NO342368B1 - System and method for performing oil field simulation operations - Google Patents

Abstract

The invention relates to a method of simulating operations for an oil field having process facilities and fire site operatively interconnected, each well site having a wellbore penetrating a subsurface formation to extract fluids from a subsurface reservoir. The process steps include selecting oil field modeling simulators therein, at least one of the simulators having functionality for modeling fluid injection, selectively coupling each of the simulators according to a predefined configuration, and modeling an oil field injection operation by selectively communicating between the simulators.

Description

BACKGROUND OF THE INVENTION

Field of the invention

[0001] The present invention relates to techniques for performing oil field operations relating to subsurface formations having reservoirs therein. More particularly, the invention relates to techniques for conducting oil field operations involving an analysis of reservoir operations and their impact on such oil field operations.

Background for related technology

[0002] Oilfield operations such as monitoring, drilling, cable testing, completion, simulation, planning and oilfield analyzes are typically performed to locate and recover valuable downhole fluids. Various aspects of oil fields and their related operations are shown in Figures 1A-1D. As shown in Fig.1A, surveys are often conducted using acquisition methods such as seismic scanners to generate maps of subsurface structures. These structures are often analyzed to determine the presence of subsurface assets such as valuable fluids or minerals. This information is used to interpret underground structures, locate formations containing desired underground values. Data obtained from the acquisition methods can be evaluated and analyzed to determine whether such valuable deposits are present and whether they are sufficiently accessible.

[0003] As shown in Fig. 1B-1D, one or more well sites can be positioned along underground structures to obtain valuable fluids from the underground reservoirs. The well sites are provided with tools capable of locating and removing hydrocarbons from the underground reservoirs. As shown in fig. 1B, drilling tools are typically lowered from oil rigs into the ground along a given path to locate valuable downhole fluids. During drilling operations, drilling tools will be able to perform downhole measurements to investigate downhole conditions. In some cases, as shown in Fig. 1C, the drilling tool will be removed and a cable tool will be placed in the wellbore to perform downhole tests in addition.

[0004] After the drilling operation has been completed, the well can then be prepared for production. As shown in Fig. 1B, wellbore completion equipment is placed in the wellbore to complete the well in preparation for production of fluids through it. Fluid is then drawn from the downhole reservoirs into the wellbore and flows to the surface. The production facilities are placed at surface locations to obtain hydrocarbons from the well site(s). Fluid extracted from underground reservoir(s) passes to the production facilities via transport mechanisms such as via pipes. Various equipment can be positioned around the oil field to monitor oil field parameters and/or to manipulate oil field operations.

[0005] During oil field operations, data will typically be obtained for analysis and/or monitoring of the oil field operations. Such data may include, e.g. underground formation, equipment, historical and/or other data. Data relating to the underground formation is obtained using a majority of sources. Such formation data can be static or dynamic. Static data relates e.g. to formation structure and geological stratigraphy that define geological structures for the underground formation. Dynamic data relates e.g. to fluids that flow through geological structures of the underground formation over time. Such static and/or dynamic data may be acquired to learn more about formations and their valuable deposits contained therein.

[0006] Sources used to obtain static data can be seismic tools, such as a seismic truck that sends pressure waves into the ground as shown in Fig. 1A. These waves are then measured to characterize changes in the density of geological structures at different depths. This information can be used to generate basic structural maps of the subsurface formation. Other static measurements can be obtained using sampling and well logging techniques. Sampling can be used to take physical samples of the formation at different depths as shown in Fig.1B. Well logging will typically involve placing downhole tools in the wellbore to obtain various downhole measurements such as density, resistivity, etc. at different depths. Such well logging can be carried out using e.g. drilling tool according to fig. 1B and/or cable tool according to fig. 1C. As soon as the well is made and completed, fluid will flow to the surface using production pipes as shown in Fig.1D. As fluid passes towards the surface, various dynamic measurements, such as fluid flow rates, pressure and composition, could be monitored. These parameters can be used to determine different characteristics of the subsurface formation.

[0007] Sensors can be positioned around the oil field to obtain data relating to various oil field operations. For example, sensors in the drilling equipment can monitor drilling conditions, sensors in well drilling can monitor fluid compositions, sensors located along the flow path can monitor flow rates and sensors at the processing facility can monitor fluids that have been collected. Other sensors may be provided to monitor downhole, surface, equipment or other conditions. Monitoring data is often used to make decisions at different locations of oil fields at different times. Data obtained by these sensors can further be 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 will sometimes be referred to as historical data.

[0008] The processed data can be used to calculate downhole conditions and to make decisions regarding oil field operations. Such decisions may involve well planning, well targeting, well completions, operating levels, production rates and other operating and/or conditions. Often this information will be used to decide when to drill new wells, re-complete existing wells or change well drilling production.

[0009] Data from one or more well drillings can be analyzed to plan or predict different outputs at a given well drilling. In some cases, data from neighboring well bores or wells with similar conditions or equipment can be used to predict how a well will perform. There are usually a large number of variables and large amounts of data to be considered when analyzing oilfield operations. It is therefore often useful to model the behavior of the oilfield operation to determine the desired direction of an action. During ongoing operations, the operating conditions may need adjustments as the conditions change and new information is received.

[0010] Techniques have been developed to model the behavior of various aspects of oilfield operations, such as geological structures, downhole reservoirs, well bores, surface facilities as well as other parts of the oilfield operation. For example, US6980940 in the name of Gurpinar discloses integrated reservoir optimization involving the assimilation of various data to optimize the overall performance of a reservoir. In another example, from WO2004/049216 in the name of Ghorayeb an integrated modeling solution for coupling a plurality of reservoir simulations and surface facility networks is shown. Other examples of such modeling techniques are shown in the patent/publication/application numbers: US5992519, WO1999/064896, WO2005/122001, US6313837, US2003/0216897, US2003/0132934, US2005/0149307, US2006/0197759, US2008/02808, and US2084/02805. .

[0011] Techniques have also been developed to predict and/or plan certain oil field operations, such as miscible water alternating gas (MWAG) injection operations. In an oil field, the initial production of hydrocarbons will be carried out by "primary extraction techniques" where only natural forces present in the reservoir are used to produce the hydrocarbons. However, upon extraction of these natural forces and upon completion of primary extraction, large quantities of hydrocarbons will still be trapped within the reservoir. Many reservoirs also lack sufficient natural forces to be able to provide production by primary methods from the start.

[0012] Recognition of these facts has led to the development and use of many stimulated recovery (EOR) techniques. Most of these techniques involve injecting at least one fluid into the reservoir to push hydrocarbons towards and into the production well. It is important that the injection of fluids takes place in a careful manner so that it pushes hydrocarbons towards the production well but at the same time does not prematurely reach the production well before all or most of the hydrocarbons have been produced.

[0013] In general, production is negatively affected as soon as the fluid reaches the production well, as the injected fluid is not normally a salable product and in some cases can be difficult to separate from the produced oil. Over the years, many attempts have been made to calculate the optimal pumping rate for injection wells and production wells to extract as much hydrocarbons as possible from a reservoir. There is significant uncertainty attached to a reservoir in terms of its geometry and geological parameters (e.g. porosity, bedrock permeabilities, etc.). In addition, the market value of hydrocarbons can vary dramatically so that financial factors can be important in determining how production should proceed to achieve maximum value from a reservoir. Examples of techniques for modeling and/or planning MWAG injection operations are provided in patent number US6775578.

[0014] Techniques have also been developed to perform reservoir simulation operations. See e.g. patent/publication/application numbers 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.

[0015] 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 spectrum of parameters affecting oilfield operations. It is desirable that such a complex analysis of oil field parameters obtained through the oil field and their influence on the injection operation should be carried out as a thru-time analysis. It is further desirable that such techniques for modeling oil field MWAG injection operations be capable of one or more of the following, including: selectively modeling oil field MWAG injection operations based on more than one simulator; selectively merging data and/or the output of more than one simulator, selectively merging data and/or the output of simulators for one or more well sites and/or oil fields, selectively linking a wide range of simulators for similar and/or different configurations , selectively linking simulators having similar and/or different applications and/or data models, selectively linking simulators for different members of an asset team of an oilfield, and providing coupling mechanisms that are able to selectively link simulators in a desired configuration.

