Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM AND METHOD FOR PERFORMING OILFIELD
SIMULATION OPERATIONS
BACKGROUND OF THE INVENTION
Field of the Invention
100011 The present invention relates to techniques for performing
oilfield
operations relating to subterranean formations having reservoirs therein.
More particularly, the invention relates to techniques for performing oilfield
operations involving an analysis of reservoir operations, and their impact on
such oilfield operations.
Background of the Related Art
[0002] Oilfield operations, such as surveying, drilling, wireline
testing,
completions, simulation, planning and oilfield analysis, are typically
performed to locate and gather valuable downhole fluids. Various aspects of
the oilfield and its related operations are shown in FIGS. 1A-1D. As shown
in FIG. 1A, surveys are often performed using acquisition methodologies,
such as seismic scanners to generate maps of underground structures. These
structures are often analyzed to determine the presence of subterranean
assets,
such as valuable fluids or minerals. This information is used to assess the
underground structures and locate the formations containing the desired
subterranean assets. Data collected from the acquisition methodologies may
be evaluated and analyzed to determine whether such valuable items are
present, and if they are reasonably accessible.
[00031 As shown in FIG. 1B-1D, one or more wellsites may be positioned
along the underground structures to gather valuable fluids from the
subterranean reservoirs. The wellsites are provided with tools capable of
locating and removing hydrocarbons from the subterranean reservoirs. As
shown in FIG. 1B, drilling tools are typically advanced from the oil rigs and
into the earth along a given path to locate the valuable downhole fluids.
During the drilling operation, the drilling tool may perform downhole
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measurements to investigate downhole conditions. In some cases, as shown
in FIG. 1C, the drilling tool is removed and a wireline tool is deployed into
the wellbore to perform additional downhole testing.
[0004] After the drilling operation is complete, the well may then be
prepared
for production. As shown in FIG. ID, wellbore completions equipment is
deployed into the wellbore to complete the well in preparation for the
production of fluid therethrough. Fluid is then drawn from downhole
reservoirs, into the wellbore and flows to the surface. Production facilities
are
positioned at surface locations to collect the hydrocarbons from the
wellsite(s). Fluid drawn from the subterranean reservoir(s) passes to the
production facilities via transport mechanisms, such as tubing. Various
equipment may be positioned about the oilfield to monitor oilfield parameters
and/or to manipulate the oilfield operations.
10005] During the oilfield operations, data is typically collected for
analysis
and/or monitoring of the oilfield operations. Such data may include, for
example, subterranean formation, equipment, historical and/or other data.
Data concerning the subterranean formation is collected using a variety of
sources. Such formation data may be static or dynamic. Static data relates to,
for example, formation structure and geological stratigraphy that define the
geological structure of the subterranean formation. Dynamic data relates to,
for example, fluids flowing through the geologic structures of the
subterranean formation over time. Such static and/or dynamic data may be
collected to learn more about the formations and the valuable assets contained
therein.
[0006] Sources used to collect static data may be seismic tools, such as
a
seismic truck that sends compression waves into the earth as shown in FIG.
1A. These waves are measured to characterize changes in the density of the
geological structure at different depths. This information may be used to
generate basic structural maps of the subterranean formation. Other static
measurements may be gathered using core sampling and well logging
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techniques. Core samples may be used to take physical specimens of the
formation at various depths as shown in FIG. 1B. Well logging typically
involves deployment of a downhole tool into the wellbore to collect various
downhole measurements, such as density, resistivity, etc., at various depths.
Such well logging may be performed using, for example, the drilling tool of
FIG. 1B and/or the wireline tool of FIG. 1C. Once the well is formed and
completed, fluid flows to the surface using production tubing as shown in
FIG. 1D. As fluid passes to the surface, various dynamic measurements, such
as fluid flow rates, pressure, and composition may be monitored. These
parameters may be used to determine various characteristics of the
subterranean formation.
[0007] Sensors may be positioned about the oilfield to collect data
relating to
various oilfield operations. For example, sensors in the drilling equipment
may monitor drilling conditions, sensors in the wellbore may monitor fluid
composition, sensors located along the flow path may monitor flow rates, and
sensors at the processing facility may monitor fluids collected. Other sensors
may be provided to monitor downhole, surface, equipment or other
conditions. The monitored data is often used to make decisions at various
locations of the oilfield at various times. Data collected by these sensors
may
be further analyzed and processed. Data may be collected and used for
current or future operations. When used for future operations at the same or
other locations, such data may sometimes be referred to as historical data.
10008] The processed data may be used to predict downhole conditions, and
make decisions concerning oilfield operations. Such decisions may involve
well planning, well targeting, well completions, operating levels, production
rates and other operations and/or conditions. Often this information is used
to
determine when to drill new wells, re-complete existing wells, or alter
wellbore production.
10009] Data from one or more wellbores may be analyzed to plan or predict
various outcomes at a given wellbore. In some cases, the data from
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neighboring wellb ores or wellbores with similar conditions or equipment may
be used to predict how a well will perform. There are usually a large number
of variables and large quantities of data to consider in analyzing oilfield
operations. It is, therefore, often useful to model the behavior of the
oilfield
operation to determine the desired course of action. During the ongoing
operations, the operating conditions may need adjustment as conditions
change and new information is received.
[0010]
Techniques have been developed to model the behavior of various
aspects of the oilfield operations, such as geological structures, downhole
reservoirs, wellbores, surface facilities as well as other portions of the
oilfield
operation. For example, US6980940 to Gurpinar discloses integrated
reservoir optimization involving the assimilation of diverse data to optimize
overall performance of a reservoir. In another example, W02004/049216 to
Ghorayeb discloses an integrated modeling solution for coupling multiple
reservoir simulations and surface facility networks. Other examples of these
modeling techniques are shown in Patent/Publication/Application Nos.
US5992519, W01999/064896, W02005/122001,
US6313837,
US2003/0216897, US2003/0132934, US2005/0149307, US2006/0197759,
US2004/0220846, and 10/586,283.
[0011]
Techniques have also been developed to predict and/or plan certain
oilfield operations, such as miscible water alternating gas (MWAG) injection
operation. In
an oilfield, initial production of the hydrocarbons is
accomplished by "primary recovery" techniques wherein only the natural
forces present in the reservoir are used to produce the hydrocarbons.
However, upon depletion of these natural forces and the termination of
primary recovery, large portions of the hydrocarbons remain trapped within
the reservoir. Also many reservoirs lack sufficient natural forces to be
produced by primary methods from the very beginning.
[0012]
Recognition of these facts has led to the development and use of many
enhanced oil recovery (EOR) techniques. Most of these techniques involve
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injection of at least one fluid into the reservoir to force hydrocarbons
towards
and into a production well. It is important that the fluid be injected
carefully
so that it forces the hydrocarbons toward the production well but does not
prematurely reach the production well before all or most of the hydrocarbons
have been produced.
100131 Generally, once the fluid reaches the production well, production
is
adversely affected as the injected fluids are not generally sellable products
and in some cases can be difficult to separate from the produced oil. Over the
years, many have attempted to calculate the optimal pumping rates for
injector wells and production wells to extract the most hydrocarbons from a
reservoir. There is considerable uncertainty in a reservoir as to its geometry
and geological parameters (e.g., porosity, rock permeabilities, etc.). In
addition, the market value of hydrocarbons can vary dramatically and so
financial factors may be important in determining how production should
proceed to obtain the maximum value from the reservoir. Examples of
techniques for modeling and/or planning MWAG injection operation are
provided in Patent No. US6775578.
100141 Techniques have also been developed for performing reservoir
simulation operations. See, for example, Patent/Publication/Application Nos.
US6230101, US6018497, US6078869, GB2336008, US6106561,
US2006/0184329, US7164990. Some simulation techniques involve the use
of coupled simulations as described, for example, in Publication No.
US2006/0129366.
100151 Despite the development and advancement of reservoir simulation
techniques in oilfield operations, there remains a need to provide techniques
capable of modeling and implementing injection operations based on a
complex analysis of a wide variety of parameters affecting oilfield
operations.
It is desirable that such a complex analysis of oilfield parameters gathered
throughout the oilfield and their impact on the injection operation be
performed as thru-time analysis. It is further desirable that such techniques
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for modeling oilfield MWAG injection operations be capable of one of more
of the following, among others: selectively modeling oilfield MWAG
injection operations based on more than one simulator; selectively merging
data and/or outputs of more than one simulator; selectively merging data
and/or outputs of simulators of one or more wellsites and/or oilfields;
selectively linking a wide variety of simulators of like and/or different
configurations; selectively linking simulators having similar and/or different
applications and/or data models; selectively linking simulators of different
members of an asset team of an oilfield; and providing coupling mechanisms
capable of selectively linking simulators in a desired configuration.
