US20140262239A1

US20140262239A1 - Preparing a Wellbore for Improved Recovery

Info

Publication number: US20140262239A1
Application number: US14/175,780
Authority: US
Inventors: Stuart R. Keller; Thomas J. Boone; John T. Linderman; Matthew A. Dawson
Original assignee: Individual
Current assignee: Individual
Priority date: 2013-03-13
Filing date: 2014-02-07
Publication date: 2014-09-18

Abstract

The present disclosure provides a system for and method of preparing a wellbore for improved recovery from a formation and a method of producing hydrocarbons from a formation. The system includes an approximately horizontal wellbore in a formation, a liner enclosing a portion of the approximately horizontal wellbore; and a packer inside the liner that comprises a swellable elastomeric material.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional No. 61/779,998, filed Mar. 13, 2013, which is incorporated by reference herein in its' entirety.

BACKGROUND

1. Fields of Disclosure
The disclosure relates generally to the field of preparing a wellbore for improved recovery and producing hydrocarbons.
2. Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Substantial volumes of hydrocarbons exist in low-permeability and high-permeability formations around the world. Low-permeability formations may be formations that are near horizontal wells with multiple fracture stimulations distributed along the well and required to produce fluids from the formation at economic rates. For example, low-permeability formations may be less than or equal to 10 millidarcies (mD) while high-permeability formations may be formations that are greater than 10 mD. Low-permeability formations may be predominantly sandstone, carbonate, or shale and/or may have some high-permeability streaks. High-permeability formations may have some low-permeability streaks.
During primary production natural reservoir energy drives hydrocarbons from the reservoir and into the wellbore. Initially, the reservoir pressure is considerably higher than the bottomhole pressure inside the wellbore. This high natural differential pressure drives hydrocarbons toward the well. During primary production the reservoir pressure declines as fluids are removed from the formation. The natural reservoir energy exploited in primary production such as oil and water expansion, evolution and expansion of gas initially dissolved in the oil, and rock compaction have limited ability to compensate for the volume of produced hydrocarbons and thereby to mitigate the pressure decline. As the reservoir pressure declines because of production, so does the differential pressure between the reservoir and wellbore, resulting in declining production rates. Primary production ends when the pressure is so low that the hydrocarbon production rate is no longer economical. Recovery during primary production is typically less than 15%. The lower the permeability of the formation the more difficult it is for pressure and fluid to be transmitted towards the well. This results in lower initial rates, more rapid pressure decline, and lower recovery of hydrocarbons.
Production of hydrocarbons from high-permeability formations often results in more satisfactory recovery rates than low-permeability formations. The recovery rate of hydrocarbons in high-permeability formations can be as high as 75%. To achieve these higher rates, different drive mechanisms may be used. For example, water injection or gas injection may be used to provide pressure support and to displace hydrocarbons. Other processes, such as injecting miscible gases, surfactants, solvents, polymers, or steam may also be used to help improve hydrocarbon recovery.
To increase the recovery rate of hydrocarbons during primary production from low-permeability formations, operators have tried using various well types and configurations, different well stimulation methods and processes that exploit different drive mechanisms during and after primary production. For example, operators have tried closely spaced vertical and horizontal wells, wells that have been stimulated using a variety of methods such as hydraulic fracturing, acid injection or acid fracturing. Stimulation methods increase the productivity of a well, enabling a well to initially produce hydrocarbons at a higher rate. Additionally, operators have tried some of the same drive-mechanisms used in high-permeability formations, such as water-flooding or gas-flooding, after fracturing during primary production. One well design that is commonly employed in low permeability formations, as shown in FIG. 1, consists of installing a horizontal well 1 and creating fractures 2 that emanate from the wellbore 5 of the well 1 to recover the hydrocarbons. As shown in FIG. 2, stimulated horizontal wells can be utilized for water-flooding by a method that entails operators installing a well 100 and injecting water so that the water displaces hydrocarbons toward producer wells 4, 204. Gas-flooding is similar to water-flooding, but entails injecting into a well instead of water to displace hydrocarbons to a production well.
Although fracturing can help primary production from a low permeability formation to be more economically attractive by increasing initial production rates, the process has two major disadvantages. First, due to rapid pressure decline in the wellbore region, the production rate of recovered hydrocarbons typically declines quickly to less than 25% of the initial rate of recovery within a year. Second, the total percentage of recovered hydrocarbons relative to the hydrocarbons contained in the formation is low. Often, the total percentage of recovered hydrocarbons is less than 15%. The low formation permeability and resulting low rate of pressure diffusion through the reservoir, results in rapid pressure decline at the well and rapidly declining production rates of hydrocarbons. Furthermore, since primary production processes rely on fluid expansion as their drive mechanisms they tend to have very low recovery levels in all oil reservoirs.
Disadvantages also result when operators use water-flooding or gas-flooding after using fracturing during primary production in a low-permeability formation. These processes have the potential to increase recovery of hydrocarbons to 20% or more. However, they require the drilling and fracturing of additional injection wells or the conversion of existing production wells into injection wells. Because of the low permeability, the injection wells need to be relatively close to the producing well to provide sufficient pressure support and achieve economic rates. Nonetheless, water-flooding in low-permeability formations is often limited by low injection rates due to the low-permeability formation, injection pressure constraints, plugging, separation between the wells and relative permeability effects. A key limiting factor is that if the injection wells are placed in close proximity to the production wells, the fractures from the wells may intersect. This results in high conductivity pathways between the wells that severely limit the rate of hydrocarbon production and the overall recovery that can be economically achieved. Gas-flooding in low-permeability formations is often limited by poor sweep due to gravity override, viscous fingering and heterogeneity contrast. These detrimental effects often cause fractures to intersect, thereby eliminating the pressure difference needed for sweep to occur. These disadvantages are often exacerbated in low-permeability formations because of tight well spacing and higher permeability streaks.
Additional disadvantages may also result when the aforementioned drive mechanisms are used in low-permeability or high-permeability formations. The effectiveness of water injection for improved recovery is sometimes adversely affected by reduced injectivity due to plugging of injection wells with solids, scale, oil, etc. Enhanced recovery techniques, such as injection of miscible gases, surfactants, solvents, polymers, modified brines, or steam can sometimes be applied to high permeability reservoirs to improve recovery, but the use of these techniques is often uneconomic. There is a significant time difference between when these relatively expensive fluids are injected into an injection well when that incremental hydrocarbon production occurs at a producing well.
A need exists for improved technology, including technology that may address one or more of the above described disadvantages.