SUMMARY OF THE INVENTION

[0016] In general, according to one aspect, the invention relates to a method of simulating operations for an oil field having process facilities and the well site operatively interconnected, where each well site has a wellbore that penetrates a subsurface formation to extract fluids from a subsurface reservoir. The method steps include selecting simulators for modeling the oil field with at least one of the simulators having functionality to model fluid injection, selectively connecting each of the simulators according to a predefined configuration, and modeling an injection operation for the oil field by selective communication between the simulators.

[0017] In general, according to one aspect, the invention relates to a method for simulating operations for an oil field that has process facilities and well sites operatively interconnected where each well site has a wellbore that penetrates a subsurface formation to extract fluids from a subsurface reservoir. The method steps include selecting simulators for modeling the oil field where at least one of the simulators has functionality to perform thru-time dynamic modeling of an injection operation, selectively connecting each of the simulators according to a predefined configuration, performing through time, dynamic modeling of the oil field by selective communication between the simulators.

[0018] Generally, according to one aspect, the invention relates to a computer-readable medium that includes instructions executable by a computer to perform the method steps for simulating operations for an oil field, having process facilities and well sites operatively interconnected, each well site having a wellbore that penetrates a subsurface formation to extract fluids from a subsurface reservoir. The method steps include selecting oil field modeling simulators where at least one of the simulators has functionality to model fluid injection, selectively connecting each of the simulators according to a predefined configuration, and modeling an oil field injection operation by selectively communicating between the simulators.

[0019] Generally, according to one aspect of the invention, it relates to a computer-readable medium that includes instructions executable by a computer to perform the method steps for simulating operations for an oil field, having process facilities and well sites operatively interconnected, each well site having a well drilling that penetrates a subsurface formation to extract fluids from a subsurface reservoir. The method steps include selecting simulators for modeling the oil field where at least one of the simulators has functionality to perform through time dynamic modeling of an injection operation, and selectively coupling each of the simulators according to a predefined configuration, and performing through time dynamic modeling of the oil field by selective communication between the simulators.

[0020] Other aspects and advantages of the invention will emerge from the following description and the associated claims.

BRIEF DESCRIPTION OF THE FIGURES

[0021] So that the above-mentioned features and advantages of the present invention can be understood in detail, a more detailed description of the invention, briefly summarized above, could appear by reference to embodiments thereof which are illustrated in the accompanying drawings. It should be noted that the accompanying drawings only illustrate typical embodiments of the invention and should therefore not be considered to limit the scope of the invention as the invention may give access to other similarly effective embodiments.

[0022] Figures 1A-1D show examples of schematic images of an oil field that has underground structures including reservoirs therein where various oil field operations are performed on the oil field. Fig.1A shows an example of survey operations carried out by a seismic truck. Fig.1B shows an example of a drilling operation which is carried out by a drilling tool suspended in a rig and which is lowered into the underground formation. Fig.1C shows an example of a cable drive which is carried out by a cable tool suspended from the rig and into the wellbore for fig. 1B. Fig.1B shows an example of a simulation operation that is carried out by a simulation tool that is led from the rig into a completed wellbore to retrieve fluids from the downhole reservoir into a surface facility.

[0023] Figures 2A-2D are examples of graphical images of data obtained by the tools for figures 1A-1D. 2A shows an example of a seismic trace for an underground formation according to fig. 1A. Fig.2B shows an example of a test roof for the formation shown in Fig.1B. Fig.2C shows an example of a well logging for the underground formation according to Fig.1C. Fig.2D shows an example of a falling curve for fluid flowing through the underground formation in simulation according to Fig.1D.

[0024] Fig.3 shows an example of a schematic image, partly in cross-section of an oil field which has a plurality of data collection tools positioned at different locations along the oil field to obtain data from the underground formation.

[0025] Fig.4 shows an example of a schematic image of an oil field that has a plurality of well sites for processing hydrocarbons from the underground formation.

[0026] Fig.5 shows an example of a schematic diagram for a part of the oil field of fig. 4 which shows the simulation operation in detail.

[0027] Fig. 6 is a schematic view of an oil field simulator for the oil field in Fig. 4, where the oil field simulator has well site and non-well site simulators selectively connected together to perform an oil field simulation.

[0028] Figures 7A and 7B are graphs indicating rate-based coupling that may be used for the oil field simulator according to Figure 6. Fig.7A shows a rate-based connection without counters. Fig.7B shows a rate-based connection for a reservoir with a counter.

[0029] Fig.8 is a graph showing a fast PI connection that can be used in the oil field simulator of Fig.6.

[0030] Figures 9A, 9B and 9C are graphs showing a chord pitch accumulation that can be used in the oil field simulator of Figure 6. Fig.9A shows a network-limited well. Fig.9B shows a reservoir-limited well. Fig.9C shows a reservoir with reduced pressure.

[0031] Fig. 10 is a flowchart showing a method for producing fluid from the oil field in Fig. 1.

DETAILED DESCRIPTION OF THE INVENTION

[0032] This preferred embodiment of the invention is shown in the figures shown above and described in detail below. In describing preferred embodiments, like or identical reference numbers will be used to identify common or corresponding elements. The figures are not necessarily to scale and certain features and certain images of the figures may be shown highlighted in scale or schematically to facilitate understanding and precision.

[0033] Figures 1A-1D show an oil field 100 that has geological structures and/or underground formations therein. As shown in these figures, different measurements for underground formations can be taken by different tools at the same location. These measurements can be used to generate information about the formation and/or the geological structures and/or fluids contained therein.

[0034] Figures 1A-1D show schematic images of an oil field 100 which has underground formations 102 containing a reservoir 104 therein and which show different oil field operations that are performed on an oil field 100. Fig. 1A shows a survey operation that is performed by a seismic truck 106a to measure properties of the underground formation. The survey operation is a seismic survey operation to produce sound vibration(s) 112. In Fig. 1A, such vibration 112 is generated by a source 110 and reflected from a plurality of floors (horizons) 114 in the earth formation 116. The sound vibration(s) 112 is received of sensors (S) such as geophone receivers 118, placed on the earth's surface and where the geophone receivers 118 produce electrical output signals referred to as data received 120 in Fig.1.

[0035] In response to the received sound vibration(s) 112 representative of various parameters (such as amplitude and/or frequency) of the sound vibration(s) 112. Data received 120 is provided as input data to a computer 122a for the seismic recording truck 106a, and in response to input data, the recording truck computer 122a will generate a seismic data output register 124. The seismic data may be further processed as desired, e.g. by data reduction.

[0036] Fig.1B shows a drilling operation which is carried out by a drilling tool 106b suspended from a rig 128 and lowered into the underground formation 102 to form a wellbore 136. A mud tank 130 is used to draw drilling mud into the drilling tool 106b via the flow line 132 to circulate drilling mud through the drilling tool 106b and back to the surface. Drilling tool 106b is lowered into the formation to reach reservoir 104. Drilling tool 106b is advantageously used to measure downhole properties. The drilling tool 106b can also be adapted to take a sample 133 as shown or be removed so that a sample 133 can be taken using another tool.

[0037] A surface unit 134 is used to communicate with the drilling tool 106b and operations external to the drilling site. The surface unit 134 is capable of communicating with the drilling tool 106b to send commands to operate the drilling tool 106b and to receive data therefrom. The surface unit 134 is advantageously provided with a computer which enables the reception, storage, processing and analysis of data from the oil field 100. The surface unit 134 collects output data 135 generated during the drilling operation. Computing means, such as those for the surface unit 134 may be positioned at various locations around the oil field 100 and/or at remote locations.

[0038] Sensors (S), such as gauges, can be positioned anywhere in the reservoir, rig, oilfield equipment (such as downhole tools), or other parts of the oilfield to obtain information about various parameters such as surface parameters, downhole parameters, and/or operating conditions . These sensors (S) advantageously measure oil field parameters such as the weight of the drill bit, torque of the drill bit, pressure, temperatures, flow rates, composition and other parameters for the oil field operations.