SUMMARY OF THE INVENTION
[0016] In general, in one aspect, the invention relates to a method of
simulating
operations of an oilfield, which has process facilities and wellsite
operatively
connected, each wellsite having a wellbore penetrating a subterranean
formation for extracting fluid from an underground reservoir. The method
steps include selecting simulators for modeling the oilfield with at least one
of
the simulators having functionality to model fluid injection, selectively
coupling each of the simulators according to a predefined configuration, and
modeling an injection operation of the oilfield by selectively communicating
between the simulators.
[0017] In general, in one aspect, the invention relates to a method of
simulating
operations of an oilfield, which has process facilities and wellsite
operatively
connected, each vvellsite having a wellbore penetrating a subterranean
formation for extracting fluid from an underground reservoir. The method
steps include selecting simulators for modeling the oilfield with at least one
of
the simulators having functionality to perform thin-time dynamic modeling of
an injection operation, selectively coupling each of the simulators according
to a predefined configuration, and performing the thin-time dynamic
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modeling of the injection operation of the oilfield by selectively
communicating between the
simulators.
[0018] In general, in one aspect, the invention relates to a computer
readable medium
having computer executable instructions stored thereon for execution by a
computer that when
executed implement a method for modeling a fluid injection operation of an
oilfield having a
subterranean formation with at least one reservoir positioned therein, the
method comprising:
selecting a plurality of simulators, each simulator modeling at least a
portion of the oilfield, at
least one of the plurality of simulators having functionality to model fluid
injection;
selectively coupling each of the plurality of simulators according to a
predefined
configuration; and modeling injection operation of the oilfield by selectively
communicating
between the plurality of simulators.
[0019] In general, in one aspect, the invention relates to a computer
readable medium
having computer executable instructions stored thereon for execution by a
computer that when
executed implement a method for thru-time dynamic modeling of an oilfield
having a
subterranean formation with at least one reservoir positioned therein, the
method comprising:
selecting a plurality of simulators, each simulator modeling at least a
portion of the oilfield, at
least one simulator having functionality to perform thru-time dynamic modeling
of fluid
injection; selectively coupling each of the plurality of simulators according
to a predefined
configuration; and performing thru-time dynamic modeling of the fluid
injection of the
oilfield by selectively communicating between the plurality of simulators.
10019a] In general, in another aspect, the invention relates to a
method of simulating
operations of an oilfield having at least one wellsite, each wellsite having a
wellbore
penetrating a subterranean formation for extracting fluid from or injecting
fluid to an
underground reservoir therein, the method comprising: selecting a plurality of
wellsite
simulators comprising a wellbore simulator, a surface network simulator, a
first reservoir
simulator having a full reservoir simulation model, a second reservoir
simulator having a tank
model proxy of the full reservoir simulation model, and a third reservoir
having a lookup table
proxy of the full reservoir simulation model; selecting a plurality of non-
wellsite simulators
comprising a process simulator and an economic simulator; establishing a fast
productivity
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index (PI) coupling between the wellbore simulator and a reservoir simulator
selected from a
group consisting of the first reservoir simulator, the second reservoir
simulator, and the third
reservoir simulator to impose a hydraulic response between the plurality of
wellsite
simulators; establishing a plurality of general node couplings between the
process simulator,
the economics simulator, and the surface network simulator; and modeling a
fluid injection by
selectively communicating between the plurality of non-wellsite simulators
using at least the
plurality of general node couplings and by: querying, using the fast PI
coupling, the reservoir
simulator for a well linear inflow performance relationship (IPR) curve at a
current operating
point; passing, using the fast PI coupling, the well linear IPR curve as a
boundary condition to
the network simulator to calculate a network pressure and a flow rate; and
setting, using the
fast PI coupling, the flow rate calculated by the network simulator in the
reservoir simulator.
10019b] In general, in another aspect, the invention relates to a
method of simulating
operations of an oilfield having at least one wellsite, each wellsite having a
wellbore
penetrating a subterranean formation for extracting fluid from or injecting
fluid to an
underground reservoir therein, the method comprising: selecting a plurality of
wells ite
simulators comprising a wellbore simulator, a surface network simulator, a
first reservoir
simulator having a full reservoir simulation model, a second reservoir
simulator having a tank
model proxy of the full reservoir simulation model, and a third reservoir
simulator having a
lookup table proxy of the full reservoir simulation model, wherein the
plurality of wellsite
simulators have functionality to perform a thru-time dynamic modeling of an
injection
operation comprising at least one selected from a group consisting of a
Miscible Water
Alternating Gas (MWAG) injection, a Thermal Heavy Oil Production with steam
injection,
and a Cold Heavy Oil Production with Sand (CHOPS) with steam injection;
selecting a
plurality of non-wellsite simulators comprising a process simulator and an
economic
simulator; establishing a fast productivity index (PI) coupling between the
wellbore simulator
and a reservoir simulator selected from a group consisting of the first
reservoir simulator, the
second reservoir simulator, and the third reservoir simulator to impose a
hydraulic response
between the plurality of wellsite simulators; establishing a plurality of
general node couplings
between the process simulator, the economics simulator, and the surface
network simulator;
and performing the thru-time dynamic modeling of the injection operation of
the oilfield by
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selectively communicating between the plurality of non-wellsite simulators
using at least the
plurality of general node couplings and by: querying, using the fast PI
coupling, the reservoir
simulator for a well linear inflow performance relationship (IPR) curve at a
current operating
point; passing, using the fast PI coupling, the well linear IPR curve as a
boundary condition to
the network simulator to calculate a network pressure and a flow rate; and
setting, using the
fast PI coupling, the flow rate calculated by the network simulator in the
reservoir simulator.
[0019c] In general, in another aspect, the invention relates to a
computer readable
medium having computer executable instructions stored thereon for execution by
a computer
that when executed implement a method for modeling a fluid injection operation
of an oilfield
having a subterranean formation with at least one reservoir positioned
therein, the method
comprising: selecting a plurality of wellsite simulators comprising a wellbore
simulator, a
surface network simulator, a first reservoir simulator having a full reservoir
simulation model,
a second reservoir simulator having a tank model proxy of the full reservoir
simulation model,
and a third reservoir having a lookup table proxy of the full reservoir
simulation model;
selecting a plurality of non-wellsite simulators comprising a process
simulator and an
economic simulator; establishing a fast productivity index (PI) coupling
between the wellbore
simulator and a reservoir simulator selected from a group consisting of the
first reservoir
simulator, the second reservoir simulator, and the third reservoir simulator
to impose a
hydraulic response between the plurality of wellsite simulators; establishing
a plurality of
general node couplings between the process simulator, the economics simulator,
and the
surface network simulator; and modeling a fluid injection operation of the
oilfield by
selectively communicating between the plurality of non-wellsite simulators
using at least the
plurality of general node couplings and by: querying, using the fast PI
coupling, the reservoir
simulator for a well linear inflow performance relationship (IPR) curve at a
current operating
point; passing, using the fast PI coupling, the well linear IPR curve as a
boundary condition to
the network simulator to calculate a network pressure and a flow rate; and
setting, using the
fast PI coupling, the flow rate calculated by the network simulator in the
reservoir simulator.
[0019d] In general, in another aspect, the invention relates to a
computer readable
medium having computer executable instructions stored thereon for execution by
a computer
that when executed implement a method for thru-time dynamic modeling of an
oilfield having
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a subterranean formation with at least one reservoir positioned therein, the
method
comprising: selecting a plurality of wellsite simulators comprising a wellbore
simulator, a
surface network simulator, a first reservoir simulator having a full reservoir
simulation model,
a second reservoir simulator having a tank model proxy of the full reservoir
simulation model,
and a third reservoir simulator having a lookup table proxy of the full
reservoir simulation
model, wherein the plurality of wellsite simulators have functionality to
perform a fiuu-time
dynamic modeling of an injection operation comprising at least one selected
from a group
consisting of Miscible Water Alternating Gas (MWAG) injection, Thermal Heavy
Oil
Production with steam injection, and Cold Heavy Oil Production with Sand
(CHOPS) with
steam injection; selecting a plurality of non-wellsite simulators comprising a
process
simulator and an economic simulator; establishing a fast productivity index
(PI) coupling
between the wellbore simulator and a reservoir simulator selected from a group
consisting of
the first reservoir simulator, the second reservoir simulator, and the third
reservoir simulator
to impose a hydraulic response between the plurality of wellsite simulators;
establishing a
plurality of general node couplings between the process simulator, the
economics simulator,
and the surface network simulator; and performing the tluu-time dynamic
modeling of the
injection operation by selectively communicating between the plurality of non-
wellsite
simulators using at least the plurality of general node couplings and by:
querying, using the
fast PI coupling, the reservoir simulator for a well linear inflow performance
relationship
(IPR) curve at a current operating point; passing, using the fast PI coupling,
the well linear
IPR curve as a boundary condition to the network simulator to calculate a
network pressure
and a flow rate; and setting, using the fast PI coupling, the flow rate
calculated by the network
simulator in the reservoir simulator.
