U.S. patent application number 11/440810 was filed with the patent office on 2007-11-29 for method and system for development of naturally fractured formations.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Lyle V. Lehman, Mohamed Soliman.
Application Number | 20070272407 11/440810 |
Document ID | / |
Family ID | 38748462 |
Filed Date | 2007-11-29 |
United States Patent
Application |
20070272407 |
Kind Code |
A1 |
Lehman; Lyle V. ; et
al. |
November 29, 2007 |
Method and system for development of naturally fractured
formations
Abstract
A method and system for development of a naturally fractured
formation may include generating a fracture model from a fracture
treatment of a well in the naturally fractured formation. The
fracture model may account for natural fractures in the naturally
fractured formation. The fracture model may include the fracture
volume of the fracture generated by the fracture treatment. Well
spacing and fracture stimulation design for one or more wells in
the naturally fractured formation may be determined based on the
fracture model.
Inventors: |
Lehman; Lyle V.; (Katy,
TX) ; Soliman; Mohamed; (Cypress, TX) |
Correspondence
Address: |
Halliburton Energy Services, Inc.
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
38748462 |
Appl. No.: |
11/440810 |
Filed: |
May 25, 2006 |
Current U.S.
Class: |
166/250.1 ;
166/308.1; 702/12; 703/10 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 49/00 20130101 |
Class at
Publication: |
166/250.1 ;
166/308.1; 702/12; 703/10 |
International
Class: |
E21B 49/00 20060101
E21B049/00 |
Claims
1. A method for development of a naturally fractured formation,
comprising: generating a fracture model from a fracture treatment
of a well in a naturally fractured formation; the fracture model
accounting for natural fractures within the naturally fractured
formation and comprising a fracture volume of a fracture generated
by the fracture treatment; and determining at least one of well
spacing and fracture treatment designed for one or more wells in
the naturally fractured formation based on the fracture model.
2. The method of claim 1, further comprising updating the fracture
model based on production data from the well in the naturally
fractured formation.
3. The method of claim 1, further comprising optimizing well
spacing and fracture treatment design for the one or more wells in
the naturally fractured formation based on the fracture model.
4. The method of claim 1, wherein the fracture model comprises
storativity and transmissibility of the fracture volume.
5. The method of claim 1, further comprising generating the
fracture model based on microseismic data collected from a fracture
treatment of a disparate well in the naturally fractured
formation.
6. The method of claim 1, wherein the fracture model comprises a
multi-dimensional model.
7. A method for well planning in a formation, comprising:
performing a fracture treatment for a well to generate a fracture
in a formation; collecting microseismic data from the fracture
treatment; using the microseismic data to generate a fracture model
of the fracture; and using the fracture model for well planning in
the formation.
8. The method of claim 7, wherein the well planning comprises at
least one of a spacing for a second well based on the fracture
model and a fracture treatment design for the second well.
9. The method of claim 7, further comprising updating the fracture
model based on production from the well.
10. The method of claim 7, further comprising determining a well
spacing and a fracture treatment design for one or more wells based
on the fracture model.
11. The method claim 10, further comprising determining the well
spacing and fracture treatment design for the one or more wells
based on an economic analysis of costs of the fracture treatment
design and revenue generated by the one or more wells based on the
fracture treatment design.
12. The method of claim 7, wherein the fracture model comprises
storativity and transmissibility of a fracture volume of the
fracture generated by the fracture treatment.
13. The method for simulating production enhancement of a well,
comprising: simulating a fracture geometry from a fracture
treatment of a well in a formation, the fracture geometry
accounting for natural fractures in the formation; and simulating
production of the well based on the fracture geometry.
14. The method of claim 13, further comprising simulating the
fracture geometry based on a volume of the facture treatment.
15. The method of claim 13, further comprising simulating the
fracture geometry based on microseismic data collected for a
disparate fracture treatment in the formation.
16. The method of claim 13, further comprising generating a visual
image of the fracture geometry, the visual image comprising induced
and natural fractures.
17. The method of claim 14, wherein the fracture geometry comprises
a fracture volume of the fracture treatment.
18. The method of claim 17, wherein the fracture geometry comprises
storativity and transmissibility of the fracture volume.
19. The method of claim 13, further comprising simulating the
fracture geometry by generating a multi-dimensional model of the
fracture treatment.
20. The method of claim 19, further comprising updating the
multi-dimensional model based on production for the well.
Description
TECHNICAL FIELD
[0001] Fracture stimulation of a well, and more particularly to a
method and system for development of naturally fractured
formations.
BACKGROUND
[0002] Oil and gas wells produce oil, gas and/or byproducts from
underground reservoirs. Oil and gas reservoirs are formations of
rock containing oil and/or gas. The type and properties of the rock
may vary by reservoir and also within reservoirs. For example, the
porosity and permeability of a reservoir rock may vary from
reservoir to reservoir and from well to well in a reservoir. The
porosity is the percentage of pore volume, or void space, within
the reservoir rock that can contain fluids. The permeability is an
estimate of the reservoir rock's ability to flow or transmit
fluids.
