U.S. patent application number 14/423235 was filed with the patent office on 2015-07-23 for system and method for performing stimulation operations.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Hongren Gu, Olga Kresse, Xiaowei Weng.
Application Number | 20150204174 14/423235 |
Document ID | / |
Family ID | 50150415 |
Filed Date | 2015-07-23 |
United States Patent
Application |
20150204174 |
Kind Code |
A1 |
Kresse; Olga ; et
al. |
July 23, 2015 |
SYSTEM AND METHOD FOR PERFORMING STIMULATION OPERATIONS
Abstract
A system and method is provided for performing a fracturing
operation about a wellbore penetrating a subterranean formation.
The method may acquire integrated wellsite data. The method may
generate a mechanical earth model using the integrated wellsite
data. The method may simulate an intersection of an induced
hydraulic fracture with a natural fracture using the mechanical
earth model. The method may determine intersection properties of
the intersected natural fracture. The method may also generate a
stimulation plan using the mechanical earth model and the
intersection properties. The stimulation plan may include a fluid
viscosity or a rate of injection of a fracturing fluid.
Inventors: |
Kresse; Olga; (Sugar Land,
TX) ; Weng; Xiaowei; (Fulshear, TX) ; Gu;
Hongren; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
50150415 |
Appl. No.: |
14/423235 |
Filed: |
August 23, 2013 |
PCT Filed: |
August 23, 2013 |
PCT NO: |
PCT/US2013/056461 |
371 Date: |
February 23, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61692867 |
Aug 24, 2012 |
|
|
|
Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 49/00 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 49/00 20060101 E21B049/00 |
Claims
1. A method of performing a fracturing operation about a wellbore
penetrating a subterranean formation, the method comprising:
acquiring integrated wellsite data, wherein the integrated wellsite
data comprise geomechanical properties of the subterranean
formation and geometrical properties of one or more natural
fractures in the subterranean formation; generating a mechanical
earth model using the integrated wellsite data; simulating an
intersection of one or more induced hydraulic fractures with the
one or more natural fractures using the mechanical earth model;
determining one or more intersection properties of an intersected
natural fracture; and generating a stimulation plan using the
mechanical earth model and the one or more intersection
properties.
2. The method of claim 1, wherein the one or more intersection
properties comprise an amount of fracturing fluid leak-off from an
induced hydraulic fracture into the one or more natural
fractures.
3. The method of claim 1, wherein the one or more intersection
properties comprise continuity of fluid mass in a natural fracture,
fracturing fluid leak-off into the subterranean formation from
natural fracture walls, pressure sensitive natural fracture
permeability, fluid rheology in a natural fracture, a change in
natural fracture permeability, a change in stress within a region
of a natural fracture, a change in pressure within a region of a
natural fracture, or combinations thereof.
4. The method of claim 1, wherein simulating the intersection
comprises modeling an opened zone of a natural fracture that is
filled with fracturing fluid from an induced hydraulic fracture,
wherein fluid pressure in the opened zone exceeds the normal stress
of the natural fracture.
5. The method of claim 1, wherein simulating the intersection
comprises modeling a closed zone of a natural fracture that is
invaded with fracturing fluid from an induced hydraulic fracture,
wherein fluid pressure in the closed zone is above the pore
pressure of the natural fracture and below the closure stress of
the natural fracture.
6. The method of claim 1, wherein simulating the intersection
comprises modeling a closed zone of a natural fracture that is
filled with original reservoir fluid and no invading fracturing
fluid, wherein fluid pressure in the closed zone is above the pore
pressure of the natural fracture.
7. The method of claim 1, further comprising simulating a
propagation of a network of induced hydraulic fractures.
8. The method of claim 1, wherein simulating the intersection
comprises modeling shear failure or shear slip in a natural
fracture.
9. The method of claim 1, wherein the one or more intersection
properties comprise an increase in permeability in the one or more
natural fractures intersected by the one or more induced hydraulic
fractures.
10. The method of claim 1, further comprising performing a
stimulation operation based on the stimulation plan.
11. The method of claim 10, further comprising validating the
simulated intersection based on observed data acquired from the
stimulation operation.
12. The method of claim 1, wherein the stimulation plan comprises a
fluid viscosity of a fracturing fluid or a rate of injection of a
fracturing fluid.
13. The method of claim 10, further comprising adjusting at least
one of the fluid viscosity and the rate of injection of the
fracturing fluid to optimize the one or more intersection
properties.
14. A method of performing a fracturing operation about a wellbore
penetrating a subterranean formation, the method comprising:
acquiring integrated wellsite data, wherein the integrated wellsite
data comprise geomechanical properties of the subterranean
formation and geometrical properties of one or more natural
fractures in the subterranean formation; generating a mechanical
earth model using the integrated wellsite data; simulating an
intersection of one or more induced hydraulic fractures with the
one or more natural fractures using the mechanical earth model;
determining one or more intersection properties of an intersected
natural fracture; and predicting hydrocarbon production from the
subterranean formation using the one or more intersection
properties.
15. The method of claim 14, wherein the hydrocarbon production
prediction uses observed data acquired from a stimulation operation
that had been performed based on the mechanical earth model.
16. The method of claim 14, wherein predicting the hydrocarbon
production comprises predicting permeability of a reservoir in the
subterranean formation using the one or more intersection
properties.
17. The method of claim 14, wherein simulating the intersection
comprises at least one of: modeling an opened zone of a natural
fracture that is filled with fracturing fluid from an induced
hydraulic fracture, wherein fluid pressure in the opened zone
exceeds the normal stress of the natural fracture; modeling an
invaded closed zone of the natural fracture that is invaded with
fracturing fluid from the induced hydraulic fracture, wherein fluid
pressure in the invaded closed zone is above pore pressure in the
natural fracture and below the closure stress of the natural
fracture; and modeling a non-invaded closed zone of the natural
fracture that is filled with original reservoir fluid and no
invading fracturing fluid, wherein fluid pressure in the
non-invaded closed zone is above the pore pressure of the natural
fracture.
18. The method of claim 17, wherein modeling the opened zone or one
of the closed zones of the natural fracture comprises using one or
more of the following parameters: flowrate of invading fracturing
fluid; length of a zone in the natural fracture; width of a zone in
the natural fracture; shear displacement; hydraulic fracture
aperture; reservoir permeability; natural fracture permeability;
and pressure field.
19. A method of performing a fracturing operation about a wellbore
penetrating a subterranean formation, the method comprising:
acquiring integrated wellsite data, wherein the integrated wellsite
data comprise geomechanical properties of the subterranean
formation and geometrical properties of one or more natural
fractures in the subterranean formation; generating a mechanical
earth model using the integrated wellsite data; simulating an
intersection of one or more induced hydraulic fractures with the
one or more natural fractures using the mechanical earth model;
determining one or more intersection properties of one or more
intersected natural fracture; and comparing the one or more
intersection properties with microseismic events in observed data
acquired from a stimulation operation based on the mechanical earth
model.
20. The method of claim 19, wherein simulating the intersection
comprises at least one of: modeling an opened zone of a natural
fracture that is filled with fracturing fluid from an induced
hydraulic fracture, wherein fluid pressure in the opened zone
exceeds the normal stress of the natural fracture; modeling an
invaded closed zone of the natural fracture that is invaded with
fracturing fluid from the induced hydraulic fracture, wherein fluid
pressure in the invaded closed zone is above pore pressure in the
natural fracture and below the closure stress of the natural
fracture; and modeling a non-invaded closed zone of the natural
fracture that is filled with original reservoir fluid and no
invading fracturing fluid, wherein fluid pressure in the
non-invaded closed zone is above the pore pressure of the natural
fracture.
21. A method of performing a fracturing operation about a wellbore
penetrating a subterranean formation, the method comprising:
acquiring integrated wellsite data, wherein the integrated wellsite
data comprise geomechanical properties of the subterranean
formation and geometrical properties of one or more natural
fractures in the subterranean formation; generating a mechanical
earth model using the integrated wellsite data; simulating leak-off
of fracturing fluid from one or more induced hydraulic fractures
into the one or more natural fractures using the mechanical earth
model; generating a stimulation plan using the mechanical earth
model; and adjusting one or more operating parameters of the
stimulation plan based on the simulated leak-off to achieve an
optimized leak-off from the one or more induced hydraulic fractures
into the one or more natural fractures.
22. The method of claim 21, wherein the one or more operating
parameters of the stimulation plan comprise at least one of the
following: fluid viscosity of the fracturing fluid; rate of
injection of the fracturing fluid; fluid ingredient in the
fracturing fluid; additives in the fracturing fluid that affect a
leak-off property; proppant size in the fracturing fluid; and
proppant concentration in the fracturing fluid.
23. The method of claim 21, wherein simulating the leak-off of
fracturing fluid comprises at least one of: modeling an opened zone
of a natural fracture that is filled with fracturing fluid from an
induced hydraulic fracture, wherein fluid pressure in the opened
zone exceeds the normal stress of the natural fracture; modeling an
invaded closed zone of the natural fracture that is invaded with
fracturing fluid from the induced hydraulic fracture, wherein fluid
pressure in the invaded closed zone is above pore pressure in the
natural fracture and below the closure stress of the natural
fracture; and modeling a non-invaded closed zone of the natural
fracture that is filled with original reservoir fluid and no
invading fracturing fluid, wherein fluid pressure in the
non-invaded closed zone is above the pore pressure of the natural
fracture.
Description
BACKGROUND
[0001] This section is intended to provide background information
to facilitate a better understanding of various technologies
described herein. As the section's title implies, this is a
discussion of related art. That such art is related in no way
implies that it is prior art. The related art may or may not be
prior art. It should therefore be understood that the statements in
this section are to be read in this light, and applicant neither
concedes nor acquiesces to the position that any given reference is
prior art or analogous prior art.
[0002] In order to facilitate the recovery of hydrocarbons from oil
and gas wells, the subterranean formations surrounding such wells
can be hydraulically fractured. Hydraulic fracturing has become a
valuable technique to create cracks in subsurface formations that
allow hydrocarbons to move toward the well. Hydraulic fractures may
extend away from the wellbore hundreds of feet in two opposing
directions according to the natural stresses within the formation.
Under certain circumstances, they may form a complex fracture
network. Complex fracture networks can include induced hydraulic
fractures and natural fractures, which may or may not intersect,
along multiple azimuths, in multiple planes and directions, and in
multiple regions.