100201 Other aspects and advantages of the invention will be apparent
from the
following description and the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
100211 So that the above recited features and advantages of the
present invention can
be understood in detail, a more particular description of the
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invention, briefly summarized above, may be had by reference to the
embodiments thereof that are illustrated in the appended drawings. It is to be
noted, however, that the appended drawings illustrate only typical
embodiments of this invention and are therefore not to be considered limiting
of its scope, for the invention may admit to other equally effective
embodiments.
[0022] FIGS. 1A-1D show exemplary schematic views of an oilfield having
subterranean structures including reservoirs therein and various oilfield
operations being performed on the oilfield. FIG. lA depicts an exemplary
survey operation being performed by a seismic truck. FIG. 1B depicts an
exemplary drilling operation being performed by a drilling tool suspended by
a rig and advanced into the subterranean formation. FIG. 1C depicts an
exemplary wireline operation being performed by a wireline tool suspended
by the rig and into the wellbore of FIG. 1B. FIG. 1D depicts an exemplary
simulation operation being performed by a simulation tool being deployed
from the rig and into a completed wellbore for drawing fluid from the
downhole reservoir into a surface facility.
100231 FIGs. 2A-2D are exemplary graphical depictions of data collected by
the
tools of FIGS. 1A-1D, respectively. FIG. 2A depicts an exemplary seismic
trace of the subterranean formation of FIG. 1A. FIG. 2B depicts exemplary
core sample of the formation shown in FIG. 1B. FIG. 2C depicts an
exemplary well log of the subterranean formation of FIG. IC. FIG. 2D
depicts an exemplary simulation decline curve of fluid flowing through the
subterranean formation of FIG. 1D.
100241 FIG. 3 shows an exemplary schematic view, partially in cross
section, of
an oilfield having a plurality of data acquisition tools positioned at various
locations along the oilfield for collecting data from the subterranean
formation.
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[0025] FIG. 4 shows an exemplary schematic view of an oilfield having a
plurality of wellsites for producing hydrocarbons from the subterranean
formation.
[0026] FIG. 5 shows an exemplary schematic diagram of a portion of the
oilfield of FIG. 4 depicting the simulation operation in detail.
[0027] FIG. 6 is a schematic view of an oilfield simulator for the
oilfield of
FIG. 4, the oilfield simulator having wellsite and non-wellsite simulators
selectively coupled together to perform an oilfield simulation.
[0028] FIG.s 7A and 7B are graphs depicting rate-based coupling that may
be
used in the oilfield simulator of FIG. 6. FIG. 7A depicts an unconstrained
rate-based coupling. FIG. 7B depicts a reservoir constrained rate-based
coupling.
[0029] FIG. 8 is a graph depicting a fast PI coupling that may be used in
the
oilfield simulator of FIG. 6.
[0030] Figures 9A, 9B, and 9C are graphs depicting a chord slope coupling
that
may be used in the oilfield simulator of FIG. 6. FIG. 9A depicts a network
constrained well. FIG. 9B depicts a reservoir constrained well. FIG. 9C
depicts a reservoir with reduced pressure.
[0031] FIG. 10 is a flowchart depicting a method of producing fluid from
of the
oilfield of Figure 1.
DETAILED DESCRIPTION OF THE INVENTION
[0032] Presently preferred embodiments of the invention are shown in the
above-identified figures and described in detail below. In describing the
preferred embodiments, like or identical reference numerals are used to
identify common or similar elements. The figures are not necessarily to scale
and certain features and certain views of the figures may be shown
exaggerated in scale or in schematic in the interest of clarity and
conciseness.
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[0033] FIGS. IA-D show an oilfield (100) having geological structures
and/or
subterranean formations therein. As shown in these figures, various
measurements of the subterranean formation are taken by different tools at the
same location. These measurements may be used to generate information
about the formation and/or the geological structures and/or fluids contained
therein.
100341 FIGS. 1A-1D depict schematic views of an oilfield (100) having
subterranean formations (102) containing a reservoir (104) therein and
depicting various oilfield operations being performed on the oilfield
(100). FIG. lA depicts a survey operation being performed by a seismic truck
(106a) to measure properties of the subterranean formation. The survey
operation is a seismic survey operation for producing sound vibration(s)
(112). In FIG. 1A, one such sound vibration (112) is generated by a source
(110) and reflects off a plurality of horizons (114) in an earth formation
(116).
The sound vibration(s) (112) is (are) received in by sensors (5), such as
geophone-receivers (118), situated on the earth's surface, and the geophone-
receivers (118) produce electrical output signals, referred to as data
received
(120) in FIG. 1.
[00351 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 data received (120) is provided as input data to a
computer (122a) of the seismic recording truck (106a), and responsive to the
input data, the recording truck computer (122a) generates a seismic data
output record (124). The seismic data may be further processed as desired,
for example by data reduction.
[0036] FIG. 1B depicts a drilling operation being performed by a drilling
tool
(106b) suspended by a rig (128) and advanced into the subterranean formation
(102) to form a wellbore (136). A mud pit (130) is used to draw drilling mud
into the drilling tool (106b) via flow line (132) for circulating drilling mud
through the drilling tool (106b) and back to the surface. The drilling tool
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(106b) is advanced into the formation to reach reservoir (104). The drilling
tool (106b) is preferably adapted for measuring downhole properties. The
drilling tool (106b) may also be adapted for taking a core sample (133) as
shown, or removed so that a core sample (133) may be taken using another
tool.
100371 A surface unit (134) is used to communicate with the drilling tool
(106b)
and offsite operations. The surface unit (134) is capable of communicating
with the drilling tool (106b) to send commands to drive the drilling tool
(106b), and to receive data therefrom. The surface unit (134) is preferably
provided with computer facilities for receiving, storing, processing, and
analyzing data from the oilfield (100). The surface unit (134) collects data
output (135) generated during the drilling operation. Computer facilities,
such as those of the surface unit (134), may be positioned at various
locations
about the oilfield (100) and/or at remote locations.
100381 Sensors (S), such as gauges, may be positioned throughout the
reservoir,
rig, oilfield equipment (such as the downhole tool), or other portions of the
oilfield for gathering information about various parameters, such as surface
parameters, downhole parameters, and/or operating conditions. These sensors
(5) preferably measure oilfield parameters, such as weight on bit, torque on
bit, pressures, temperatures, flow rates, compositions and other parameters of
the oilfield operation.
[0039] The information gathered by the sensors (S) 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 (S) may be used alone or in
combination with other data. The data may be collected in a database and all
or select portions of the data may be selectively used for analyzing and/or
predicting oilfield operations of the current and/or other wellbores.
100401 Data outputs from the various sensors (S) positioned about the
oilfield
may be processed for use. The data may be historical data, real time data, or
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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 housed in separate databases, or
combined into a single database.
[0041] 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, reservoir engineering, and/or production
simulations. The reservoir, wellbore, surface and/or process data may be used
to perform reservoir, wellbore, or other production simulations. The data
outputs from the oilfield operation may be generated directly from the sensors
(S), or after some preprocessing or modeling. These data outputs may act as
inputs for further analysis.
[0042] The data is collected and stored at the surface unit (134). One or
more
surface units (134) may be located at the oilfield (100), or linked 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 (100). The surface unit (134) may be a manual or automatic
system. The surface unit (134) may be operated and/or adjusted by a user.
[0043] The surface unit (134) may be provided with a transceiver (137) to
allow
communications between the surface unit (134) and various portions (or
regions) of the oilfield (100) or other locations. The surface unit (134) may
also be provided with or functionally linked to a controller for actuating
mechanisms at the oilfield (100). The surface unit (134) may then send
command signals to the oilfield (100) 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) and make the decisions to actuate the
controller. In this manner, the oilfield (100) may be selectively adjusted
based on the data collected to optimize fluid recovery rates, or to maximize
the longevity of the reservoir and its ultimate production capacity. These
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adjustments may be made automatically based on computer protocol, or
manually by an operator. In some cases, well plans may be adjusted to select
optimum operating conditions, or to avoid problems.
[0044] FIG. 1C depicts a wireline operation being performed by a wireline
tool
(106c) suspended by the rig (128) and into the wellbore (136) of FIG.
1B. The wireline tool (106c) is preferably adapted for deployment into a
wellbore (136) for performing well logs, performing downhole tests and/or
collecting samples. The wireline tool (106c) may be used to provide another
method and apparatus for performing a seismic survey operation. The
wireline tool (106c) of FIG. 1C may have an explosive or acoustic energy
source (143) that provides electrical signals to the surrounding subterranean
formations (102).
[0045] The wireline tool (106c) may be operatively linked to, for example,
the
geophones (118) stored in the computer (122a) of the seismic recording truck
(106a) of FIG. 1A. The wireline tool (106c) may also provide data to the
surface unit (134). As shown data output (135) is generated by the wireline
tool (106c) and collected at the surface. The wireline tool (106c) may be
positioned at various depths in the wellbore (136) to provide a survey of the
subterranean formation.