[0003] Oil and gas production from a well may be stimulated by
fracture, acid or other production enhancement treatment. In a
fracture treatment, fluids are pumped downhole under high pressure
to artificially fracture the reservoir rock in order to increase
permeability and production. First, a pad, which is fracture fluids
without proppants is pumped down the well until formation
breakdown. Then, the fracturing fluid with proppants is pumped
downhole to hold the fractures open after pumping stops. At the end
of the fracture treatment, a clear fluid flush may be pumped down
the well to clean the wellbore of proppants.
[0004] Shales and other carboniferous and naturally fractured
formations are often fracture stimulated, or treated, to improve
natural production. A typical fracture treatment requires thousands
to millions of gallons of water with proppant pumped at a high rate
of velocity. These fracture treatments are often generic, using
little technology to design them. Microseismic monitoring of these
fracture treatments indicates the typical fracture pattern is not a
single-wing pattern as in other formations, but a maze of induced
fractures which engage or hook-up with natural fractures in the
shales. The natural fractures are typically, but not always,
oriented 90 degrees orthogonal to the direction of the induced
fractures or in the direction of minimum horizontal stress. The
natural fractures contain natural gas which may be produced after
stimulation. For a given volume, several areas of natural fractures
are connected by the induced fractures. The improvement from the
fracture treatment is a function of the amount of area of the shale
that is exposed and allowed to dissorb gas from the formation.
SUMMARY
[0005] A method and system for development of naturally fractured
formations are provided. In accordance with one embodiment, a
method for development of a naturally fractured formation includes
generating a fracture model from a fracture treatment of a well in
the naturally fractured formation. The fracture model accounts for
natural fractures in the naturally fractured formation. The
fracture model may include a fracture volume generated by the
fracture treatment. At least one of well spacing and fracture
treatment design for one or more wells in the naturally fractured
formation may be determined based on the fracture model.
[0006] In a specific embodiment, microseismic data may be used to
define the boundaries of the fracture volume. The performance of
the fracture may be defined in the classical planar bi-wing
fracture, fracture volume, or a fracture volume surrounding a
bi-wing fracture. The characterization of fracture volume may be in
terms of a new storativity, transmissibility, and/or the fracture's
permeability. These parameters may be determined from, for example,
either testing or history matching of production. The model may be
used for long-term prediction of production.
[0007] Technical advantages of one or more embodiments of the
method and system may include providing a fracture simulator which
models the fracture geometry of shales and other formations with
natural fractures. The model may account for induced and natural
fractures. In addition, the model may be calibrated by microseismic
data. The model may be used in design and real time modes and
provide special three-dimensional models. The design model may be
used to plan large field developments.
[0008] Other technical advantages of one or more embodiments may
include an integrated approach to stimulation, analysis, reservoir
response forecasting and field development planning for shale and
other fractured formations. The integrated approach may include the
linkage of microseismic measurement, the numerical simulation of
the fracture propagation, and the numerical simulation of reservoir
performance and/or matching reservoir productivity.
[0009] Details of the one or more embodiments of the disclosure are
set forth in the accompanying drawings in the description below.
Other features, objects, and advantages of some of the embodiments
will be apparent from the description and drawings, and from the
claims. Some, all, or none of the embodiments may include
advantages described herein.
DESCRIPTION OF DRAWINGS
[0010] FIG. 1 illustrates one embodiment of a fracture treatment
for a well;
[0011] FIG. 2 illustrates an exemplary fracture value generated by
the fracture treatment of FIG. 1;
[0012] FIG. 3 illustrates one embodiment of the fracture
simulator;
[0013] FIGS. 4A-B illustrate exemplary inputs and outputs of the
fracture simulator of FIG. 3;
[0014] FIG. 5 illustrates one embodiment of a method for
development of a naturally fractured formation using fracture
simulation, analysis and reservoir response forecasting; and
[0015] FIG. 6 illustrates exemplary development of a field using
fracture treatments.
DETAILED DESCRIPTION
[0016] FIG. 1 illustrates one embodiment of a fracture treatment 10
for a well 12. The well 12 may be an oil and gas well intersecting
a reservoir or formation 14. In this embodiment, the formation 14
comprises an underground formation of naturally fractured rock
containing oil and/or gas. For example, the formation 14 may
comprise a fractured shale. The well 12 may in other embodiments,
intersect other suitable types of formations 14, including
reservoirs that are not naturally fractured in any significant
amount.
[0017] The fracture treatment 10 may comprise a mini fracture test
treatment or other suitable treatment. In the mini fracture test
treatment embodiment, the fracture treatment 10 may be used to
determine formation properties and fracture properties before a
regular or full fracture treatment. The formation properties may
comprise, for example, reservoir pressure and formation
permeability. The formation permeability is an estimate of the
reservoir rock's ability to flow or transmit fluids. The fracture
properties may comprise, for example, a fracture value and
distribution of fractures in the fracture value. In other
embodiments, the fracture treatment 10 may comprise a regular or
full fracture treatment, a follow-on fracture treatment, a final
fracture treatment or other suitable fracture treatment.
