventually there will be no pressure signal detected in one wellbore 270 as a result of pressure changes in the adjacent wellbore 272. At this point, the well-bores are too far away and there is no longer sufficient interconnection of the fractures 274.

FIG. 28 illustrates a projection view of a plurality of a plurality of adjacent horizontal wellbores 21, 23, 25, 27, 29, 31, 33 having an angle A between their bore directions according to an exemglary embodiment. This embodiment is similar to that shown in FIG. 27, except rather than just two adjacent wellbores 270, 272 utilized for testing, FIG. 28 includes seven wellbores organized in a gun barrel cylinder configuration. The center wellbore 21 may be a straight-line wellbore drilled from a starting position D0 illustrated at the upper left-hand corner of FIG. 28. Each of the surrounding wellbores 23, 25, 27, 29, 31, 33 may diverge from the center wellbore 21 by an angle of A. As such a cone-shaped configuration of wellbores 21, 23, 25, 27, 29, 31, 33 is formed where the distance of any surrounding wellbore 23, 25, 27, 29, 31, 33 gets further and further away from the center wellbore 21 as the distance from the starting point D0 extends to D9.

As a result of the cone shaped configuration, not only can testing personnel empirically test to find the optimal wellbore separation distance Dsep for maximum flow rates (as can be done in FIG. 28), the testing personnel may also empirically determine what type of positional spacing and orientation of wellbores 21, 23, 25, 27, 29, 31, 33 maximizes cross wellbore flow rates. For instance, it may be determined that for wellbores that are vertically stacked (such as wellbore 23 being over wellbore 21), maximum flow rates are achieved around the D3 distance. The D3 distance can be utilized with the known angle A to correlate to a first optimal wellbore separation Dsepl at which vertically stacked horizontal wellbores can be drilled to maximize production. Likewise, the cone configuration of FIG. 28 may show that for horizontally adjacent wellbores (such as wellbore 33 being beside center wellbore 21), maximum flow rates are achieved around the distance range D5 distance. Again, the D5 distance can be utilized along with the known angle A in order to determine a second optimal wellbore separation distance Dsep2 at which horizontally adjacent wellbores can be drilled to maximize production.

The cone shaped configuration of FIG. 28 also allows the field testing personnel to check for the effects of the natural formation stresses. For instance, certain subterranean formations may have naturally better permeability in certain directions or orientations. The cone shaped configuration of FIG. 28 has a plurality of wellbores 23, 25, 27, 29, 31, 33 surrounding a center wellbore 21 and therefore many angles of natural stresses can be tested.

In an exemplary embodiment, recovering hydrocarbons from a subterranean formation includes drilling first and second adjacent wells and detonating charges in each thereby causing fractures in the subterranean formation to extend from each well and interconnect in a fracture network. The charge detonations may include charges separated by delay units to create a pulse train at a resonant frequency of the subterranean formation. Sensors may be positioned within one or more of the wellbores and the surface, and the pulse train may be detected by the sensors to ensure the fracture network between the adjacent wellbores is sufficiently interconnected. The adjacent wells may be parallel to each other and separated by an optimal separation distance determined by testing different sections of test wellbores that diverge from an intersection point at a known angle. The charges may be propellant based. Fluids/gases may be injected into injection wells and production performed from interconnected production wells.

Although the invention has been described in connection with preferred embodiments, it should be understood that various modifications, additions and alterations may be made to the invention by one skilled in the art without departing from the spirit and scope of the invention. For example, the above techniques may be applied to any combination of horizontal, vertical and sloping wells. Wellbores may be horizontal or highly deviated. Although the injection well is preferred to be surrounded on other sides by production wells so that all fractures are utilized to provide pressure to other wells, this is not a strict requirement and injection may also be performed utilizing an edge well connected on only one side rather than a centrally connected well. Additionally, both the injection wells and the production wells may contain additional fractures that are not interconnected to any other adjacent well. Having additional unconnected fractures may work to maximize production.

Either propellants (solid or liquid or gas) and/or explosives (solid or liquid or gas) may be used as the charges 502. Wellbores may be lined with casing (cemented in place or uncemented), may contain a slotted liner or may be open hole completions. Entire lengths of wellbores may be stimulated simultaneously or small sections sequentially. The ignition can be a rapid continuous process such as when liquid propellant is utilized or when a plurality of charge sections are simultaneously detonated as a group, or may include a certain number of micro/millisecond/other delays intermediate separate charge sections to provide desired pulse trains for sensor detection and/or to establish resonant frequencies designed to maximize: rock breakdown, creation of off plane fractures and fracture extension. In an exemplary embodiment, the charge delays are set to create a pulse train of detonations at the resonant frequency of the subterranean rock material surrounding the wellbore. Entire lengths of wellbores may produce and/or be injected into simultaneously or small sections can be activated and produce/injected into sequentially. Single wellbores may use the same process by stimulating lengths of the wellbore and then isolating part of the stimulated length and injection into it while producing from the area that is not isolated. Multiple fluids and or gases can be used for injection including but not restricted to: nitrogen, methane, propane, butane, carbon dioxide, methanol, water or any combination of these and/or other fluids/gases.