[0039] The information obtained by the sensors (S) may be collected by the surface unit 134 and/or other data collection sources for analysis or other processing. Data collected by the sensors (S) can be used alone or in combination with other data. Data may be collected in a database and all or a selected portion of data may be selectively used to analyze and/or predict oil field operations for current and/or other well drilling.

[0040] The data output from the various sensors (S) positioned around the oil field can be processed for use. Data can be historical data, real-time data or combinations of these. Real-time data can be used in real time, or stored for later use. Data can also be combined with historical data or other inputs for further analysis. Data can be stored in separate databases or combined in a single database.

[0041] The collected data can be used to perform analyses, such as modeling operations. For example, the seismic data output could be used to perform geological, geophysical, reservoir engineering, and/or production simulations. The reservoir, wellbore, surface and/or process data can be used to perform reservoir, wellbore, or other production simulations. The data output from oilfield operations can be generated directly from the sensors (S) or after some pre-processing or modeling. These data outputs can act as inputs for further analysis.

[0042] Data is acquired and stored in the surface unit 134. One or more surface units 134 can be located at the oil field 100, or be connected remotely thereto. The surface unit 134 may be a time domain, or a complex network of units used to perform the necessary data management functions throughout the oil field 100. The surface unit 134 may be a manual or automatic system. Surface unit 134 can be operated and/or customized by a user.

[0043] The surface unit 134 may be provided by a transceiver 137 to allow communications between the surface unit 134 and various parts (or regions) of the oil field 100 or other locations. The surface unit 134 may also be provided with or functionally coupled to a control unit to activate mechanisms at the oil field 100. The surface unit 134 may then send command signals to the oil field 100 in response to data received. The surface unit 134 can receive commands via the transceiver or can itself execute commands to the control unit (the controller). A processor may be provided to analyze data (local or remote) or to make decisions to activate the control unit. In this way, the oil field 100 can be selectively adapted based on data obtained to optimize fluid recovery rates or to maximize the lifetime of the reservoir and its ultimate production capacity. These adjustments can be made automatically based on computer protocol or manually by an operator. In some cases, well planning can be adapted to select optimal operating conditions or to avoid problems.

[0044] Fig. 1C shows a cable operation as performed by a cable tool 106c suspended from the rig 128 and into the wellbore 136 of Fig. 1B. The cable tool 106c is advantageously adapted to be lowered into a wellbore 136 to perform well logging, perform downhole tests and/or obtain samples. The cable tool 106c may be used to provide another method and apparatus for performing a seismic survey operation. The cable tool 106c of FIG. 1c may have an explosive or acoustic energy source 143 that provides electrical signals to surrounding underground formations 102.

[0045] The cable tool 106c may be operatively connected to, for example, the geophones 118 stored in the computer 122a of the seismic recording truck 106a of Fig. 1A. The cable tool 106c may also provide data to the surface unit 134. As shown, the data output 135 is generated by the cable tool 106c and collected at the surface. The cable tool 106c may be positioned at various depths in the wellbore 136 to provide a survey of the subsurface formation.

[0046] Fig. 1D shows a production operation that is performed by a production tool 106d submerged from a production unit or a Christmas tree 129 into a completed wellbore 136 of Fig. 1C to draw fluids from the downhole reservoirs into the surface facilities 142. Fluid flows from the 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 collection network 146.

[0047] Sensors (S), such as gauges, can be positioned around the oil field to obtain data relating to various oil field operations as described above. As shown, the sensor (S) can be arranged in the production tool 106d or associated equipment such as Christmas tree, collection network, surface facilities and/or the production facility to measure fluid parameters, such as fluid composition, fluid flow rate, pressure, temperatures, and/or other parameters of the production operation.

[0048] Since only simplified well site configurations are shown, it should be understood that the oil field can cover a part of mud, sea and/or water locations that include one or more well sites. Production may also include injection wells (not shown) for added recovery. One or more collection facilities may be operatively connected to one or more of the well locations to selectively collect downhole fluids from one or more well locations.

[0049] As figures 1B-1D show tools used to measure properties for an oil field 100, it should be understood that tools can be used in connection with operations outside oil fields, such as at mines, aquifer formations, storage or other underground facilities. Also, as specific data acquisition tools are shown, it should be understood that various measurement tools capable of sensing parameters, such as seismic two-way travel time, density, resistivity, production rate, etc., of the subsurface formation and/or its geological formations may get used.

Different sensors (S) can be located at different positions along the wellbore and/or monitoring tools to collect and/or monitor desired data. Other sources of data may also be provided from external sites.

[0050] Oil field configuration in Figures 1A-1D is intended to provide a brief description for an example of an oil field that can be used with the present invention. Part or all of the oil field 100 may be land-based and/or sea-based. Also, although a single oil field adapted to a single location is shown, the present invention may also be utilized with any combination of one or more oil fields 100, one or more processing facilities, and one or more well sites.

[0051] Figures 2A-2D are graphical representations of data obtained by the tools of Figures 1A-1B. Fig.2A shows a seismic trace 202 for the underground formation according to Fig.1A taken by the survey tool 106a. The seismic trace measures a bidirectional response over a period of time. Fig.2B shows a sample 133 taken by the drilling tool 106b. The sample test will typically provide a graph of density, resistivity, or other physical properties of the sample 133 over the length of the sample. Tests for density and viscosity are often carried out on the fluids in the core at different pressures and temperatures. Fig.2C shows a well log 204 for the underground formation according to Fig.1C taken by a cable tool 106c. The cable log will typically provide a resistivity measurement for the formation at various depths. Fig. 2D shows a falling production curve 206 for fluid flowing through the subsurface formation of Fig. 1D taken by the production tool 106d. The falling production line 206 typically provides the production rate Q as a function of time t.

[0052] The respective graphs for Figures 2A-2C contain static measurements that describe the physical characteristics of the formation. These measurements can be compared to determine the accuracy of the measurements and/or to check for errors. In this way, the plots for each of the respective measurements can be adapted and scaled for comparison and verification of the properties.

[0053] Fig. 2B provides a dynamic measurement of fluid properties throughout the wellbore. As the fluid flows through the wellbore, measurements will be taken for fluid properties such as flow rates, pressure, composition, etc. As described above, the static and dynamic measurements can be used to generate models for underground formations to determine their characteristics.

[0054] Fig.3 is a schematic view partially in cross-section of an oil field 300 which has data acquisition tools 302a, 302b, 302c and 302d positioned at various locations along the oil field to acquire data from subsurface formations 304. The data acquisition tools 302a-302d can be the same as the data collection tools 106a-106d of Fig.1. As shown, the data collection tools 302-302d 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 collection tool 302a-302d. 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 data for a sample taken from a sample taken for the formation 304 corresponding to sample taken 133 for Figure 2B. Static data plots 308c are log traces corresponding to the well log 204 for Fig.2C. Data plot 308d is a dynamic data plot of fluid flow rate over time, corresponding to graph 206 of FIG. 2D. Other data may also be collected, such as historical data, user input, financial information, or measurement data, and other parameters of interest.

[0056] The subsurface 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 collection tools are advantageously adapted to measure the formation and detect characteristics to geological structures of the formation.

[0057] As a specific underground formation 304 with specific geological structures is shown, it should be understood that the formation may contain a plurality of geological structures. Fluid may also be present in different parts of the formation. Each of the measuring devices can be used to measure properties of the formation and/or its underlying structures. As each collection tool is shown at specific locations along the formation, it should be understood that one or more types of measurements may be taken at one or more locations across one or more oil fields or other locations for comparison and/or analysis.

[0058] Data collected from various sources, such as the data collection tools for Figs. 3, can then be evaluated. Typically, seismic data, shown in the static data plot 308a from data acquisition tool 302a will be used by a geophysicist to determine characteristics of the subsurface formation 304. Sampling data, shown in the static plot 308b and/or log data from the well log 308c are typically used by a geologist to determine various characteristics of the geological structures of the subsurface formation 304. Production data from the production graph 308d is typically used by a reservoir engineer to determine fluid flow reservoir characteristics.

[0059] Fig.4 shows an oil field 400 for performing stimulation operations. As shown, the oil field has a plurality of well sites 402 that are operatively interconnected to a central processing facility 454. The oil field configuration of FIG. 4 is not intended to limit the scope of the invention. Part or all of the oil fields may be on land and/or at sea. Also, since a single oil field with a single processing facility and a plurality of well sites is shown, any combination of one or more oil fields, one or more processing facilities, and one or more well sites may be present.

