System and method for real time reservoir management

Information

  • Patent Grant
  • 6266619
  • Patent Number
    6,266,619
  • Date Filed
    Tuesday, July 20, 1999
    25 years ago
  • Date Issued
    Tuesday, July 24, 2001
    23 years ago
Abstract
A method of real time field wide reservoir management comprising the steps of processing collected field wide reservoir data in accordance with one or more predetermined algorithms to obtain a resultant desired field wide production/injection forecast, generating a signal to one or more individual well control devices instructing the device to increase or decrease flow through the well control device, transmitting the signal to the individual well control device, opening or closing the well control device in response to the signal to increase or decrease the production for one or more selected wells on a real time basis. The system for field wide reservoir management comprising a CPU for processing collected field wide reservoir data, generating a resultant desired field wide production/injection forecast and calculating a target production rate for one or more wells and one or more down hole production/injection control devices.
Description




BACKGROUND




Historically, most oil and gas reservoirs have been developed and managed under timetables and scenarios as follows: a preliminary investigation of an area was conducted using broad geological methods for collection and analysis of data such as seismic, gravimetric, and magnetic data, to determine regional geology and subsurface reservoir structure. In some instances, more detailed seismic mapping of a specific structure was conducted in an effort to reduce the high cost, and the high risk, of an exploration well. A test well was then drilled to penetrate the identified structure to confirm the presence of hydrocarbons, and to test productivity. In lower-cost onshore areas, development of a field would commence immediately by completing the test well as a production well. In higher cost or more hostile environments such as the North Sea, a period of appraisal would follow, leading to a decision as to whether or not to develop the project. In either case, based on inevitably sparse data, further development wells, both producers and injectors would be planned in accordance with a reservoir development plan. Once production and/or injection began, more dynamic data would become available, thus, allowing the engineers and geoscientists to better understand how the reservoir rock was distributed and how the fluids were flowing. As more data became available, an improved understanding of the reservoir was used to adjust the reservoir development is plan resulting in the familiar pattern of recompletion, sidetracks, infill drilling, well abandonment, etc. Unfortunately, not until the time at which the field was abandoned, and when the information is the least useful, did reservoir understanding reach its maximum.




Limited and relatively poor quality of reservoir data throughout the life of the reservoir, coupled with the relatively high cost of most types of well intervention, implies that reservoir management is as much an art as a science. Engineers and geoscientists responsible for reservoir management discussed injection water, fingering, oil-water contacts rising, and fluids moving as if these were a precise process. The reality, however, is that water expected to take three years to break through to a producing well might arrive in six months in one reservoir but might never appear in another. Text book “piston like” displacement rarely happens, and one could only guess at flood patterns.




For some time, reservoir engineers and geoscientists have made assessments of reservoir characteristics and optimized production using down hole test data taken at selected intervals. Such data usually includes traditional pressure, temperature and flow data is well known in the art. Reservoir engineers have also had access to production data for the individual wells in a reservoir. Such data as oil, water and gas flow rates are generally obtained by selectively testing production from the selected well at selected intervals.




Recent improvements in the state of the art regarding data gathering, both down hole and at the surface, have dramatically increased the quantity and quality of data gathered. Examples of such state of the art improvements in data acquisition technology include assemblies run in the casing string comprising a sensor probe with optional flow ports that allow fluid inflow from the formation into the casing while sensing wellbore and/or reservoir characteristics as described and disclosed in international PCT application WO 97/49894, assigned to Baker Hughes, the disclosure of which is incorporated herein by reference. The casing assembly may further include a microprocessor, a transmitting device, and a controlling device located in the casing string for processing and transmitting real time data. A memory device may also be provided for recording data relating to the monitored wellbore or reservoir characteristics. Examples of down hole characteristics which may be monitored with such equipment include: temperature, pressure, fluid flow rate and type, formation resistivity, cross-well and acoustic seismometry, perforation depth, fluid characteristics and logging data. Using a microprocessor, hydrocarbon production performance may be enhanced by activating local operations in additional downhole equipment. A similar type of casing assembly used for gathering data is described and illustrated in international PCT application WO 98/12417, assigned to BP Exploration Operating Company Limited, the disclosure of which is incorporated by reference.