[0003] A formation is fractured by introducing a specially
engineered fluid (referred to as "fracturing fluid" or "fracturing
slurry") at high pressure and high flow rates into the formation
through one or more wellbores. Oilfield service companies have
developed a number of different oil- and water-based fluids and
treatments to more efficiently induce and maintain permeable and
productive fractures. The composition of these fluids varies
significantly, from simple water and sand to complex polymeric
substances with a multitude of additives. Each type of fracturing
fluid has unique characteristics, and each possesses its own
positive and negative performance traits. It is desirable to
selectively modify certain qualities of the fracturing fluid, and
pumping characteristics, to achieve a desired complexity of the
fracture network.
[0004] For example, a highly complex fracture network geometry may
create much larger surface area compared to relatively simpler and
straight fractures. Larger fracture surface area may enhance
production in very low permeability reservoirs. On the other hand,
a complex fracture network may contain tortuous fractures, multiple
kinking and changes in fracture directions which may make the
fracture opening too narrow or create pinch points that hampers
hydrocarbon or particle transport. To achieve better production of
fractured reservoirs, it may be desirable to have the optimal
geometry to maximize both fracture surface area and transport
characteristics.
[0005] In some cases, the occurrence of fractures and the extent of
the fractures in the formation may be numerically modeled to infer
hydraulic fracture propagation over time. Conventional hydraulic
fracture models typically assume a bi-wing type induced fracture.
These bi-wing fractures may be short in representing the complex
nature of induced fractures in some unconventional reservoirs with
pre-existing discontinuities, such as natural fractures (NF).
Moreover, while some commercially available fracture models may
take into account pre-existing natural fractures in the formation,
many of the published models are oversimplified and neglect to
account for the rigorous elastic solution of the interaction
between induced fractures and natural fractures. Further, the vast
majority of published models do not explicitly take into account
the pumping properties of the fluid, which may include the
injection rate, viscous properties of the fluid, and concentration
of fluid additives.
SUMMARY
[0006] Described herein are embodiments of various technologies for
a method for performing a fracturing operation about a wellbore
penetrating a subterranean formation. The method may acquire
integrated wellsite data. Integrated wellsite data may include
geomechanical, geological, and/or geophysical properties of the
subterranean formation as well as mechanical, geomechanical, and/or
geometrical properties of natural fractures in the subterranean
formation. The method may generate a mechanical earth model using
the integrated wellsite data. The method may simulate an
intersection of an induced hydraulic fracture with a natural
fracture using the mechanical earth model. The method may determine
intersection properties of the intersected natural fracture. The
method may also generate a stimulation plan using the mechanical
earth model and the intersection properties. The stimulation plan
may include a fluid viscosity or a rate of injection of a
fracturing fluid.
[0007] Described herein are embodiments of various technologies for
a method for performing a fracturing operation about a wellbore
penetrating a subterranean formation. The method may acquire
integrated wellsite data. Integrated wellsite data may include
geomechanical, geological, and/or geophysical properties of the
subterranean formation as well as mechanical, geomechanical and/or
geometrical properties of natural fractures in the subterranean
formation. The method may generate a mechanical earth model using
the integrated wellsite data. The method may simulate an
intersection of an induced hydraulic fracture with a natural
fracture using the mechanical earth model. The method may determine
intersection properties of the intersected natural fracture. The
method may predict hydrocarbon production from the subterranean
formation using the intersection properties.
[0008] Described herein are embodiments of various technologies for
a method for performing a fracturing operation about a wellbore
penetrating a subterranean formation. The method may acquire
integrated wellsite data. Integrated wellsite data may include
geomechanical, geological, and/or geophysical properties of the
subterranean formation as well as mechanical, geomechanical, and/or
geometrical properties of natural fractures in the subterranean
formation. The method may generate a mechanical earth model using
the integrated wellsite data. The method may simulate an
intersection of an induced hydraulic fracture with a natural
fracture using the mechanical earth model. The method may determine
intersection properties of the intersected natural fracture. The
method may compare the intersection properties with microseismic
events in observed data that is acquired from a stimulation
operation based on the mechanical earth model.
[0009] Described herein are embodiments of various technologies for
a method for performing a fracturing operation about a wellbore
penetrating a subterranean formation. The method may acquire
integrated wellsite data. Integrated wellsite data may include
geomechanical, geological, and/or geophysical properties of the
subterranean formation as well as mechanical, geomechanical, and/or
geometrical properties of natural fractures in the subterranean
formation. The method may generate a mechanical earth model using
the integrated wellsite data. The method may simulate leak-off of
fracturing fluid from an induced hydraulic fracture into a natural
fracture using the mechanical earth model. The method may also
generate a stimulation plan using the mechanical earth model. The
stimulation plan may include a fluid viscosity or a rate of
injection of a fracturing fluid. The method may also adjust
operating parameters of the stimulation plan based on the simulated
leak-off to achieve an optimized leak-off from the induced
hydraulic fracture into the natural fracture.
[0010] The above referenced summary section is provided to
introduce a selection of concepts that are further described below
in the detailed description section. The summary is not intended to
identify features of the claimed subject matter, nor is it intended
to be used to limit the scope of the claimed subject matter.
Furthermore, the claimed subject matter is not limited to
implementations that solve any or most disadvantages noted in any
part of this disclosure. Indeed, the systems, methods, processing
procedures, techniques, and workflows disclosed herein may
complement or replace conventional methods for identifying,
isolating, and/or processing various aspects of wellsite data or
other data that is collected from a subsurface region or other
multi-dimensional space.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] Implementations of various technologies will hereafter be
described with reference to the accompanying drawings. It should be
understood, however, that the accompanying drawings illustrate
various embodiments described herein and are not meant to limit the
scope of various technologies described herein.
[0012] FIGS. 1A-1D illustrate schematic views of oilfield
operations at a wellsite in accordance with various embodiments
described herein.
[0013] FIGS. 2A-2D illustrate schematic views of data collections
in accordance with various embodiments described herein.
[0014] FIG. 3A illustrates a schematic view of a wellsite with
various downhole stimulation operations in accordance with various
embodiments described herein.
[0015] FIGS. 3B-3D illustrate various fractures of a wellsite in
accordance with various embodiments described herein.
[0016] FIG. 4A illustrates a flow diagram in accordance with
various embodiments described herein.
[0017] FIG. 4B illustrates a schematic diagram of a downhole
stimulation operation in accordance with various embodiments
described herein.
[0018] FIGS. 5.1-5.4 illustrate fracture growth about a wellbore
during a fracture operation in accordance with various embodiments
described herein.
[0019] FIG. 6 illustrates a hydraulic fracture network in
accordance with various embodiments described herein.
[0020] FIG. 7 illustrates an intersection between an induced
hydraulic fracture and a natural fracture in accordance with
various embodiments described herein.
[0021] FIG. 8 is a flow diagram for simulating and performing
hydraulic fracturing in accordance with various embodiments
described herein.
[0022] FIG. 9 illustrates a computer system in which the various
technologies and techniques described herein may be incorporated
and practiced.
DETAILED DESCRIPTION
[0023] The discussion below is directed to certain specific
embodiments. It is to be understood that the discussion below is
for the purpose of enabling a person with ordinary skill in the art
to make and use any subject matter defined now or later by the
patent "claims" found in any issued patent herein.
[0024] Reference will now be made in detail to various embodiments,
examples of which are illustrated in the accompanying drawings and
figures. In the following detailed description, numerous specific
details are set forth in order to provide a thorough understanding
of the claimed invention. However, it will be apparent to one of
ordinary skill in the art that the claimed invention may be
practiced without these specific details. In other instances, well
known methods, procedures, components, circuits, and networks have
not been described in detail so as not to unnecessarily obscure
aspects of the claimed invention.
[0025] It will also be understood that, although the terms first,
second, etc. may be used herein to describe various elements, these
elements should not be limited by these terms. These terms are used
to distinguish one element from another. For example, a first
object or block could be termed a second object or block, and,
similarly, a second object or block could be termed a first object
or block, without departing from the scope of various embodiments
described herein. The first object or block, and the second object
or block, are both objects or blocks, respectively, but they are
not to be considered the same object or block.
[0026] The terminology used in the description herein is for the
purpose of describing particular implementations and is not
intended to limit the claimed invention. As used herein, the
singular forms "a", "an" and "the" are intended to include the
plural forms as well, unless the context clearly indicates
otherwise. It will also be understood that the term "and/or" as
used herein refers to and encompasses any possible combinations of
one or more of the associated listed items. It will be further
understood that the terms "includes," "including," "comprises,"
and/or "comprising," when used in this specification, specify the
presence of stated features, integers, blocks, operations,
elements, and/or components, but do not preclude the presence or
addition of one or more other features, integers, blocks,
operations, elements, components, and/or groups thereof.
[0027] As used herein, the term "if" may be construed to mean
"when" or "upon" or "in response to determining" or "in response to
detecting," depending on the context. Similarly, the phrase "if it
is determined" or "if [a stated condition or event] is detected"
may be construed to mean "upon determining" or "in response to
determining" or "upon detecting [the stated condition or event]" or
"in response to detecting [the stated condition or event],"
depending on the context.
[0028] Various embodiments described herein are directed to systems
and methods for performing and simulating a fracturing operation in
a subterranean formation. These embodiments will be described in
more detail with reference to FIGS. 1-9.
Oilfield Operation
[0029] FIGS. 1A-1D depict various oilfield operations that may be
performed at a wellsite, and FIGS. 2A-2D depict various information
that may be collected at the wellsite. FIGS. 1A-1D depict
simplified, schematic views of a representative oilfield or
wellsite 100 having subsurface formation 102 containing, for
example, reservoir 104 therein and depicting various oilfield
operations being performed on the wellsite 100. FIG. 1A depicts a
survey operation being performed by a survey tool, such as seismic
truck 106.1, to measure properties of the subsurface formation. The
survey operation may be a seismic survey operation for producing
sound vibrations. In FIG. 1A, one such sound vibration 112
generated by a source 110 reflects off a plurality of
discontinuities 114 in an earth formation 116. The sound
vibration(s) 112 may be received by sensors, such as
geophone-receivers 118, situated on the earth's surface, and the
geophones 118 produce electrical output signals, referred to as
data received 120 in FIG. 1A.
[0030] In response to the received sound vibration(s) 112
representative of different parameters (such as amplitude and/or
frequency) of the sound vibration(s) 112, the geophones 118 may
produce electrical output signals containing data concerning the
subsurface formation. The data received 120 may be provided as
input data to a computer 122.1 of the seismic truck 106.1, and
responsive to the input data, the computer 122.1 may generate a
seismic and microseismic data output 124. The seismic data output
124 may be stored, transmitted or further processed as desired, for
example by data reduction.