[0018] For a mini fracture embodiment, analysis of the test
typically is used to determine, for example, the formation
permeability, fracture closure pressure, and fissure opening
pressure. The fracture closure pressure may be very close to the
maximum horizontal stress and may be shown by deviation of the
induced fracture from a straight line emanating from the well 12.
In addition, the effective permeability of the fractured system may
be determined from analysis of the induced fracture. The mini
fracture test may also be used to estimate the dual porosity
parameters.
[0019] The presence of pre-hydraulic production data or a test
could also or instead be used to determine original storativity and
transmissibility. This would provide dual porosity parameters for
the original reservoir and for the fracture volume. In another
embodiment, production data may be matched with theoretically
simulated data from a simulator such as QUIKLOOK from HALLIBURTON.
In real time operation, the prediction of the reservoir performance
can be used to enhance or optimize the design of the fractured
volume. Real time monitoring of seismic can determine whether the
design has been achieved and/or the fracture that was achieved. The
improved reservoir description may be used to give better forecast
of future performance.
[0020] The well 12 may include a well bore 20, casing 22 and well
head 24. The well bore 20 may be a vertical or deviated bore. The
casing 22 may be cemented or otherwise suitably secured in the well
bore 12. Perforations 26 may be formed in the casing 22 at the
level of the formation 14 to allow oil, gas, and by-products to
flow into the well 12 and be produced to the surface 25.
Perforations 26 may be formed using shape charges, a perforating
gun or otherwise.
[0021] For the fracture treatment 10, a work string 30 may be
disposed in the well bore 20. The work string 30 may be coiled
tubing, sectioned pipe or other suitable tubing. A fracturing tool
32 may be coupled to an end of the work string 30. The fracturing
tool 32 may comprise a SURGIFRAC or COBRA FRAC tool manufactured by
HALLIBURTON or other suitable fracturing tool. Packers 36 may seal
an annulus 38 of the well bore 20 above and below the formation 14.
Packers 36 may be mechanical, fluid inflatable or other suitable
packers.
[0022] One or more pump trucks 40 may be coupled to the work string
30 at the surface 25. The pump trucks 40 pump fracture fluid 58
down the work string 30 to perform the fracture treatment 10 and
generate the fracture 60. The fracture fluid 58 may comprise a
fluid pad, proppants and/or a flush fluid. The pump trucks 40 may
comprise mobile vehicles, equipment such as skids or other suitable
structures.
[0023] One or more instrument trucks 44 may also be provided at the
surface 25. The instrument truck 44 may include a fracture control
system 46 and a fracture simulator 47. The fracture control system
46 monitors and controls the fracture treatment 10. The fracture
control system 46 may, in one embodiment, control the pump trucks
40 and fluid valves to stop and start the fracture treatment 10 as
well as to stop and start the pad phase, proppant phase and/or
flush phase of the fracture treatment 10. The fracture control
system 46 communicates with surface and/or subsurface instruments
to monitor and control the fracture treatment 10. In one
embodiment, the surface and subsurface instruments may comprise
surface sensors 48, down-hole sensors 50 and pump controls 52.
[0024] Surface and down-hole sensors 48 and 50 may comprise
pressure, rate, temperature and/or other suitable sensors. Pump
controls 52 may comprise controls for starting, stopping and/or
otherwise controlling pumping as well as controls for selecting
and/or otherwise controlling fluids pumped during the fracture
treatment 10. Surface and down-hole sensors 48 and 50 as well as
pump controls 52 may communicate with the fracture control system
46 over wire-line, wireless or other suitable links. For example,
surface sensors 48 and pump controls 52 may communicate with the
fracture control system 46 via a wire-line link while down-hole
sensors 50 communicate wirelessly to a receiver at the surface 25
that is connected by a wire-line link to the fracture control
system 46. In another embodiment, the down-hole sensors 50 may upon
retrieval from the well 12 be directly or otherwise connected to
fracture control system 46.
[0025] The fracture simulator 47 may simulate the fracture 60
during a design phase and/or use data collected from the fracture
treatment 10 to simulate further fracture treatments 10 in the
formation 14. In either case, the fracture simulator 47 may be
updated during and after the fracture treatment 10 based on
measured and/or observed data, including fracture, subsequent
production and/or other data. The fracture simulator 47 may also be
used for planning field development. For example, the fracture
simulator 47 may estimate or otherwise determine fracture geometry
based on fracture volume pumped (v.sub.p), determine production
based on fracture geometry and/or determine economically optimal or
other well spacing and fracture treatment design for field
development.