Recent technology improvements in downhole flow control devices are disclosed in UK Patent Application GB 2,320,731A which describes a number of downhole flow control devices which may be used to shut off particular zones by using downhole electronics and programing with decision making capacity, the disclosure of which is incorporated by reference.




Another important emerging technology that may have a substantial impact on managing reservoirs is time lapsed seismic, often referred to a 4-D seismic processing. In the past, seismic surveys were conducted only for exploration purposes. However, incremental differences in seismic data gathered over time are becoming useful as a reservoir management tool to potentially detect dynamic reservoir fluid movement. This is accomplished by removing the non-time varying geologic seismic elements to produce a direct image of the time-varying changes caused by fluid flow in the reservoir. By using 4-D seismic processing, reservoir engineers can locate bypassed oil to optimize infill drilling and flood pattern. Additionally, 4-D seismic processing can be used to enhance the reservoir model and history match flow simulations.




International PCT application WO 98/07049, assigned to Geo-Services, the disclosure of which is incorporated herein by reference, describes and discloses state of the art seismic technology applicable for gathering data relevant to a producing reservoir. The publication discloses a reservoir monitoring system comprising: a plurality of permanently coupled remote sensor nodes, wherein each node comprises a plurality of seismic sensors and a digitizer for analog signals; a concentrator of signals received from the plurality of permanently coupled remote sensor nodes; a plurality of remote transmission lines which independently connect each of the plurality of remote sensor nodes to the concentrator, a recorder of the concentrated signals from the concentrator, and a transmission line which connects the concentrator to the recorder. The system is used to transmit remote data signals independently from each node of the plurality of permanently coupled remote sensor nodes to a concentrator and then transmit the concentrated data signals to a recorder. Such advanced systems of gathering seismic data may be used in the reservoir management system of the present invention as disclosed hereinafter in the Detailed Description section of the application.




Historically, down hole data and surface production data has been analyzed by pressure transient and production analysis. Presently, a number of commercially available computer programs such as Saphir and PTA are available to do such an analysis. The pressure transient analysis generates output data well known in the art, such as permeability-feet, skin, average reservoir pressure and the estimated reservoir boundaries. Such reservoir parameters may be used in the reservoir management system of the present invention.




In the past and present, geoscientists, geologists and geophysicists (sometimes in conjunction with reservoir engineers) analyzed well log data, core data and SDL data. The data was and may currently be processed in log processing/interpretation programs that are commercially available, such as Petroworks and DPP. Seismic data may be processed in programs such as Seisworks and then the log data and seismic data are processed together and geostatistics applied to create a geocellular model.




Presently, reservoir engineers may use reservoir simulators such as VIP or Eclipse to analyze the reservoir. Nodal analysis programs such as WEM, Prosper and Openflow have been used in conjunction with material balance programs and economic analysis programs such as Aries and ResEV to generate a desired field wide production forecast. Once the field wide production has been forecasted, selected wells may be produced at selected rates to obtain the selected forecast rate. Likewise, such analysis is used to determine field wide injection rates for maintenance of reservoir pressure and for water flood pattern development. In a similar manner, target injection rates and zonal profiles are determined to obtain the field wide injection rates.




It is estimated that between fifty and seventy percent of a reservoir engineer's time is spent manipulating data for use by each of the computer programs in order for the data gathered and processed by the disparate programs (developed by different companies) to obtain a resultant output desired field wide production forecast. Due to the complexity and time required to perform these functions, frequently an abbreviated incomplete analysis is performed with the output used to adjust a surface choke or recomplete a well for better reservoir performance without knowledge of how such adjustment will affect reservoir management as a whole.




SUMMARY OF THE INVENTION




The present invention comprises a field wide management system for a petroleum reservoir on a real time basis. Such a field wide management system includes a suite of tools (computer programs) that seamlessly interface with each other to generate a field wide production and injection forecast. The resultant output of such a system is the real time control of downhole production and injection control devices such as chokes, valves and other flow control devices and real time control of surface production and injection control devices. Such a system and method of real time field wide reservoir management provides for better reservoir management, thereby maximizing the value of the asset to its owner.