[0031] FIG. 1B depicts a drilling operation being performed by a
drilling tool 106.2 suspended by a rig 128 and advanced into the
subsurface formations 102 to form a wellbore 136 or other channel.
A mud pit 130 may be used to draw drilling mud into the drilling
tools via flow line 132 for circulating drilling mud through the
drilling tools, up the wellbore 136 and back to the surface. The
drilling mud may be filtered and returned to the mud pit. A
circulating system may be used for storing, controlling or
filtering the flowing drilling muds. In this illustration, the
drilling tools are advanced into the subsurface formations to reach
reservoir 104. Each well may target one or more reservoirs. The
drilling tools may be adapted for measuring downhole properties
using logging while drilling tools. The logging while drilling tool
may also be adapted for taking a core sample 133 as shown in FIGS.
1B and 2B, or removed so that a core sample 133 may be taken using
another tool.
[0032] A surface unit 134 may be used to communicate with the
drilling tool 106.2 and/or offsite operations. The surface unit 134
may communicate with the drilling tool 106.2 to send commands to
the drilling tool 106.2, and to receive data therefrom. The surface
unit 134 may be provided with computer facilities for receiving,
storing, processing, and/or analyzing data from the operation. The
surface unit 134 may collect data generated during the drilling
operation and produce data output 135 which may be stored or
transmitted. Computer facilities, such as those of the surface unit
134, may be positioned at various locations about the wellsite
and/or at remote locations.
[0033] Sensors (S), such as gauges, may be positioned about the
oilfield to collect data relating to various operations as
described previously. As shown, the sensor (S) may be positioned in
one or more locations in the drilling tool 106.2 and/or at the rig
to measure drilling parameters, such as weight on bit, torque on
bit, pressures, temperatures, flow rates, compositions, rotary
speed and/or other parameters of the operation. Sensors (S) may
also be positioned in one or more locations in the circulating
system.
[0034] The data gathered by the sensors may be collected by the
surface unit 134 and/or other data collection sources for analysis
or other processing. The data collected by the sensors may be used
alone or in combination with other data. The data may be collected
in one or more databases and/or transmitted on or offsite. All or
select portions of the data may be selectively used for analyzing
and/or predicting operations of the current and/or other wellbores.
The data may be historical data, real-time data or combinations
thereof. The real-time data may be used in real-time, or stored for
later use. The data may also be combined with historical data or
other inputs for further analysis. The data may be stored in
separate databases, or combined into a single database.
[0035] The collected data may be used to perform analysis, such as
modeling operations. For example, the seismic data output may be
used to perform geological, geophysical, and/or reservoir
engineering analysis. The reservoir, wellbore, surface and/or
processed data may be used to perform reservoir, wellbore,
geological, and geophysical or other simulations. The data outputs
from the operation may be generated directly from the sensors, or
after some preprocessing or modeling. These data outputs may act as
inputs for further analysis.
[0036] The data may be collected and stored at the surface unit
134. One or more surface units 134 may be located at the wellsite,
or connected remotely thereto. The surface unit 134 may be a single
unit, or a complex network of units used to perform the necessary
data management functions throughout the oilfield. The surface unit
134 may be a manual or automatic system. The surface unit 134 may
be operated and/or adjusted by a user.
[0037] The surface unit 134 may be provided with a transceiver 137
to allow communications between the surface unit 134 and various
portions of the current oilfield or other locations. The surface
unit 134 may also be provided with or functionally connected to one
or more controllers for actuating mechanisms at the wellsite 100.
The surface unit 134 may then send command signals to the oilfield
in response to data received. The surface unit 134 may receive
commands via the transceiver or may itself execute commands to the
controller. A processor may be provided to analyze the data
(locally or remotely), make the decisions and/or actuate the
controller. In this manner, operations may be selectively adjusted
based on the data collected. Portions of the operation, such as
controlling drilling, weight on bit, pump rates or other
parameters, may be optimized based on the information. These
adjustments may be made automatically based on computer protocol,
and/or manually by an operator. In some cases, well plans may be
adjusted to select optimum operating conditions, or to avoid
problems.
[0038] FIG. 1C depicts a wireline operation being performed by a
wireline tool 106.3 suspended by the rig 128 and into the wellbore
136 of FIG. 1B. The wireline tool 106.3 may be adapted for
deployment into a wellbore 136 for generating well logs, performing
downhole tests and/or collecting samples. The wireline tool 106.3
may be used to provide another method and apparatus for performing
a seismic survey operation. The wireline tool 106.3 of FIG. 1C may,
for example, have an explosive, radioactive, electrical, or
acoustic energy source 144 that sends and/or receives electrical
signals to the surrounding subsurface formations 102 and fluids
therein.
[0039] The wireline tool 106.3 may be operatively connected to, for
example, the geophones 118 and the computer 122.1 of the seismic
truck 106.1 of FIG. 1A. The wireline tool 106.3 may also provide
data to the surface unit 134. The surface unit 134 may collect data
generated during the wireline operation and produce data output 135
which may be stored or transmitted. The wireline tool 106.3 may be
positioned at various depths in the wellbore 136 to provide a
survey or other information relating to the subsurface
formation.
[0040] Sensors (S), such as gauges, may be positioned about the
wellsite 100 to collect data relating to various operations as
described previously. As shown, the sensor (S) is positioned in the
wireline tool 106.3 to measure downhole parameters which relate to,
for example porosity, permeability, fluid composition and/or other
parameters of the operation.
[0041] FIG. 1D depicts a production operation being performed by a
production tool 106.4 deployed from a production unit or Christmas
tree 129 and into the completed wellbore 136 of FIG. 1C for drawing
fluid from the downhole reservoirs into surface facilities 142.
Fluid flows from reservoir 104 through perforations in the casing
(not shown) and into the production tool 106.4 in the wellbore 136
and to the surface facilities 142 via a gathering network 146.
[0042] Sensors (S), such as gauges, may be positioned about the
oilfield to collect data relating to various operations as
described previously. As shown, the sensor (S) may be positioned in
the production tool 106.4 or associated equipment, such as the
Christmas tree 129, gathering network, surface facilities and/or
the production facility, to measure fluid parameters, such as fluid
composition, flow rates, pressures, temperatures, and/or other
parameters of the production operation.
[0043] While only simplified wellsite configurations are shown, it
will be appreciated that the oilfield or wellsite 100 may cover a
portion of land, sea and/or water locations that hosts one or more
wellsites. Production may also include injection wells (not shown)
for added recovery or for storage of hydrocarbons, carbon dioxide,
or water, for example. One or more gathering facilities may be
operatively connected to one or more of the wellsites for
selectively collecting downhole fluids from the wellsite(s).
[0044] It should be appreciated that FIGS. 1B-1D depict tools that
can be used to measure not only properties of an oilfield, but also
properties of non-oilfield operations, such as mines, aquifers,
storage, and other subsurface facilities. Also, while certain data
acquisition tools are depicted, it will be appreciated that various
measurement tools (e.g., wireline, measurement while drilling
(MWD), logging while drilling (LWD), core sample, etc.) capable of
sensing parameters, such as seismic two-way travel time, density,
resistivity, production rate, etc., of the subsurface formation
and/or its geological formations may be used. Various sensors (S)
may be located at various positions along the wellbore and/or the
monitoring tools to collect and/or monitor the desired data. Other
sources of data may also be provided from offsite locations.
[0045] The oilfield configuration of FIGS. 1A-1D depict examples of
a wellsite 100 and various operations usable with the techniques
provided herein. Part, or all, of the oilfield may be on land,
water and/or sea. Also, while a single oilfield measured at a
single location is depicted, reservoir engineering may be utilized
with any combination of one or more oilfields, one or more
processing facilities, and one or more wellsites.
[0046] FIGS. 2A-2D are graphical depictions of examples of data
collected by the tools of FIGS. 1A-1D, respectively. FIG. 2A
depicts a seismic trace 202 of the subsurface formation of FIG. 1A
taken by seismic truck 106.1. The seismic trace 202 may be used to
provide data, such as a two-way response over a period of time.
FIG. 2B depicts a core sample 133 taken by the drilling tools
106.2. The core sample may be used to provide data, such as a graph
of the density, porosity, permeability or other physical property
of the core sample over the length of the core. Tests for density
and viscosity may be performed on the fluids in the core at varying
pressures and temperatures. FIG. 2C depicts a well log 204 of the
subsurface formation of FIG. 1C taken by the wireline tool 106.3.
The well log 204 may provide a resistivity or other measurement of
the formation at various depts. FIG. 2D depicts a production
decline curve or graph 206 of fluid flowing through the subsurface
formation of FIG. 1D measured at the surface facilities 142. The
production decline curve may provide the production rate Q as a
function of time t.
[0047] The respective graphs of FIGS. 2A, 2C, and 2D depict
examples of static measurements that may describe or provide
information about the physical characteristics of the formation and
reservoirs contained therein. These measurements may be analyzed to
define properties of the formation(s), to determine the accuracy of
the measurements and/or to check for errors. The plots of each of
the respective measurements may be aligned and scaled for
comparison and verification of the properties.
[0048] FIG. 2D depicts an example of a dynamic measurement of the
fluid properties through the wellbore. As the fluid flows through
the wellbore, measurements are taken of fluid properties, such as
flow rates, pressures, composition, etc. As described below, the
static and dynamic measurements may be analyzed and used to
generate models of the subsurface formation to determine
characteristics thereof. Similar measurements may also be used to
measure changes in formation aspects over time.
Stimulation Operations
[0049] FIG. 3A depicts stimulation operations performed at
wellsites 300.1 and 300.2. The wellsite 300.1 includes a rig 308.1
having a vertical wellbore 336.1 extending into a formation 302.1.
Wellsite 300.2 includes rig 308.2 having wellbore 336.2 and rig
308.3 having wellbore 336.3 extending therebelow into a
subterranean formation 302.2. While the wellsites 300.1 and 300.2
are shown having specific configurations of rigs with wellbores, it
will be appreciated that one or more rigs with one or more
wellbores may be positioned at one or more wellsites.
[0050] Wellbore 336.1 extends from rig 308.1, through
unconventional reservoirs 304.1-304.3. Wellbores 336.2 and 336.3
extend from rigs 308.2 and 308.3, respectfully to unconventional
reservoir 304.4. As shown, unconventional reservoirs 304.1-304.3
are tight gas sand reservoirs and unconventional reservoir 304.4 is
a shale reservoir. One or more unconventional reservoirs (e.g.,
such as tight gas, shale, carbonate, coal, heavy oil, etc.) and/or
conventional reservoirs may be present in a given formation.