[0026] In one embodiment, the fracture simulator 47 may consider
the considerable increase in fluid leak-off and the creation of
fractures that are at angle to the main induced hydraulic
fractures. The presence of these natural fractures may cause the
arrest of the propagation of the main fracture. In particular, the
simulator 47 may set limits of the fracture propagation model (both
in direction of the main fracture and in a direction perpendicular
to the main fracture) from the micro seismic monitoring, set up the
three determined stresses, and design the main fracture while
varying the leak-off into the formation to get the length
determined by micro seismic. The simulator 47 may also use the
observed maximum horizontal stress (from mini fracture) and the
observed pressure coupled with the length determined from micro
seismic to calculate the volume necessary to create the fracture.
By comparing the volume leaked off from the first fracture to the
volume needed to create the second fracture, a measure of fracture
distribution can be reached.
[0027] The fracture simulator 47 may communicate with a
microseismic system 56. The microseismic system 56 may comprise one
or more sensors at the surface and/or in an observation well normal
to the fracture plane. The microseismic system 56 may detect,
record and provide information on points in the formation 14 at
which fracturing is observed. In another embodiment, tilt meters or
other sensors able to collect information indicative of the area of
the formation 14 effected by the fracture 60 may be used in
addition to and/or in place of the microseismic system 56.
[0028] In operation, the fracturing tool 32 is coupled to the work
string 30 and positioned in the well 12. The packers 36 are set to
isolate the formation 14. The pump trucks 40 pump fracture fluid 58
down the work string 30 to the fracturing tool 32. The fracture
fluid 58 exits the fracturing tool 32 and creates the fracture 60
in the formation 14. In a particular embodiment, a fracture fluid
58 may comprise a fluid pad pumped down the well 12 until breakdown
of the formation in the formation 14. Proppants may then be pumped
down-hole followed by a clear fluid flush. The fracture treatment
10 may be otherwise suitably performed.
[0029] During the fracture treatment 10, the microseismic system 56
collects data on the location in the formation 14 where rock slips
and/or other fracturing occurs. Additionally, or alternately, the
microseismic system 56 may record rock slips and/or other activity
indicative of the location of fractures during closure of the
fracture 60 following the fracture treatment 10. The fracture
simulator 47 may develop, refine, or otherwise generate a fracture
model of the fracture 60 based on microseismic data collected by
the microseismic system 56. As described in more detail below, the
fracture model may include a fracture volume of the fracture 60
and/or a fracture geometry of the fracture 60. The fracture
geometry may include the fracture volume as well as storativity and
transmissibility of the fracture volume.
[0030] FIG. 2 illustrates one embodiment of the fracture 60 formed
from the well 12 in the formation 14. The fracture 60 includes a
swarm or pattern of fractures 80. The fractures 80 include natural
fractures 82 and induced fractures 84. The induced fractures 84 are
perpendicular to the natural fractures 82 and formed by fracture
treatment 10. The natural fractures 82 may be elongated, enlarged
or otherwise affected by the fracture treatment 10. Together, the
natural fractures 82 and induced fractures 84 form the effected
zone, or other fracture volume 86.
[0031] In the fracture volume 86, one or more individual fractures
84 may emit from the well bore and each intersect several natural
fractures 82. Most, if not all, natural fractures 82 will take
fluid but some will divert the flow from the induced fracture 84 so
that the flow quits its original path and instead fluid goes down
the natural fracture 82. At some point, the natural fracture 82 may
cease to exist, in which case the energy in this portion of a
fracture 60 is sufficient to re-start an induced fracture 84 along
the original fracturing plane. The induced hydraulic fracture 84
will typically be located in the middle of the fracture volume 86.
The boundaries of the fracture volume 86 may be determined from
seismic data. In some embodiments, the fracturing treatment will
not change the basic parameters of fracture volume 86, but will
change the dimensions of the fracture volume 86 (will get
bigger).
[0032] The induced fractures 84 may provide primary porosity in the
fracture volume 86 while the natural fractures 82 provide secondary
porosity. The fracture swarm may have ratios of about forty percent
(40%) induced fractures 84 (and fracture length) in the fracture
volume 86 about forty-five percent (45%) natural fractures 82 (and
fracture length) in the fracture volume 86 and about five percent
(5%) horizontal fractures (associated with either natural or
induced) in the fracture volume 86.
[0033] FIG. 3 illustrates one embodiment of the fracture simulator
47. In this embodiment, the fracture simulator 47 is implemented as
an integrated computer system such as a personal computer, laptop,
or other stand-alone system. In other embodiments, the fracture
simulator 47 may be implemented as a distributed computer system
with elements of the fracture simulator 47 connected locally and/or
remotely by a computer or other communication network.
[0034] The fracture simulator 47 may comprise any processors or set
of processors that execute instructions and manipulate data to
perform the operations such as, for example, a central processing
unit (CPU), a blade, an application specific integrated circuit
(ASIC), or a field-programmable gate array (FPGA). Processing may
be controlled by logic which may comprise software and/or hardware
instructions. The software may comprise a computer readable program
coded and embedded on a computer readable medium for performing the
methods, processes and operations of the respective engines.
[0035] Referring to FIG. 3, the fracture simulator 47 includes a
data collection and processing unit 150, fracture geometry
simulator 152, a fracture property simulator 154, a production
simulator 156, an economic simulator 158, and user interface 160.