[0046] FIG. 1D depicts a production operation being performed by a
production
tool (106d) 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 the surface facilities (142). Fluid flows from reservoir (104)
through perforations in the casing (not shown) and into the production tool
(106d) in the wellbore (136) and to the surface facilities (142) via a
gathering
network (146).
[0047] Sensors (S), such as gauges, may be positioned about the oilfield
to
collect data relating to various oilfield operations as described previously.
As
shown, the sensor (S) may be positioned in the production tool (106d) or
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associated equipment, such as the christmas tree, 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.
100481 While only simplified wellsite configurations are shown, it will be
appreciated that the oilfield 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. 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).
100491 While FIGS. 1B-1D depict tools used to measure properties of an
oilfield (100), it will be appreciated that the tools may be used in
connection
with non-oilfield operations, such as mines, aquifers, storage or other
subterranean facilities. Also, while certain data acquisition tools are
depicted,
it will be appreciated that various measurement tools capable of sensing
parameters, such as seismic two-way travel time, density, resistivity,
production rate, etc., of the subterranean 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.
[00501 The oilfield configuration in FIGS. 1A-1D are intended to provide a
brief description of an example of an oilfield usable with the present
invention. Part, or all, of the oilfield (100) may be on land and/or sea.
Also,
while a single oilfield measured at a single location is depicted, the present
invention may be utilized with any combination of one or more oilfields
(100), one or more processing facilities and one or more wellsites.
[0051] FIGS. 2A-2D are graphical depictions of data collected by the tools
of
FIGS. 1A-D, respectively. FIG. 2A depicts a seismic trace (202) of the
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subterranean formation of FIG. 1A taken by survey tool (106a). The seismic
trace measures a two-way response over a period of time. FIG. 2B depicts a
core sample (133) taken by the drilling tool (106b). The core test typically
provides a graph of the density, resistivity, or other physical property of
the
core sample (133) over the length of the core. Tests for density and viscosity
are often performed on the fluids in the core at varying pressures and
temperatures. FIG. 2C depicts a well log (204) of the subterranean formation
of FIG. 1C taken by the wireline tool (106c). The wireline log typically
provides a resistivity measurement of the formation at various depths. FIG.
2D depicts a production decline curve (206) of fluid flowing through the
subterranean formation of FIG. 1D taken by the production tool (106d). The
production decline curve (206) typically provides the production rate Q as a
function of time t.
[00521 The respective graphs of FIGS. 2A-2C contain static measurements
that
describe the physical characteristics of the formation. These measurements
may be compared to determine the accuracy of the measurements and/or for
checking for errors. In this manner, the plots of each of the respective
measurements may be aligned and sealed for comparison and verification of
the properties.
[00531 FIG. 2D provides 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 used
to generate models of the subterranean formation to determine characteristics
thereof.
[0054] FIG. 3 is a schematic view, partially in cross section of an
oilfield (300)
having data acquisition tools (302a), (302b), (302c), and (302d) positioned at
various locations along the oilfield for collecting data of a subterranean
formation (304). The data acquisition tools (302a-302d) may be the same as
data acquisition tools (106a-106d) of FIG. 1, respectively. As shown, the data
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acquisition tools (302a-302d) generate data plots or measurements (308a-
308d), respectively.
[0055] Data plots (308a-308c) are examples of static data plots that may
be
generated by the data acquisition tools (302a-302d), respectively. Static data
plot (308a) is a seismic two-way response time and may be the same as the
seismic trace (202) of FIG. 2A. Static plot (308b) is core sample data
measured from a core sample of the formation (304), similar to the core
sample (133) of FIG. 2B. Static data plot (308c) is a logging trace, similar
to
the well log (204) of FIG. 2C. Data plot (308d) is a dynamic data plot of the
fluid flow rate over time, similar to the graph (206) of FIG. 2D. Other data
may also be collected, such as historical data, user inputs, economic
information, other measurement data, and other parameters of interest.
10056j The subterranean formation (304) has a plurality of geological
structures
(306a-306d). As shown, the formation has a sandstone layer (306a), a
limestone layer (306b), a shale layer (306c), and a sand layer (306d). A fault
line (307) extends through the formation. The static data acquisition tools
are
preferably adapted to measure the formation and detect the characteristics of
the geological structures of the formation.
100571 While a specific subterranean formation (304) with specific
geological
structures are depicted, it will be appreciated that the formation may contain
a
variety of geological structures. Fluid may also be present in various
portions
of the formation. Each of the measurement devices may be used to measure
properties of the formation and/or its underlying structures. While each
acquisition tool is shown as being in specific locations along the formation,
it
will be appreciated that one or more types of measurement may be taken at
one or more location across one or more oilfields or other locations for
comparison and/or analysis.
[0058] The data collected from various sources, such as the data
acquisition
tools of FIG. 3, may then be evaluated. Typically, seismic data displayed in
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the static data plot (308a) from the data acquisition tool (302a) is used by a
geophysicist to determine characteristics of the subterranean formation
(304). Core data shown in static plot (308b) and/or log data from the well log
(308c) is typically used by a geologist to determine various characteristics
of
the geological structures of the subterranean formation (304). Production data
from the production graph (308d) is typically used by the reservoir engineer
to determine fluid flow reservoir characteristics.
[00591 FIG. 4 shows an oilfield (400) for performing simulation
operations. As
shown, the oilfield has a plurality of wellsites (402) operatively connected
to
a central processing facility (454). The oilfield configuration of FIG. 4 is
not
intended to limit the scope of the invention. Part or all of the oilfield may
be
on land and/or sea. Also, while a single oilfield with a single processing
facility and a plurality of wellsites is depicted, any combination of one or
more oilfields, one or more processing facilities and one or more wellsites
may be present.
10060] Each wellsite (402) has equipment that forms a wellbore (436) into
the
earth. The wellb ores extend through subterranean formations (406) including
reservoirs (404). These reservoirs (404) contain fluids, such as
hydrocarbons. The wellsites draw fluid from the reservoirs and pass them to
the processing facilities via surface networks (444). The surface networks
(444) have tubing and control mechanisms for controlling the flow of fluids
from the wellsite to the processing facility (454).
100611 FIG. 5 shows a schematic view of a portion (or region) of the
oilfield
(400) of FIG. 4, depicting a producing wellsite (402) and surface network
(444) in detail. The wellsite (402) of FIG. 5 has a wellbore (436) extending
into the earth therebelow. In addition, FIG. 5 shows an injection wellsite
(502) having an injection wellbore (506). As shown, the wellbores (436) and
(506) has already been drilled, completed, and prepared for production from
reservoir (404).
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100621 Wellbore production equipment (564) extends from a wellhead (566)
of
wellsite (402) and to the reservoir (404) to draw fluid to the surface. The
wellsite (402) is operatively connected to the surface network (444) via a
transport line (561). Fluid flows from the reservoir (404), through the
wellbore (436), and onto the surface network (444). The fluid then flows
from the surface network (444) to the process facilities (454).
[0063] As described above, fluid may be injected through an injection
wellbore,
such as the wellbore (506) to gain additional amounts of hydrocarbon. Fluid
may be injected to sweep hydrocarbons to producing wells and/or to maintain
reservoir pressure by balancing extracted hydrocarbons with injected fluid.
The wellbore (506) may be a new well drilled specifically to serve as an
injection wellbore, or an already existing well that is no longer producing
hydrocarbons economically. As shown in FIG. 5, wellbore injection
equipment (514) extends from a wellhead (516) of injection wellsite (502) to
inject fluid (e.g., shown as (511) and (512) in FIG. 5) in or around the
periphery of the reservoir (404) to push hydrocarbons (e.g., shown as (513) in
FIG. 5) toward a producing wellbore, such as the wellbore (436). The
injection wellsite (502) is operatively connected to an injection transport
line
(515), which provides the injection fluid to the injection wellsite (502)
through the wellhead (516) and down through the well injection equipment
(514).
[0064] The injected fluid may include water, steam, gas (e.g., carbon
dioxide),
polymer, surfactant, other suitable liquid, or any combinations thereof. A
substance that is capable of mixing with hydrocarbons remaining in the well
is called miscible. For example, a surfactant (e.g., shown as (511) in FIG.
5),
a chemical similar to washing detergents, can be injected into a reservoir
mixing with some of the hydrocarbons locked in rock pores (e.g., shown as
(512) in FIG. 5), and releases the hydrocarbons so that fluid (e.g., shown as
(513) in FIG. 5) can be pushed towards the producing wells. One technique
in fluid injection is MWAG injection, which involves the use of gases such as
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natural gas (i.e., naturally occurring mixture of hydrocarbon gases), carbon
dioxide, or other suitable gases. The injected gas (e.g., natural gas, carbon
dioxide, etc.) mixes with some of the remaining hydrocarbons in the reservoir,
unlocks it from the pores, and pushes the fluid (e.g., shown as (513) in FIG.
5)
to producing wells. Water (e.g., shown as (511) in FIG. 5) is often injected
behind the gas (e.g., shown as (512) in FIG. 5) to push the miscible gas and
unlocked hydrocarbons along based on the incompressible nature of water.