[0051] The stimulation operations of FIG. 3A may be performed alone
or in conjunction with other oilfield operations, such as the
oilfield operations of FIGS. 1A and 1D. For example, wellbores
336.1-336.3 may be measured, drilled, tested and produced as shown
in FIGS. 1A-1D. Stimulation operations performed at the wellsites
300.1 and 300.2 may involve, for example, perforation, fracturing,
injection, and the like. The stimulation operations may be
performed in conjunction with other oilfield operations, such as
completions and production operations (see, e.g., FIG. 1D). As
shown in FIG. 3A, the wellbores 336.1 and 336.2 have been completed
and provided with perforations 338.1-338.5 to facilitate
production.
[0052] Downhole tool 306.1 is positioned in vertical wellbore 336.1
adjacent tight gas sand reservoirs 304.1 for taking downhole
measurements. Packers 307 are positioned in the wellbore 336.1 for
isolating a portion thereof, proximate adjacent perforations 338.2.
Once the perforations are formed about the wellbore fluid may be
injected through the perforations and into the formation to create
and/or expand fractures therein to stimulate production from the
reservoirs.
[0053] Reservoir 304.4 of formation 302.2 has been perforated and
packers 307 have been positioned to isolate the wellbore 336.2
about the perforations 338.3-338.5. As shown in the horizontal
wellbore 336.2, packers 307 have been positioned at stages St.sub.1
and St.sub.2 of the wellbore. As also depicted, wellbore 304.3 may
be an offset (or pilot) well extended through the formation 302.2
to reach reservoir 304.4. One or more wellbores may be placed at
one or more wellsites. Multiple wellbores may be placed as
desired.
[0054] Fractures may be extended into the various reservoirs
304.1-304.4 for facilitating production of fluids therefrom.
Examples of fractures that may be formed are schematically shown in
FIGS. 3B-3D about a wellbore 304. As shown in FIGS. 3B-3C,
mechanical discontinuities 340, such as natural fractures, bedding
planes, faults, and planes of weakness, extend in layers in the
formation. Natural fractures as described herein refer to planar
discontinuities in the formation having different properties than
the surrounding formation. Perforations (or perforation clusters)
342 may be formed about the wellbore 304, and fluids 344 and/or
fluids mixed with proppant 346 may be injected through the
perforations 342. As shown in FIGS. 3B-3C, hydraulic fracturing may
be performed by injecting through the perforations 342, creating
fractures along a maximum stress plane .sigma..sub.hmax and opening
and extending the natural fractures.
[0055] At the surface of the wellsite shown in FIG. 3B, a pumping
system 329 is positioned about the wellhead 308.4 for passing
fluids 344 and/or fluids mixed with proppant 346 therein through
tubing 315.
[0056] The pumping system 329 is depicted as being operated by a
field operator 327 for recording maintenance and operational data
and/or performing maintenance in accordance with a prescribed
maintenance plan. The pumping system 329 pumps the fluid 344 from
the surface to the wellbore 304 during an oilfield operation.
[0057] In one example arrangement, the pumping system 329 may
include a plurality of water tanks 331, which feed water to a gel
hydration unit 333. The gel hydration unit 333 combines water from
the tanks 331 with a gelling agent to form a gel. The gel is then
sent to a blender 335 where it is mixed with a proppant from a
proppant transport unit 337 to form a fracturing fluid 344. The
gelling agent may be used to increase the viscosity of the
fracturing fluid and allows the proppant to be suspended in the
fracturing fluid. It may also act as a friction reducing agent to
allow higher pump rates with less frictional pressure. The gel
hydration unit 333 may combine additional fluid additives to the
water to form a fracturing fluid 344 with specific properties.
[0058] The fracturing fluid 344 is then pumped from the blender 135
to the treatment trucks 320 with plunger pumps as shown by solid
lines 343. Each treatment truck 320 receives the fracturing fluid
at a low pressure and discharges it to a common manifold 339
(sometimes called a missile trailer or missile) at a high pressure
as shown by dashed lines 341. The missile 339 then directs the
fracturing fluid from the treatment trucks 320 to the wellbore 304
as shown by solid line 315. One or more treatment trucks 320 may be
used to supply fracturing fluid at a desired rate.
[0059] Each treatment truck 320 may be normally operated at any
rate, such as well under its maximum operating capacity. Operating
the treatment trucks 320 under their operating capacity may allow
for one to fail and the remaining to be run at a higher speed in
order to make up for the absence of the failed pump. As shown, a
computerized control system 345 may be employed to direct the
entire pump system 329 during the fracturing operation.
[0060] FIG. 3D shows another view of the fracturing operation about
the wellbore 304. In this view, the induced fractures 348 extend
radially about the wellbore 304. The induced fractures may be used
to reach the pockets of microseismic events 351 (shown
schematically as dots) about the wellbore 304. The fracture
operation may be used as part of the stimulation operation to
provide pathways for facilitating movement of hydrocarbons to the
wellbore 304 for production.
[0061] Referring back to FIG. 3A, sensors (S), such as gauges, may
be positioned about the oilfield to collect data relating to
various operations as described previously. Some sensors, such as
geophones, may be positioned about the formations during fracturing
for measuring microseismic waves and performing microseismic
mapping. The data gathered by the sensors may be collected by the
surface unit 334 and/or other data collection sources for analysis
or other processing as previously described (see, e.g., surface
unit 134). As shown, surface unit 334 is linked to a network 352
and other computers 354.
[0062] A stimulation tool 350 may be provided as part of the
surface unit 334 or other portions of the wellsite for performing
stimulation operations. For example, information generated during
one or more of the stimulation operations may be used in well
planning for one or more wells, one or more wellsites and/or one or
more reservoirs. The stimulation tool 350 may be operatively linked
to one or more rigs and/or wellsites, and used to receive data,
process data, send control signals, etc., as will be described
further herein. The stimulation tool 350 may include a reservoir
characterization unit 363 for generating a mechanical earth model
(MEM), a stimulation planning unit 365 for generating stimulation
plans, an optimizer 367 for optimizing the stimulation plans, a
real-time unit 369 for optimizing in real-time the optimized
stimulation plan, a control unit 368 for selectively adjusting the
stimulation operation based on the real-time optimized stimulation
plan, an updater 370 for updating the reservoir characterization
model based on the real-time optimized stimulation plan and post
evaluation data, and a calibrator 372 for calibrating the optimized
stimulation plan as will be described further herein. The
stimulation planning unit 365 may include a staging design tool 381
for performing staging design, a stimulation design tool 383 for
performing stimulation design, a production prediction tool 385 for
predicting production and a well planning tool 387 for generating
well plans.
[0063] Wellsite data used in the stimulation operation may range
from, for example, core samples to petrophysical interpretation
based on well logs to three dimensional seismic data (see, e.g.,
FIGS. 2A-2D). Stimulation design may employ, for example, oilfield
petrotechnical experts to conduct manual processes to collate
different pieces of information. Integration of the information may
involve manual manipulation of disconnected workflows and outputs,
such as delineation of a reservoir zones, identification of desired
completion zones, estimation of anticipated hydraulic fracture
growth for a given completion equipment configurations, decision on
whether and where to place another well or a plurality of wells for
better stimulation of the formation, and the like. This stimulation
design may also involve semi-automatic or automatic integration,
feedback and control to facilitate the stimulation operation.
[0064] Stimulation operations for conventional and unconventional
reservoirs may be performed based on knowledge of the reservoir.
Reservoir characterization may be used, for example, in well
planning, identifying optimal target zones for perforation and
staging, design of multiple wells (e.g., spacing and orientation),
and geomechanical models. Stimulation designs may be optimized
based on a resulting production prediction. These stimulation
designs may involve an integrated reservoir centric workflow which
include design, real-time (RT), and post treatment evaluation
components. Well completion and stimulation design may be performed
while making use of multi-disciplinary wellbore and reservoir
data.
[0065] FIG. 4A is a schematic flow diagram 400 depicting a
stimulation operation, such as those shown in FIG. 3A. The flow
diagram 400 is an iterative process that uses integrated
information and analysis to design, implement and update a
stimulation operation. The method involves
pre-treatment/pre-stimulation evaluation 445, stimulation planning
447, real-time treatment optimization 451, and design/model update
453. Part or all of the flow diagram 400 may be iterated to adjust
stimulation operations and/or design additional stimulation
operations in existing or additional wells.
[0066] The pre-stimulation evaluation 445 involves reservoir
characterization 460 and generating a three-dimensional mechanical
earth model (MEM) 462. The reservoir characterization 460 may be
generated by integrating information, such as the information
gathered in FIGS. 1A-1D, to perform modeling using united
combinations of information from historically independent technical
regimes or disciplines (e.g., petrophysicist, geologist,
geomechanic and geophysicist, and previous fracture treatment
results). Such reservoir characterization 460 may be generated
using integrated static modeling techniques to generate the MEM 462
as described, for example, in US Patent Application Nos.
2009/0187391 and 2011/060572, the entire contents of which are
hereby incorporated by reference. By way of example, software, such
as PETREL.TM., VISAGE.TM., TECHLOG.TM., and GEOFRAME.TM.
commercially available from SCHLUMBERGER.TM., may be used to
perform the pre-treatment evaluation 445.
[0067] Reservoir characterization 460 may involve capturing a
variety of information, such as data associated with the
underground formation and developing one or more models of the
reservoir. The information captured may include, for example,
reservoir (pay) zone, geomechanical (stress, elasticity, and the
like) zone, geometrical (fracture orientation and size)
distribution of the mechanical discontinuities (natural fractures)
in the formation, and mechanical (permeability, conductivity,
stress, fracture toughness, tensile strength, and the like) of the
discontinuities. The reservoir characterization 460 may be
performed such that information concerning the stimulation
operation is included in pre-stimulation evaluations. Generating
the MEM 462 may simulate the subterranean formation under
development (e.g., generating a numerical representation of a state
of stress and formation mechanical properties for a given
stratigraphic section in an oilfield or basin).