SUMMARY

A system for preparing a wellbore for improved recovery from a formation may include an approximately horizontal wellbore in a formation, a liner enclosing a portion of the approximately horizontal wellbore, and a packer inside the liner that comprises a swellable elastomeric material.
A method of preparing a wellbore for improved recovery from a formation may comprise drilling a wellbore in a formation, wherein the wellbore is approximately horizontal; enclosing a portion of the wellbore with a liner; forming a first fracture in the formation that emanates from the wellbore; forming a second fracture in the formation that emanates from the wellbore and is substantially parallel and directly adjacent to the first fracture; and installing a packer inside the liner that comprises a swellable elastomeric material.
A method of producing hydrocarbons from a formation may comprise drilling a wellbore in a formation, wherein the wellbore is approximately horizontal; enclosing a portion of the wellbore with a liner; forming a first fracture in the formation that emanates from the wellbore; forming a second fracture in the formation that emanates from the wellbore and is substantially parallel and directly adjacent to the first fracture; installing a packer inside the liner that that comprises a swellable elastomeric material; and producing hydrocarbons from the first fracture.
The foregoing has broadly outlined some of the features of the present disclosure in order that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects and advantages of the disclosed embodiments will become apparent from the following description, appending claims and the accompanying exemplary embodiments shown in the drawings, which are briefly described below.

FIG. 1 is a top, schematic view of a conventional well.

FIG. 2 is a top, schematic view of conventional production well and a conventional injection well.

FIG. 3 is a top, schematic view of a well.

FIG. 4 is a top, schematic view of a well.

FIG. 5 is a top, schematic view of a well.

FIG. 6 is a schematic of a method.

FIG. 7 is a chart comparing recovery rates for different recovery methods.

FIG. 8 is a chart comparing cumulative production of hydrocarbons over time for the present disclosure to that of merely using hydraulic fracturing during primary production.

FIG. 9 is a chart comparing the recovery rate of hydrocarbons over time for the present disclosure to that of merely using hydraulic fracturing during primary production.

It should be noted that the figures are merely examples of several embodiments of the present disclosure and no limitations on the scope of the present disclosure are intended thereby. Moreover, not all features of an embodiment may be shown in the figures. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of certain embodiments of the disclosure.