The fracture simulator 47 and/or components of the fracture
simulator 47 may comprise additional, different, and/or other
suitable elements, as well as any suitable subset of the
elements.
[0036] Data collection and processing unit 150 receives, accesses,
and/or stores geomechanical data 170, reservoir properties 172,
microseismic data 174, production data 176 and job design data 178
for the formation 14, which may include data for similar formations
if appropriate. Additional, different and/or other suitable
information may be collected, stored and/or accessed, as well as
any suitable subset of information. The collection and processing
unit 150 may correlate received signals to a corresponding measured
value, filter the data, fill in missing data and/or calculate data
derivatives used by one or more of the fracture geometry simulator
152, fracture property simulator 154, production simulator 156
and/or economic simulator 158. The data collection and processing
unit 150 may comprise data input/output (I/O) and data storage. The
data I/O may be coupled by wireline or wirelessly to local and/or
remote instruments or data sources. The data storage may be one or
more databases or other persistent or non-persistent storage.
[0037] The geomechanical data 170 may be received from database
sources, from imaging logs such as Formation Micro-Imager (FMI) or
otherwise. In the FMI embodiment, the FMI tool determines a maximum
horizontal stress (.upsilon..sub.H max), a minimum horizontal
stress (.upsilon..sub.H min), stress directions, and the
relationship between the maximum and minimum stresses. The FMI tool
may comprise, for example, a 4, 5 or 6 arm tool. This and other or
different geomechanical information is stored in geomechanical data
170.
[0038] The reservoir properties data 172 may be received from
database sources, from well logs or otherwise. The reservoir
properties 172 may comprise, for example, rock mechanic properties
such as Young's Modulus, Poisson's Ratio, fracture stress,
permeability, thickness, pressure, porosity, and spacing of natural
fractures 82. The reservoir properties 172 may comprise other
suitable data indicative of formation 14 and/or conditions in the
formation 14.
[0039] The microseismic data 174 may be collected from the
microseismic system 56, or other suitable sources. The microseismic
data 174 may comprise the distribution of natural and induced
fractures 82 and 84 for fracture treatments 10 in the formation 14,
as well as the fracture value generated by the fracture treatments
10. Measured microseismic data may be processed by manually or
otherwise plotting points where rock slips during the fracture
treatment 10, which may be recorded as pops or snaps during the
fracture treatment 10. The points may be in or just outside the
natural fractures 82 and/or induced fractured 84. The microseismic
data 174 may comprise other, different and/or additional
information, as well as a subset of the described information.
[0040] The production data 176 may be directly measured and/or
received from database sources or otherwise. The production data
176 may comprise oil, gas and/or water production data as well as
bottom hole pressure and temperature information from wells drilled
and producing in the formation 14. The production data 176 may also
comprise production and other decline data, as well as other
information indicative of production. Production data 176 may
comprise other, additional or different information, as well as a
subset of the described information.
[0041] The job design data 178 may comprise data for a planned
fracture treatment 10. The job design data 178 may include a
fracture volume 86, volume pumped for the fracture treatment 10
and/or rate (Q) for the fracture treatment 10. In one embodiment,
simulations of the fracture simulator 47 are based on volume pumped
data for a planned fracture treatment 10. In this embodiment,
fracture geometry may be simulated based on volume pumped. The
simulation may be based on additional or different data. The job
design data 178 may comprise other, different and/or additional
data for the planned fracture treatment 10, as well as a subset of
the identified data.
[0042] The fracture geometry simulator 152, fracture property
simulator 154, production simulator 156 and economic simulator 158
may each be coupled to the data collection and processing unit 150
and the user interface 160, as well as to each other. Accordingly,
each may access data collected, calculated and/or simulated and
each may be accessed by an operator or other user via the user
interface 160. The user interface 160 may comprise a graphical
interface, a text based interface or other suitable interface. In a
particular embodiment, the fracture geometry simulator 152 may
provide a fracture geometry model and/or access to the fracture
geometry model to the fracture property simulator 154. Similarly,
the fracture property simulator 154 may provide a fracture property
model and/or access to the fracture property model to the
production simulator 156. The production simulator 156 may provide
a production model or access to a production model to the economic
simulator 158. Accordingly, each simulator may store its own
generated model and/or may transfer the model to another simulator
for processing. In another embodiment, models may be stored in the
data collection and processing unit 150 and/or displayed by the
user interface 160. The simulations may in a particular embodiment
be generated and/or displayed in real-time to the input of job
design data and/or at a fracture site.
[0043] The fracture geometry simulator 152 may simulate, or model,
geometry of the fracture 60 generated by a planned fracture
treatment 10 based on volume pumped or the job design data 178 for
the planned fracture treatment 10. An operation is based on data or
another element when it uses and/or accounts for the data or other
element. Accordingly, the operation may also use and/or account for
other data and other information. A generated fracture geometry
model may comprise fracture volume 86. In a particular embodiment,
the fracture geometry model may also comprise the distribution
and/or pattern of the natural fractures 82 and induced fractures
84.
