Controlling Fracture Growth During Stimulation of Subsurface Reservoirs Using Offset Wells

This application is a continuation of U.S. patent application Ser. No. 18/234,220 filed on Aug. 15, 2023, which claims the benefit of priority to U.S. Provisional Patent Application Ser. No. 63/398,070 filed Aug. 15, 2022, which applications and publications are incorporated herein by reference in their entirety.

Typically, in the production of natural resources from formations within the earth a well or borehole is drilled into the earth to the location where the natural resource is believed to be located. These natural resources may be a heat source for geothermal energy, a hydrocarbon reservoir, containing natural gas, crude oil and combinations of these; the natural resource may be fresh water; or it may be some other natural resource that is located within the ground.

These resource-containing formations may be a few hundred feet, a few thousand feet, or tens of thousands of feet below the surface of the earth, including under the floor of a body of water, e.g., below the sea floor. In addition to being at various depths within the earth, these formations may cover areas of differing sizes, shapes and volumes.

Unfortunately, and generally, when a well is drilled into these formations the natural resources rarely flow into and out of the formation, and into the well at rates, durations and amounts that are economically viable. This problem occurs for several reasons, some of which are well understood, others of which were not as well understood, some of which may not yet be known, and several of which, prior to the present systems and techniques were incorrect. These problems can relate to the viscosity of the natural resource, the porosity of the formation, the geology of the formation, the formation pressures, and the perforations that place the production tubing in the well in fluid communication with the formation, to name a few.

Typically, and by way of general illustration, in drilling a well an initial borehole is made into the earth, e.g., the surface of land or seabed, and then subsequent and smaller diameter boreholes are drilled to extend the overall depth of the borehole. In this manner as the overall borehole gets deeper its diameter becomes smaller; resulting in what can be envisioned as a telescoping assembly of holes with the largest diameter hole being at the top of the borehole closest to the surface of the earth.

Typically, when completing a well, it is necessary to perform a perforation operation. In general, when a well has been drilled and casing, e.g., a metal pipe, is run to the prescribed depth, the casing is typically cemented in place by pumping cement down and into the annular space between the casing and the earth. (It is understood that many different down hole casing, open hole, and completion approaches may be used.) The casing, among other things, prevents the hole from collapsing and fluids from flowing between permeable zones in the annulus. Thus, this casing forms a structural support for the well and a barrier to the earth.

While important for the structural integrity of the well, the casing and cement present a problem when they are in the production zone. Thus, in addition to holding back the earth, they also prevent the resources or fluid from flowing into and out of the well and from being recovered. Additionally, the formation itself may have been damaged by the drilling process, e.g., by the pressure from the drilling mud, and this damaged area of the formation may form an additional barrier to the flow of resources. Similarly, in most situations where casing is not needed in the production area, e.g., open hole, the formation itself is generally tight, and more typically can be very tight, and thus, will not permit the flow of resources into and out of the well.

To address, in part, this problem of the flow of resources e.g., geothermal, hydrocarbons, etc. into the well being blocked by the casing, cement and the formation itself, openings, e.g., perforations, are made in the well in the area of the pay zone. Generally, a perforation is a small, about ¼″to about 1″ or 2″ in diameter hole that extends through the casing, cement and damaged formation and goes into the formation. This hole creates a passage for the resource to flow from the formation into the well. In a typical well, a large number of these holes are made through the casing and into the formation in the pay zone.

As used herein, unless specified otherwise, the term “earth” should be given its broadest possible meaning, and includes, the ground, all natural materials, such as rocks, and artificial materials, such as concrete, that are or may be found in the ground, including without limitation rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite and shale rock.