DETAILED DESCRIPTION

For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the information illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications in the described embodiments, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the figures for the sake of clarity.
As shown in FIGS. 3-5, a system of preparing a wellbore may include an approximately horizontal wellbore 57, 67, 76, a liner 60, 70, and a packer 62, 72.
The approximately horizontal wellbore 57, 67, 76 may be a wellbore that is at a high angle or a dipping angle, but not completely horizontal, or a wellbore that is substantially horizontal.
The wellbore 57, 67, 76 is a hole, within a formation having a reservoir 51, 61, 71 (FIGS. 3-5). The formation may be a low-permeability formation or a high-permeability formation. Generally speaking, low-permeability formations may be formations that are near approximately horizontal wells with multiple fracture stimulations distributed along the well and required to produce fluids from the formation at economic rates. For example, a low-permeability formation may be less than or equal to 10's of mD, 10's of mD on average, 10 mD, or 10 mD on average. Low-permeability formations may have some high-permeability streaks and high-permeability formations may have some low-permeability streaks.
The permeability of a formation may be measured by any suitable method. For example, the permeability may be measured or determined from core tests or well tests. The average permeability of a formation may be based on a thickness-weighted arithmetic average of measured or estimated permeabilities within the formation, or it may be based on well test measurements. Furthermore, it is recognized that permeability can vary greatly from place to place within a given reservoir and there may not be consistency between different measures of permeability.
The wellbore 57, 67, 76 may comprise a single wellbore. In other words, the wellbore 57, 67, 76 may comprise one wellbore. The single or one wellbore may be within one or more formations having one or more reservoirs.
The wellbore 57, 67, 76 may include an injection tubing string 65, 175 and a production tubing string 64, 174 (FIGS. 3-5). The injection tubing string 65, 175 may be substantially parallel to the production tubing string 65, 175 such that an injection tubing string longitudinal axis 69-69, 79-79 (FIGS. 4-5) of the injection tubing string 65, 175 is substantially parallel to a production tubing string longitudinal axis 68-68, 78-78 of the production tubing string 64, 174 (FIGS. 4-5). The production tubing string longitudinal axis 69-69, 79-79 and injection tubing string longitudinal axis 68-68, 78-78 are substantially parallel to a longitudinal axis 59-59 (FIG. 3) of the wellbore 57, 67, 76.
The injection tubing string 65 includes at least one opening. The opening may be constructed and arranged to inject fluid into a second fracture 53 (FIG. 4). The opening creates a pathway between the injection tubing string 63 and the second fracture 53 so that the second fracture 53 can receive the fluid from the injection tubing string 63. The opening may be any suitable opening, such as a perforation.
As shown in FIG. 4, the injection tubing string 65 may be directly adjacent to the production tubing string 64 and may be the same length or about the same length as the production tubing string 64. Moreover, the injection tubing string 65 and the production tubing string 64 may both extend through a production zone and an injection zone 74 of the wellbore 67. The production zone 75 is the zone in the well 75 that directly communicates with the portion of the formation that receives hydrocarbons from the reservoir. The injection zone 74 is the zone in the well that directly communicates with the portion of the formation that receives fluid injected into the wellbore from the reservoir.
As shown in FIGS. 4 and 5, the production zone 75 is separated or isolated from the injection zone 74. The production zone 75 may be hydraulically separated or isolated from the injection zone 74 by any suitable device, such as a packer 62. The packer 62 may be a single packer or a dual-string packer.
The liner 60, 70 (FIGS. 4-5) encloses a portion of the approximately horizontal wellbore to line the wellbore. The liner 60, 70 may be made out of any suitable material, such as steel and/or cement. The liner 60, 70 may house the injection tubing string 65, 175 and the production tubing string 64, 174.
The packer 62 may be any type of suitable packer. For example, the packer 62 may be a mechanical, inflatable or swellable packer. If the packer is a mechanical packer, the packer may be a hydraulically set packer. If the packer is a swellable packer, the packer may comprise a swellable elastomeric material.
A swellable packer may be preferable to a mechanical or inflatable packer because a swellable packer may have larger clearances than a mechanical or inflatable packer. The swellable packer may have a larger clearance because the expansion of the elastomeric material of the swellable packer is due to swelling rather than or in addition to mechanical extrusion. An increased clearance is particularly important when the packer is placed in a high-angle or horizontal well. For example, in an approximately horizontal well debris, and other elements, which may build-up in the well, do not fall to the bottom of the well as in a vertical well because gravity does not force the debris and other elements to fall to the bottom. As a result, the debris and other elements build-up in an approximately horizontal well and make it hard for a packer that does not have larger clearances to be set along the length of the approximately horizontal well. The smaller clearance prevents the packer from being set within the well at some locations where debris and/or other elements have built-up.
A swellable packer may also be preferable to a mechanical or inflatable packer because the swellable packer may be easier to run through a casing and/or liner, such as the casing and/or liner 60, 70, that has a smaller inner diameter than a distal casing and/or distal lining where the packer is to be set. The distal casing and/or casing is distal from the smaller inner diameter section of the casing and/or liner where the packer is to be set. A casing or liner may have the smaller inner diameter when (a) the packer must pass through a liner patch or scab liner, (b) it is desired to pass a packer through tubing and then set the packer in an inside casing, or (c) a heavier wall casing is used above a lighter wall casing for tubular design considerations. A liner patch or scab liner is a downhole assembly or tool system used in the repair of liner damage, corrosion or leaks.
An injection tubing string flow control device 63 may be used to assist in setting the packer 62 in the wellbore and/or to regulate fluid flow into and/or out of the second fracture 53. As shown in FIG. 4, the fluid may be discontinuously injected from the injection tubing string 65 to the second fracture 53 with the flow control device 63, 163. Specifically, the injection tubing string flow control device 63, 163 may be constructed and arranged to discontinuously create a pathway between the injection tubing string 65 and the second fracture 53. For example, the injection tubing string flow control device 63, 163 may not cover or cover the opening in the injection tubing string. When the injection tubing string flow control device is open, a fluid pathway exists between the injection tubing string 65 and the second fracture 53. When the injection tubing string flow control device is closed, a fluid pathway does not exist between the injection tubing string 65 and the second fracture 53. As a result, fluid injected into the injection tubing string 65 may only enter the second fracture 53 when the injection tubing string flow control device is open.
The injection tubing string flow control device 63, 163 may comprise any suitable mechanism. For example, the injection tubing string flow control device 63, 163 may comprise one of a sliding sleeve, a pressure, activated valve, a mechanically activated valve, an electrically activated valve, an inflow control device, an outflow control device, a choke and a limited-entry perforation. When the injection tubing string flow control device assists in setting the packer, the injection tubing string flow control device may not be an inflow control device or an outflow control device.
The injection tubing string flow control device 63, 163 may enclose a portion of the injection tubing string 65. The injection tubing string flow control device 63, 163, may be a separate element from the injection tubing string 65. The injection tubing string flow device 63, 163 may be part of the injection tubing string 65.
A portion of the production tubing string 64 may be enclosed by a production tubing string flow control device or the production tubing string may include a production tubing string flow control device 263 (FIG. 4). The production tubing string flow control device may discontinuously create a pathway between the production tubing string 64 and a first fracture 52 so that the production tubing string discontinuously receives hydrocarbons from the first fracture 52. The production tubing string flow control device may help to gain additional flexibility as it pertains to producing hydrocarbons from the first fracture 52. The production tubing string flow control device 263 may function the same way that the injection tubing string flow control device functions. The production tubing string flow control device may be any suitable element, such as a sliding sleeve, a pressure, activated valve, a mechanically activated valve, an electrically activated valve, an inflow control device, an outflow control device, a choke OR a limited-entry perforation.
The production tubing string 64 may include at least one opening. The opening may be constructed and arranged to receive the hydrocarbons from the first fracture 52 (FIG. 4). The opening creates a pathway between the production tubing string 64 and the first fracture 52 so that the production tubing string 64 can receive hydrocarbons from the first fracture 52. The opening may be any suitable opening, such as a perforation.