It may be beneficial to place in-well sensors 500 in an existing wellbore to detect changes of pressure and/or other characteristics as a result of detonating charges in an adjacent second wellbore; however, both the in-well sensors 500 and surface sensors 1700 are optional and may be omitted in other embodiments.

Although parallel wellbores are preferred to create fracture network between them, fracture network may also be created between wellbores that are not parallel to each other. For instance, a horizontal wellbore may be adjacent a portion of a vertical wellbore and a fracture network may be created between these two non-parallel wellbores. The fractures are not limited to being bi-wing fractures and can instead be created in any configuration extending outward at any angle from a wellbore. The fractures may be limited in some configurations to only be directed toward adjacent wells to maximize interconnection with fractures from those other wellbores, or fractures may be directed in any other directions from the wellbore.

Charge 502 detonation is beneficial for creating interconnected fractures between wellbores because the charge detonation occurs fast enough that a plurality of fractures are created substantially simultaneously. There is little time for excess pressure to bleed off before additional fractures are created. For this reason, preferred embodiments employ charge sections 502 for creating interconnected fracture networks 306, 316 between adjacent wellbores. In contrast, in hydraulic fracturing the fractures are created from a slower pressure build-up of pumped fracture fluid and therefore it is more difficult to create interconnected fracture networks using hydraulic fluid. However, it should be noted that in some embodiments of the invention, interconnected fractures and fracture networks may include fractures that were originally created utilizing hydraulic fracturing techniques. For example, an initial wellbore may first be fracked utilizing hydraulic fracturing methods and then an adjacent wellbore may be interconnected therewith utilizing the propellant based techniques described herein. Fractures and interconnected fracture networks may be created utilizing any desired process, and any combination of hydraulically and charge based fractures may be employed in different embodiments.

After drilling and stimulation, wellbore production may be performed by producing hydrocarbons from some wellbores while simultaneously injecting fluids or gases into others. This combined injection/production process is illustrated in FIG. 8. However, it should be noted that the injection does not necessarily need to start immediately with production. Instead, injection may be delayed by several weeks/months after the wells are drilled, and/or may be delayed by several weeks/months after production is started. For instance, regular production without fluid injection may immediately follow step 738 of FIG. 7. Then, some period of time later, perhaps upon well depletion becoming evident, the combined injection/production process of FIG. 8 may begin at step 800.

In some embodiments, processing facilities are added at surface to refine the produced hydrocarbons to a burnable product, which is utilized to fuel electric generating equipment. Carbon dioxide may be captured from the combustion and then injected back into the wells. As the volume of carbon dioxide will be greater than the volume of the produced hydrocarbons, a small amount of the refined product can also be utilized as feedstock to produce plastics. In this way, the entire process is tied together and can result in a “carbon neutral” method of producing electricity.

Furthermore, although the above examples have focused on creating and producing from multiple wellbores, the disclosed techniques for maximizing fracture length and creation efficiency may also be performed in a single wellbore. For instance, the resonant frequency stimulation process may be utilized to stimulate a single wellbore and then inject into one part of the single wellbore while producing from another of the single wellbore.

The computer simulations illustrated in FIGS. 9-13 and 21 and utilized to estimate charge intensity and time delays at steps 704 and 720 of FIG. 7 may be implemented by software executed by one or more processors operating pursuant to instructions stored on a tangible computer-readable medium such as a storage device. Examples of the tangible computer-readable medium include optical media (e.g., CD-ROM, DVD discs), magnetic media (e.g., hard drives, diskettes), and other electronically readable media such as flash storage devices and memory devices (e.g., RAM, ROM). The computer-readable medium may be local to the computer executing the instructions, or may be remote to this computer such as when coupled to the computer via a computer network such as the Internet. The processors may be included in a general-purpose or specific-purpose computer or computer server that becomes the simulation program or any of the above-described functionality as a result of executing the instructions. In addition to a dedicated physical computing device, the word “server” may also mean a service daemon on a single computer, virtual computer, or shared physical computer or computers, for example.

In other embodiments, rather than being software modules executed by one or more processors, the above-described simulation functionality may be implemented as hardware modules configured to perform the above-described functions. Examples of hardware modules include combinations of logic gates, integrated circuits, field programmable gate arrays, and application specific integrated circuits, and other analog and digital circuit designs.

The term “charge” and related derivatives such as “charges”, “charge section”, “charge blasts”, etc. are intended in this description to encompass both propellant and high explosives. Upon ignition, propellant deflagrates in a rapid burn whereas high explosive detonates in an explosion. As such, the term “detonation” and its related derivatives such as “detonating”, “detonate”, etc. as utilized herein are intended to encompass both deflagration of propellant and detonation of high explosives.

Regarding the term bi-wing fractures, this term is utilized herein to include hydraulic and propellant driven fractures. For instance, bi-wing as utilized herein can refer to both hydraulic fractures as well as multiple radial fractures that are propellant driven.