As used herein, unless specified otherwise, the term “borehole” should be given it broadest possible meaning and includes any opening that is created in a material, a work piece, a surface, the earth, a structure (e.g., building, protected military installation, nuclear plant, offshore platform, or ship), or in a structure in the ground, (e.g., foundation, roadway, airstrip, cave or subterranean structure) that is substantially longer than it is wide, such as a well, a well bore, a well hole, a micro hole, slimhole, a perforation and other terms commonly used or known in the arts to define these types of narrow long passages. Wells may further include exploratory, production, abandoned, reentered, reworked, and injection wells. Although boreholes are generally oriented substantially vertically, they may also be oriented on an angle from vertical, to and including horizontal. Thus, using a vertical line, based upon a level as a reference point, a borehole can have orientations ranging from 0° i.e., vertical, to 90°,i.e., horizontal and greater than 90° e.g., such as a heel and toe and combinations of these such as for example “U” and “Y” shapes. Boreholes may further have segments or sections that have different orientations, they may have straight sections and arcuate sections and combinations thereof; and for example may be of the shapes commonly found when directional drilling is employed. Thus, as used herein unless expressly provided otherwise, the “bottom” of a borehole, the “bottom surface” of the borehole and similar terms refer to the end of the borehole, i.e., that portion of the borehole furthest along the path of the borehole from the borehole's opening, the surface of the earth, or the borehole's beginning. The terms “side” and “wall” of a borehole should to be given their broadest possible meaning and include the longitudinal surfaces of the borehole, whether or not casing or a liner is present, as such, these terms may include the sides of an open borehole or the sides of the casing that has been positioned within a borehole. Boreholes may be made up of a single passage, multiple passages, connected passages and combinations thereof, in a situation where multiple boreholes are connected or interconnected each borehole may have a borehole bottom. Boreholes may be formed in the sea floor, under bodies of water, on land, in ice formations, or in other locations and settings.

Boreholes are generally formed and advanced by using mechanical drilling equipment having a rotating drilling tool, e.g., a bit. For example and in general, when creating a borehole in the earth, a drilling bit is extending to and into the earth and rotated to create a hole in the earth. In general, to perform the drilling operation the bit must be forced against the material to be removed with a sufficient force to exceed the shear strength, compressive strength or combinations thereof, of that material. Thus, in conventional drilling activity mechanical forces exceeding these strengths of the rock or earth must be applied. The material that is cut from the earth is generally known as cuttings, e.g., waste, which may be chips of rock, dust, rock fibers and other types of materials and structures that may be created by the bit's interactions with the earth. These cuttings are typically removed from the borehole by the use of fluids, which fluids can be liquids, foams or gases, or other materials know to the art.

As used herein, unless specified otherwise, the term “advancing” a borehole should be given its broadest possible meaning and includes increasing the length of the borehole. Thus, by advancing a borehole, provided the orientation is not horizontal, e.g., less than 90° the depth of the borehole may also be increased. The true vertical depth (“TVD”) of a borehole is the distance from the top or surface of the borehole to the depth at which the bottom of the borehole is located, measured along a straight vertical line. The measured depth (“MD”) of a borehole is the distance as measured along the actual path of the borehole from the top or surface to the bottom. As used herein unless specified otherwise the term depth of a borehole may refer to MD. In general, a point of reference may be used for the top of the borehole, such as the rotary table, drill floor, well head or initial opening or surface of the structure in which the borehole is placed.

As used herein, unless specified otherwise, the terms “workover,” “completion” and “workover and completion” and similar such terms should be given their broadest possible meanings and may include activities that place at or near the completion of drilling a well, activities that take place at or the near the commencement of production from the well, activities that take place on the well when the well is producing or operating well, activities that take place to reopen or reenter an abandoned or plugged well or branch of a well, and may also include for example, perforating, cementing, acidizing, fracturing, pressure testing, the removal of well debris, removal of plugs, insertion or replacement of production tubing, forming windows in casing to drill or complete lateral or branch wellbores, cutting and milling operations in general, insertion of screens, stimulating, cleaning, testing, analyzing and other such activities. These terms may further include applying heat, directed energy, optionally in the form of a high power laser beam to heat, melt, soften, activate, vaporize, disengage, desiccate and combinations and variations of these, materials in a well, or other structure, to remove, assist in their removal, cleanout, condition and combinations and variation of these, such materials.

Generally, the term “about” as used herein unless stated otherwise is meant to encompass a variance or range of ±10%, the experimental or instrument error associated with obtaining the stated value, and optionally the larger of these.

As used herein, unless specified otherwise, the terms “formation,” “reservoir,” “pay zone,” and similar terms, are to be given their broadest possible meanings and may include all locations, areas, and geological features within the earth that contain, may contain, or are believed to contain, the desired resource, e.g., geothermal heat, hydrocarbons, etc.

As used herein, unless specified otherwise, the terms “field,” “oil field” “geothermal field” and similar terms, are to be given their broadest possible meanings, and may include any area of land, sea floor, or water that is loosely or directly associated with a formation, and more particularly with a resource containing formation, thus, a field may have one or more exploratory and producing wells associated with it, a field may have one or more governmental body or private resource leases associated with it, and one or more field(s) may be directly associated with a resource containing formation.