As shown in FIG. 5, the injection tubing string 175 and the production tubing string 174 may be interspersed throughout the wellbore 76. As such, the production tubing string 174 only extends through the injection zone 75 of the wellbore 76 and not the production zone 74 of the wellbore 76 and the injection tubing string 175 only extends through the production zone 74 of the wellbore 76 and not the injection zone 75 of the wellbore 76. In other words, the tubing strings 174, 175 in the wellbore 76 may comprise jumper tubing strings. When this occurs, the production tubing string 174 communicates with the second fracture 53 and the injection tubing string 175 communicates with the first fracture 52.
When the injection tubing string 175 and the production tubing string 174 are interspersed throughout the wellbore 76 (FIG. 5), the wellbore 76 may include a packer 72 and the injection tubing string 175 and production tubing string 174 may be housed within the liner 70 (FIG. 5). The packer 72 may separate the production zone from the injection zone. The packer 72 may be a similar or identical to the packer 62 disclosed in paragraphs [0036]-[0038] and, therefore, these paragraphs can be referenced for information on the packer 72.
The interspersed nature of the injection tubing string 175 and the production tubing string 174 allow for the liner 70 to be smaller than the liner 60 of FIG. 5, but may expose the liner 70 to the fluid or the hydrocarbons and pressure. Moreover, the interspersed nature allows for less flexibility to control the inflow and outflow of the fluid and the hydrocarbons, respectively, than that of the configuration shown in FIG. 5.
The system includes the first fracture 52. The first fracture 52 is in the formation and emanates from the wellbore 57, 67, 76 (FIGS. 3-5). The first fracture 52 is formed by any suitable type of fracturing. For example, the first fracture 52 may be formed by a hydraulic fracturing treatment with or without proppant, or with acid injection. The first fracture 52 may be any suitable size. The first fracture 52 may receive hydrocarbons from a reservoir in the formation.
The first fracture 52 is constructed and arranged to receive hydrocarbons when the second fracture 53 receives a fluid injected into the wellbore. In other words, the first fracture 52 is sized and located to receive hydrocarbons from a reservoir in the formation. The first fracture 52 is in fluid communication with a tubing string that receives the hydrocarbons (i.e., the production tubing string) so that this tubing string can receive the hydrocarbons that the first fracture 52 receives and, therefore, produces.
The fluid injected into the wellbore may be any suitable fluid. For example, the fluid may comprise at least one of water, a hydrocarbon gas, a non-condensable gas, surfactants, foaming agents, polymers, and solids. If the fluid comprises a gas, the gas may be a miscible gas. The water may comprise any type/form of water. For example, the water may comprise at least one of modified brine, hot water, cold water and steam. The non-condensable gas may comprise any type of non-condensable gas. For example, the non-condensable gas may comprise at least one of carbon dioxide, methane, ethane, propane and nitrogen gas.
Before or after injecting the fluid, a plugging agent may be injected into the wellbore to promote diversion of the fluid away from any high-permeability streaks in a low-permeability formation, any low-permeability streaks in a high-permeability formation, and/or other short-circuit paths so better displacement is obtained. The plugging agent may be any suitable plugging agent, such as at least one of cement, polymer, foam, gel, or gel forming chemical. The gel forming chemical may be any suitable chemical, such as at least one of sodium silicate solution, solid, or salt. The plugging agent may be injected into at least one of the first fracture 52 and the second fracture.
A casing and/or liner patch may be installed in the wellbore. The casing and/or liner patch promotes diversion of the fluid away from any section of the wellbore that is connected to the reservoir to block flow into regions of the reservoir having high permeability paths and/or other short-circuit paths so better displacement is obtained elsewhere in the reservoir. The casing and/or liner patch may be installed into at least one of the first fracture 52 and the second fracture 53. The casing and/or liner patch may be installed into the wellbore after a period of operation and/or a production log identifying excessive flow.
The system includes the second fracture 53. The second fracture 53 is in the formation and emanates from the wellbore 57, 67, 76 (FIGS. 3-5). The second fracture 53 may be formed by any suitable type of fracturing. For example, the second fracture 53 may be formed by a hydraulic fracturing treatment with or without proppant, or with acid injection. The second fracture 53 may be any suitable size. The second fracture 53 may comprise an injection fracture that receives the fluid. The packer 62, 72 isolates the first fracture 52 from the second fracture 53.
The second fracture 53 is constructed and arranged to receive the fluid injected into the injection tubing string 65, 1755 (FIGS. 4-5) that increases pressure in the formation in an area adjacent to the first fracture 52. In other words, the second fracture 53 is sized to receive the fluid and is in fluid communication with the injection tubing string that receives the fluid when the fluid is injected into the wellbore so that the second fracture 53 can receive the fluid from the injection tubing string.
When the fluid injected into the second fracture 53 increases pressure in the formation in an area adjacent to the first fracture 52, hydrocarbons are displaced from the first fracture 52 and are produced by the first fracture 52. In other words, when the fluid injected into the second fracture 53 increases pressure, the hydrocarbons travel into the first fracture 52 and from the first fracture 52 into the production tubing string. The hydrocarbons are displaced in-part because the injection of the fluid creates a pressure difference between the area surrounding the first fracture and the area surrounding the second fracture that leads to hydrocarbons entering the first fracture. The hydrocarbons are also displaced because the first fracture and the second fracture do not intersect. If the first fracture intersects the second fracture, the efficiency of the process is reduced due to the high permeability pathway that results allowing the injected fluids to flow directly to the first fracture 52 without displacing the targeted hydrocarbons in the reservoir. Provided that the locations of the fractures is controlled such that the fractures are initiated at a spacing of 10's of meters or more along the well, the fractures would not be expected to intersect.
The first fracture 52 may comprise a plurality of first fractures and the second fracture 53 may comprise a plurality of second fractures. Each of the plurality of first fractures may be directly adjacent to one of the plurality of second fractures so that the first and second fractures alternate along a length of the wellbore. Each first fracture 52 may be about 25 to 300 m or 100 to 200 m from each second fracture 53. This spacing between the first fracture 52 and the second fracture 53 may depend on the permeability of the formation, formation heterogeneities, completion costs, risk of fracture intersection, etc. Each first fracture 52 may not be used for production. Each second fracture 53 may not be used for injection. Alternatively, some of the plurality of first fractures may be directly adjacent to each other to form a first fracture group and some of the plurality of second fractures may be directly adjacent to each other to form a second fracture group. Each fracture may be about 25 to 300 m apart, such as between 100 to 200 m apart. The first fracture group may be directly adjacent to a second fracture group. There may be a plurality of first and/or second fracture groups. Not all of the first and/or second fracture groups may be used for production and injection, respectively.
The first fracture 52 and the second fracture 53 may extend from the wellbore 57, 67, 76 for any suitable distance. For example, the first fracture 52 and the second fracture 53 may extend from the wellbore 57, 67, 76 for 20 to 500 m or 100 to 300 m. The length of the wellbore extends along the longitudinal axis 59-59 of the wellbore.
At least one of the first fracture 52 and the second fracture 53 may comprise one of a propped fracture, an unpropped fracture and an acid fracture. When the first and/or second fracture 52, 53 comprise a propped fracture, the first and/or second fracture 52, 53 include a material that props the fracture 52, 53 open during and after fracturing so that a fluid path between the fracture 52, 53 and the wellbore remains open. The material may comprise sized particles that are mixed with the fluid used to create the fracture 52, 53. The sized particles may include sand grains, proppants or any other suitable sized particles. When the first and/or second fractures 52/53 comprise an unpropped fracture, the first and/or second fractures 52/53 remain propped because of the natural properties of the formation after fracturing. When the first and/or second fracture 52, 53 comprise an acid fracture, the first and/or second fracture 52, 53 may be fractured with an acid. The acid may be any suitable acid, such as a hydrochloric acid. The acid fracture may be used in carbonate formations where it's practical to dissolve the rock in the formation with an acid. Propped fractures may be applied in most types of reservoirs, including both carbonate and clastics (e.g. sandstone, shale).
The injected fluid may enter the reservoir at a high enough pressure to hydraulically fracture the reservoir during the process of fluid injection and production. In this mode of operation one may not have performed a fracture treatment of any form previously discussed.