[0060] Each well site 402 has equipment that forms a well bore 436 into the ground. The wellbore extends through subsurface formations 406 including reservoirs 404. These reservoirs 404 contain fluids such as hydrocarbons. The well sites draw fluid from the reservoirs and lead them to the processing facility via surface network 444. Surface network 444 has pipes and control mechanisms to control the flow of fluids from the well site to the processing facility 454.

[0061] Fig.5 shows a schematic image of a part (or area) of an oil field 400 for fig. 4 showing a production well site 402 and surface network 444 in detail.

The well site 402 of FIG. 5 has a wellbore 436 which extends into the ground below it. In addition, FIG. 5 shows an injection well site 502 having an injection wellbore 506. As shown, the wellbores 436 and 506 have already been drilled, completed and prepared for production from the reservoir 404.

[0062] The well drilling production equipment 564 extends from the wellhead 566 for the well site 402 and to the reservoir 404 to draw fluids to the surface. The well site 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 to the surface network 444. The fluid then flows from the surface network 444 to the processing facilities 454.

[0063] As described above, fluid may be injected through an injection wellbore such as wellbore 506 to obtain an additional amount of hydrocarbons. Fluid may be injected to carry (sweep) hydrocarbons to production wells and/or to maintain reservoir pressure by balancing extracted hydrocarbon with injected fluid. The well bore 506 may be a new well drilled specifically to serve as an injection well bore or a pre-existing well that no longer economically produces hydrocarbons. As shown in FIG. 5, wellbore injection equipment 514 may extend from a wellhead 516 of injection well site 502 to inject fluid (eg, shown as 511 and 512 in FIG. 5.) into or around the periphery of reservoir 404 to pushing hydrocarbons (e.g. shown as 513 in FIG. 5) towards a producing wellbore such as wellbore 436. The injection well site 502 is operatively connected to an injection transport line 515, which provides injection fluid to the injection well site 502 through the wellhead 516 and down through the well injection equipment 514.

[0064] The injected fluid may include water, steam, gas (eg carbon dioxide), polymer, surfactant, other suitable liquids, or any of these. A substance that is able to mix with hydrocarbons remaining in the well is called miscible. For example, a surfactant (shown as 511 in Fig.5) a chemical product similar to detergents can be injected into the reservoir to mix with some of the hydrocarbons trapped in the bedrock pores e.g. shown as 512 in Fig.5. and release the hydrocarbons so that fluid (e.g. shown as 513) in fig.5) can be pushed towards the production wells. One fluid injection technique is MWAG injection, which involves the use of gases such as natural gases (ie 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, frees it from its pores and pushes the fluids (e.g. shown as 513 in fig.5) to the production wells . Water (eg shown as 511 in Fig.5) is often injected behind the gas (eg shown as 512 in Fig.5) to push the miscible gases and released hydrocarbons together based on the incompressible property of water. Another technique involves injecting steam for Cold Heavy Oil Production with Sand (CHOPS). CHOPS involves a desired injection of sand inflow into a perforated oil well to produce oil along with the sand. Steam injection causes a pressure drop in the formation to improve movement of the heavy, cold mixture of sand and oil.

[0065] The injected fluid may include water, steam, gas (eg carbon dioxide), polymer, surfactant, other suitable liquids, or any of these. A substance that is able to mix with hydrocarbons remaining in the well is called miscible. For example, a surfactant (shown as 511 in Fig.5) a chemical product similar to detergents can be injected into the reservoir to mix with some of the hydrocarbons trapped in the bedrock pores e.g. shown as 512 in Fig.5. and release the hydrocarbons so that fluid (e.g. shown as 513) in fig.5) can be pushed towards the production wells. One fluid injection technique is MWAG injection, which involves the use of gases such as natural gases (ie 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, frees it from its pores and pushes the fluids (e.g. shown as 513 in fig.5) to the production wells . Water (eg shown as 511 in Fig.5) is often injected behind the gas (eg shown as 512 in Fig.5) to push the miscible gases and released hydrocarbons together based on the incompressible property of water. Another technique involves injecting steam for heavy oil production such as Thermal Heavy Oil Production with steam injection and Cold Heavy Oil Production with Sand (CHOPS). CHOPS refers to a non-thermal primary process for producing heavy oil. In this method, a continuous production of sand improves the extraction of heavy oil from the reservoir. In many cases, an artificial lift system will be used to lift oil with sand. In other words, CHOPS often involves a desired initiation of sand inflow into a perforated oil well to produce oil along with the sand.

Steam injection enables pressure drop in the formation to enhance movement of heavy, cold mixture of sand and oil.

[0066] The effectiveness of MWAG injection in the recovery of residual hydrocarbons from an oil field depends on accurate planning for injection schedules such as fluid selection, determination of fluid composition to ensure its miscibility, pumping rate, switching cycles between different injected fluids, controlled interface and capillary forces between different injected fluids, etc. MWAG injection schemes must be determined by considering geologists and geophysical information such as temperature, pressure, porosity, permeability, composition, etc. In addition to the complexity of determining MWAG injection schemes, the source of injection fluid can , the limitations of processing facilities and surface networks and the market value of oil have an impact on the overall performance of oilfield operations. Similarly, the impact of using steam injection to improve thermal heavy oil production and/or CHOPS will also depend on accurate planning of the injection schemes as described above.

[0067] An integrated simulation approach described below can be used, for example, to model MWAG injection operations and heavy oil production with steam injection (eg CHOPS) operation including various aspects of the oil field, such as geological, geophysical, operational, financial , etc. In the integrated simulation approach, various constraints for oilfield operations will be considered such as network constraints, processing facility constraints, fluid source constraints, reservoir constraints, market price constraints, financial constraints, etc.

[0068] As further shown in Fig.5, sensors (S) are located around the oil field 400 to monitor various parameters during oil field operations. The sensors (S) can measure e.g. pressures, temperatures, flow rates, composition and other parameters of the reservoir, wellbore, surface network, process facilities and/or other parts (or regions) of the oilfield operation. These sensors (S) are operatively connected to a surface unit 534 to collect data therefrom. The surface unit may, for example, be equivalent to the surface unit 134 of Figures 1A-1D.

[0069] One or more surface units 534 may be located at the oil field 400, or connected remotely thereto. The surface unit 534 may be a stand-alone unit or a complex network of units used to perform the necessary modeling/planning/control functions (eg, in MWAG injection schemes or steam injection schemes for heavy oil production such as CHOPS) throughout the oilfield 400. The surface unit may be a manual or automatic system. The surface device may be powered and/or customized by a user. The surface unit is adapted to receive and store data.

The surface unit can also be provided to communicate with various oilfield equipment. The surface can then send command signals to the oil field in response to data received or for modeling performed. For example, MWAG injection schemes or steam injection schemes can be adjusted and/or optimized based on modeling results updated according to changes in parameters throughout the oil field such as geological parameters, geophysical parameters, network parameters, process facility parameters, fluid injection parameters, market parameters, and financial parameters, etc.

[0070] As shown in Fig.5, the surface unit 534 has computer features, such as inside 520, control unit 522, processor 524, and display unit 526, for handling data. Data is collected in memory 520, and processed by processor 524 for analysis. Data may be collected from oil field sensors (S) and/or by other sources. For example, oilfield data may be supplemented by historical data collected from other operations or user input.

[0071] The analyzed data (e.g. based on modelling) can then be used to make choices. A transceiver (not shown) may be provided to allow communications between the surface unit 534 and the oil field 400. The control unit 522 may be used to activate mechanisms at the oil field 400 via the transceiver and be based on these decisions. In this way, the oil field 400 can be selectively adapted based on collected data. These adjustments can be made automatically based on computer protocol and/or manually by an operator. In some cases, well planning can be adapted to select optimal operating conditions or to avoid problems.

[0072] To facilitate the processing and analysis of data, simulators can be used to process data to model various aspects of the oil field operation. Specific simulators are often used in connection with specific oil field operations such as reservoir or well drilling simulation. Data fed into the simulator(s) can be historical data, real-time data or a combination of these. Simulation through one or more of the simulators can be repeated or adapted based on received data.