[0068] Conventional geomechanical modeling may be used to generate
the MEM 462. Examples of MEM techniques are provided in US Patent
Application No. 2009/0187391, the entire contents of which is
hereby incorporated by reference. The MEM 462 may be generated by
information gathered using, for example, the oilfield operations of
FIGS. 1A-1D, 2A-2D and 3A-3D. For example, the three-dimensional
MEM may take into account various reservoir data collected
beforehand, including the seismic data collected during early
exploration of the formation and logging data collected from the
drilling of one or more exploration wells before production (see,
e.g., FIGS. 1A-1D). The MEM 462 may be used to provide, for
example, geomechanical information for various oilfield operations,
such as casing point selection, optimizing the number of casing
strings, drilling stable wellbores, designing completions,
performing fracture stimulation, etc.
[0069] The generated MEM 462 may be used as an input in performing
stimulation planning 447. The three-dimensional MEM may be
constructed to identify potential drilling wellsites. In one
embodiment, when the formation is substantially uniform and is
substantially free of major natural fractures and/or high-stress
barriers, it can be assumed that a given volume of fracturing fluid
pumped at a given rate over a given period of time will generate a
substantially identical fracture network in the formation. In
another embodiment, when the formation includes a complex network
of mechanical discontinuities and/or high stress barriers, a
desired stimulated area, volume and/or shape of volume may be
achieved by adjusting at least one of the fluid viscosity, the rate
of injection, and the fluid loss additives to thereby optimize the
crossing behaviors between the induced fracture and the
discontinuities present in the formation. Seismic data 202, such as
those shown in FIGS. 1A and 2A, may provide useful information in
analyzing fracture properties of the formation.
[0070] The stimulation planning 447 may involve well planning 465,
staging design 466, stimulation design 468, and production
prediction 470. In particular, the MEM 462 may be an input to the
well planning 465 and/or the staging design 466 and stimulation
design 468. Some embodiments may include semi-automated methods to
identify, for example, well spacing and orientation, multistage
perforation design and hydraulic fracture design. To address a wide
variation of characteristics in hydrocarbon reservoirs, some
embodiments may involve dedicated methods per target reservoir
environments, such as, but not limited to, tight gas formations,
sandstone reservoirs, naturally fractured shale reservoirs, or
other unconventional reservoirs.
[0071] The stimulation planning 447 may involve a semi-automated
method used to identify potential drilling wellsites by
partitioning underground formations into multiple set of discrete
intervals, characterizing each interval based on information such
as the formation's geophysical properties and its proximity to
natural fractures, then regrouping multiple intervals into one or
multiple drilling wellsites, with each wellsite receiving a well or
a branch of a well. The spacing and orientation of the multiple
wells may be determined and used in optimizing production of the
reservoir. Characteristics of each well may be analyzed for stage
planning and stimulation planning. In some cases, a completion
advisor may be provided, for example, for analyzing vertical or
near vertical wells in tight-gas sandstone reservoir following a
recursive refinement workflow.
[0072] Well planning 465 may be performed to design oilfield
operations in advance of performing such oilfield operations at the
wellsite. The well planning 465 may be used to define, for example,
equipment and operating parameters for performing the oilfield
operations. Some such operating parameters may include, for
example, perforating locations, injection rate, operating
pressures, stimulation fluids, and other parameters used in
stimulation. Information gathered from various sources, such as
historical data, known data, and oilfield measurements (e.g., those
taken in FIGS. 1A-1D), may be used in designing a well plan. In
some cases, modeling may be used to analyze data used in forming a
well plan. The well plan generated in the stimulation planning may
receive inputs from the staging design 466, stimulation design 468,
and production prediction 470 so that information relating to
and/or affecting stimulation is evaluated in the well plan.
[0073] The well planning 465 and/or MEM 462 may also be used as
inputs into the staging design 466. Reservoir and other data may be
used in the staging design 466 to define certain operational
parameters for stimulation. For example, staging design 466 may
involve defining boundaries in a wellbore for performing
stimulation operations as described further herein. Examples of
staging design are described in US Patent Application No.
2011/0247824, the entire contents of which is hereby incorporated
by reference. Staging design may be an input for performing
stimulation design 468.
[0074] Stimulation design defines various stimulation parameters
(e.g., perforation placement) for performing stimulation
operations. The stimulation design 468 may be used, for example,
for fracture modeling. Examples of fracture modeling are described
in US Patent Application No. 2008/0183451, 2006/0015310 and PCT
Publication No. WO2011/077227, the entire contents of which are
hereby incorporated by reference. Stimulation design may involve
using various models to define a stimulation plan and/or a
stimulation portion of a well plan. Additional examples of complex
fracture modeling are provided in SPE Paper 140185, the entire
contents of which is hereby incorporated by reference. This complex
fracture modeling illustrates the application of two complex
fracture modeling techniques in conjunction with microseismic
mapping to characterize fracture complexity and evaluate completion
performance. The first complex fracture modeling technique is an
analytical model for estimating fracture complexity and distances
between orthogonal fractures. The second technique uses a gridded
numerical model that allows complex geologic descriptions and
evaluation of complex fracture propagation. These examples
illustrate how embodiments may be utilized to evaluate how fracture
complexity is impacted by changes in fracture treatment design in
each geologic environment. To quantify the impact of changes in
fracture design using complex fracture models despite inherent
uncertainties in the MEM and "real" fracture growth, microseismic
mapping and complex fracture modeling may be integrated for
interpretation of the microseismic measurements while also
calibrating the complex stimulation model. Such examples show that
the degree of fracture complexity can vary depending on geologic
conditions.
[0075] Stimulation design may integrate three-dimensional reservoir
models (formation models), which can be a result of seismic
interpretation, drilling geo-steering interpretation, geological or
geomechanical earth model, as a starting point (zone model) for
completion design. For some stimulation designs, a fracture
modeling algorithm may be used to read a three-dimensional MEM and
run forward modeling to predict fracture growth. This process may
be used so that spatial heterogeneity of a complex reservoir may be
taken into account in stimulation operations.
[0076] Microseismic mapping may also be used in the stimulation
design 468 to understand complex fracture growth. Some workflows
may integrate these predicted fracture models in a single
three-dimensional canvas where microseismic events are overlaid
(see, e.g., FIG. 3D), which can be used in fracture design and/or
calibrations. The nature and degree of fracture complexity may be
assessed using microseismic mapping, and then optimized as
discussed herein.
[0077] The nature and degree of fracture complexity may be analyzed
to select an optimal stimulation design and completion strategy.
Fracture modeling may be used to predict the fracture geometry that
can be calibrated and the design optimized based on real-time
microseismic mapping and evaluation. Fracture growth may be
interpreted based on existing hydraulic fracture models. Some
complex hydraulic fracture propagation modeling and/or
interpretation may also be performed for unconventional reservoirs
(e.g., tight gas sand and shale) as will be described further
herein. Reservoir properties, and initial modeling assumptions may
be corrected and fracture design optimized based on microseismic
evaluation.
[0078] Production prediction 470 may involve estimating production
based on the well planning 465, staging design 466 and stimulation
design 468. The result of stimulation design 468 (i.e. simulated
fracture models and input reservoir model) can be carried over to a
production prediction workflow, where a conventional analytical or
numerical reservoir simulator may operate on the models and
predicts hydrocarbon production based on dynamic data. The
pre-production prediction 470 can be useful, for example, for
quantitatively validating the stimulation planning 447 process.
[0079] Part or all of the stimulation planning 447 may be
iteratively performed as indicated by the flow arrows in FIG. 4A.
As shown, optimizations may be provided after the staging design
466, stimulation design 468, and production prediction 470, and may
be used as a feedback to optimize 472 the well planning 465, the
staging design 466 and/or the stimulation design 468. The
optimizations may be selectively performed to feedback results from
part or all of the stimulation planning 447 and iterate as desired
into the various portions of the stimulation planning process and
achieve an optimized result. The stimulation planning 447 may be
manually carried out, or integrated using automated optimization
processing as schematically shown by the optimization 472 in
feedback loop 473.
[0080] FIG. 4B schematically depicts a portion of the stimulation
planning operation 447. As shown in this figure, the staging design
446, stimulation design 468 and production prediction 470 may be
iterated in the feedback loop 473 and optimized 472 to generate an
optimized result 480, such as an optimized stimulation plan with an
optimized crossing behavior. This iterative method allows the
inputs and results generated by the staging design 466 and
stimulation design 468 to `learn from each other` and iterate with
the production prediction for optimization therebetween.
[0081] Various portions of the stimulation operation may be
designed and/or optimized. Examples of optimizing fracturing are
described, for example, in U.S. Pat. No. 6,508,307, the entire
contents of which is hereby incorporated by reference. In another
example, financial inputs, such as fracture operation costs (both
fixed and variable), oil and natural gas futures, and contribution
margins, each of which may affect operations, may also be provided
in the stimulation planning 447. Optimization may be performed by
optimizing the stimulation design 466 with respect to predicted
production while taking into consideration financial inputs. Such
financial inputs may involve costs for various stimulation
operations at various stages in the wellbore.
[0082] Referring back to FIG. 4A, various optional features may be
included in the stimulation planning 447. For example, a multi-well
planning advisor may be used to determine if it is necessary to
construct multiple wells in a formation. If multiple wells are to
be formed, the multi-well planning advisor may provide the spacing
and orientation of the multiple wells, as well as the best
locations within each for perforating and treating the formation.
As used herein, the term "multiple wells" may refer to multiple
wells each being independently drilled from the surface of the
earth to the subterranean formation; the term "multiple wells" may
also refer to multiple branches kicked off from a single well that
is drilled from the surface of the earth (see, e.g., FIG. 3A). The
orientation of the wells and branches can be vertical, horizontal,
or anywhere in between.
[0083] When multiple wells are planned or drilled, simulations can
be repeated for each well so that each well has a staging plan,
perforation plan, and/or stimulation plan. Thereafter, multi-well
planning can be adjusted if necessary. For example, if a fracture
stimulation in one well indicates that a stimulation result will
overlap a nearby well with a planned perforation zone, the nearby
well and/or the planned perforation zone in the nearby well can be
eliminated or redesigned. On the contrary, if a simulated fracture
treatment cannot penetrate a particular area of the formation,
either because the pay zone is simply too far away for a first
fracture well to effectively stimulate the pay zone or because the
existence of a natural fracture or high-stress barrier prevents the
first fracture well from effectively stimulating the pay zone, a
second well/branch or a new perforation zone may be included to
provide access to the untreated area. The three-dimensional
reservoir model may take into account simulation models and
indicate a candidate location to drill a second well/branch or to
add an additional perforation zone. A spatial X'-Y'-Z' location may
be provided for the oilfield operator's ease of handling.