Functions of single elements described above may be separated into multiple units, or the functions of multiple elements may be combined into a single unit. All combinations and permutations of the above described features and embodiments may be utilized in conjunction with the invention.

Claims

1. A method of recovering hydrocarbons from a subterranean formation, the method comprising:

drilling a first well;

drilling a second well adjacent to the first well;

detonating a first charge in the first well thereby causing first fractures in the subterranean formation to extend from the first well toward the second well;

detonating a second charge in the second well thereby causing second fractures in the subterranean formation to extend from the second well toward the first well;

ensuring via a sensor coupled to at least one of the first well and the second well that a degree of interconnectivity between the first fractures and the second fractures is above a threshold value; and

recovering hydrocarbons from at least one of the first well and the second well.

2. (canceled)

3. The method of claim 1, wherein the second well is drilled substantially parallel to the first well, the method further comprising separating the first well and the second well from one another by a separation distance determined by:

drilling a first test well extending in a first direction;

drilling a second test well extending in a second direction, the second direction having an angle difference with the first direction such that the first test well and the second test increase in distance from one another as they extend away from an intersection point;

detonating a first test charge in the first well thereby causing first test fractures in the subterranean formation to extend from the first test well toward the second test well;

detonating a second test charge in the second test well thereby causing second test fractures in the subterranean formation to extend from the second test well toward the first test well;

performing a plurality of tests to gauge fracture interconnection levels between the first test well and the second test well in a corresponding plurality of sections of at least one of the first test well and the second test well;

determining an optimal one of the sections that has an optimal fracture interconnection level by comparing results of the tests for the plurality of sections; and

determining the separation distance according to a distance the optimal one of the sections is from the intersection point and the angle between the first direction and the second direction.

4. The method of claim 1, further comprising forming at least one of the first charge and the second charge as a plurality of charge sections coupled in series with a respective delay unit interspaced therebetween, wherein each delay unit provides a detonation delay between each of the charge sections.

5. (canceled)

6. The method of claim 4, further comprising setting the detonation delay to form a detonation pulse train at a resonance frequency of the subterranean formation.

7. The method of claim 4, wherein a total number of charge sections coupled in series is at least ten.

8. The method of claim 4, wherein the detonation delay of each respective delay unit is a same value in a range from one-tenth milliseconds to ten milliseconds.

9. The method of claim 4, further comprising analysing the subterranean formation according to a plurality of data received from a plurality of surface sensors measuring a plurality of successive ignition impulses formed by detonation of the charge sections.

10. The method of claim 9, wherein analysing the subterranean formation comprises generating a three-dimensional map of subterranean formation according to the data received from the surface sensors.

11. The method of claim 9, further comprising ensuring that at least some of the first fractures interconnect with at least some of the second fractures according to the data received from the surface sensors.

12. The method of claim 1, further comprising:

drilling the first well with a first horizontal section;

drilling the second well with a second horizontal section adjacent to the first horizontal section;

ensuring the first fractures and second fractures extend toward each between the first horizontal section and the second horizontal section.

13. The method of claim 1, further comprising selecting burn intensities of the first charge and the second charge in advance utilizing a computer simulation process designed to achieve a desired amount of interconnection between the first fractures and the second fractures given a plurality of known parameters of the subterranean formation.

14. The method of claim 13, further comprising:

measuring an actual amount of interconnection between the first fractures and the second fractures after detonating the first charge and the second charge; and

updating the known parameters of the subterranean formation according to differences between the desired amount of interconnection and the actual amount of interconnection.

15. The method of claim 1, further comprising, after ensuring that at least some of the first fractures interconnect with at least some of the second fractures, injecting material into the second well while recovering hydrocarbons from the first well.

16. The method of claim 15, further comprising:

drilling a third well adjacent to the second well;

detonating a third charge in the third well thereby causing third fractures in the subterranean formation to extend from the third well toward the second well;

ensuring that at least some of the third fractures interconnect with at least some of the second fractures; and

simultaneously recovering hydrocarbons from the first well and the second well while injecting a material into the second well.

17. (canceled)

18. The method of claim 1, further comprising:

placing a plurality of in-well sensors within the first well prior to detonating the second charge in the second well; and

ensuring that at least some of the first fractures interconnect with at least some of the second fractures according to data received from the in-well sensors in response to detonating the second charge in the second well.

19. The method of claim 1, wherein the sensor is one of a plurality of in-well include pressure sensors for measuring pressure changes in the first well resulting from detonating the second charge in the second well.

20. The method of claim 1, wherein the sensor is one of a plurality of in-well seismic sensors for measuring vibrations detected in the first well resulting from detonating the second charge in the second well.

21-22. (canceled)

23. The method of claim 1, wherein at least one of the first charge and the second charge are propellant charges.

24. The method of claim 1, further comprising drilling a plurality of additional wells such that the first well and the second well in combination with the additional wells form a gun barrel cylinder configuration having a center wellbore with a plurality of surrounding wellbores running plurality.

25. (canceled)

26. The method of claim 1, further comprising ensuring that a cross wellbore flow rate achieved between the first well and the second well is greater than a predetermined threshold.