[0073] As shown, the oil field operation is provided with well site and non-well site simulators. The well site simulators may include a reservoir simulator 340, a well bore simulator 342, and a surface network simulator 344. The reservoir simulator 340 locates hydrocarbon flow through the reservoir bedrock and into the well bore. The wellbore simulator 342 and surface network simulator 344 find the hydrocarbon flow through the wellbore and the surface network 444 for the pipelines. As shown, some of the simulators can be separate or combined depending on the available systems.

[0074] The off-well simulators may include process 346 and economics simulators 348. The processing unit has a process simulator 346. The process simulator 346 models the processing facility (e.g., the process facilities 454)) where hydrocarbon(s) are separated into constituent components (e.g. . methane, ethane, propane, etc.) and prepared for sale. The oil field 400 is provided by an economic simulator 348. The economic simulator 348 models costs for parts of or all of the oil field 400 through part or all of the duration of the oil field operation. Various combinations of these and other oilfield simulators can be provided.

[0075] Fig.6 shows a schematic image of an oil field simulator 300 for modeling operations for an oil field 300. This simulator 300 can form part of a full production system for an oil field. As shown, several simulators for the oil field can be operationally connected as an integrated target model (asset model) to model integrated operations between them. Depending on a desired output, certain simulators can be selectively connected to a desired configuration. As one can imagine a plurality of combinations, Fig.6 shows the combination of three reservoir simulators 340a, 340b, 340c, two well drilling simulators 342a, 342b, a surface network simulator 344, a process simulator 346 and an economic simulator 348. A plurality of combinations of two or multiple simulators can be selectively linked to perform integrated simulations.

[0076] In the example shown, a set of simulators is selected to calculate different sources that affect the flow of fluid through the oil field. On the far left are three different reservoir simulators 340a, 340b, 340c, which are provided to calculate different levels of approximation in the mathematical representation of the reservoir. These reservoir simulators 340a, 340b, 340c calculate the flow of hydrocarbon(s) from the reservoir into the well and 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 may be a full reservoir simulation model with increased accuracy but decreased speed. Reservoir simulator 340b is a tank model surrogate for 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 find solutions. Reservoir simulator 340c is a lookup table replacement for a reservoir simulator that is typically even easier and faster to find solutions.

[0077] Fig.6 demonstrates that, depending on the desired analyses, different combinations of one or more simulators can be used to perform an overall simulation. Each can have advantages and the different outputs can be compared. In the example shown, some of the simulators could take more than a week to run once. Thus, one or more of the desired reservoir simulators can be selectively included to provide more immediate outputs that can be compared to more precise simulations that are generated later.

[0078] As further shown in FIG. 6, the wellbore simulators 342a, 342b and the surface network simulator 344 are integrated into the oil field simulation adjacent to the reservoir simulators 340a, 340b, 340c. The surface network simulator 344 is operatively coupled to the wellbore simulators 342a, 342b. These wellbore simulators 342a, 342b and the surface network simulator 344 calculate the flow of hydrocarbons in the well and through the surface pipeline network (not shown). The simulator is also used to model the injection of fluids into the reservoir. As shown, there are various well drilling simulators 342a, 342b that can be used for oil field simulation. The wellbore simulators 342a, 342b are selectively coupled to the reservoir simulators 340a, 340b, 340c to provide data flow therebetween, as will be described below.

[0079] As reservoir simulator 340a, 340b, 340c, well drilling simulators 342a, 342b, and surface network simulator 344, process 346 and/or economics simulator(s) 348 may also be used in the overall oil field simulation. The process simulator 346 can model activities of, e.g. a crude oil & gas simulation facility for the separation of petroleum into its components and the formation of salable products. The process simulator 346 is operatively coupled to the surface network simulator 344. Finally, the economist simulator 348 may be operatively coupled to the process simulator 346. A spreadsheet model may alternatively prepare production data from the process simulator 346 for economic analysis. The economic simulator 348 models the economic development at each time step for an integrated target model (asset model). Although fig.6 shows one example of how the economics simulator is connected to perform integrated simulation, in other examples the economics model can be connected to any point in the integrated target 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 for the network representing the total production for the area, or from separate hydrocarbon component streams in the process plant.

[0080] The simulators in Fig.6 suggest that the simulators are operatively connected for data flow between them. The simulators are selectively coupled to allow data to flow between the desired simulators. As soon as they are linked together, the simulators will be able to be configured to share data and/or output data between the connected simulators. Data and/or other outputs received from one simulator may affect the results of other simulators.

[0081] The production system can be used to link different parts of oilfield operations, such as reservoir, well drilling, surface, processing and economics simulators as indicated. The simulators can be platform independent and/or in real time. One or more simulators may be of similar configurations or provided by different sources so that they may cause problems in communication between them. The simulators are therefore linked in a way that allows operation between them. The simulators can be linked, e.g. when using reservoir to surface coupling and/or stream/variable (stream/variable)-based couplings. Advantageously, these couplings can link models together so that the models can fill solutions together for the full simulation time frame. In some cases, the simulators will initially model separately, which is prepared for a full simulation.

[0082] The connection between simulators will advantageously allow a selective transmission of data between them. In some cases, data will flow freely between the simulators. In other cases, data flow will be limited or selectively permitted. For example, it may be more time efficient to allow a simulator to complete its simulation process before connecting to other simulators and receiving additional data from them. It may also be desirable to exclude certain simulators if e.g. a defect exists in the simulation.

[0083] User input can also be used to provide limitations, alarms, filters or other operating parameters for the simulators. Thus, where one simulator indicates that the operating conditions are unacceptable, then such limitations will be transferred to other simulators to limit the available parameters for the remaining part of the oilfield operation.

[0084] Simulators are typically connected using connections, such as generic node/variable connections or special network connections. As shown in Fig.6, numerical node/variable links 352a, 352b form connections between wellbore simulators 342a, 342b and surface network simulator 344. A generic node/variable link 354 forms a connection between surface network simulator 344 and processor simulator 346. Another generic node/variable link 354 variable link 356 forms a connection between process simulator 346 and economy simulator 348. These types of links allow data to flow freely between the simulators. Thus, data from the well drilling, the surface, processing, and the economic simulators can freely flow between them.

[0085] In other cases, special network connections 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 well drilling simulator 342a, via special network connections 350a and 350b. Reservoir simulator 340c is connected to well drilling simulator 342b via special network connection 350c.

[0086] The special network coupling 350c, such as implicit or explicit coupling can be used between the reservoir and well drilling simulator to impose accurate hydraulic response from the network on the reservoir. These connections allow the connected simulators to model network equipment such as gas lift valves, pumps, compressors and reducing valves. The couplings can also be configured to allow the coupled simulators to take into account flow safety tasks such as wax and hydrate formation.

[0087] An implicit coupling allows simultaneous solution of the coupled simulators. For example, a coupling can be used to provide reservoir and wellbore governing equations. In some cases, this can be a faster way to run the simulations and to provide for sharing data between the simulators. In the example shown in Fig. 6, an implicit link is provided between reservoir simulator 340c and well drilling simulator 342b for simultaneous simulation based on all available data for both simulators.

[0088] An explicit coupling can be used to solve the reservoir and wellbore governing equations sequentially in an iterative process. With the sequential process, one simulator will perform its simulation before the next simulator begins its simulation. In this way, the first simulator will be able to impose boundary conditions on the next simulator. In the example, shown in Fig.6, an explicit link 350c between reservoir simulator 340c and well drilling simulator 342b may indicate that the reservoir simulator completes its simulation before the link to well drilling simulator 342b. Thus, well drilling simulator 342b will be affected by the output of well drilling simulator 340c. In other words, reservoir simulator 340c will impose boundary conditions on the wellbore simulator. The wellbore is thus clarified and the reservoir and wellbore pressure and flow rates are compared. If flow and pressure are within a given tolerance, then the reservoir and the well drilling simulators are assumed to be balanced.