Modeling Intersections Between Hydraulic Fractures and Natural
Fractures
[0084] While taking into account the leak-off of the fracturing
fluid into the formation, the leak-off into the natural fractures
(NF) may also be considered, especially in low-matrix permeability
conditions. Natural fractures influence hydraulic fracture (HF)
propagation in different ways. A major aspect that leads to
creation of complex hydraulic fracture network during a fracture
stimulation is the possibility of a hydraulic fracture branching
when a respective hydraulic fracture intersects a natural fracture.
Another aspect where natural fractures effect hydraulic fracture
geometry is their effect on fluid loss from the hydraulic fracture
into permeable natural fractures, leading to reduced hydraulic
fracture length.
[0085] FIGS. 5.1-5.4 depict an example of a hydraulic fracture
growth pattern. As shown in FIG. 5.1, in its initial state, a
fracture network 506.1 with natural fractures 523 is positioned
about a subterranean formation 502 with a wellbore 504
therethrough. As proppant is injected into the subterranean
formation 502 from the wellbore 504, pressure from the proppant
creates induced hydraulic fractures 591 about the wellbore 504. The
induced hydraulic fractures 591 extend into the subterranean
formation 502 along length L.sub.1 and length L.sub.2 (FIG. 5.2),
and encounter other fractures in the fracture network 506.1 over
time as indicated in FIGS. 5.2-5.3. The points of contact with the
other fractures are intersections 525.
[0086] Hydraulic fractures may extend from the wellbore 504 and
into the natural fracture network of the subterranean formation 502
to form a hydraulic fracture network 506.4 including the natural
fractures 523 and the induced hydraulic fractures 591 as shown in
FIG. 5.4. The fracture growth pattern is based on natural fracture
parameters and a minimum stress and a maximum stress on the
subterranean formation 502.
[0087] As shown in FIGS. 5.1-5.4, intersections 525 between induced
hydraulic fractures 591 and natural fractures 523 may produce
specific crossing behavior in multiple scenarios: (i) an induced
fracture may continue propagating past the encountered natural
fracture at the intersection point; (ii) an induced hydraulic
fracture may stop at the encountered natural fracture or propagate
along a portion of the encountered natural fracture after stopping;
or (iii) an induced hydraulic fracture may propagate along the
encountered natural fracture for a distance and then branch away
from the natural fracture at some offset distance away from the
intersection point. The crossing behavior, or intersection between
the natural fracture and the induced hydraulic fracture, depends on
a number of factors, such as, for example, the reservoir
geomechanical properties, confining stress, the incident angle of
interaction, friction coefficient, the cohesional properties of the
pre-existing natural fractures, the viscosity of the fracturing
fluid, the injection rate of the fluid, and the presence and
concentration of fluid loss additives in the fracturing fluid.
[0088] Depending on downhole conditions, the fracture growth
pattern may be unaltered or altered when the hydraulic fracture
encounters a natural fracture (i.e., "the encountered fracture").
When a fracture pressure is greater than stress acting on the
encountered fracture, the fracture growth pattern may propagate
along the encountered fracture. The fracture growth pattern may
continue propagation along the encountered fracture until the end
of the natural fracture is reached. The fracture growth pattern may
change direction at the end of the natural fracture, with the
fracture growth pattern extending in a direction normal to a
minimum stress at the end of the natural fracture. As shown in FIG.
5.4, the induced hydraulic fracture extends on a new path 527
according to the local stresses .sigma..sub.1 and
.sigma..sub.2.
[0089] When a natural fracture is intercepted by an induced
hydraulic fracture (HF), the fluid pressure in the hydraulic
fracture may transmit to the natural fracture. If the fluid
pressure is less than the normal stress on the natural fracture,
the natural fracture may remain closed. Even closed natural
fractures may have hydraulic conductivities much larger than the
surrounding rock matrix, and in this case fracturing fluid may
invade the natural fractures in greater amounts than leak-off into
the surrounding rock matrix. By losing fracturing fluid into closed
natural fractures, the main hydraulic fracture may have reduced
fracturing fluid volume available for further fracture growth.
[0090] For a closed fracture, the equivalent fluid conductivity may
be expected to change with the fluid pressure since contact
deformation is a function of effective normal stress. This
pressure-induced dilatancy and the associated increase in
conductivity may increase flow through some segments of the natural
fracture path that may be subject to compressive contact stress.
Also, any reduction in effective contact stress may result in
fracture sliding, which can lead to local stress variations and
slip induced fracture dilation, which may in turn change the
overall conductivity of fracture networks. This shear-slip induced
conductivity may enhance the pressure transmission in the natural
fractures and may allow microseismic events to be triggered at a
distance away from the actual hydraulic fractures for natural
fractures that have relatively low original permeability.
[0091] Different regions or zones may coexist along a natural
fracture invaded by an induced hydraulic fracture. For example, the
regions along a natural fracture may include a hydraulically opened
region filled with fracturing fluid, a region of the natural
fracture which is still closed but invaded by fracturing fluid
and/or pressure due to natural fracture permeability, and a region
of the natural fracture filled with original reservoir fluid. FIG.
7 illustrates more information about the different regions or
zones.
[0092] FIG. 6 depicts a complex hydraulic fracture network 600 with
microseismic events 630 due to fracturing fluid leak-off 640 into
natural fractures 650. Similar to FIGS. 5.1-5.4, fracturing fluid
may leak into natural fractures at intersections 605 with hydraulic
fractures 620, for both the case of a hydraulic fracture crossing
the natural fracture and the case of a hydraulic fracture
propagating along the natural fracture. The fracturing fluid
leak-off 640 may cause the fluid pressure in the natural fractures
650 to elevate above the original pore pressures. The elevated pore
pressure may reduce the confining stress on natural fractures 650
and cause shear slippage along a respective natural fracture. This
shear slippage may be a primary mechanism for triggering the
microseismic events 630.
[0093] By incorporating fluid loss into natural fracture
simulations, a more accurate and reliable prediction of complex
fracture geometry may be obtained. By modeling the fluid loss into
the natural fractures, for instance, fracturing fluid invasion into
the natural fractures and the rock matrix surrounding the fractures
may be calculated. This fluid invasion may be used in the flow back
and clean-up of the fracturing fluid when the well is produced, and
may be performed for an ultra-low permeability reservoir where
fluid injected may form a block to the gas during production. By
accounting for the initial saturation of the fracturing fluid in a
reservoir simulation model, a production estimation may be
obtained. By modeling the fluid pressure inside the natural
fractures, the potential shear slip condition may be evaluated
along the natural fractures, and the likelihood of microseismic
events may be assessed and predicted, which may provide a direct
connection between the predicted fracture geometry and microseismic
trigger mechanisms.
[0094] FIG. 7 illustrates an intersection 700 between an induced
hydraulic fracture 720 and an intersected natural fracture 705, and
regions/zones along the intersected natural fracture 705. Four
intersection zones in particular are presented as follows:
[0095] (1) An opened zone 715 (also called "opened part") of the
intersected natural fracture 705 is filled with invaded fracturing
fluid. In the opened zone 715, fluid pressure may exceed the normal
stress on the intersected natural fracture 705. The initial length
760 (also called L.sub.opened) of the opened zone 715 may be
evaluated from volume balance accounting for the intersected
natural fracture 705 and fluid properties, which may include
corresponding tip asymptotes. The width, pressure, height, leak-off
volume, volume of slurry and other parameters of individual regions
in the opened zone 715 may be calculated from a combination of a
flow equation (e.g., laminar, turbulent, Darcy, etc.), a mass
continuity equation and an elasticity equation. These calculations
may also account for height growth, proppant transport and
leak-off.
[0096] (2) An invaded closed zone 725 (also called "invaded closed
part of NF" or "filtration zone") of the intersected natural
fracture 705 is filled with fracturing fluid. In the invaded closed
zone 725, the fluid pressure may be above pore pressure but below
the closure stress of the intersected natural fracture 705. The
initial length 770 of invaded closed zone 725 may be estimated
based on Equation (5) below, which may account for fracturing fluid
leak-off into the reservoir. The filtration front velocity of the
invaded closed zone 725 may be estimated to track the interface
between filtration zones (e.g., invaded closed zone 725) and
pressurized zones (e.g., noninvaded closed zone 735). The pressure
dependent permeability, mass continuity, Darcy flow, leak-off into
the rock matrix, and compressibility considerations may be
accounted for to estimate length, pressure, width, height, and
volume within the invaded closed zone 725.
[0097] (3) A noninvaded closed zone 735 (also called "closed
pressurized part" or "pressurized zone") of the intersected natural
fracture 705 is filled with pressurized original reservoir fluid
and no invading fracturing fluid. In the noninvaded closed zone
735, the fluid pressure may be above the pore pressure. The initial
length 780 (also called L.sub.pressurized) of noninvaded closed
zone 735 may be evaluated based on pressure and flow rate at the
interface between the invaded closed zone 725 and the noninvaded
closed zone 735. The leak-off into the rock matrix from the
noninvaded closed zone 735 may be controlled by compressibility.
Governing equations for the noninvaded closed zone 735 may include
equations for continuity, compressibility, Darcy flow, pressure
dependent permeability and conductivity.
[0098] (4) A closed undisturbed zone 745 (also called "the
reservoir zone") of intersected natural fracture 705 is filled with
reservoir fluid under original pore pressure conditions.
[0099] In modeling the zones of a natural fracture, various
interface fronts and interfacial properties corresponding to
different intersection zones may be updated throughout a
simulation. For instance, the front of the invaded closed zone 725
and the front of the noninvaded closed zone 735 may be moved to
different points in a respective natural fracture at different time
steps. Interface fronts may be updated based on continuity (mass
balance), compressibility considerations and other intersection
parameters. If leak-off for the invaded closed zone 725 in the rock
matrix is negligible, for instance, then there may be no
pressurized region corresponding to the noninvaded closed zone
735.
[0100] In formations with a complex discrete fracture network,
special evaluation of intersections may be conducted between
invaded closed zone 725/noninvaded closed zone 735, opened zone
715/invaded closed zone 725 and opened closed zone 715/hydraulic
fracture 720 interceptions. Mass balance and fluid continuity
conditions may be satisfied, and appropriate rules for zone
interface propagation through the intersection 700 may be
prescribed.
[0101] Explicit modeling of hydraulic fractures interacting with
permeable natural fractures may become complicated, where the
modeling may include determining intersection properties, such as
the continuity of fluid mass in a natural fracture, pressure drops
along natural fractures, leak-off into the formation from natural
fracture walls, pressure sensitive natural fracture permeability,
properties and content of natural fractures, and the fluid rheology
of a natural fracture. This modeling may be performed by tracking
zone interfaces along an invaded natural fracture.