The first fracture 52 may comprise one type of fracture, such as a hydraulic fracture, and the second fracture 53 may comprise another type of fracture, such as an acid fracture. When the fractures comprise different types of fractures, one type of fracture may have to be produced at a first time and the other type of fracture may have to be produced at a second time that is different from the first time. For example, the first fracture 52 may have to be produced at the first time and the second fracture 53 may have to be produced at the second time. Alternatively, the different types of fractures may be produced at the same time.
The first fracture 52 may include a first fracture longitudinal axis 156-156 and the second fracture may include a second fracture longitudinal axis 157-157 (FIGS. 4-5). The first fracture longitudinal axis 156-156 may be substantially parallel to the second fracture longitudinal axis 157-157 such that the first fracture 52 is substantially parallel to the second fracture 53. The first and second fracture longitudinal axes 156-156, 157-157 may be substantially transverse to the longitudinal axis 59-59 of the wellbore 57, 67, 76, 84 (FIGS. 3-6). In other words, at least one of first fracture 52 and the second fracture 53 may be substantially oblique and/or irregular with respect to the wellbore.
As shown in FIG. 6, a method of preparing a wellbore and/or producing hydrocarbons from a formation may include drilling the wellbore in the formation 200, enclosing a portion of the wellbore 201, forming the first fracture 52 that emanates from the wellbore 57, 67, 76, 202, forming the second fracture 53 that emanates from the wellbore 57, 67, 76 and is substantially parallel to the first fracture 52, 203, and installing a packer 62, 72, 204. A Method of producing hydrocarbons from a formation may include all of the above steps of preparing a wellbore and may include producing hydrocarbons from the first fracture 305. The elements relevant to the method of preparing a wellbore and/or producing hydrocarbon from a formation are the same elements as those previously discussed in the disclosure. Thus, these elements are not again described in detail,
The methods may include simultaneously (a) injecting the fluid from the injection tubing string in communication with the second fracture 53 and (b) producing the hydrocarbons that travel from the first fracture 52 into the production tubing string.
Simultaneously is defined as occurring at the same time or almost occurring at the same time such that there is not a significant time lag between when the fluid is injected and the hydrocarbons are produced. While the injection and production generally occur simultaneously, there may be instances where injection occurs without production and/or production occurs without injection. Injection and production may not occur at the same time to manage excessive communication between the injection tubing string, the production tubing string, the first fracture, and/or the second fracture.
The wellbore may be drilled by any suitable mechanism and the wellbore may be approximately horizontal when the wellbore is drilled. Specifically, the orientation of the wellbore may be approximately parallel relative to the Earth's surface. The longitudinal axis 59-59 of the wellbore 57, 67, 76 may be approximately parallel to the lateral axis of the Earth and approximately transverse to the longitudinal axis of the Earth.
The fluid is injected from the injection tubing string 65, 175 to the second fracture 53 and the hydrocarbons are produced from a reservoir communicating with the first fracture 52 to the production tubing string 64, 174 that is substantially parallel to the injection tubing string 65, 75, simultaneously. As previously discussed, the injection of the fluid into the second fracture 53 increases pressure in an area of the formation adjacent to the first fracture 52.
The fluid may be discontinuously injected 203 from the injection tubing string 65 (FIG. 4) to the second fracture 53 with the flow control device 63, 163 and/or fluid/hydrocarbons may be discontinuously injected from the production tubing string 64 by the flow control device 263 (FIG. 4). At least paragraphs [0039]-[0041] of the disclosure provides examples of what the flow control device 63, 16, 263 may comprise and how the fluid may be discontinuously injected from the injection tubing string 65 and/or the production tubing string 64.
Regardless of whether the flow control device 63, 163, 263 is a separate element from the injection tubing string 65 and/or the production tubing string 64 or part of the injection tubing string 65 and/or the production tubing string 64, the flow control device 63, 163, 263 forms a complete or partial enclosure around the opening of the injection tubing string 65 and/or the production tubing string 64 that may be constructed and arranged to receive a fluid from the second fracture 53 and/or hydrocarbons from the first fracture 52. When the flow control device 63, 163, 263 forms a complete enclosure, the flow control device 63, 163, 263 surrounds the entire circumference of a portion of the injection tubing string 65 and/or the production tubing string 64. When the flow control device 63, 163, 263 forms a partial enclosure, the flow control device 63, 163, 263 surrounds less than the entire circumference of a portion of the injection tubing string and/or the production tubing string 64. When the flow control device 63, 163, 263 is in an open position, there is a continuous fluid pathway between the opening and the second fracture 53 and/or the first fracture 52 so that the fluid can be injected into the second fracture 53 and/or hydrocarbons can be received from the first fracture 52. When the flow control device 63, 163, 263 is in a closed position, there is no pathway between the opening and the second fracture 53 and/or the first fracture 52 so that the fluid cannot be injected into the second fracture 53, unwanted fluid or hydrocarbons cannot enter the injection tubing string from the wellbore, hydrocarbons cannot be injected into the production tubing string 64, and/or unwanted fluid or hydrocarbons cannot enter the production tubing string from the wellbore. In other words, the closed flow control device 63, 163, 263 prevents fluid and/or hydrocarbons from exiting or entering the opening of the injection tubing string 65 and/or the production tubing string 64.
When the packer 62, 72 is installed inside the liner 60, 70, the packer 62, 72 isolates 203 the first fracture 52 from the second fracture 53. The packer 62, 72 may be installed after forming the first fracture 52 and the second fracture 53. The packer 62, 72 may be installed before producing hydrocarbons 305. The packer 62, 72 may be installed before simultaneously injecting the fluid and producing the hydrocarbons. While this disclosure references using one packer 62, 72, multiple packers 62, 72 may be used. Likewise, multiple flow control devices may be used.
The methods may include removing equipment 207 from the wellbore 57, 67, 76 before isolating the first fracture 52 from the second fracture 53 and/or before discontinuously injecting the fluid. The method may include removing the equipment when the mechanism for forming the first fracture 52 and/or the second fracture 53 results in leaving equipment in the wellbore. When such a mechanism is used, the equipment must be removed before installing the packer 62, 72 and/or the flow control device 63, 163 that isolate the fractures 52, 53 and discontinuously injecting/receiving the fluid/hydrocarbons. Any suitable mechanism may be used to remove the equipment. For example, the equipment may be removed by using milling equipment to mill-out the equipment.
The methods may include installing the liner 60, 70 (FIGS. 4-5). The installation may occur before forming the fracture 52, 53. The installation may occur after drilling the wellbore 200. The methods may include installing the first tubing string and the first tubing string.
Before simultaneously (a) injecting the fluid and (b) producing the hydrocarbons 204, hydrocarbons may first be produced from at least one of the first fracture and the second fracture. The hydrocarbons may first be produced during primary production. Primary production may occur until the rate of recovery of hydrocarbons has declined substantially from the peak rate of recovery. After the substantial decline, the simultaneous injection of fluid and production of hydrocarbons 204 may occur. This sequence of events (i.e., first using primary production and then using simultaneous injection of fluid and production of hydrocarbons) may minimize the amount of capital investment risked and may work particularly well in low-permeability formations where the initial rate of recovery is relatively high, but significantly declines during the first year that the well is operated.
To further reduce the initial capital costs, the completion elements, such as the packer and/or flow control device, may be installed in the wellbore after the well has produced under primary production. This ensures that the installation of the completion elements does not affect the amount of hydrocarbons produced during primary recovery. If the completion elements are installed after primary production, a rig or other mechanism may have to be used to aid in installation. If problems occur while simultaneously injecting and producing, injection could be stopped and only production commenced or the problematic injection fracture(s) 53 could be closed off by plugging, closing the flow control device, etc.
Alternatively, hydrocarbons may initially be produced by simultaneously injecting fluid and producing hydrocarbons as opposed to initially producing hydrocarbons by primary production and then later switching to simultaneously injecting fluid and producing hydrocarbons.