[0089] The selected connections can also be tight or loose. A tight coupling provides coupling at a Newton level. Consider a reservoir simulation at time t0. To advance to time t1, the reservoir material balance equations will be solved at each non-linear (Newton) iteration. To introduce the effects of the network on the reservoir model (hydraulic response, injection, withdrawal) the network will be balanced with the reservoir at a predetermined number of Newtons. For example, where a reservoir simulator is connected to a well drilling simulator using a tight coupling, the system could be balanced using a selected network balancing method. The reservoir material balance equations are then solved by the first Newton iteration. The wellbore and reservoir simulators are then rebalanced. This process can be repeated if desired.

[0090] Tight coupling can also be used to balance the reservoir and the wellbore at the end of the time step. The network can then be modeled in the reservoir during the coupling process. This can be used to reduce the effect if the well interaction in the reservoir is significant. Depending on the number of Newtons and iterations, tight connections may require a high number of network balancing iterations.

[0091] Loose couplings involve a single reservoir-network balance at the start of the time step. Once a balanced solution has been achieved, the reservoir will be able to complete its time step without further interaction with the network. This is equivalent to tight coupling, but where the reservoir simulator is initialized to zero. This type of coupling is used to couple a plurality of reservoirs, since two reservoirs may assume different numbers of Newton iterations to perform the same time step.

[0092] The coupling can be positioned at different locations around the wellbore. For example, the reservoir well drilling simulator coupling may be a bottomhole, tophole or group coupling. With a bottomhole coupling, the well completion will be modeled in the reservoir model from the sand front to the bottomhole. The well pipe is modeled in the network. This means that an inflow model in the network well is typically ignored. The downhole can typically be used to provide more accurate modeling for the well (multiphase flow correlations/pressure propagation) and flow assurance (composition model/temperature variations). However, the bottomhole coupling can provide unstable areas on the well curve that cause convergence problems, involving the solution of extra branch per well, which requires pipe paths defined in both reservoir and network, and ignores specific completion models.

[0093] With the tophole coupling, the well completion and the production pipe are modeled in reservoirs. The well boundary node in the network takes this into account. In the case of the well drilling simulator, springs or depressions are used to represent wells. Tophole couplings can typically provide smaller branches in the network model, no expensive well drilling estimates in the reservoir, and smoothing of the reservoir VLP curve. But it may lose resolution in the wellbore calculation, and will not necessarily be compatible with certain network balancing schemes.

[0094] With group connection, a reservoir-well group representing a production manifold could be connected to a source in a network. The integrated simulator can set a common tophole pressure limitation on the well, and impose a hydraulic response from the network. A large network can be significantly reduced in size, but resolution can be lost in the network simulation.

[0095] In some cases there are limitations on the type of connections, 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 will exchange boundary conditions in order to produce a convergent solution. Once convergence has been achieved, the reservoir can be illustrated to continue to the next time step. At this point, the oilfield simulator will be able to impose constraints on the reservoir well that reflect the conditions of the converged system.

[0096] Other limitations are may involve limitations on the simulation. For example, tophole pressure may not be a valid constraint in the case of bottomhole coupling anyway; keeping the pressure in cash over a long step can result in a drop in the rate and a pessimistic production forecast; keeping the rate constant over a long time step can result in a pressure drop. These additional constraints may be included to prevent over-optimistic production forecasts, or wells shutting in. As limitations can occur at any connection, these limitations will typically occur along the reservoir/wellbore connection.

[0097] It is desirable to leave the oilfield simulator connected in a way that will achieve a network balance within a given set of constraints. In some cases, production may begin to decline after a period of stable production.

Well flow control can be imposed in the reservoir as a well or group constraint. It can also be enforced in the network as a rate limit on a network branch. After an initial period, the well will be able to begin to decline. This may be a result of insufficient oil production potential for the well to produce according to requirements. In this case, the reservoir will be able to switch the well's management mode from oil to its second most stringent management mode. This could be a different rate control (water/gas) or a pressure limitation imposed on the well as a result of network balancing.

[0098] One reason for this may be that the system is limited by reservoir delivery capability. In order to be able to produce the daily needs through the network, a minimum reservoir pressure (PW) may be required to be greater than or equivalent to the network pressure (PN). As fluid is withdrawn from the reservoir, the reservoir pressure will typically drop. When PW < PN, the network can be cut back to increase the flow. In such cases, the system will be limited by network delivery capability.

[0099] Network balancing can be performed to select optimal operating conditions. Every time a simulator asks the network for a solution, it has to decide which boundary conditions to transfer to the network. The type of network model and network balancing strategy chosen by the user determines the basis for this choice.

[00100] The network type may be automatically determined by the oilfield simulator.

The network is determined by considering boundary conditions and, in addition, fluid characteristic data that is transferred from the oilfield simulator to the network. Depending on the type of network, a boundary condition may be specified. For example, black oil production may have boundary conditions for stock tank rates or linear IPR (one-phase), GOR and water fraction (watercut). The production composition can have a boundary condition for mass rate or mole fractions, or mass IPR, and mole fractions. Water injection can have boundary conditions for stock tank water rate or water injectivity pressure flow relationship. Black oil injection can have a boundary condition for the stock tank gas rate (stock tank gas rate) or gas injection pressure flow relationship (gas injectivty pressure flow relationship). The injection assembly may have a mass rate boundary condition or mass injection pressure flow conditions. Other networks and corresponding boundary conditions can be defined.

[00101] The network can also have defined types of connections such as rate base, fixed PI, chord progression and obey reserve limits. Rate-based connection is the simplest form of connecting a reservoir to a network. This type of connection specifies the rates in the network and imposes pressure restrictions on the reservoir. With this type of connection, the oilfield simulator will transfer rate-based boundary conditions to the network.

[00102] Based on the integrated simulation procedures described above, an optimized workflow will use the integrated model that combines the reservoir model with the surface facility network model and the process plant model to define the optimal MWAG cycle or the optimal heavy oil production (eg, CHOPS) with steam injection.

[00103] Figure 7A is a graph (400a) illustrating the case where a reservoir well is connected to a network well without rate limitations. In this case, the reservoir well must produce up to the pressure limit provided by the hydraulic response for the network model. This requires the network balance process to iterate to find the intersection of the reservoir inflow curve and the network well performance curve. In order to achieve this balance, the following steps can be carried out.

● The reservoir well model is asked for its pressure and flow (P1 and Q1), this gives us point 1 on the reservoir inflow curve.

● The rate, Q1, is set as a boundary condition for the network, which seeks to find point 2 – the first point on the well curve.

● Pressure P2 is set as a boundary in the reservoir well model which is solved to give point 3.

● The resulting rate, Q4, is put into the network to find point 4.

[00104] This process can 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 assumed a plurality of iterations to find a solution. This is because the system is limited by network back pressure. As a result, the algorithm will have to move towards the intersection of the curve (ie where both pressure and flow rate converge).

[00106] Figure 7B illustrates a system where the reservoir well connected to a network well is rate limited in the reservoir. The reservoir's inflow curve is limited to a specific value - Qlimit. The system operates at this limitation as long as the pressure limitation imposed on the well does not overwrite a maximum threshold indicated by Pmax.

[00107] The rate-based switching algorithm treats this situation as follows:

● The well model is asked for its operating conditions and will return Qlimit and Pmas.

● Qlimit is set as a limitation in the network. The network solutions return a pressure (Pn) and flow (Qn = Qlimit).

● Since 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 there are positive pressure differences between the reservoir pressure (Pmax) and the network pressure (Pn) can be absorbed by a network choke.

[00109] Figure 8 shows how the fast PI method finds a solution. The fast PI method is a non-iterative network balancing process. This link has linear IPRs that are specified in the network and the rate constraints are enforced on the reservoir. The network balancing is a three-step process.

These steps are:

● Query the reservoir for its well linear IPR curve at the current operating point.

● Transfer the IPR as a boundary condition to the network simulator and solve with respect to network pressure and flow.

● Set the flow rate calculated by the network simulator in the reservoir.

[00110] The method relies on the network performing the rate allocation. So that any rate limiting will be enforced at the network level. Because the balancing algorithm sets rates in the reservoir, existing reservoir rate targets and constraints will be obeyed. To impose streaming rate constraints on the system, rate constraints are imposed on the network model.