Another technique involves injecting steam for Cold Heavy Oil Production
with Sand (CHOPS). CHOPS involves the deliberate initiation of sand influx
into a perforated oil well to produce oil along with the sand. Steam injection
facilitates pressure drops in the formation to enhance the movement of heavy
cold mixture of sand with oil.
[0065] The injected fluid may include water, steam, gas (e.g., carbon
dioxide),
polymer, surfactant, other suitable liquid, or any combinations thereof A
substance that is capable of mixing with hydrocarbons remaining in the well
is called miscible. For example, a surfactant (e.g., shown as (511) in FIG.
5),
a chemical similar to washing detergents, can be injected into a reservoir
mixing with some of the hydrocarbons locked in rock pores (e.g., shown as
(512) in FIG. 5), and releases the hydrocarbons so that fluid (e.g., shown as
(513) in FIG. 5) can be pushed towards the producing wells. One technique
in fluid injection is MWAG injection, which involves the use of gases such as
natural gas (i.e., naturally occurring mixture of hydrocarbon gases), carbon
dioxide, or other suitable gases. The injected gas (e.g., natural gas, carbon
dioxide, etc.) mixes with some of the remaining hydrocarbons in the reservoir,
unlocks it from the pores, and pushes the fluid (e.g., shown as (513) in FIG.
5)
to producing wells. Water (e.g., shown as (511) in FIG. 5) is often injected
behind the gas (e.g., shown as (512) in FIG. 5) to push the miscible gas and
unlocked hydrocarbons along based on the incompressible nature of water.
Another technique involves injecting steam for heavy oil production such as
Thermal Heavy Oil Production with steam injection and Cold Heavy Oil
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Production with Sand (CHOPS). CHOPS typically refers to a non-thermal
primary process for producing heavy oil. In this method, continuous
production of sand improves the recovery of heavy oil from the reservoir. In
many cases, an artificial lift system is used to lift the oil with sand. Said
in
another word, CHOPS often involves the deliberate initiation of sand influx
into a perforated oil well to produce oil along with the sand. Steam injection
facilitates pressure drops in the formation to enhance the movement of heavy
cold mixture of sand with oil.
100661 The efficacy of the MWAG injection in recovering remaining
hydrocarbons from an oilfield depends on careful planning of the injection
schedules such as the selection of fluid, the determination of the composition
of the fluid to ensure the miscibility, the pumping rate, the switching cycles
between different injected fluid, the controlled interface, and capillary
forces
between different injected fluid, etc. The MWAG injection schedule should
be determined considering geological and geo-physical information, such as
temperature, pressure, porosity, permeability, composition, etc. In addition
to
the complexity in determining MWAG injection schedules, the source of the
injection fluid, the constraints of the processing facilities and surface
network,
and market value of oil can all impact the overall performance of the oilfield
operation. Similarly, the efficacy in using steam injection to enhance thermal
heavy oil production and/or CHOPS also depends on careful planning of the
injection schedules as described above.
[0067] An integrated simulation method described below, can be used, for
example, to model the MWAG injection operation and the heavy oil
production with steam injection (e.g., CHOPS) operation including various
aspects of the oilfield, such as geological, geo-physical, operational,
financial,
etc. In the integrated simulation method, various constraints of the oilfield
operation may be considered, such as the network constraints, the processing
facility constraints, the fluid source constraints, the reservoir constraints,
the
market price constraints, the financial constraints, etc.
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[0068] As further shown in FIG. 5, sensors (S) are located about the
oilfield
(400) to monitor various parameters during oilfield operations. The sensors
(5) may measure, for example, pressure, temperature, flow rate, composition,
and other parameters of the reservoir, wellbore, surface network, process
facilities and/or other portions (or regions) of the oilfield operation. These
sensors (S) are operatively connected to a surface unit (534) for collecting
data therefrom. The surface unit may be, for example, similar to the surface
unit (134) of FIGS. 1A-D.
[0069] One or more surface units (534) may be located at the oilfield
(400), or
linked remotely thereto. The surface unit (534) may be a single unit, or a
complex network of units used to perform the necessary
modeling/planning/management functions (e.g., in MWAG injection
scheduling or steam injection scheduling for heavy oil production such as
CHOPS) throughout the oilfield (400). The surface unit may be a manual or
automatic system. The surface unit may be operated and/or adjusted by a
user. The surface unit is adapted to receive and store data. The surface unit
may also be equipped to communicate with various oilfield equipment. The
surface unit may then send command signals to the oilfield in response to data
received or modeling performed. For example, the MWAG injection
schedule or the steam injection schedule may be adjusted and/or optimized
based on modeling results updated according to changing parameters
throughout the oilfield, such as geological parameters, geo-physical
parameters, network parameters, process facility parameters, injection fluid
parameters, market parameters, financial parameters, etc.
[0070] As shown in FIG. 5, the surface unit (534) has computer facilities,
such
as memory (520), controller (522), processor (524), and display unit (526),
for
managing the data. The data is collected in memory (520), and processed by
the processor (524) for analysis. Data may be collected from the oilfield
sensors (S) and/or by other sources. For example, oilfield data may be
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supplemented by historical data collected from other operations, or user
inputs.
[0071] The analyzed data (e.g., based on modeling performed) may then be
used to make decisions. A transceiver (not shown) may be provided to allow
communications between the surface unit (534) and the oilfield (400). The
controller (522) may be used to actuate mechanisms at the oilfield (400) via
the transceiver and based on these decisions. In this manner, the oilfield
(400) may be selectively adjusted based on the data collected. These
adjustments may be made automatically based on computer protocol and/or
manually by an operator. In some cases, well plans are adjusted to select
optimum operating conditions or to avoid problems.
[0072] To facilitate the processing and analysis of data, simulators may
be used
to process the data for modeling various aspects of the oilfield operation.
Specific simulators are often used in connection with specific oilfield
operations, such as reservoir or wellbore simulation. Data fed into the
simulator(s) may be historical data, real time data or combinations thereof.
Simulation through one or more of the simulators may be repeated or adjusted
based on the data received.
[0073] As shown, the oilfield operation is provided with wellsite and non-
wellsite simulators. The wellsite simulators may include a reservoir simulator
(340), a wellbore simulator (342), and a surface network simulator (344). The
reservoir simulator (340) solves for hydrocarbon flow through the reservoir
rock and into the wellbores. The wellbore simulator (342) and surface
network simulator (344) solves for hydrocarbon flow through the wellbore
and the surface network (444) of pipelines. As shown, some of the simulators
may be separate or combined, depending on the available systems.
10074] The non-wellsite simulators may include process (346) and economics
(348) simulators. The processing unit has a process simulator (346). The
process simulator (346) models the processing plant (e.g., the process
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facilities (454)) where the hydrocarbon(s) is/are separated into its
constituent
components (e.g., methane, ethane, propane, etc.) and prepared for sales. The
oilfield (400) is provided with an economics simulator (348). The economics
simulator (348) models the costs of part or the entire oilfield (400)
throughout
a portion or the entire duration of the oilfield operation.
Various
combinations of these and other oilfield simulators may be provided.
[0075]
FIG. 6 depicts a schematic view of an oilfield simulator (300) for
modeling operations of an oilfield (300). This simulator (300) may form part
of an overall production system of the oilfield. As shown, several simulators
of the oilfield are operatively linked as an integrated asset model for
modeling
integrated operation therebetween. Depending on the desired outcome,
certain simulators may be selectively linked in a desired configuration. While
a variety of combinations may be envisioned, FIG. 6 depicts the combination
of three reservoir simulators (340a, 340b, 340c), two wellbore simulators
(342a, 342b), a surface network simulator (344), a process simulator (346)
and an economics simulator (348). A variety of combinations of two or more
simulators may be selectively linked to perform integrated simulations.
100761 In
the example shown, a set of simulators is selected to depict the
various sources that affect the flow of fluid through the oilfield. At the far
left
are three different reservoir simulators (340a, 340b, 340c), which are
provided to depict various levels of approximation in mathematical
representation of the reservoir. These reservoir simulators (340a, 340b, 340c)
calculate the flow of hydrocarbon(s) from the reservoir and into the wells and
the flow of fluid into the reservoir from injection wells. One or more of the
same and/or different reservoir simulators may be used. For example,
reservoir simulator (340a) is a full reservoir simulation model with increased
accuracy, but reduced speed. Reservoir simulator (340b) is a tank model
proxy of a reservoir simulator, which typically provides a simplified
representation of a reservoir simulation model. This type of reservoir
simulator is typically less accurate, but faster to solve. Reservoir simulator
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(340c) is a lookup table proxy of a reservoir simulator, which is typically
even
more simplified and faster to solve.
[0077] [FIG. 6 demonstrates that, depending on the desired analysis,
various
combinations of one or more simulators may be used to perform the overall
simulation. Each may have benefits, and the various outcomes may be
compared. In the depicted example, some of the simulations can take more
than a week to run once. Thus, one or more of the desired reservoir
simulators may be selectively included to provide more immediate outputs
that may be compared with the more precise simulations that are generated
later.