[0102] Depending on rock and reservoir properties, modeling of
zones (1), (2), and (3) may be performed using various
equations.
[0103] The continuity of fluid mass in a natural fracture may be
determined using the following equation:
.differential. q m .differential. s + m . + .rho. f q L = 0 , q L =
2 hC tot rock t - .tau. ( s ) Eq . ( 1 ) ##EQU00001##
where q.sub.m(t) is mass flux (rate of change of fluid mass) in a
natural fracture; s represents a length increment along the natural
fracture; q.sub.L represents a volume rate of leak-off per unit
length; m represents a fluid mass in the natural fracture; h
represents the height of the natural fracture; C.sub.tot.sup.rock
represents a total leak-off coefficient from the closed invaded
zone and the reservoir zone; and .rho..sub.f represents the
filtrate fluid density of the natural fracture.
[0104] Pressure drop along a closed natural fracture may be
determined using the following equation:
.differential. p .differential. s = .mu. f .rho. f k NF A q = .mu.
f .rho. f k NF wh q , at the inlet : p = p i n ( t ) Eq . ( 2 )
##EQU00002##
where k.sub.NF represents the permeability of the closed natural
fracture; .mu..sub.f represents the filtrate fluid viscosity of the
closed natural fracture; .rho..sub.f represents the filtrate fluid
density of the closed natural fracture; A represents a
cross-sectional area of the closed natural fracture, where A=wh and
where w is the effective (or average) width of the natural
fracture, and h is the effective height of the natural fracture;
p.sub.in represents the pressure at the inlet; and q represents the
mass flux of the natural fracture.
[0105] Natural fracture permeability due to stress and pressure
changes may be determined using the following equation:
k NF n = k o { C ln [ .sigma. * .sigma. n - p ] } 3 Eq . ( 3 )
##EQU00003##
where constants C and .sigma.* (reference stress state) are
determined from field data; k.sub.o is the natural fracture
permeability (reservoir permeability under in-situ conditions);
.sigma..sub.n is the normal stress on the natural fracture (i.e.,
where n indicates normal stress); and p is the pressure in the
natural fracture.
[0106] The width of closed invaded natural fracture, w(s), as a
function of the distance along the natural fracture, s, may be
determined using the following equation:
w ( s ) = w o 1 + 9 .sigma. eff .sigma. n ref , .sigma. eff =
.sigma. n - p f ( s ) Eq . ( 4 ) ##EQU00004##
where .sigma..sub.eff is the effective normal stress on the natural
fracture; .sigma..sub.n.sup.ref is the effective reference stress
on the natural fracture; w.sub.0 is the initial fracture aperture;
and p.sub.f(s) is the fluid pressure as a function of the distance
along the natural fracture.
[0107] Frictional sliding may occur when the shear stress reaches
the frictional shear strength of the natural fractures. The slip
may cause a fracture to grow in a shearing mode and may give rise
to the opening of other fractures that the fracture intersects. For
a closed fluid-filled fracture, the effective stress may be reduced
as the pressure increases, which may result in reduced shear
strength and fracture sliding. Coulomb's frictional law may be used
to calculate the frictional stress and conditions for shear
slippage. Shear slippage may be determined to enhance leak-off and
may result in offsets in fracture growth, as well as indicate a
justification for the presence of a microseismic event. Shear
slippage may also cause dilation of a natural fracture and an
increase in the effective width w(s), which may lead to enhanced
permeability and conductivity of the natural fracture and
contribute to enhancing hydrocarbon production.
[0108] When accounting for fracturing fluid leak-off into a
reservoir from the walls of the natural fracture, the length 770 of
the invaded closed zone 725 may be estimated using the following
equation:
L filtr ini ( t ) = tq i n h ( 3 w _ filtr + 4 C L 2 t ) , C L = C
tot rock Eq . ( 5 ) ##EQU00005##
where q.sub.in represents the initial fracturing fluid flow rate
into the invaded closed zone 725 from the opened zone 715;
w.sub.filtr represents an average width of invaded closed zone 725;
h represents the height of the natural fracture; t represents a
time of invasion; and C.sub.L=C.sub.tot.sup.rock represents the
total leak-off coefficient for the invaded closed zone 725 and the
reservoir zone 745.
[0109] The change in fluid density as a function of pressure and
temperature may be determined from the following equation:
.rho. 1 = .rho. 0 1 - .beta. ( T 1 - T 0 ) .times. 1 1 - p 1 - p 0
B Eq . ( 6 ) ##EQU00006##
where B is bulk modulus fluid elasticity in Pa, .beta. is
volumetric expansion coefficient, T.sub.0 is a temperature and
.rho..sub.0 is the fluid density at pressure p.sub.0, T.sub.1 is a
temperature and .rho..sub.1 is the fluid density at pressure
p.sub.1.
[0110] The above equations may be solved analytically at a given
time step (i.e., a reference point in time at which a hydraulic
fracturing network is being modeled) for the lengths and pressure
drops in specific intersection zones. The above equations may also
be solved using averaged properties for a given zone. A natural
fracture's permeability may also be updated based on pressure
changes and shear slip for a given time increment (i.e., with the
next time step). Solutions may also be obtained by solving these
equations numerically by discretizing the natural fracture into
smaller elements. For instance, mass balance, fluid loss into the
matrix, pressure drop in the natural fracture, natural fracture
permeability enhancement due to dilation and shear slip may be
solved and tracked locally at a specific element to obtain pressure
distributions and fluid fronts in a natural fracture.
Fracturing Operations Based on Intersection Properties Between
Hydraulic Fractures and Natural Fractures
[0111] FIG. 8 illustrates a flow diagram of a method 800 for
simulating and performing hydraulic fracturing in accordance with
various embodiments described herein. It should be understood that
while the operational flow diagram indicates a particular order of
execution of the operations, in other embodiments, the operations
might be executed in a different order. Further, in some
embodiments, additional operations or blocks may be added to the
method. Likewise, some operations or blocks may be omitted.
[0112] At block 810, integrated wellsite data is acquired for a
subterranean formation. Integrated wellsite data may include
geomechanical, geological, and/or geophysical properties of the
subterranean formation. Integrated wellsite data may also include
mechanical, geomechanical and/or geometrical properties of natural
fractures in the subterranean formation.
[0113] At block 820, a mechanical earth model is generated using
integrated wellsite data. The mechanical earth model may include a
model such as the MEM 462 described in FIG. 4A.
[0114] At block 830, an intersection of one or more induced
hydraulic fractures with one or more natural fractures is
simulated. For instance, the simulation may include modeling the
leak-off of fracturing fluid from the one or more induced hydraulic
fractures into the one or more natural fractures. Shear failure or
the shear slip of a natural fracture may also be modeled in the
simulated intersection.
[0115] In one embodiment, the simulated intersection may include
modeling one or more intersection zones such as those described in
regard to FIG. 7. The intersection zones may include the opened
zone 715, the invaded closed zone 725, the noninvaded closed zone
735, or the closed undisturbed zone 745.
[0116] In another embodiment, a hydraulic fractured growth pattern
may be simulated at block 830. The hydraulic fractured growth
pattern may include modeling new intersections between natural
fractures and induced hydraulic fractures, as well as existing or
previously created intersections. The simulated intersection may
include updating various elements (i.e., intersection properties or
altered interfacial properties of an intersected natural fracture)
in one or more intersection zones at respective time steps. For
instance, the gradual dilation of a respective intersection zone in
a natural fracture may be modeled to show the transition from a
closed undisturbed zone into an opened zone in a natural fracture.
This process may include modeling the fracture growth pattern as
described in FIGS. 5 and 6.
[0117] At block 840, one or more intersection properties of the
simulated intersection and/or intersected natural fracture in block
830 are determined. Intersection properties may refer to the
altered interfacial properties of an intersected natural fracture
and may include specific properties relating to the modeling of
intersection zones or the interfaces between intersection zones.
For instance, one intersection property may include the amount of
fracturing fluid leak-off from an induced hydraulic fracture into
the one or more natural fractures. Other intersection properties
may be the lengths of various intersection zones, the continuity of
fluid mass in a natural fracture, fracturing fluid leak-off into
the subterranean formation from a natural fracture's walls,
pressure sensitive natural fracture permeability, fluid rheology in
a natural fracture, a change in natural fracture permeability, a
change in stress within a region of a natural fracture, a change in
pressure within a region of a natural fracture, or any other
related properties.
[0118] At block 850, a stimulation plan is generated using the
mechanical earth model and the one or more intersection properties.
In generating the stimulation plan, intersection properties may be
used as an input in a similar fashion to how the mechanical earth
model may be used an input for stimulation planning, as described
in FIGS. 4A-4B. For instance, the amount of leak-off from a
hydraulic fracture into the one or more natural fractures may be
used determine a stimulation plan with a rate of injection for a
fracturing fluid that accounts for the amount of leak-off. FIGS.
4A-4B illustrate more information on stimulation planning and
design.
[0119] At block 855, one or more operating parameters of the
stimulation plan are adjusted to achieve one or more optimized
intersection properties. Operating parameters may include the fluid
viscosity of a fracturing fluid, the rate of injection of the
fracturing fluid, one or more fluid ingredients in the fracturing
fluid, one or more additives in the fracturing fluid that may
affect a leak-off property, a proppant size in the fracturing
fluid, a proppant concentration in the fracturing fluid, or any
other operating parameters.
[0120] The optimized intersection properties may be the same or
different intersection properties as those from block 840. For
instance, an intersection property may be optimized to achieve a
predetermined value for the respective intersection property or
another intersection property (e.g., adjusting an amount of
leak-off into a natural fracture may be used to obtain an optimized
natural fracture permeability). Optimized intersection properties
may also be used to achieve specific results, such as increasing
the permeability of a reservoir.
[0121] At block 860, a stimulation operation is performed based on
the stimulation plan from block 850 or an adjusted stimulation plan
from block 855. The stimulation operation may be performed using
methods as described in regard to FIGS. 1-4B. Using observed data
acquired from the stimulation operation, the simulated intersection
in block 830 may be validated for accuracy, confidence, or any
other criteria.
[0122] At block 870, the one or more intersection properties are
compared with microseismic events in observed data from the
stimulation operation from block 860.
[0123] At block 880, hydrocarbon production from the subterranean
formation is predicted using the one or more intersection
properties.