As used herein, unless specified otherwise, the terms “conventional gas”, “conventional oil”, “conventional”, “conventional production” and similar such terms are to be given their broadest possible meaning and include hydrocarbons, e.g., gas and oil, that are trapped in structures in the earth. Generally, in these conventional formations the hydrocarbons have migrated in permeable, or semi-permeable formations to a trap, or area where they are accumulated. Typically, in conventional formations a non-porous layer is above, or encompassing the area of accumulated hydrocarbons, in essence trapping the hydrocarbon accumulation. Conventional reservoirs have been historically the sources of the vast majority of hydrocarbons produced. As used herein, unless specified otherwise, the terms “unconventional gas”, “unconventional oil”, “unconventional”, “unconventional production” and similar such terms are to be given their broadest possible meaning and includes hydrocarbons that are held in impermeable rock, and which have not migrated to traps or areas of accumulation.

As used herein, unless specified otherwise, the terms “hydrocarbon exploration and production”, “exploration and production activities”, “E&P”, and “E&P activities”, and similar such terms are to be given their broadest possible meaning, and include surveying, geological analysis, well planning, reservoir planning, reservoir management, drilling a well, workover and completion activities, hydrocarbon production, flowing of hydrocarbons from a well, collection of hydrocarbons, secondary and tertiary recovery from a well, the management of flowing hydrocarbons from a well, and any other upstream activities.

As used herein, unless specified otherwise, the terms “poroelastic”, “poroelasticity”, “poroelastic stresses”, “poroelastic forces” and similar such terms should be given their broadest possible meanings and may include the forces, stresses and effects that are based upon the interaction between fluid flow and solid deformation within a porous medium. Typically, in evaluating poroelastic effects Darcy's law, which describes the relation between fluid motion and pressure within a porous medium, is coupled with the structural displacement of the porous matrix. Thermal stresses are mathematically analogous to poroelastic stresses, except that they are caused by expansion or contraction of rock due to changes in temperature.

As used herein, unless specified otherwise, the terms “geothermal”, “geothermal well”, “geothermal resource”, “geothermal energy” and similar such terms, should be given their broadest possible meaning and including wells, systems and operations that recover or utilize the heat energy that is contained within the earth. Such systems and operations may include enhanced geothermal well, engineered geothermal wells, binary cycle power plants, dry steam power plants, flash steam power plants, open looped systems, and closed loop systems.

The ability of, or ease with which, the natural resource can flow out of the formation and into the well or production tubing (into and out of, for example, in the case of engineered geothermal wells, and some advanced recovery methods for hydrocarbon wells) can generally be understood as the fluid communication between the well and the formation. As this fluid communication is increased several enhancements or benefits may be obtained: the volume or rate of flow (e.g., gallons per minute) can increase; the distance within the formation out from the well where the natural resources will flow into the well can be increase (e.g., the volume and area of the formation that can be drained by a single well is increased, and it will thus take less total wells to recover the resources from an entire field); the time period when the well is producing resources can be lengthened; the flow rate can be maintained at a higher rate for a longer period of time; and combinations of these and other efficiencies and benefits.

Fluid communication between the formation and the well can be increased by the use of hydraulic stimulation techniques. The first uses of hydraulic stimulation date back to the late 1940s and early 1950s. In general, hydraulic treatments involve forcing fluids down the well and into the formation, where the fluids enter the formation and crack, e.g., force the layers of rock to break apart or fracture. These fractures create channels or flow paths that may have cross sections of a few micron's, to a few millimeters, to several millimeters in size, and potentially larger. The fractures may also extend out from the well in all directions for a few feet, several feet and tens of feet or further. It should be remembered that the longitudinal axis of the well in the reservoir may not be vertical: it may be on an angle (either slopping up or down) or it may be horizontal. The section of the well located within the reservoir, i.e., the section of the formation containing the natural resources, can be called the pay zone.

Although hydraulic stimulation has been used in geothermal wells, the use of proppants has generally not been used, and its use has been discredited by those in the art.