[00781 As further shown in FIG. 6, the wellbore simulators (342a, 342b)
and
surface network simulator (344) are integrated into the oilfield simulation
adjacent the reservoir simulators (340a, 340b, 340c). Surface network
simulator (344) is operatively linked to the wellbore simulators (342a, 342b).
These wellbore simulators (342a, 342b) and surface network simulator (344)
calculate the flow of hydrocarbons in the well and through the surface
pipeline surface network (not shown). The simulators are also used to model
injection of fluids into the reservoir. As shown, there are different wellbore
simulators (342a, 342b) that may be used for the oilfield simulation. The
wellbore simulators (342a, 342b) are selectively linked to the reservoir
simulators (340a, 340b, 340c) to provide data flow therebetween, as will be
described further below.
[0079] Like the reservoir simulator (340a, 340b, 340c), wellbore
simulator
(342a, 342b), and surface network simulator (344), process (346) and/or
economics simulator(s) (348) may also be used in the overall oilfield
simulation. The process simulator (346) models the activities of, for example,
a crude oil & gas processing plant for separation of petroleum into
constituent
components and creation of sellable products. The process simulator (346) is
operatively connected to the surface network simulator (344). Finally, the
economics simulator (348) is operatively connected to the process simulator
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(346). A spreadsheet model may optionally prepare the production data from
the process simulator (346) for economic analysis. The economics simulator
(348) models the economic evaluation at every time step of an integrated asset
model. Although FIG. 6 shows one example of how the economic simulator
is connected for performing the integrated simulation, in other examples the
economics model can actually be connected to any point in the integrated
asset model where oil and gas production forecasts can be generated; from a
well in the reservoir simulator, from a well in the network model, from the
export node of the network representing the total production of the field, or
from separated hydrocarbon component streams in the process plant.
[0080] The simulators of FIG. 6 depict the simulators operatively linked
for
data flow therebetween. The simulators are selectively linked to permit data
to flow between the desired simulators. Once linked, the simulators may be
configured to share data and/or outputs between the connected simulators.
The data and/or outputs received from one simulator may affect the results of
other simulators.
[0081] The production system may be used to link different parts of
oilfield
operations, such as the reservoir, wellbore, surface, processing, and
economics simulators depicted. The simulators may be cross-platform and/or
real-time. One or more simulators may be of similar configurations, or
provided by different sources that may cause problems in cross-
communication. The simulators, therefore, are linked in a manner that
permits operation therebetween. The simulators may be linked, for example,
using reservoir to surface coupling and/or stream/variable based couplings.
Preferably, these couplings link models together so that the models may solve
together over the full simulation timeframe. In some cases, the simulators
will initially model separately, in preparation for a full simulation.
[0082] The coupling between simulators preferably permits selective
passing of
data therebetween. In some cases, data flows freely between simulators. In
other cases, data flow is restricted or selectively permitted. For example, it
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may be more time efficient to permit a simulator to complete its simulation
process prior to linking to other simulators and receiving additional data
therefrom. It may also be desirable to exclude certain simulators if, for
example, a defect exists in the simulation.
[0083] User inputs may be used to provide constraints, alerts, filters,
or other
operating parameters for the simulators. Thus, where one simulator indicates
that operating conditions are unacceptable, such restrictions may be passed to
other simulators to limit the available parameters for the remainder of the
oilfield operation.
[0084] Simulators are typically linked using couplings, such as generic
node/variable couplings or special network couplings. As shown in FIG. 6,
generic node/variable couplings (352a, 352b) form connections between
wellbore simulators (342a, 342b) and surface network simulator (344),
respectively. A generic node/variable coupling (354) forms a connection
between surface network simulator (344) and process simulator (346).
Another generic node/variable coupling (356) forms a connection between
process simulator (346) and economics simulator (348). These types of
couplings permit data to flow freely between the simulators. Thus, data from
the wellbore, surface, processing, and economics simulators is free to flow
therebetween.
[0085] In other cases, special network couplings are used to facilitate
and/or
manipulate the flow of data between the simulators. As shown in FIG. 6,
reservoir simulators (340a, 340b) are connected to wellbore simulator (342a)
via special network couplings (350a and 350b), respectively. Reservoir
simulator (340c) is connected to wellbore simulator (342b) via special
network coupling (350c).
[0086] The special network coupling (350c), such as implicit or explicit
couplings, may be used between the reservoir and wellbore simulators to
impose accurate hydraulic response from the network on the reservoir. These
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couplings permit the coupled simulators to model network equipment, such as
gas lift valves, pumps, compressor, and chokes. The couplings may also be
configured to permit the coupled simulators to take account of flow assurance
issues such as wax and hydrate formation.
[0087] An implicit coupling permits simultaneous solution of the coupled
simulators. For example, a coupling can be used to provide reservoir and the
wellbore governing equations. In some cases, this may be a faster method for
performing the simulations, and provide for sharing of data between the
simulators. In the example shown in FIG. 6, an implicit coupling between
reservoir simulator (340c) and wellbore simulator (342b) provides for
simultaneous simulation based on all available data of both simulators.
[0088] An explicit coupling may be used to solve reservoir and wellbore
governing equations sequentially in an iterative process. With the sequential
process, one simulator performs its simulation before the other simulator
begins its simulation. In this manner, the first simulator can impose boundary
conditions onto the next simulator. In the example shown in FIG. 6, an
explicit coupling (350c) between reservoir simulator (340c) and wellbore
simulator (342b) indicates that the reservoir simulator completes its
simulation prior to linking to wellbore simulator (342b). Thus, wellbore
simulator (342b) is impacted by the output of wellbore simulator (340c). In
other words, reservoir simulator (340c) imposes boundary conditions on the
wellbore simulator. The wellbore is then solved and the reservoir and
wellbore pressures and flow rates are compared. If the flows and pressure are
within a given tolerance, the reservoir and wellbore simulators are considered
balanced.
[0089] The selected couplings may also be tight or loose. A tight coupling
provides coupling at a Newton level. Consider a reservoir simulation at time
to. In order to progress to time tithe reservoir material balance equations
are
solved at each non-linear (Newton) iteration. In order to introduce the
effects
of the network on the reservoir model (hydraulic response, injection,
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withdrawal), the network is balanced with the reservoir at a prescribed
number of Newtons. For example, where a reservoir simulator is coupled to
a wellbore simulator using tight coupling, the system may be balanced using a
chosen network balancing method. Reservoir material balance equations are
then solved at the first Newton iteration. The wellbore and reservoir
simulators are then rebalanced. This process may be repeated as desired.
[0090] Tight coupling may be used to balance the reservoir and the
wellbore at
the end of the timestep. The network may then be modelled in reservoir
during the coupling process. This may be used to reduce the effect if well
interaction in the reservoir is significant. Depending on the number of
Newtons and iterations, tight coupling may require a high number of network
balancing iterations.
[0091] Loose couplings involve a single reservoir network balance at the
start
of the timestep. Once a balanced solution has been achieved, the reservoir
may complete its timestep without further interaction with the network. This
is similar to tight coupling, but with the reservoir simulator initialized to
zero.
This type of coupling may be used for coupling multiple reservoirs, since two
reservoirs may take a different number of Newton iterations to perform the
same timestep.
[0092] The coupling may be positioned in different locations about the
wellbore. For example, the reservoir-wellbore simulator coupling may be a
bottom-hole, top-hole, or group coupling. With a bottom-hole coupling, the
well completion is modelled in the reservoir model from sandface to bottom
hole. The well tubing is modelled in the network. This means that an inflow
model in the network well is typically ignored. The bottom hole may be used
to provide more well accurate modelling (multiphase flow correlations /
pressure traverse), and flow assurance (compositional model / temperature
variations). However, the bottom-hole coupling may provide unstable region
on well curve that causes convergence issues, involve solving an extra branch
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per well, require tubing defined in both reservoir and network, and ignore
certain completion models.
[0093] With top-hole coupling, the well completion and tubing is modelled
in
the reservoir. The well boundary nodes in the network take account of this.
In the case of the wellbore simulator, sources or sinks are used to represent
wells. Top-hole coupling typically provides less branches in network model,
inexpensive well bore lookup in reservoir, and smoothing in the reservoir
VLP curve. However, it may lose resolution in the well bore calculation, and
may not be compatible with certain network balancing schemes.
[0094] With group coupling, a reservoir well-group representing a
production
manifold may be coupled to a source in a network. The integrated simulator
may set a common top-hole pressure constraint on the wells, and impose a
hydraulic response from the network. A large network may be significantly
reduced in size, but resolution may be lost in the network simulation.