Two or more simultaneous injection-production wells may be drilled and completed in a reservoir approximately parallel to each other. After at least one of these wells has produced under simultaneous injection and production for a prolonged period and hydrocarbon recovery rate has declined significantly due to an increasing fraction of water or gas in the produced fluids, injection may be stopped in at least one of the wells and production may be stopped in at least one of the wells adjacent to the at least one of the wells where injection is stopped. This will allow water, gas or other injected fluids to displace hydrocarbons from the area between the adjacent wells to the producing well, thereby increasing hydrocarbon recovery.
As shown in FIGS. 7-9, the system and method recovers substantially more hydrocarbons than those conventionally recovered. FIG. 7 shows the present value cumulative hydrocarbon recovery from two homogenous models with a permeability of 5 mD and 1 mD for five different recovery methods. The recovery methods include transverse fracturing and primary production A, water-flooding B, longitudinal fracturing and water-flooding C, transverse fracturing and water-flooding D, and the system and method E. As depicted in FIG. 7, the system and method E recovers substantially more hydrocarbons than recovery methods A-D.
FIGS. 8-9 show preliminary reservoir simulation results that compare the system to a conventional, fractured well assuming that each fracture is spaced 100 m from the adjacent fracture and the permeability of the formation is 1 mD. The system is assumed to be cumulatively produced by only fracturing during primary production for 1500 days and then converted to simultaneously injecting the fluid and producing hydrocarbons. As can be seen in FIG. 8, the cumulative production for the system is significantly higher than fracturing during primary production. As can be seen in FIG. 9, the system achieves significant increase in hydrocarbon rate after it is converted from the hydrocarbons being produced by fracturing during primary production to simultaneously injecting the fluid and producing the hydrocarbons. Although FIGS. 8-9 show the conversion at 1500 days, the conversion could occur at any time. If the conversion occurs earlier, such as at 300 days, the enhanced performance of the simultaneously injected fluid and produced hydrocarbons would occur earlier. If the conversion occurs later, the enhanced performance of the simultaneously injected fluid and produced hydrocarbons would occur later.
The system and method also significantly reduces a distance that the fluid injected into the wellbore has to travel before hydrocarbons are produced. Reducing the distance can improve the economics of injecting the fluid. The economics of injecting the fluid are frequently challenged in conventional systems because there is a significant time lag between when the fluid is injected and when production occurs. Because the system reduces the displacement distance between one well to another to the spacing between the first fracture 52 and the second fracture 53, the lag between the injection of the fluid and the production of the hydrocarbons can be reduced to a point where injection of the fluid and production of the hydrocarbons occurs simultaneously.
This acceleration of production can be beneficial to the economics of enhanced hydrocarbon recovery methods such as surfactant injection, miscible gas injection, etc. The cost of enhanced hydrocarbon recovery injectants is relatively high compared to water. By accelerating incremental production resulting from displacing hydrocarbons with an enhanced hydrocarbon recovery injectant, the simultaneous injection-production well can improve the economics of enhanced hydrocarbon recovery processes.
To mitigate fracture intersection and thereby mitigate short-circuiting, careful selection of the field, well orientation and/or spacing between the fractures can be implemented. To help carefully select the field, well orientation and/or spacing between the fractures, the method may include at least one of (a) at least one of logging the formation while drilling the wellbore, (b) at least one of monitoring and analyzing at least one of pressures and flow rates, (c) well testing after forming at least one of the first fracture and the second fracture, and (d) monitoring pressures in adjacent wells. (A) may include logging to obtain wellbore data and analyzing the wellbore data to assist in forming the first fracture and the second fracture. (B) may include at least one of monitoring and analyzing while forming at least one of the first fracture and the second fracture. (C) may include well testing to assess the effective fracture lengths. (D) may include monitoring while forming at least one of the first fracture and the second fracture.
Log data can be used to design the fracture spacing to reduce the risk of fracture intersection while still maintaining good well performance. The planned fracture spacing for the well can be adjusted based on reservoir quality as estimated from porosity or resistivity logs. The usual well plan will normally have a consistent spacing of fractures along the well, but it is possible to adjust fracture spacing or the planned location of fractures if the logs showed substantial reservoir quality variations along the wellbore.
Analyzing wellbore and monitoring data may include assessing where fractures spread, determining the anisotropy in the horizontal stresses in the formation, first fracture, and/or second fracture, etc. After the wellbore data is analyzed, information such as the stress state, location of the axis of the wellbore and/or the minimum in-situ horizontal stress could be used to mitigate the risk of fracture intersection. For example, the stress state could be leveraged and the axis of the wellbore could be aligned with the minimum in-situ horizontal stress to mitigate the risk of fracture intersection since fractures tend to open against a minimum in-situ stress and tend to propagate in a directional fashion in reservoirs with strong anisotropy in the horizontal stresses.
Fractures may tend to propagate preferably more to one side of a well (i.e. North) rather than the other direction (i.e., South), which may need to be accounted for in the design. Increasing fracture spacing may reduce the risk of fracture intersection. Fractures may be spaced at intervals as close as 25 m and as much as 300 m. For example, the fractures may be between 10 and 200 m apart and 25 and 100 m apart. The design of fracture spacing will depend on the permeability of the formation, reservoir heterogeneities, completion costs, risk of fracture intersection, and other factors. Identifying whether at least one of the fractures is at least 50 m long (i.e., the end of the fracture that emanates from the wellbore is at least 50 m from the other end of the fracture where the fracture has two ends) may also reduce the risk of fracture intersection. Fracture half length (i.e. the distance from the furthest end of the fracture and the wellbore) may also affect the risk of fracture intersection. Fracture half lengths may range from 50 m to more than 200 m. Longer fracture half lengths may increase recovery but also increase the risk of fracture intersection.
During the stimulation job to create the fractures, measurements of fluid volumes injected as well as injection pressures may be used with developed correlations to assess the likely fracture dimensions. Careful monitoring of injection fluid volumes and injection pressures during the stimulation job to create a fracture may be used to evaluate whether the new fracture may be at risk of intersecting other fractures and to change or curtail the injection that is creating the fracture.
Analyzing the fracture data may include reviewing the data to assess whether the first and/or second fractures are having communication challenges and to identify what zone (i.e., production or injection) the fracture is in. After simultaneous injection and production begin, early production of water can indicate whether fractures are intersecting. Production logging tools that measure pressures, temperatures, flow rates, fluid capacitance, fluid density, water-hydrocarbon fractions and/or fluid properties along the wellbore can be used to identify which production fractures in the wellbore may be communicating with an injection fracture. An alternative way of identifying which production fractures might be in communication with injection fractures is to monitor data from fixed sensors that have been installed as part of the completion, such as a fiber optic cable used as a distributed temperature sensor. Another way of identifying which production fractures might be in communication with injection fractures is to include different tracers with proppant for each fracture and analyzing produced fluids for relative tracer concentrations If one or more of the fractures is having communication challenges, workovers may be implemented to plug a problematic injection zone. Or a flow control device that can enclose the opening in the injection tubing string may be used to prevent injection of the fluid into the problematic zone. While some of these ways to identify are discussed as being alternatives to one another, one or more of the ways may be implemented in the system.
To mitigate fracture intersection, the method may also include monitoring the forming of each fracture and/or creating clusters of tightly spaced fractures with larger spaced buffers between the clusters. To increase the likelihood that the fractures do not intersect, the fractures may be formed concurrently so that the formed fractures shield one another, thereby preventing fracture intersection. Concurrent fracturing decreases the likelihood that the fractures do not intersect.
Moreover, to mitigate fracture intersection, the method may also include monitoring at least one of the first fracture and the second fracture during or after at least one of forming the first fracture and forming the second fracture. The monitoring may be performed using any suitable method, such as microseismic methods. The data obtained while monitoring may be analyzed and/or evaluated to identify whether fractures are approaching one another. If the data indicates that fractures are approaching one another, the method may also include ceasing formation of a fracture or plugging of a fracture. A fracture may be plugged by injecting a plugging agent into the formation or a casing and/or liner patch may be used, such as those discussed in paragraph [0051]-[0052] of this disclosure.