Generally, in prior geothermal wells, even those that have been hydraulically stimulated, the performance and efficiency of the well, and geothermal power plant, has been less than desirable and suboptimal. This suboptimal performance has hindered the adoption of geothermal energy, making its replace of hydrocarbon energy sources difficult. This suboptimal performance has reduced the ability of geothermal energy, which is a clean, carbon free energy source, from being widely adopted and replacing carbon emitting, e.g., coal, oil, natural gas, power generation sources.

This low efficiency or lack of performance in geothermal wells is also seen in the inefficiency of the recovery of oil and natural gasses from hydrocarbon wells, i.e., wells that are production hydrocarbons.

One of the reasons for this lack of efficiency, and suboptimal performance of wells, e.g., geothermal and hydrocarbon, occurs because in unconventional oil and gas reservoir it is necessary to increase the permeability of the reservoir through hydraulic stimulation to achieve commercially viable production. In some geothermal reservoirs, hydraulic stimulation is also used. Typically, in the oil and gas industry, hydraulic fracturing is the stimulation method, where fluid is injected at relatively high pressures to cause new tensile fractures to form. In the geothermal industry, the most common stimulation method is called hydroshearing, where fluid is injected at pressures sufficiently high to cause shear slip and dilation on preexisting natural fractures. These prior techniques, however, have many short communing and have, among other things lead to the lack of efficiency in the recovery of energy from boreholes in the earth.

Both the hydraulic fracturing and hydroshearing methods are controlled largely by the in-situ state of stress, which can be influenced by many factors including: depth, remote tectonic forces, local material heterogeneity, thermoporoelastic effects, faulting, fluid flow, stress concentrations due to wellbores, and combinations and various of these, as well as other factors. In the hydraulic fracturing method, fluid pressure must exceed the magnitude of the minimum principal stress to ensure formation and growth of new tensile fractures. In the hydroshearing method, fluid pressure must locally be sufficiently high such that the shear stresses driving slip on fractures overcome the frictional resistance to slip. The stress state is typically measured at the onset of a project and the stimulation treatments are designed based on the initial characterization; however, thermo-hydromechanical effects can cause the state of stress to evolve during a treatment, which are generally not managed or controlled by these prior techniques. The stress state can also change during the production phase, which is generally not managed or controlled by these prior techniques. Refracturing treatments, commonly performed in oil and gas wells that declined in production rate, may consider how the stress orientations rotated due to poroelastic effects, but generally not in a dynamic manner and not during, or as a planning or actual tool in performing the refracturing operation. The systems and techniques described herein may be used for enhancing the recovery of resources from within the ground. In particular, examples of the present systems and techniques relate to novel systems and operations to alter, modify and change subterranean formations through hydraulic stimulation operations to enhance the recovery of resources from those formations. The systems and techniques described herein relate to the recovery of subsurface resources, such as minerals, ores, gems, metals, water and energy sources including hydrocarbon and geothermal.

In an example, a low-stress region is created by placing a well on production; hydraulic stimulation is performed on an offset well to the producing well, and fracture growth into the low-stress regions of the producing well is encouraged.

In an example, a low-stress region is created by placing a well on production; hydraulic stimulation is performed on an offset well to the producing well, and fracture growth into the low-stress regions of the producing well is encouraged such that a ‘frac hit’ occurs effectively connecting the two wells.

In an example, a high-stress region in a producing well is created by injecting fluid into a well to increase pressure, temperature, and both, thereby inducing poroelastic stresses, thermal stresses, and both, that increase the complexity of the fractures and fluid communication pathways between the two wells.

In an example hydraulic stimulation is performed on an offset well, and propagating fractures in the producing well are encouraged to turn or branch away from the high-stress region created by the stimulation in the offset well.

In an example, mechanically-induced stress changes caused by fracture propagation and deformation (i.e., ‘stress shadowing’) is taken advantage of to encourage fractures to propagate away from the wellbore in an asymmetric fashion, and accounted for in terms of fracture spacing connecting offset wells.

In an example, the fluid pressure and flow rates are manipulated in two adjacent wellbores connected by a fracture to control fracture closure and proppant immobilization.

In an example, distributed acoustic, distributed temperature, and distributed strain fiber optic sensing cables installed in one well are used to evaluate properties of fractures propagating away from an offset well; this information is used to adjust the stimulation treatment parameters in real-time.

In general, the systems and techniques described herein relate to influencing, controlling, characterizing, or observing the growth of the stimulated reservoir volume during hydraulic stimulation treatments in subsurface reservoirs, with application to oil and gas, geothermal energy, and mining activities.