[0095] In some cases, there are constraints on the type of coupling, such
as
bottom-hole pressure, top-hole pressure, oil rate, water rate, gas rate,
liquid
rate, reservoir volume rate. During the network balancing process, the
reservoir and the network exchange boundary conditions in order to arrive at a
converged solution. Once convergence has been achieved, the reservoir may
be instructed to continue to the next timestep. At this point, the oilfield
simulator may impose constraints on the reservoir wells that reflect the
conditions of the converged system.
[0096] Other constraints may involve limitations to the simulation. For
example, top-hole pressure may not be a valid constraint in the case of bottom
hole coupling; holding pressure constant over a long step results may result
in
a decline in rate and a pessimistic production forecast; holding rate constant
over a long timestep may result in a pressure decline. These additional
constraints may be included to prevent overly optimistic production forecast,
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or wells shutting in. While constraints may occur at any coupling, these
constraints typically occur along the reservoir/wellbore coupling.
[0097] It is desirable to have the oilfield simulator coupled in a manner
that will
achieve network balancing within a given set of constraints. In some cases,
production may begin to decline after a period of steady production. The
wells rate control could be imposed in the reservoir as a well or group limit.
It could also be imposed in the network as a rate limit on a network branch.
After the initial period, the well may start to decline. This could be a
result of
insufficient oil production potential for the well to produce its
requirements.
In this case, the reservoir may switch the wells control mode from oil to its
next most stringent control mode. This may be another rate control
(water/gas) or a pressure limit imposed on the well as a result of network
balancing.
[0098] One reason for this may be that the system is constrained by
reservoir
deliverability. In order to produce the daily requirements through the
network, the minimum reservoir pressure (PW) may be required to be greater
than or equal to the network pressure (PN). As fluid is withdrawn from the
reservoir, the reservoir pressure typically declines. When PW < PN, the
network may be cut back in order to increase flow. In such a case, the system
is constrained by network deliverability.
[0099] Network balancing may be performed to select the optimum operating
conditions. Each time a simulator asks the network to solve, it must decide
what boundary conditions to pass to the network. The type of network model
and the network balancing strategy chosen by the user determine the basis for
this decision.
[00100] The network type may be automatically determined by the oilfield
simulator. The network is determined by considering boundary conditions
and additional fluid characterization data that are passed from oilfield
simulator to the network. Depending on the type of network, a boundary
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condition may be specified. For example, black oil production may have a
boundary condition for Stock tank rates or Linear IPR (single phase), GOR,
and watercut. Compositional production may have a boundary condition for
mass rate and mole fractions, or mass IPR, and mole fractions. Water
injection may have a boundary condition of stock tank water rate or water
injectivity pressure flow relationship. Black oil injection may have a
boundary condition of stock tank gas rate or gas injectivity pressure flow
relationship. Compositional injection may have a boundary condition of mass
rate or mass injectivity pressure flow relationship. Other networks and
corresponding boundary conditions may be defined.
[00101] The network may have further defined types of couplings, such as
rate
base, fast PI, chord slope, and obey reserve limits. Rate based coupling is
the
simplest form of coupling a reservoir to a network. This type of coupling
specifies rates in the network and imposes pressure limits on the reservoir.
With this type of coupling, the oilfield simulator transfers rate-based
boundary conditions to the network.
[00102] Based on the integrated simulation method described above, an
optimization workflow uses the integrated models that combine the reservoir
model with the surface facility network model and the process plant model to
define the optimum MWAG cycle or the optimum heavy oil production (e.g.,
CHOPS) with steam injection.
[00103] FIG. 7A is a graph (400a) illustrating the case where a reservoir
well is
coupled to a network well without rate constraint. In this case, the reservoir
well should produce up to the pressure limit supplied by the hydraulic
response of the network model. This requires the network balancing process
to iterate to find the intersection of the reservoir inflow curve and the
network
well performance curve. To achieve this balancing, the following steps may
be performed
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= The reservoir well model is queried for its pressure and flow (P1
and Q1) this give us point 1 on the reservoir inflow curve.
= The rate, Ql, is set as the boundary condition to the network,
which solves to find point 2¨ the first point on the well curve.
= Pressure P2 is set as a limit in the reservoir well model which is
solved to give point 3.
= The resulting rate, Q4, is set in the network to find point 4.
[00104] This process may be repeated until the reservoir and network
pressure
and flow values are within a given tolerance.
[00105] In FIG. 7A, the rate based balancing process has taken multiple
iterations to find a solution. This is because the system is constrained by
network backpressure. As a result, the algorithm must home in on the curve
intersection (i.e. converge both pressure and flow rate).
[00106] FIG. 7B illustrates a system where the reservoir well coupled to a
network well is rate constrained in the reservoir. The reservoir inflow curve
is limited to a specific value - Qiimit. The system operates at this limit as
long
as the pressure constraint imposed on the well does not exceed a maximum
threshold denoted by
[00107] The rate based coupling algorithm deals with this situation as
follows:
= The well model is queried for its operations conditions and will
return Qlimit and Pmas.
= Qlimit is set as a constraint in the network. The network solves
are returns a pressure (Pn) and flow (Qn = Qlimit).
= As Pn < Pmax, the system is considered to be converged.
[00108] The converged system is achieved here in a single iteration. This
is
because an assumption is made that the positive pressure difference between
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the reservoir pressure (P.)) and the network pressure (Pa) can be taken up by
a network choke.
[00109] FIG. 8 shows how the fast PI method finds a solution. The fast PI
method is a non-iterative network balancing process. This coupling has linear
IPR's that are specified in the network, and the rate limits are imposed on
the
reservoir. The network balancing is a three-step process. These steps are:
= Query the reservoir for the well linear IPR curve at the current
operating point.
= Pass the IPR as a boundary condition to the network simulator
and solve for network pressure and flow.
= Set the flow rate calculated by the network simulator in the
reservoir.
[00110] The method relies on the network to perform the rate allocation.
So any
rate limits should be imposed at the network level. Because the balancing
algorithm sets rates in the reservoir, existing reservoir rate targets and
limits
are obeyed. In order to impose flow rate constraints on the system, rate
constraints are imposed on the network model.
[00111] At the start of the timestep, the linear IPR for the well is
queried. This
will be the tangent to the well curve at its current operating pressure and
flow
rate. This IPR is passed to the network, which solves for point 2. The
corresponding flow rate is set in the reservoir. This balancing scheme is non-
iterative. The rate from the network is taken as the updated operating point.
There is no test for convergence. In some cases, material may be balanced,
while pressure may not. It may possible to improve the accuracy of this
method by performing fast PI balances at multiple Newton iterations, usually
if a single reservoir is coupled. The fast PI coupling is non-iterative, and
robust. However, it may prohibit reservoir based well management, and may
be inaccurate since only rate is balanced.
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[00112] Figures 9A, 9B, and 9C contain graphs illustrating the chord slope
scheme. The chord slope scheme sets a chord slope of rates and PI taken
from the reservoir model in the network. This coupling specifies either rates
or IPR's in the network and imposes pressure limits on the reservoir. It aims
to work with any pre-existing well and group controls in the reservoir models,
as wells as imposing network back pressure.
[00113] The algorithm adapts itself to the reservoir by considering the
last two
operating points on the reservoir IPR. This means that non-linear behavior in
the 1PR (e.g. effects of skin factors or well/group constraints) can be passed
to
the network. To obtain information on how the IPR changes, at least two
network balancing iterations are typically performed.
1001141 Figures 9A and 9B consider a coupled reservoir to network
simulation
with two distinct sets of well management controls. FIG. 9A depicts a
Network Constrained System. A reservoir simulation containing 20 wells fed
into a common manifold (group). The reservoir wells are coupled to a
network model. The wells in the reservoir are controlled on bottom hole
pressure (no well or group rate control). The network contains the sink
pressure specification and a given sink rate limit. In this case, the wells
are
controlled by the network back-pressure imposed on the reservoir.
= Query the initial operating conditions of the reservoir wells to
obtain point 1 on the IPR.
= Pass the boundary conditions to the network. This may be:
Rate (shown in figure)
Linear PI Queried from well model
= The network is solved to obtain point 2 on the well curve.
= The network pressure is set in the reservoir.
= The well model is solved and queried to return point 3.
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= A Linear PI is constructed using the last two operating points on
the TR.
= The PI is passed to the network that solves to give point 4.
= Steps 4 through 7 are repeated until convergence is achieved.
[00115] At subsequent timesteps, the boundary condition passed to the
network
on the first timestep is the PI calculated at the convergence solution at the
previous timestep.
[00116] FIG. 9B depicts a graph of a Reservoir Constrained System. The
wells
are controlled using the reservoir group control target limit. Underlying
wells
operate up to an allocated quantity based on their production potential and
the
group target. The network models are restricted based on the sink pressure.
In this case, the wells are controlled by the reservoir well controls ¨
assuming
the reservoir has sufficient pressure to support the flow through the network.
= Query the initial operating conditions of the reservoir wells to
obtain point 1 on the IPR.
= Pass the boundary conditions to the network. This may be:
Rate
Linear PI Queried from well model (shown in figure)
= The network is solved to obtain point 2 on the well curve.