To analyze at least one of the fluid and hydrocarbons flowing one of in, out and along the wellbore, the system and method may include analyzing a production log. The production log may include any suitable production log. For example, the production log may measure pressure, temperature, flow rate, fluid capacitance, fluid density, or other fluid properties along the wellbore. Analyzing of the production log may be used to analyze directly or indirectly the fluid and/or hydrocarbons flowing in, out and/or along the wellbore. As an alternative or complement to production logs, the system and method may include at least one of the use of (a) fixed sensors that have been installed as part of the completion, such as a fiber optic cable used as a distributed temperature sensor and (b) different tracers with proppant for each fracture and the analysis of produced fluids for relative tracer concentrations.
Information on fluid flowing one of in, out and along the wellbore, from production logs, tracer analysis or other measurements can be obtained after fractures are created in the wellbore during primary production and/or before the completion equipment enabling simultaneous injection and production is installed in the well. The information on flow performance along the wellbore can be used to help design holes, orifices, or other sorts of inflow control devices or outflow control devices that may be installed as part of the completion equipment enabling simultaneous injection and production in the well. These inflow control devices and outflow control devices, such as flow control device 163, 263 (FIG. 4) can be used to restrict flow between the well and the formation. Adjusting these devices so that flow is more evenly distributed along the wellbore can be used to optimize the recovery of hydrocarbons during simultaneous injection and production.
The method may include logging the formation at least one of prior to fracturing and installing completion equipment. Open hole or cased hole logs could be used to log the formation. Completion equipment may include any suitable completion element, such as a packer, adjustment element, liner patch, casing, cement, etc. Logging the formation before fracturing and/or installing completion equipment may an operator or a computer identify areas of the reservoir, which is within the formation, that are best suited or worst suited for simultaneous injection and production. For example, some logging while drilling may help identify the likely near-wellbore orientation of natural fractures in the formation based at least on breakouts and other data. And other logging while drilling may help identify regions of natural fractures in the formation. These regions of natural fractures may short-circuit the simultaneous injection and production process by allowing fractures to intersect and thereby prevent the pressure difference needed to cause the first fracture to produce hydrocarbons. Consequently, identifying where natural fractures may or may not occur may be an indicator that fracturing should not take place in the region where natural fractures may occur where completion equipment can be placed to separate the fractures formed.
The method may include logging the formation after installation of completion equipment. Logging the formation with cased hole logs or production logs after installation of completion equipment could help an operator or computer identify channels in the cement or completion equipment that could cause short circuiting during simultaneous injection and production process.
Persons skilled in the technical field will readily recognize that in practical applications of the disclosed methodologies, one or more steps may be performed on a computer, typically a suitably programmed digital computer. Further, some portions of the detailed descriptions have been presented in terms of procedures, steps, logic blocks, processing and other symbolic representations of operations on data bits within a computer memory. These descriptions and representations are the means used by those skilled in the data processing arts to most effectively convey the substance of their work to others skilled in the art. In the present application, a procedure, step, logic block, process, or the like, is conceived to be a self-consistent sequence of steps or instructions leading to a desired result. The steps are those requiring physical manipulations of physical quantities. Usually, although not necessarily, these quantities take the form of electrical or magnetic signals capable of being stored, transferred, combined, compared, and otherwise manipulated in a computer system.
It should be borne in mind, however, that all of these and similar terms are to be associated with the appropriate physical quantities and are merely convenient labels applied to these quantities. Unless specifically stated otherwise as apparent from the following discussions, it is appreciated that throughout the present application, discussions utilizing the terms such as “analyzing,”, “identifying,” “monitoring,” “processing” or “computing,” “calculating,” “determining,” “displaying,” “copying,” “producing,” “storing,” “accumulating,” “adding,” “applying,” “identifying,” “consolidating,” “waiting,” “including,” “executing,” “maintaining,” “updating,” “creating,” “implementing,” “generating” or the like, may refer to the action and processes of a computer system, or similar electronic computing device, that manipulates and transforms data represented as physical (electronic) quantities within the computer system's registers and memories into other data similarly represented as physical quantities within the computer system memories or registers or other such information storage, transmission or display devices.
It is important to note that the steps depicted in FIG. 6 are provided for illustrative purposes only and a particular step may not be required to perform the inventive methodology. The claims, and only the claims, define the inventive system and methodology.
Embodiments of the present disclosure may also relate to an apparatus for performing some of the operations herein. This apparatus may be specially constructed for the required purposes, or it may comprise a general-purpose computer selectively activated or reconfigured by a computer program stored in the computer. Such a computer program may be stored in a computer readable medium. A computer-readable medium includes any mechanism for storing or transmitting information in a form readable by a machine (e.g., a computer). For example, but not limited to, a computer-readable (e.g., machine-readable) medium includes a machine (e.g., a computer) readable storage medium (e.g., read only memory (“ROM”), random access memory (“RAM”), magnetic disk storage media, optical storage media, flash memory devices, etc.), and a machine (e.g., computer) readable transmission medium (electrical, optical, acoustical or other form of propagated signals (e.g., carrier waves, infrared signals, digital signals, etc.). The computer-readable medium may be non-transitory.
Furthermore, as will be apparent to one of ordinary skill in the relevant art, the modules, features, attributes, methodologies, and other aspects of the disclosure can be implemented as software, hardware, firmware or any combination of the three. Of course, wherever a component of the present disclosure is implemented as software, the component can be implemented as a standalone program, as part of a larger program, as a plurality of separate programs, as a statically or dynamically linked library, as a kernel loadable module, as a device driver, and/or in every and any other way known now or in the future to those of skill in the art of computer programming. Additionally, the present disclosure is in no way limited to implementation in any specific operating system or environment.
As shown in FIG. 6, for example, disclosed aspects may be used to produce hydrocarbons. Disclosed aspects may also be used in other hydrocarbon management activities, in addition to hydrocarbon production. As used herein, “hydrocarbon management” or “managing hydrocarbons” includes hydrocarbon extraction, hydrocarbon production, hydrocarbon exploration, identifying potential hydrocarbon resources, identifying well locations, determining well injection and/or extraction rates, identifying reservoir connectivity, acquiring, disposing of and/or abandoning hydrocarbon resources, reviewing prior hydrocarbon management decisions, and any other hydrocarbon-related acts or activities. The term “hydrocarbon management” is also used for the injection or storage of hydrocarbons or CO₂, for example the sequestration of CO₂, such as reservoir evaluation, development planning, and reservoir management. Other hydrocarbon management activities may be performed according to known principles.
As utilized herein, the terms “approximately,” “substantially,” and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
It should be noted that the term “exemplary” as used herein to describe various embodiments is intended to indicate that such embodiments are possible examples, representations, and/or illustrations of possible embodiments (and such term is not intended to connote that such embodiments are necessarily extraordinary or superlative examples).
It should be understood that the preceding is merely a detailed description of specific embodiments of this disclosure and that numerous changes, modifications, and alternatives to the disclosed embodiments can be made in accordance with the disclosure here without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features embodied in the present examples may be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.
The articles “the”, “a” and “an” are not necessarily limited to mean only one, but rather may be inclusive and open ended so as to include, optionally, multiple such elements.