The systems and techniques described herein include controlling fluid flow and heat flow between wellbores though the use of creating stress levels in adjacent stimulation wells, and through controlled use of poroelastic conditions of the formation in near the producing well to be used for a stimulation plan and delivery through, or by way, of the adjacent well.

The systems and techniques described herein have application to oil and gas activities, such as waterflooding, steam flooding, steam assisted gravity drainage, and enhanced oil recovery. The systems and techniques described herein have application to geothermal energy activities, where thermal energy is extracted from subsurface formations by circulating a working fluid, such as water or carbon dioxide, through the formation and recovering the heated fluid.

The commercial viability of a geothermal power system depends on the long-term thermal sustainability of the reservoir. Thermal energy recovery efficiency is defined as the amount of heat recovered over the lifetime of a project relative to the initial amount of heat in place. Thermal breakthrough is defined as the time at which the temperature of the produced fluid has dropped by a threshold amount, which is controlled by the rate at which the thermal front propagates through the reservoir. The systems and techniques described herein include design of geothermal reservoir systems to control heat recovery efficiency and thermal breakthrough to improve the system's thermal sustainability.

In an example, the systems and techniques described herein may be used for recovery of geothermal resources and hydrocarbon resources from beneath the surface of the earth. In other examples, the systems and techniques described herein may be used for drilling or completing wells, or well configurations in the recovery of minerals and ores, and other resources within the ground.

In general, examples of the present well configurations have one, two, three, four or more wells. These wells can be vertical, vertical with horizontal section, vertical with sloped section, branched configurations, comb configurations, combinations and variations of these, and other configurations known to or later developed by the art and combinations and variations of these. These wells can have a TVD of from about 1,000 feet (ft) to about 20,000 ft, from about 2,000 ft to about 10,000 ft, about 2,000 ft to about 15,000 ft, and all values within these ranges, as well as larger and smaller values. These wells can have MD from about 1,000 feet (ft) to about 25,000 ft, from about 2,000 ft to about 10,000 ft, about 2,000 ft to about 15,000 ft, and all values within these ranges, as well as larger and smaller values.

Inthere is shown a perspective view of a hydraulic fracturing site. Thus, positioned near the well headthere are, pumping trucks, proppant, e.g., sand, ceramic, resin coated, etc., storage containers,, a proppant feeder assembly, a mixing truck, and fracturing fluid holding units. It is understood thatis an illustration and simplification of a fracturing site. Such sites may have more, different, and other pieces of equipment such as pumps, holding tanks, mixers, and chemical holding units, mixing and addition equipment, lines, valves and transferring equipment, as well as control and monitoring equipment.

A high-pressure linethat transfers high pressure fracturing fluid from the pump trucksinto the well. The wellheadmay also have further well control devices associated with it, such as a BOP. Fracturing fluid from holding unitsis transferred through linesto mixing truck, where proppant from storage containers,is feed, (metered in a controlled fashion) by assemblyand mixed with the fracturing fluid. The fracturing fluid and proppant mixture is then transferred to the pump trucks, by line, where the pump truckspump the fracturing fluid into the well by way of high pressure line.

In some examples, the proppants are mixed with fracking fluids for down hole hydraulic fracturing operations to, for example, recover hydrocarbons, such as crude oil and natural gas. Typically, between about 0.1 and about 12 lbs/gal, between about 3 and about 10 lbs/gal, between about 0.1 and about 1 lbs/gal, between about 1.1 and about 2 lbs/gal, between about 2.1 and about 4 lbs/gal, and between about 3.1 and about 8 lbs/gal of proppants are mixed into fracking fluid, greater and lesser amounts than about 12 lbs/gal and about 1 lbs/gal are also contemplated. Typically, at least about 10,000 gals, at least about 100,000 gals, at least about 1,000,000 gals and more of fracking fluid are used in a fracking operation. Thus, in general hundreds of thousands, if not millions of pounds of proppant, may be used in a single hydraulic fracturing operation.