[00111] At the start of the time step, the linear IPR for the well is requested. This will be the tangent of the well curve at its current operating pressure and flow rate. This IPR is transferred to the network, which solves with regard to point 2. The corresponding flow rate is set in the reservoir. This balance sheet is non-iterative. The rate from the network is taken as the updated operating point. There is no convergence test. In some cases, the material will be able to be balanced, while pressure will not be. It may be possible to improve the accuracy of this method by performing fast PI balance at a plurality of Newton iterations, usually if a single reservoir is connected. The fast PI coupling is non-iterative and robust. However, it may prevent reservoir-based well control, and may be inaccurate since only rates are balanced.

[00112] Figures 9A, 9B and 9C contain graphs illustrating the chord pitch scheme. The chord pitch scheme sets a chord pitch for rates and PI taken from the reservoir model in the network. This link specifies either rates or IPRs in the network and imposes pressure constraints on the reservoir. It seeks to work with any pre-existing well and group control in the reservoir models as well as forced network back pressure.

[00113] The algorithm adapts itself to the reservoir by taking into account the last two operating points on the reservoir IPR. This means that non-linear behavior in the IPR (eg effects of surface factors or well/group limitation) can be transferred to the network. In order to obtain information on how the IPR changes, at least two network balancing iterations will typically be performed.

[00114] Figures 9A and 9B consider a coupled reservoir to network simulation with two distinct sets of well control controls. Figure 9A suggests a network constrained system. A reservoir simulation containing 20 wells fed into a common manifold (group). The reservoir wells are connected to a network model. The wells in the reservoir are regulated on bottomhole pressure (no well or group rate regulation). The network contains a drilling pressure specification (sink pressure specification) and a given drilling rate limit (sink rate limit). In this case, the wells are regulated by the network's back pressure imposed on the reservoir.

● Request the initial operating conditions for the reservoir wells to achieve point 1 on the IPR.

● Transfer the boundary condition to the network. This can be:

Rate (shown in figure)

Linear PI requested from the well model

● The network is solved to achieve point 2 on the well curve.

● Network pressure is set in the reservoir.

● The well model is found and queried to return to point 3.

● A linear PI is constructed using the last two operating points of the IPR.

● The PI is passed to the network which solves with respect to yield point 4. ● Steps 4 to 7 are repeated until convergence is achieved.

[00115] In subsequent time steps, the boundary conditions transferred to the network at the first time step will be PI-calculated by the convergence solution at the preceding time step.

[00116] Figure 9B suggests a graph for a Reservoir Constrained System. The wells are regulated using the reservoir group control target limit (reservoir group control target limit). Underlying wells are driven up to an allocated quantity based on their production potential and the group target. Network models are limited based on the sink pressure. In this case, wells are regulated by the regulations for the reservoir well - where it is assumed that the reservoir has sufficient pressure to support the flow through the network.

● Request initial operating conditions for the reservoir wells to achieve point 1 of the IPR.

● Transfer boundary conditions to the network. This could be:

Rate

Linear PI requested from the well model (shown in the figure)

● The network is solved to achieve point 2 on the well curve.

● Network pressure is set in the reservoir.

● The well model is found and asked to return to point 3. Note that this is on the cash rate portion of the IPR.

● A linear PI is constructed using the smallest two operating points of the IPR.

● The PI is transferred to the network which solves to yield point 4. ● The resulting network pressure is transferred to the reservoir at point 5. ● The algorithm detects that points 3 and 5 have the same flow rate – indicating that the well is being operated under a rate control forced that the reservoir.

● The network is specified with a constant rate constraint condition and solved.

● Provided the reservoir pressure is greater than the network pressure, the well is considered to be converged.

[00117] As the reservoir simulation moves through time, a withdrawal will result in a pressure drop.

[00118] Figure 9C suggests a graph for a well drilling operation with a reduced reservoir pressure (Reduced Reservoir Pressure). This graph shows a well curve that intersects with an IPR curve, which is significantly flatter than in the previous figures. This is intended to illustrate reduced reservoir pressure.

● Request initial operating condition for the reservoir well to achieve point 1 of the IPR.

● Set rate-based boundary conditions and solve the network. This results in point 2.

● The resulting network pressure is put into the reservoir and the well model is found to give point 3.

● The reservoir cannot flow at the given pressure and is shut off in the reservoir.

● At this point, the well revival logic built into the connection algorithm will kick in.

Any well that has been "temporarily" shut in as a result of a network-enforced pressure restriction is revived in the reservoir.

The resuscitation limit can be set by the user to avoid unnecessary iterations.

If the recovery limit is breached, the well will be permanently closed in the reservoir.

● A linear PI is constructed using points 1 and 3. This is transferred to the network as a boundary condition.

● The network finds a solution and returns to point 4.

● The resulting network pressure is put into the reservoir and the well model is solved to give point 5.

● If the flow rate is 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, PI is constructed using the current operating point and the last streaming operating point. In this case, the linear PI will be constructed using points 5 and point 1.

● PI is transferred to the network and solved considering point 6 where the system reaches convergence.

[00119] It may be necessary to perform well refresh until a convergence solution is achieved. This can result in increased driving time and in some cases unnecessary well shutdowns. This will typically provide accurate, iterative couplings to ensure pressure and rate convergence, obeying various simulator constraints simultaneously. However, this process is iterative and can be slow.

Wells can also be shut down as a result of insufficient reservoir pressure.

[00120] Another coupling configuration that may be used is to obey the reservoir boundaries. This link specifies rates in the network and imposes rate restrictions in the reservoir. The well controls available in the reservoir simulator are extensive. The purpose of this approach is to allow a reservoir to be connected to the network with minimal intervention as a result of network limitations. This can be done to ensure that the reservoir well control regulation is obeyed while at the same time avoiding well shut-in problems, such as those that can occur according to the chord rise method.

[00121] The connected networks only need to be pressure specified in the export note. This method does not contain rate restrictions. The obey eclipse coupling algorithm works as shown below:

● The well model is requested for its operating point.

● Constant rate boundary condition is sent to the network and it is solved. ● If any of the network well pressures are greater than the respective reservoir well pressures, the well must be cut back (the well must be cut back).

A relaxation parameter is calculated for the well based on the pressure difference.

The reservoir well is reduced using the relaxation parameter (0 < r < 1)

● The well model is solved with the new rate.

● Steps 1-4, detailed immediately above, are repeated until no well violates the pressure constraints imposed by the network.

● The reservoir continues to the next time step.

[00122] The primary difference between other coupling methods and this method is what is put into the reservoir.

[00123] Figure 10 suggests a method for producing fluids from an oil field, such as the oil field of Fig.1. This method involves selectively chaining simulators throughout the oil field to predict and/or regulate oil field operations.

[00124] Data is collected from the oil field operation (step 1001). In some cases, this data is historical data based on corresponding oil field operations, corresponding geological formations, or applicable scenarios. User input data can be provided based on known parameters such as sampling of formation fluids. Data can also be collected from sensors positioned around the oil field as shown in fig.

5. Data can be stored in memory and accessed as needed to perform simulations therein.

[00125] The method involves selecting simulators for the oil field (step 1002). A plurality of simulators may be selected to define oil field simulation such as 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, reservoir simulator (340a) may include functionality to model fluid injection and/or perform through-time analysis be selected for modeling MWAG injection operation or heavy oil production (eg, CHOPS) with steam injection.

[00126] The selected simulators are positioned along a flow path (step 1004). This brings the oil field simulations into a process flow diagram format as shown in fig.

6. The connections are advantageously established to provide a sequence for the flow of production through the flowchart. As shown in Fig.6, the production fluid flows from the reservoir simulator, to the well drilling simulator, to the surface network simulator to the process simulator, and to the economics simulator.

[00127] The connections are established between the selected simulators (step 1006). These connections are specified according to the type of connection desired for the specific flowchart. As shown in Fig.6, connections 352a, 352b, 354 and 356 are general node connections. The couplings 350, 350b, 350c are special couplings. For example, the couplings may involve coupling a reservoir simulator with functionality to model fluid injection and/or perform through-time analysis be chosen to model MWAG injection operation or heavy oil production (eg CHOPS) with steam injection.

[00128] The linked simulators are then formatted (step 1008). For example, the coupled reservoir and well drilling simulators can be defined as bottomhole, tophole or clustered connections. Because the surface network, process and economy simulators are general connections, no such definition will be necessary.