= The network pressure is set in the reservoir.
= The well model is solved and queried to return point 3. Note that
this is on the constant rate section of the IPR.
= A Linear PI is constructed using the last two operating points on
the IPR.
= The PI is passed to the network that solves to give point 4.
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= The resulting network pressure is passed to the reservoir to point
5.
= The algorithm detects that points 3 and 5 have the same flowrate
¨ indicating the well is operating under a rate control imposed by
the reservoir.
= The network is specified with a constant rate boundary condition
and solved.
= Assuming the reservoir pressure is greater than the network
pressure, the well is considered to be converged.
[00117] As the reservoir simulation marches through time, withdrawal will
result
in pressure decline.
1001181 FIG. 9C depicts a graph of a wellbore operation with a Reduced
Reservoir Pressure. This graph shows a well curve intersecting with an IPR
curve, which is significantly flatter than in previous figures. This is meant
to
illustrate reduced reservoir pressure.
= Query the initial operating conditions of the reservoir wells to
obtain point 1 on the IPR.
= Set rate based boundary conditions and solve the network. This
results in point 2.
= The resulting network pressure is set in the reservoir and the well
model is solved to give point 3.
= The reservoir cannot flow at the given pressure and is shut in the
reservoir.
= At this point, the Well Revival logic build into the coupling
algorithm comes into effect.
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Any wells that have been "temporarily" shut as a result of
a network imposed pressure constraint are
revived in the reservoir.
The revival limit may be set by the user to avoid excessive
iterations.
If the revival limit is exceeded, the well is permanently
shut in the reservoir.
= A linear PI is constructed using points 1 and 3. This is passed to
the network as a boundary condition.
= The network solves and returns point 4.
= The resulting network pressure is set in the reservoir and the well
model is solved to give point 5.
= If the flowrates are different, the algorithm will use the last two
operating points to construct a PI, or, if they are the same, a
constant rate. In the limiting case of no flow, the PI is
constructed using the current operating point and the last flowing
operating point. In this case, the linear PI is constructed using
points 5 and point 1.
= The PI is passed to the network and solved for point 6 where the
system reaches convergence.
[00119] If may be necessary to perform well revivals until a convergence
solution is achieved. This can result in increased run times and, in some
case,
unnecessary wells shutting. This typically provides accurate, iterate coupling
to ensures pressure and rate convergence, and obeys various simulator
constraints simultaneously. However, this process is iterative and may be
slower. Also, wells may shut in due to insufficient reservoir pressure.
[00120] Another coupling configuration that may be used is the obey
reservoir
limits. This coupling specifies rates in the network, and imposes rate limits
in
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the reservoir. The well management available in the reservoir simulator is
extensive. The aim of this method is to allow a reservoir to be coupled to a
network with minimal intervention as a result of network constraints. This
may be done to ensure that the reservoir well management controls are
obeyed whilst avoiding the well shut-in problems, such as those that may
occur with the Chord Slope method.
[00121] The coupled network may only be pressure specified at the export
note.
This method does not contain rate constraints. The obey eclipse coupling
algorithm work as shown below:
= The well model is queried for its operating point.
= Constant rate boundary condition is sent to the network and it is
solved.
= If any network well pressures are greater than the respective
reservoir well pressure, the well must be cut back.
A relaxation parameter is calculated for the well based on
the difference pressure difference.
The reservoir well is cut back using the relaxing parameter
( 0 < r < 1 )
= The well model is solved with the new rate.
= Steps 1-4, detailed immediately above, are repeated until no well
violate the pressure limit imposed by the network.
= The reservoir continues to the next timestep.
[00122] The primary difference between other coupling method and this
method
is what is set in the reservoir.
[00123] FIG. 10 depicts a method of producing fluids from an oilfield,
such as
the oilfield of Figure 1. This method involves the selective linking of
simulators throughout the oilfield to predict and/or control oilfield
operations.
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[00124] Data is gathered from the oilfield operation (Step 1001). In some
cases,
this data is historical data based on similar oilfield operations, similar
geological formations, or applicable scenarios. User inputs may be provided
based on known parameters, such as sampling of formation fluid. Data may
also be collected from sensors positioned about the oilfield as shown in FIG.
5. Data may be stored in memory and accessed as needed to perform the
simulations herein.
100125] The method involves selecting simulators for the oilfield (Step
1002). A
variety of simulators may be selected to define the oilfield simulation, such
as
the reservoir simulators (340a, 340b, 340c), wellbore simulators (342a, 342b),
surface network simulator (344), process simulator (346) and economics
simulator (348) of FIG. 6. For example, the reservoir simulator (340a) may
include functionality to model fluid injection and/or perform thru-time
analysis is selected for modeling MWAG injection operation or the heavy oil
production (e.g., CHOPS) with steam injection.
[001261 The selected simulators are positioned along a flow path (Step
1004).
This brings the oilfield simulation into a process flow diagram format as
shown in FIG. 6. The connections are preferably established to provide a
sequence for the flow of production through the flow diagram. As shown in
FIG. 6, the production fluid flows from reservoir simulator, to wellbore
simulator, to surface network simulator to process simulator, and to the
economics simulator.
100127] Couplings are established between the selected simulators (Step
1006).
These couplings are specified according to the type of coupling desired for
the
specific flow diagram. As shown in FIG. 6, couplings (352a), (352b), (354)
and (356) are general node couplings. Couplings (350, 350b, 350c) are
special couplings. For example, the coupling may involve coupling a
reservoir simulator with functionality to model fluid injection and/or perform
thru-time analysis is selected for modeling MWAG injection operation or
heavy oil production (e.g., CHOPS) with steam injection.
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1001281 The coupled simulators are then formatted (Step 1008). For
example,
the coupled reservoir and wellbore simulators are defined as bottom-hole, tap-
hole, or grouped couplings. Because the surface network, process and
economics simulators are general couplings, no such definition is required.
[00129] The processing setup for the oilfield simulator is then set (Step
1009).
Setup parameters may include, for example, time frame, frequency, display,
etc., and be used to determine, for example, start time, end time, and
reporting
frequency during simulation runs.
1001301 The oilfield simulator is then performed (Step 1010). As shown in
the
configuration of FIG. 6, the reservoir simulation will solve first. The
simulation model and the well/network model iterate until they come to a
common solution for the deliverability of each well within a pre-defined
tolerance. The results from the network are then sent to the process
simulator,
which then solves the plant operations defined therein. The economics
simulator is then linked to any model that generates a production forecast.
[00131] Results and/or reports are generated as desired (Step 1012). As
the
oilfield simulator runs, status messages and/or results of underlying
simulators may be displayed. Interim and/or final results may be selectively
generated.
[00132] The results may be used to adjust changes in the oilfield
simulator, for
example, in modeling MWAG injection operation or heavy oil production
(e.g., CHOPS) with steam injection (Step 1014). If the simulator is not
providing results as desired, or if other data suggests a problem, the
simulator
may be adjusted. For example, the coupling or constraints defined for the
simulation may be altered.
[00133] The oilfield operation, for example, the MWAG injection operation
or
heavy oil production (e.g., CHOPS) with steam injection, may also be
adjusted (Step 1016). The simulators may provide information indicating
problems at the wellsites that require action. The simulators may also
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indicate that adjustments in the oilfield operation may be made to improve
efficiency, or correct problems. Well management strategy may be adjusted
to define different development scenarios to be included in the integrated
simulation run.
[00134] The steps of portions or all of the process may be repeated as
desired.
Repeated steps may be selectively performed until satisfactory results
achieved. For example, steps may be repeated after adjustments are made.
This may be done to update the simulator and/or to determine the impact of
changes made.
[00135] The data input, coupling, layout, and constraints defined in the
simulation provide flexibility to the simulation process. These factors of the
various simulators are selected to meet the requirements of the oilfield
operation. Any combination of simulators may be selectively linked to create
the overall oilfield simulation. The process of linking the simulators may be
re-arranged and simulations repeated using different configurations.
Depending on the type of coupling and/or the arrangement of simulators, the
oilfield simulation may be selected to provide the desired results. Various
combinations may be tried and compared to determine the best outcome.
Adjustments to the oilfield simulation may be made based on the oilfield, the
simulators, the arrangement and other factors. The process may be repeated
as desired.
[00136] It will be understood from the foregoing description that various
modifications and changes may be made in the preferred and alternative
embodiments of the present invention without departing from its true spirit.
For example, the simulators, couplings and arrangement of the system may be
selected to achieve the desired simulation. The simulations may be repeated
according to the various configurations, and the results compared and/or
analyzed.
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1001371 This description is intended for purposes of illustration only and
should
not be construed in a limiting sense. The scope of this invention should be
determined only by the language of the claims that follow. The term
"comprising" within the claims is intended to mean "including at least" such
that the recited listing of elements in a claim are an open group. "A," "an"
and
other singular terms are intended to include the plural forms thereof unless
specifically excluded.
42
