U.S. patent application number 14/175780 was filed with the patent office on 2014-09-18 for preparing a wellbore for improved recovery.
The applicant listed for this patent is Thomas J. Boone, Matthew A. Dawson, Stuart R. Keller, John T. Linderman. Invention is credited to Thomas J. Boone, Matthew A. Dawson, Stuart R. Keller, John T. Linderman.
Application Number | 20140262239 14/175780 |
Document ID | / |
Family ID | 51522268 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262239 |
Kind Code |
A1 |
Keller; Stuart R. ; et
al. |
September 18, 2014 |
Preparing a Wellbore for Improved Recovery
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.
Inventors: |
Keller; Stuart R.; (Houston,
TX) ; Boone; Thomas J.; (Calgary, CA) ;
Linderman; John T.; (Houston, TX) ; Dawson; Matthew
A.; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Keller; Stuart R.
Boone; Thomas J.
Linderman; John T.
Dawson; Matthew A. |
Houston
Calgary
Houston
Sugar Land |
TX
TX
TX |
US
CA
US
US |
|
|
Family ID: |
51522268 |
Appl. No.: |
14/175780 |
Filed: |
February 7, 2014 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61779998 |
Mar 13, 2013 |
|
|
|
Current U.S.
Class: |
166/250.01 ;
166/179; 166/308.1 |
Current CPC
Class: |
E21B 43/267 20130101;
E21B 33/1208 20130101 |
Class at
Publication: |
166/250.01 ;
166/179; 166/308.1 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
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: 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.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] 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
[0002] 1. Fields of Disclosure
[0003] The disclosure relates generally to the field of preparing a
wellbore for improved recovery and producing hydrocarbons.
[0004] 2. Description of Related Art
[0005] 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.
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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.
[0013] A need exists for improved technology, including technology
that may address one or more of the above described
disadvantages.
SUMMARY
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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
[0018] 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.
[0019] FIG. 1 is a top, schematic view of a conventional well.
[0020] FIG. 2 is a top, schematic view of conventional production
well and a conventional injection well.
[0021] FIG. 3 is a top, schematic view of a well.
[0022] FIG. 4 is a top, schematic view of a well.
[0023] FIG. 5 is a top, schematic view of a well.
[0024] FIG. 6 is a schematic of a method.
[0025] FIG. 7 is a chart comparing recovery rates for different
recovery methods.
[0026] 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.
[0027] 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.
[0028] 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
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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).
[0062] 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.
[0063] 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.
[0064] 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.
[0065] 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,
[0066] 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.
[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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.
[0072] 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.
[0073] 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.
[0074] 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.
[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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.
[0084] 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.
[0085] 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.
[0086] 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.
[0087] 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.
[0088] 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.
[0089] 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.
[0090] 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.
[0091] 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.
[0092] 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.
[0093] 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.
[0094] 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.
[0095] 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.
[0096] 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.
[0097] 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.
[0098] 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.
[0099] 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.
[0100] 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 CO.sub.2, for example the sequestration of
CO.sub.2, such as reservoir evaluation, development planning, and
reservoir management. Other hydrocarbon management activities may
be performed according to known principles.
[0101] 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.
[0102] 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).
[0103] 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.
[0104] 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.
* * * * *