Claims

1. A system for preparing a wellbore for improved recovery from a formation, the system comprising:

an approximately horizontal wellbore in a formation;

a liner enclosing a portion of the approximately horizontal wellbore; and

a packer inside the liner that comprises a swellable elastomeric material.

2. The system of claim 1, wherein the formation has an average permeability of no more than 100 millidarcies.

3. The system of claim 1, wherein the liner comprises a casing string.

4. The system of claim 1, further comprising:

a first fracture in the formation that emanates from the wellbore; and

a second fracture in the formation that emanates from the wellbore and that is substantially parallel and directly adjacent to the first fracture,

wherein the packer isolates the first fracture from the second fracture.

5. The system of claim 4,

wherein the second fracture is constructed and arranged to receive a fluid that increase pressure in an area of the formation adjacent to the first fracture, and

wherein the first fracture is constructed and arranged to receive hydrocarbons.

6. The system of claim 4, wherein the first fracture is between 25 m and 300 m from the second fracture.

7. A method of preparing a wellbore for improved recovery from a formation, the method comprising:

drilling a wellbore in a formation, wherein the wellbore is approximately horizontal;

enclosing a portion of the wellbore with a liner;

forming a first fracture in the formation that emanates from the wellbore;

forming a second fracture in the formation that emanates from the wellbore and is substantially parallel and directly adjacent to the first fracture; and

installing a packer inside the liner that comprises a swellable elastomeric material.

8. The method of claim 7, wherein the formation has an average permeability of no more than 100 millidarcies.

9. The method of claim 7, further comprising installing an injection tubing string and a production tubing string in the wellbore, wherein the injection tubing string is substantially parallel to the production tubing string.

10. The method of claim 8, wherein the production tubing string communicates with the first fracture and the injection tubing string communicates with the second fracture.

11. The method of claim 7, further comprising:

logging the formation while drilling the wellbore to obtain wellbore data; and

evaluating the wellbore data to assist in forming the first fracture and the second fracture.

12. The method of claim 7, further comprising microseismically monitoring at least one of the first fracture and the second fracture after at least one of forming the first fracture and forming the second fracture.

13. The method of claim 7, further comprising microseismically monitoring at least one of forming of the first fracture and forming of the second fracture.

14. A method of producing hydrocarbons from a formation, the method comprising:

enclosing a portion of the wellbore with a liner;

forming a first fracture in the formation that emanates from the wellbore;

forming a second fracture in the formation that emanates from the wellbore and is substantially parallel and directly adjacent to the first fracture;

installing a packer inside the liner that that comprises a swellable elastomeric material; and

producing hydrocarbons from the first fracture.