BRIEF DESCRIPTION OF THE DRAWINGS




The disclosed invention will be described with reference to the accompanying drawings, which show important sample embodiments of the invention and which are incorporated in the specification hereof by reference. A more complete understanding of the present invention may be had by reference to the following Detailed Description when taken in conjunction with the accompanying drawings, wherein:





FIG. 1

is a block diagram of the method of field wide reservoir management of the present invention;





FIG. 2

is a cross section view of a typical well completion system that may be used in the practice of the present invention;





FIG. 3

is a cross section of a flat back cable that may be used to communicate data from sensors located in a wellbore to the data management and analysis functions of the present invention and communicate commands from the reservoir management system of the present invention to adjust downhole well control devices;





FIG. 4

is a block diagram of the system of real time reservoir management of the present invention;





FIG. 4A

is a generalized diagrammatic illustration of one exemplary embodiment of the system of

FIG. 4

;





FIG. 5

illustrates exemplary operations which can be performed by the controller of

FIG. 4A

to implement the data management function of

FIG. 4

;





FIG. 6

illustrates exemplary operations which can be performed by the controller of

FIG. 4A

to implement the nodal analysis function and the material balance function of

FIG. 4

;





FIG. 7

illustrates exemplary operations which can be performed by the controller of

FIG. 4A

to implement the reservoir simulation function of

FIG. 4

; and





FIG. 8

illustrates exemplary operations which can be performed by the controller of

FIG. 4A

to implement the risked economics function of FIG.


4


.











DETAILED DESCRIPTION




Reference is now made to the Drawings wherein like reference characters denote like or similar parts throughout the Figures.




Referring now to

FIGS. 1 and 4

, the present invention comprises a method and system of real time field wide reservoir management. Such a system includes a suite of tools (computer programs of the type listed in Table 1) that seamlessly interface with each other in accordance with the method to generate a field wide production and injection forecast. It will be understood by those skilled in the art that the practice of the present invention is not limited to the use of the programs disclosed in Table 1. Programs listed in Table 1 are merely some of the programs presently available for practice of the invention.




The resultant output of the system and method of field wide reservoir management is the real time control of downhole production and injection control devices such as chokes, valves, and other flow control devices (as illustrated in

FIGS. 2 and 3

and otherwise known in the art) and real time control of surface production and injection control devices (as known in the art).




Efficient and sophisticated “field wide reservoir data” is necessary for the method and system of real time reservoir management of the present invention. Referring now to blocks


1


,


2


,


3


,


5


and


7


of

FIG. 1

, these blocks represent some of the types of “field wide reservoir data” acquired generally through direct measurement methods and with devices as discussed in the background section, or by methods well known in the art, or as hereinafter set forth in the specification. It will be understood by those skilled in the art that it is not necessary for the practice of the subject invention to have all of the representative types of data, data collection devices and computer programs illustrated and described in this specification and the accompanying Figures, nor is the present invention limited to the types of data, data collection devices and computer programs illustrated herein. As discussed in the background section, substantial advancements have been made and are continuing to be made in the quality and quantity of data gathered.




In order to provide for more efficient usage of “field wide reservoir data”, the data may be divided into two broad areas: production and/or injection (hereinafter “production/injection”) data and geologic data. Production/injection data includes accurate pressure, temperature, viscosity, flow rate and compositional profiles made available continuously on a real time basis or, alternatively, available as selected well test data or daily average data.




Referring to box


18


, production/injection data may include downhole production data


1


, seabed production data


2


and surface production data


3


. It will be understood that the present invention may be used with land based petroleum reservoirs as well as subsea petroleum reservoirs. Production/injection data is pre-processed using pressure transient analysis in computer programs such as Saphir by Kappa Engineering or PTA by Geographix to output reservoir permeability, reservoir pressure, permeability-feet and the distance to the reservoir boundaries.