[0044] The fracture geometry simulator 152 provides in one
embodiment a dual porosity model that accounts for natural
fractures 82 as well as geomechanical data 170 and reservoir
properties 172. In this embodiment, the fracture geometry model may
be based on volume pumped for the fracture 60 and distance from the
well bore 20 of the natural fractures 82 and induced fractures 84.
The fracture geometry may be otherwise simulated, estimated or
otherwise determined, by the fracture geometry simulator 152.
[0045] The fracture properties simulator 154 may simulate, or
model, fracture properties based on the fracture geometry model
generated by the fracture geometry simulator 152 and the volume
pumped or other job design data 178. The fracture properties may be
otherwise simulated, estimated or otherwise determined by the
fracture property simulator 154. In simulating fracture properties,
the fracture property simulator 154 may, for example, account for
natural fractures 82 and induced fractures 84, as well as
geomechanical data 170, and reservoir properties 172. In a
particular embodiment, fracture properties may comprise storativity
(.omega.) and transmissibility (4). Storativity is the ratio of the
fracture volume to the total system volume. Transmissibility is
proportional to the ratio of matrix permeability to the natural
fracture system. The created fracture volume 86 will typically have
larger storativity, smaller transmissibility and higher fractured
system permeability. The fracture permeability may increase by the
same ratio of the decrease in transmissibility. The change in
storativity, transmissibility, and fracture permeability may be a
result of ballooning the naturally fractured system around the
created hydraulic fracture.
[0046] The fracture geometry simulator 152 and fracture property
simulator 154 may be calibrated using geomechanical data 170,
reservoir properties 172, microseismic data 174, and/or production
data 176. In a particular embodiment, the fracture geometry
simulator 152 may be calibrated by correlating volume pumped for
fracture treatments 10 in formation 14 with fracture volume 86
generated by the fracture treatments 10 as determined by
microseismic data 174 for the fracture treatments 10. For example,
the fracture property simulator 154 and fracture geometry simulator
152 may create a distribution of fracture geometry in terms of
percentage into the induced fracture azimuth, natural fracture
azimuth and horizontal components. These simulators can be
calibrated by taking measurements from geomechanical properties,
micro seismic studies of area fracture treatments, known reservoir
properties such as lambda and omega, plus other reservoir
components mentioned above. The output would be similar to FIG. 2
which indicates a plane view of the fracture network system. In one
embodiment, an example of output would be: "40% induced, 55%
natural and 5% horizontal components." These values may then be
used to determine the fracture value of the fracture network. This
fracture volume can be input into the reservoir model to determine
economical benefit from the volume of fluid pumped.
[0047] In addition, the fracture property simulator 154 may in a
particular embodiment be calibrated by correlating volume pumped
and fracture volume 86 for fracture treatments 10 in formation 14
with production data 176 resulting from the fracture treatments 10
to simulate, estimate or otherwise determine fracture properties.
For example, storativity and transmissibility correlating to a
pumped volume and fracture volume 86 may be adjusted to values that
account for measured production from fracture treatments 10 in the
formation 14. As another example, leak off parameters and
properties of the formation 14 surrounding the fracture 16 may be
modified to match observed fracture growth as a fracture 60 and as
a total area surrounding the fracture 60. In particular, a
non-linear regression may be used to vary storativity and
transmissibility until a calculated production curve matches
observed production. The fracture property simulator 154 may be
otherwise suitably calibrated.
[0048] The production simulator 156 simulates production for a
planned fracture treatment 10 based on the fracture model generated
by the fracture geometry simulator 152 and fracture property
simulator 154. The fracture model may comprise the fracture volume
86 determined by the fracture geometry simulator 152 and the
storativity and transmissibility of the fracture volume 86
determined by the fracture property simulator 154. The fracture
model may provide geometry and growth patterns with time (volume of
fluid pumped) to replicate the longitudinal and horizontal growth
of the fracture network. The fracture model may also include, for
example, distribution of the induced and natural fractures 82 and
84. The fracture model may comprise other suitable criteria for
determining production from the fracture treatment 10. In addition,
the production simulator 156 may simulate production from a
performed fracture treatment 10 based on actual data measured
during or after the fracture treatment 10, such as microseismic
data, as well as measured or simulated fracture properties. In
another embodiment, the fracture model will be generated without
the fracture geometry model. In this embodiment, the microseismic
effect may be matched. For example, a natural fracture model can be
generated from micro seismic observations and matched to induced
fractures 84.
[0049] The production simulator 156 may simulate oil, gas and/or
water or other byproduct production, as well as production incline
and decline curves. In one embodiment, the simulated production, or
production model, comprises oil and water production curves over
the expected life of the well 12. The production curves may be
printed, displayed in the user interface 160 or otherwise made
available to the operator. In a particular embodiment, the
production curves may plot volume produced in barrels or other
units versus time in years. The production similar 156 may be
calibrated by correlating measured storativity and transmissibility
from fracture treatments 10 in wells 12 in the formation 14 to
measured production of the wells 12.