In an example of the systems and techniques described herein, fractures initiating at one well, e.g., the stimulation well, are encouraged to propagate toward an adjacent well, e.g., the production well, by manipulating the stress field near the adjacent well, e.g., the production well. The stress field in a reservoir can be manipulated or changed in a way that is predictable (based on the theory of porothermoelasticity) by causing pressure or temperature changes in the reservoir rock through, for example, injection or production of fluids. Fractures are encouraged to propagate into low-stress regions of the reservoir. The adjacent wellbore may be set on production for a significant period of time prior to the stimulation treatment in the first well. The pressure depletion that occurs due to production may cause a poroelastic stress change in the reservoir that may have the effect of reducing the compressive stress, effectively creating a low-stress zone near the adjacent wellbore. As fractures propagate away from the first well, they may be encouraged to propagate into the low-stress region toward the adjacent wellbore. In some cases, the propagating fractures may intersect and connect with the adjacent well. These newly created fractures near the producing well increase conductivity of the reservoir with the production well and thus increase production from that well or circulation rates between the wells.

In an example of the systems and techniques described herein, fractures initiating at one well, e.g., the stimulation well, are encouraged to turn and branch as they approach an adjacent well, the production well, by manipulating the stress field near the adjacent well. Fractures are discouraged from propagating into high-stress regions of the reservoir. Fluid injection occur into the adjacent wellbore for a significant period of time prior to the stimulation treatment in the first well. The pressurization that occurs due to injection may cause a poroelastic stress change in the reservoir that may have the effect of increasing the compressive stress, effectively creating a high stress zone near the adjacent wellbore. As fractures propagate away from the first well, they may be discouraged from propagating into the high-stress region and may tend to bend or branch away from their original path. The complex fracture growth may encourage intersection with other tensile or preexisting fractures, increasing effective fracture surface area and reservoir pore volume. These newly created fractures near the producing well increase conductivity of the reservoir with the production well and thus increase production from that well as well as increasing the residence time for fluid flowing between wells.

In an example, the stress changes induced by fracture propagation and deformation (i.e., “stress shadowing”) is taken advantage of to encourage fractures to propagate away from the wellbore in an asymmetric fashion. For example, in a system containing one injection well and two offset production wells, where the injection well is stimulated hydraulically, for every two fractures that propagate away from the injection well, only one fracture intersects each offset well (see FIG.). In this manner, the fracture spacing can be designed to improve thermal sustainability.

In one example of the systems and techniques described herein, the fluid pressure and flow rate conditions in two wellbores connected by a fracture are manipulated to control fracture closure and proppant immobilization. During hydraulic stimulation treatments, a slurry mixture of water, chemicals, and proppant are injected. As fluid flows through a propagating fracture, various forces control the rate of proppant settling. Fracture conductivity is influenced significantly by how evenly proppant is distributed within the fracture after pumping stops. Proppant immobilization largely depends on a competition between the rate of fracture closure and the rate of proppant settling. The fracture may close once the fluid pressure drops below the normal stress acting on the fracture. The flow rates and pressures in the two wellbores are controlled to effectively drop the pressure in the fracture to rapidly close the fracture, ensuring the proppant is immobilized before proppant settling becomes significant and encouraging even distribution of proppant within the fracture. These newly created fractures, and proppant distribution, near the producing well increase conductivity of the reservoir with the production well and thus increase production from that well.

In an example, fractures initiating at one well are detected and characterized as they approach an adjacent well using distributed sensing optical fibers installed in the adjacent well. As fractures deform and propagate, they perturb the surrounding material. The length-scale over which stress and deformation perturbations is proportional to the dimension of the fracture, which grows larger throughout a stimulation treatment. Distributed acoustic sensing, distributed temperature sensing, and distributed strain sensing fiber optic cables may be installed in the adjacent well. Fluid pressure and temperature are also monitored in the adjacent well. These measurements combined are used to interpret where and when fractures that initiated at the first well approach the adjacent well. Properties such as fracture length, fracture width, rate of propagation, fracture spacing, and perforation/cluster efficiency can be interpreted. This information is used to adjust the stimulation treatment parameters, such as flow rate and proppant concentration, in the first well. In this manner these newly created fractures, and proppant distribution, near the producing well increase conductivity of the reservoir with the production well and thus increase production from that well.

The first or stimulation well may be a depleted production well, or a new well drilled solely for the purpose of stimulating a second well, e.g., the producing well. One stimulation well may be used to enhance the fracture pattern of one, two, three or more production wells that are adjacent to the stimulation well. By adjacent it is meant that the stimulation well is in the same general location or field as the well, or well, from which increased production is sought. It being understood that there can be one or more other wells between the stimulation well and the production well.

illustrate distributions of reservoir pressure in accordance with examples described herein.