Computing System
[0124] Implementations of various technologies described herein may
be operational with numerous general purpose or special purpose
computing system environments or configurations. Examples of well
known computing systems, environments, and/or configurations that
may be suitable for use with the various technologies described
herein include, but are not limited to, personal computers, server
computers, hand-held or laptop devices, multiprocessor systems,
microprocessor-based systems, set top boxes, programmable consumer
electronics, network PCs, minicomputers, mainframe computers,
smartphones, smartwatches, personal wearable computing systems
networked with other computing systems, tablet computers, and
distributed computing environments that include any of the above
systems or devices, and the like.
[0125] The various technologies described herein may be implemented
in the general context of computer-executable instructions, such as
program modules, being executed by a computer. Generally, program
modules include routines, programs, objects, components, data
structures, etc. that performs particular tasks or implement
particular abstract data types. While program modules may execute
on a single computing system, it should be appreciated that, in
some implementations, program modules may be implemented on
separate computing systems or devices adapted to communicate with
one another. A program module may also be some combination of
hardware and software where particular tasks performed by the
program module may be done either through hardware, software, or
both.
[0126] The various technologies described herein may also be
implemented in distributed computing environments where tasks are
performed by remote processing devices that are linked through a
communications network, e.g., by hardwired links, wireless links,
or combinations thereof. The distributed computing environments may
span multiple continents and multiple vessels, ships or boats. In a
distributed computing environment, program modules may be located
in both local and remote computer storage media including memory
storage devices.
[0127] FIG. 9 illustrates a schematic diagram of a computing system
900 in which the various technologies described herein may be
incorporated and practiced. Although the computing system 900 may
be a conventional desktop or a server computer, as described above,
other computer system configurations may be used.
[0128] The computing system 900 may include a central processing
unit (CPU) 930, a system memory 926, a graphics processing unit
(GPU) 931 and a system bus 928 that couples various system
components including the system memory 926 to the CPU 930. Although
one CPU is illustrated in FIG. 9, it should be understood that in
some implementations the computing system 900 may include more than
one CPU. The GPU 931 may be a microprocessor specifically designed
to manipulate and implement computer graphics. The CPU 930 may
offload work to the GPU 931. The GPU 931 may have its own graphics
memory, and/or may have access to a portion of the system memory
926. As with the CPU 930, the GPU 931 may include one or more
processing units, and the processing units may include one or more
cores. The system bus 928 may be any of several types of bus
structures, including a memory bus or memory controller, a
peripheral bus, and a local bus using any of a variety of bus
architectures. By way of example, and not limitation, such
architectures include Industry Standard Architecture (ISA) bus,
Micro Channel Architecture (MCA) bus, Enhanced ISA (EISA) bus,
Video Electronics Standards Association (VESA) local bus, and
Peripheral Component Interconnect (PCI) bus also known as Mezzanine
bus. The system memory 926 may include a read-only memory (ROM) 912
and a random access memory (RAM) 916. A basic input/output system
(BIOS) 914, containing the basic routines that help transfer
information between elements within the computing system 900, such
as during start-up, may be stored in the ROM 912.
[0129] The computing system 900 may further include a hard disk
drive 950 for reading from and writing to a hard disk, a magnetic
disk drive 952 for reading from and writing to a removable magnetic
disk 956, and an optical disk drive 954 for reading from and
writing to a removable optical disk 958, such as a CD ROM or other
optical media. The hard disk drive 950, the magnetic disk drive
952, and the optical disk drive 954 may be connected to the system
bus 928 by a hard disk drive interface 936, a magnetic disk drive
interface 938, and an optical drive interface 940, respectively.
The drives and their associated computer-readable media may provide
nonvolatile storage of computer-readable instructions, data
structures, program modules and other data for the computing system
900.
[0130] Although the computing system 900 is described herein as
having a hard disk, a removable magnetic disk 956 and a removable
optical disk 958, it should be appreciated by those skilled in the
art that the computing system 900 may also include other types of
computer-readable media that may be accessed by a computer. For
example, such computer-readable media may include computer storage
media and communication media. Computer storage media may include
volatile and non-volatile, and removable and non-removable media
implemented in any method or technology for storage of information,
such as computer-readable instructions, data structures, program
modules or other data. Computer storage media may further include
RAM, ROM, erasable programmable read-only memory (EPROM),
electrically erasable programmable read-only memory (EEPROM), flash
memory or other solid state memory technology, CD-ROM, digital
versatile disks (DVD), or other optical storage, magnetic
cassettes, magnetic tape, magnetic disk storage or other magnetic
storage devices, or any other medium which can be used to store the
desired information and which can be accessed by the computing
system 900. Communication media may embody computer readable
instructions, data structures, program modules or other data in a
modulated data signal, such as a carrier wave or other transport
mechanism and may include any information delivery media. The term
"modulated data signal" may mean a signal that has one or more of
its characteristics set or changed in such a manner as to encode
information in the signal. By way of example, and not limitation,
communication media may include wired media such as a wired network
or direct-wired connection, and wireless media such as acoustic,
RF, infrared and other wireless media. The computing system 900 may
also include a host adapter 933 that connects to a storage device
935 via a small computer system interface (SCSI) bus, a Fiber
Channel bus, an eSATA bus, or using any other applicable computer
bus interface. Combinations of any of the above may also be
included within the scope of computer readable media.
[0131] A number of program modules may be stored on the hard disk
950, magnetic disk 956, optical disk 958, ROM 912 or RAM 916,
including an operating system 918, one or more application programs
920, program data 924, and a database system 948. The application
programs 920 may include various mobile applications ("apps") and
other applications configured to perform various methods and
techniques described herein. The operating system 918 may be any
suitable operating system that may control the operation of a
networked personal or server computer, such as Windows.RTM. XP, Mac
OS.RTM. X, Unix-variants (e.g., Linux.RTM. and BSD.RTM.), and the
like.
[0132] A user may enter commands and information into the computing
system 900 through input devices such as a keyboard 962 and
pointing device 960. Other input devices may include a microphone,
joystick, game pad, satellite dish, scanner, or the like. These and
other input devices may be connected to the CPU 930 through a
serial port interface 942 coupled to system bus 928, but may be
connected by other interfaces, such as a parallel port, game port
or a universal serial bus (USB). A monitor 934 or other type of
display device may also be connected to system bus 928 via an
interface, such as a video adapter 932. In addition to the monitor
934, the computing system 900 may further include other peripheral
output devices such as speakers and printers.
[0133] Further, the computing system 900 may operate in a networked
environment using logical connections to one or more remote
computers 974. The logical connections may be any connection that
is commonplace in offices, enterprise-wide computer networks,
intranets, and the Internet, such as local area network (LAN) 976
and a wide area network (WAN) 966. The remote computers 974 may be
another a computer, a server computer, a router, a network PC, a
peer device or other common network node, and may include many of
the elements describes above relative to the computing system 900.
The remote computers 974 may also each include application programs
970 similar to that of the computer action function.
[0134] When using a LAN networking environment, the computing
system 900 may be connected to the local network 976 through a
network interface or adapter 944. When used in a WAN networking
environment, the computing system 900 may include a router 964,
wireless router or other means for establishing communication over
a wide area network 966, such as the Internet. The router 964,
which may be internal or external, may be connected to the system
bus 928 via the serial port interface 942. In a networked
environment, program modules depicted relative to the computing
system 900, or portions thereof, may be stored in a remote memory
storage device 972. It will be appreciated that the network
connections shown are merely examples and other means of
establishing a communications link between the computers may be
used.
[0135] The network interface 944 may also utilize remote access
technologies (e.g., Remote Access Service (RAS), Virtual Private
Networking (VPN), Secure Socket Layer (SSL), Layer 2 Tunneling
(L2T), or any other suitable protocol). These remote access
technologies may be implemented in connection with the remote
computers 974.
[0136] It should be understood that the various technologies
described herein may be implemented in connection with hardware,
software or a combination of both. Thus, various technologies, or
certain aspects or portions thereof, may take the form of program
code (i.e., instructions) embodied in tangible media, such as
floppy diskettes, CD-ROMs, hard drives, or any other
machine-readable storage medium wherein, when the program code is
loaded into and executed by a machine, such as a computer, the
machine becomes an apparatus for practicing the various
technologies. In the case of program code execution on programmable
computers, the computing device may include a processor, a storage
medium readable by the processor (including volatile and
non-volatile memory and/or storage elements), at least one input
device, and at least one output device. One or more programs that
may implement or utilize the various technologies described herein
may use an application programming interface (API), reusable
controls, and the like. Such programs may be implemented in a high
level procedural or object oriented programming language to
communicate with a computer system. However, the program(s) may be
implemented in assembly or machine language, if desired. In any
case, the language may be a compiled or interpreted language, and
combined with hardware implementations. Also, the program code may
execute entirely on a user's computing device, partly on the user's
computing device, as a stand-alone software package, partly on the
user's computer and partly on a remote computer or entirely on the
remote computer or a server computer.
[0137] Those with skill in the art will appreciate that any of the
listed architectures, features or standards discussed above with
respect to the example computing system 900 may be omitted for use
with a computing system used in accordance with the various
embodiments disclosed herein because technology and standards
continue to evolve over time.
[0138] Of course, many processing techniques for collected data,
including one or more of the techniques and methods disclosed
herein, may also be used successfully with collected data types
other than wellsite data. While certain implementations have been
disclosed in the context of wellsite data collection and
processing, those with skill in the art will recognize that one or
more of the methods, techniques, and computing systems disclosed
herein can be applied in many fields and contexts where data
involving structures arrayed in a three-dimensional space and/or
subsurface region of interest may be collected and processed, e.g.,
medical imaging techniques such as tomography, ultrasound, MRI and
the like for human tissue; radar, sonar, and LIDAR imaging
techniques; and other appropriate three-dimensional imaging
problems.
[0139] Although the subject matter has been described in language
specific to structural features and/or methodological acts, it is
to be understood that the subject matter defined in the appended
claims is not limited to the specific features or acts described
above. Rather, the specific features and acts described above are
disclosed as example forms of implementing the claims.
[0140] While the foregoing is directed to implementations of
various technologies described herein, other and further
implementations may be devised without departing from the basic
scope thereof. Although the subject matter has been described in
language specific to structural features and/or methodological
acts, it is to be understood that the subject matter defined in the
appended claims is limited to the specific features or acts
described above. Rather, the specific features and acts described
above are disclosed as example forms of implementing the
claims.
* * * * *