[0050] The economic simulator 158 simulates economics of the
planned fracture treatment 10 for the well 12 based on, in one
embodiment, cost of the fracture treatment 10 and revenue generated
by the well 12 in response to the fracture treatment 10. In a
particular embodiment, the economic simulator 158 may determine the
volume pumped or other criteria for the fracture treatment 10 based
on balancing costs of the fracture treatment 10 versus increased
revenues from the fracture treatment 10. The economic simulator 158
may account for increased and/or earlier production when weighing
various treatment design options. The design of the planned
fracture treatment 10 may be enhanced or optimized by iteratively
simulating the economics of various treatment designs. For example,
a number of treatment designs may be fed into the fracture
simulator 47 and a fracture geometry model, fracture property
model, production model and economic model generated for each
treatment design, with the treatment design leading to the most
economic model selected for the fracture treatment 10.
[0051] In addition, or alternately, well spacing for wells 12 in
the formation 14 may be determined based on fracture economics. In
this embodiment, well spacing may be selected to enhance or
optimize revenues from production of the field. For example, cost
of well formation versus cost of well fracturing, as well as
resulting production, may be evaluated for the field. It may, in
some cases, be economically advantageous to drill an increased
number of wells 12 that each need a smaller fracture volume 86 than
to drill a decreased number of wells 12 each needing an increased
fracture volume 86 to complete the field, or vice versa. In a
particular embodiment, an optimum well spacing and the
corresponding fracture volume 86 for the wells 12 may be selected
to complete the field. In addition to fracture treatment 10, well
spacing and field planning, the fracture simulator 47 may be used
after a fracture treatment 10 to simulate production and economics
based in microseismic or other data from the fracture treatment 10.
In this embodiment, the production simulation includes the effect
of fracture 60 as well as the total affected formation 14, or
reservoir, volume as observed from microseismic measurements. In
still another embodiment, the existing microseismic data may be
used to perform matching after-treatment to calibrate the model and
further refine the terms that represent the natural fractures 82
which may be the ratio of fluid that occupies or propagates into
the natural fracture 82 system versus the induced fracture 84
system. In other words, if the output is 50/45/05, then 45 percent
of the fracture volume propagates into the natural fracture 82
system and 50 percent propagates into the induced fracture 84
system. Horizontal fracture geometries typically range from 7
percent down to 2 percent. Therefore, in one embodiment, a common
output from the model would be dependent upon volume pumped. As a
first example, volume is 1,000,000 gallons of fracture fluid
(water) and fracture height to be stimulated is 600 feet. Rate is
85 barrels per minute. Output is 52/45/03, which translates to 52
percent induced fractures 82, 45 percent natural fractures 84, and
3 percent horizontal fractures. The model would generate these
geometries with time and the horizontal geometries not appearing
until late in the treatment. As a second example, volume is
3,500,000 gallons of fracture fluid (water) with the other fracture
values the same as the first example. Output is 48/48/04, which
translates to 48 percent induced fracture 82, 48 percent natural
fractures 84 and 4 percent horizontal fractures. This example
generates a differently shaped rectangle in the plan view than the
first example. The overall area is greater as more fluid is
injected, but the final shape would resemble a square more so than
in the first example.
[0052] In still another embodiment, existing microseismic data and
production data may be used and a multiple history matching
approach, to evaluate the success or lack of it from the fracturing
treatment 10. In this embodiment, the model would include
geomechanics effect and may also indicate whether the affected
volume by the fracture treatment 10 has been closing or has already
closed.
[0053] FIGS. 4A-B illustrate exemplary inputs and outputs of the
fracture simulator 47. In particular, FIG. 4A illustrates a
microseismic map 200 from a fracture treatment 10. FIG. 4B
illustrates an exemplary fracture model 250 display generated by
the fracture simulator 47 for a planned fracture treatment 10. The
fracture simulator 47 may comprise other or different suitable
inputs and outputs.
[0054] Referring to FIG. 4A, the microseismic map 200 comprises
measured data. In one embodiment, the microseismic map 200
comprises a number of points 202 where the rock slipped in
formation 14 during the fracture treatment 10. As previously
described, the slips may be recorded as pops or snaps during the
fracture treatment 10. The points 202 may be just inside the
natural fractures 82 and/or induced fractures 84. The microseismic
map 200 may include plotted natural fractures 82 and induced
fractures 84. The microseismic map 200 may be two-dimensional and
indicate location within the field. In another embodiment, the
microseismic map 200 may be three-dimensional indicating rock slips
202, natural fractures 82 and induced fractures 84 at different
depths of the formation 14. An observation well 204 from which the
data was recorded may also be recorded on the microseismic map
200.