[00129] The processing setup for the oilfield simulator is then set (step 1009).

The setup parameters can include, for example, time frame, frequency, display, etc., and are used to determine, for example, the start time, end time and reporting frequency during the simulation runs.

[00130] The oilfield simulator is then executed (step 1010). As shown in the configuration for fig. 6, the reservoir simulation will be solved first. The simulation model and the well/network model iterate until they arrive at a common solution for deliverability for each well within a predefined tolerance. The results from the network are then sent to the process simulator, which then solves the plant operation defined therein. The financial simulator is then linked to any model that generates a production forecast.

[00131] The results and/or reports are generated as desired (step 1012). While the oilfield simulator is running, status messages and/or results for underlying simulators may be displayed. Interim and/or final results can be selected and generated.

[00132] The results can be used to adjust changes in the oilfield simulator, for example, when modeling MWAG injection operations or heavy oil production (eg, CHOPS) with steam injection (step 1014). If the simulator does not provide results as desired, or if other data suggests a problem, the simulator may have been adjusted. For example, the coupling or constraints defined for the simulation can be changed.

[00133] The oilfield operation, for example, MWAG injection operation or heavy oil production (eg, CHOPS) with steam injection, may also be adjusted (step 1016). The simulators can provide information that indicates problems at the well site that require action. The simulators can also indicate that adjustments in oilfield operations can be made to improve efficiency or correct problems. Well control strategy can be adjusted to define different development scenarios to be included in the integrated simulation run.

[00134] The steps for part or all of the processes may be repeated as needed.

Repeated steps may be chosen to be performed until satisfactory results are achieved. For example, steps may be repeated after adjustments are made. This may be done to update the simulator and/or determine the impact of changes being made.

[00135] Input data, coupling, layout and constraints defined in the simulation provide flexibility for the simulation process. These factors for different simulators are chosen to meet the requirements for oilfield operations. Any combination of simulators can be selectively linked to create an overall oilfield simulation. The process of linking simulators can be rearranged and simulations can be repeated using different configurations. Depending on the type of coupling and/or arrangement of simulators, the oilfield simulations may be selected to provide the desired results. Different combinations can be tried and compared to determine the best output.

Adjustments to oilfield simulation can be made based on the oilfield, the simulators, the arrangement and other factors. The process can be repeated as desired.

[00136] It is to 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 the true spirit of the invention. For example, simulators, connections and arrangements for the system can be selected to achieve the desired simulation. The simulations can be repeated according to different configurations and results compared and/or analyzed.

[00137] This description is intended for illustration purposes only and should not be interpreted in a limiting manner. The scope of this invention shall be determined only by the language of the claims which follow. The terminology "comprehensive" within the claims is intended to mean "at least inclusive" such that the recited listing of elements in a claim is an open group. Singular terms are intended to include plural forms thereof unless otherwise specifically excluded.

Claims (25)

P A T E N T CLAIMS 1. A method of simulating operations for an oil field having at least one well site, where each well site has a wellbore that penetrates a subsurface formation to extract fluid from or to inject fluid into a subsurface reservoir therein, the method comprising: selecting a plurality of simulators, each simulator modeling at least a portion of the oil field, at least one of a plurality of simulators having functionality to model fluid injection; selectively connecting each of the plurality of simulators according to a predefined configuration, and model an oil field injection operation by selectively communicating between the plurality of simulators. 2. Method according to claim 1, wherein the injection operation comprises 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. 3. Method according to claim 1, wherein the injection operation comprises at least one selected from the group consisting of water injection, natural gas injection, polymer injection, steam injection, carbon dioxide injection, surfactant injection and combinations thereof. 4. Method according to claim 1, where the majority of simulators receive data from sensors positioned around the oil field to measure parameters for the oil field. 5. Method according to claim 1, further comprising implementing a plan defined by the majority of simulators. 6. Method according to claim 5, which further comprises modifying the plan based on the modeling for the injection operation, where the plan comprises at least one selected from the group consisting of an MWAG injection plan. Thermal Heavy Oil Production with steam injection plan, and a CHOPS steam injection plan. 7. Method according to claim 1, wherein at least one of a plurality of simulators comprises at least one selected from the group consisting of a reservoir simulator, a well drilling simulator and a surface network simulator. 8. Method according to claim 1, further comprising selecting at least one off-site simulator that models an off-well site region for the oil field. 9. Method according to claim 8, where at least one simulator outside the well site comprises at least one selected from the group consisting of a process simulator and an economic simulator. 10. Method according to claim 1, wherein at least one coupling comprises at least one selected from the group consisting of an implicit coupling, an explicit coupling, a general node/variable coupling, a tight coupling, a loose coupling, a bottom hole coupling, a tophole coupling, a group coupling, a rate-based coupling, a fast PI coupling and a chord slope coupling. 11. Method according to claim 1, wherein at least one link is constrained according to at least one selected from the group consisting of a network constraint, a reservoir constraint and combinations thereof. 12. Method for simulating operations for an oil field having at least one well location, each well location having a wellbore that penetrates a subsurface formation to extract fluids from or to inject fluid into a subsurface reservoir therein, wherein the method comprises: selecting a plurality of simulators, each simulator modeling at least a portion of the oil field, at least one of a plurality of simulators having functionality to perform through-time dynamic modeling of an injection operation, selectively selecting one of a plurality of simulators according to a predefined configuration; and to perform through-time dynamic modeling for the oil field by selectively communicating between the plurality of simulators. 13. Method according to claim 12, wherein through-time dynamic modeling comprises at least one selected from the 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. 14. Method according to claim 12, wherein the injection operation comprises at least one selected from the group consisting of water injection, natural gas injection, polymer injection, steam injection, carbon dioxide injection, surfactant injection and combinations thereof. 15. Method according to claim 12, where the majority of simulators receive data from sensors positioned around the oil field to measure parameters for the oil field. 16. Method according to claim 12, which further comprises implementing a plan defined by the majority of simulators. 17. Method according to claim 16, further comprising modifying the plan based on modeling the injection operation, wherein the plan comprises an MWAG injection plan, Thermal Heavy Oil Production with steam injection, and a CHOPS with steam injection. 18. Method according to claim 12, wherein at least one of a plurality of simulators comprises at least one selected from the group consisting of a reservoir simulator, a well drilling simulator and a surface network simulator. 19. Method according to claim 12, further comprising selecting at least one non-well site simulator that models a non-well site region for the oil field. 20. Method according to claim 19, where at least one non-well site simulator comprises at least one selected from the group consisting of a process simulator and an economic simulator. 21. Method according to claim 12, wherein at least one link comprises at least one selected from the group consisting of an implicit link, an explicit link, a general node/variable link, a tight link, a loose link, a bottom hole link, a tophole coupling, a group coupling, a rate-based coupling, fast PI coupling and a chord pitch coupling. 22. Method according to claim 12, wherein at least one coupling is restricted according to at least one selected from a group consisting of a restriction, a reservoir restriction and combinations thereof. 23- A computer-readable medium comprising instructions executable by a computer for performing the method steps of modeling a fluid injection operation for an oil field having a subsurface formation with at least one reservoir positioned therein, the instructions comprising functionality for: selecting a plurality of simulators, each simulator modeling at least a portion of the oil field, at least one of the plurality of simulators having functionality to model fluid injection; selectively connecting each of the plurality of simulators according to a predefined configuration; and model injection operations for the oil field by selectively communicating between the plurality of simulators. 24. The computer readable medium of claim 23, wherein at least one of the plurality of simulators comprises at least one selected from the group consisting of a reservoir simulator, a wellbore simulator and a surface network simulator. 25. A computer-readable medium comprising instructions executable by a computer for performing the method steps of through-time dynamic modeling for an oil field having a subsurface formation with at least one reservoir positioned therein, the instructions comprising functionality for: selectively selecting a plurality of simulators, each simulator modeling at least a portion of the oil field, at least one simulator having functionality to perform through-time dynamic modeling for fluid injection; selectively connecting each of the plurality of simulators according to a predefined configuration, and perform through-time dynamic modeling of fluid injection for the oil field by selectively communicating between the majority of simulators.