[0055] Referring to FIG. 4B, the fracture model display 250 may
indicate the fracture volume 86 for a planned fracture treatment 10
having a certain job design. Storativity and transmissibility of
the fracture 60 in the fracture volume 86 may be indicated (not
shown) as well as the job design data (not shown). In addition,
distribution of natural and induced fractures 82 and 84 may also be
indicated as well as the location of the well 12. The fracture
model display 250 may comprise a two-dimensional or
three-dimensional display. In the three-dimensional embodiment, the
fracture model display 250 may display variations in fracture
distribution and/or transmissibility or storativity by depth of the
formation 14. The fracture model 250 may be otherwise suitably
displayed to the operator in textural, other graphical and/or other
forms.
[0056] FIG. 5 illustrates one embodiment of a method for
development of a naturally fractured formation using fracture
simulation, analysis and reservoir response forecasting. In this
embodiment, the fracture simulator 47 determines an enhanced or
optimized fracture design for one or more wells 12 in the formation
14. Other suitable data and/or simulators may be used without
departing from the scope of the invention.
[0057] Referring to FIG. 5, the method begins at step 300 in which
data is collected and processed. In one embodiment, the data
includes the geomechanical data 170, formation properties 172,
microseismic data 174, and production data 176. The data may be
determined from previous wells 12 in the formation 14 and/or other
suitable sources.
[0058] Proceeding to step 302, fracture job properties are defined.
Fracture job properties may be defined in the job design data 178
of fracture simulator 47. The fracture job properties may comprise
a specific design, a set of specific designs and/or one or more
specific designs with predefined variations for iterative testing
and/or optimization of treatment design. Fracture job properties
may be otherwise suitably defined.
[0059] At step 304, a fracture geometry model may be generated. The
fracture geometry model may be generated by the fracture geometry
simulator 152 and comprise a fracture volume 86 for a fracture
treatment 10. The fracture geometry model may also comprise the
distribution of natural fractures 82 and induced fractures 84.
[0060] Next, at step 306, a fracture property model may be
generated for the fracture geometry model. The fracture property
model may be generated by the fracture property simulator 154. The
fracture property model may comprise the storativity and
transmissibility of the formation 14 in the fracture volume 86. As
previously described, the fracture geometry model and fracture
property model may together comprise a fracture model. The fracture
model may be displayed to the operator as fracture model display
250 or otherwise. In another embodiment, fracture model may not be
displayed or available to the operator. Similarly, the fracture
geometry model and fracture property model may or may not be
displayed to the operator.
[0061] At step 308, a production model is generated. The production
model may be generated by the production simulator 156. The
production model may provide estimated oil, gas and/or water
production curves for the well 12 in response to the planned
fracture treatment 10. The production model may be displayed to the
operator in graphical or textual form. In another embodiment, the
production model may not be displayed to the operator.
[0062] At step 310, an economic model may be generated for the well
12 based on the production model. The economic model may be
generated by the economic simulator 158. The economic model may
provide the net present value or other indication of value to be
obtained from the well 12 based on estimated production following
the planned fracture treatment 10. The economic model may also
indicate cost of the well 12 including cost of the fracture
treatment 10 and/or provide a net gain or loss obtained from the
well 12 in response to the fracture treatment 10.
[0063] Proceeding to decisional step 312, it is determined if the
design of the fracture treatment 10 is complete. Design of the
fracture treatment 10 may be complete when the fracture treatment
10 is optimized economically or otherwise or exceeds an economical
or other threshold. If design of the fracture treatment 10 is not
complete, the No branch of decisional step 312 returns to step 302
where fracture job properties are redefined or otherwise varied.
After the fracture treatment 10 has been optimized or the fracture
treatment 10 has been selected by an operator, the Yes branch of
decisional step 312 leads to step 314, in which the fracture
treatment 10 may be executed based on the optimized or selected
design.
[0064] Next, at step 314, data may be collected during the fracture
treatment 10 and used to calibrate or update the fracture simulator
47. In addition, production and other data may be measured over the
life of the well 12 and used to update the fracture simulator 47.
During drilling and production of additional wells 12, well spacing
may be determined based on the optimized or otherwise selected
fracture treatment 10 design.
[0065] FIG. 6 illustrates exemplary development of a field 350
using fracture treatments 10. Referring to FIG. 6, the field 350
includes a plurality of wells 12 each having a fracture 60. The
fractures 60 include natural fractures 82 and induced fractures 84.
The induced fractures 84 are perpendicular to natural fractures 82
and formed by the fracture treatment 10. The natural fractures 82
and induced fractures 84 together form the fracture volume 86.
[0066] The wells 12 may be optimally spaced to allow completion of
the field 350 at the least cost and/or greatest revenue. For
example, the necessary number of wells 12 and corresponding size of
the fracture values 86 for the wells may be determined to produce
the field 350 at minimum cost and/or greatest net revenues. Well
spacing 12 may deviate in one or more parts of the field based on
topology of the field 350 and/or other considerations.
[0067] Although this disclosure has been described in terms of
certain embodiments and generally associated methods, alterations
and permutations of these embodiments and methods will be apparent
to those skilled in the art. Accordingly, the above description of
example embodiments does not define or constrain this disclosure.
Other changes, substitutions, and alterations are also possible
without departing from the spirit and scope of this disclosure.
* * * * *