Referring to box


20


, geologic data includes log data, core data and SDL data represented by block


5


and seismic data represented by block


7


. Block


5


data is pre-processed as illustrated in block


6


using such computer programs such as Petroworks by Landmark Graphics, Prizm by Geographix and DPP by Halliburton to obtain water and oil saturations, porosity, and clay content. Block


5


data is also processed in stratigraphy programs as noted in block


6


A by programs such as Stratworks by Landmark Graphics and may be further pre-processed to map the reservoir as noted in block


6


B using a Z-Map program by Landmark Graphics.




Geologic data also includes seismic data block


7


that may be conventional or real time 4D seismic data (as discussed in the background section). Seismic data may be collected conventionally by periodically placing an array of hydrophones and geophones at selected places in the reservoir or 4D seismic may be collected on a real time basis using geophones placed in wells. Block


7


seismic data is processed and interpreted as illustrated in block


8


by such programs as Seisworks and Earthcube by Landmark Graphics to obtain hydrocarbon indicators, stratigraphy and structure.




Output from blocks


6


and


8


is further pre-processed as illustrated in block


9


to obtain geostatistics using Sigmaview by Landmark Graphics. Output from blocks


8


,


9


and


6


B are input into the Geocellular (Earthmode) programs illustrated by block


10


and processed using the Stratamodel by Landmark Graphics. The resultant output of block


10


is then upscaled as noted in block


11


in Geolink by Landmark Graphics to obtain a reservoir simulation model.




Output from upscaling


11


is input into the data management function of block


12


. Production/injection data represented by downhole production


1


, seabed production


2


and surface production


3


may be input directly into the data management function


12


(as illustrated by the dotted lines) or pre-processed using pressure transient analysis as illustrated in block


4


as previously discussed. Data management programs may include Openworks, Open/Explorer, TOW/cs and DSS32, all available from Landmark Graphics and Finder available from Geoquest.




Referring to box


19


of

FIG. 1

, wherein there is disclosed iterative processing of data gathered by and stored in the data management program. Reservoir simulation may be accomplished by using data from the data management function


12


using VIP by Landmark Graphics or Eclipse by Geoquest. Material Balance calculations may be performed using data from the reservoir simulation


13


and data management function


12


to determine hydrocarbon volumes, reservoir drive mechanisms and production profiles, using MBAL program of Petroleum Experts.




Nodal Analysis


15


may be performed using the material balance data output of


14


and reservoir simulation data of


13


and other data such as wellbore configuration and surface facility configurations to determine rate versus pressure for various system configurations and constraints using such programs as WEM by P. E. Moseley and Associates, Prosper by Petroleum Experts, and Openflow by Geographix.




Risked Economics


16


may be performed using Aries or ResEV by Landmark Graphics to determine an optimum field wide production/injection rate. Alternatively, the target field wide production/injection rate may be fixed at a predetermined rate by factors such as product (oil and gas) transportation logistics, governmental controls, gas oil or water processing facility limitations, etc. In either scenario, the target field wide production/injection rate may be allocated back to individual wells.




After production/injection for individual wells is calculated the reservoir management system of the present invention generates and transmits a real time signal used to adjust one or more interval control valves located in one or more wells or adjust one or more subsea control valves or one or more surface production control valves to obtain the desired flow or injection rate. It will be understood by those skilled in the art that an interrelationship exists between the interval control valves. When one is opened, another may be closed. The desired production rate for an individual well may be input directly back into the data management function


12


and actual production from a well is compared to the target rate on a real time basis. The system may include programming for a band width of acceptable variances from the target rate such that an adjustment is only performed when the rate is outside the set point.




Opening or closing a control valve


17


to the determined position may have an almost immediate effect on the production/injection data represented by blocks


1


,


2


,


3


; however, on a long term basis the reservoir as a whole is impacted and geologic data represented by blocks


5


and


7


will be affected (See dotted lines from control valve


17


). The present invention continually performs iterative calculations as illustrated in box


19


using reservoir simulation


13


, material balance


14


, nodal analysis


15


and risked economics


16


to continuously calculate a desired field wide production rate and provide real time control of production/injection control devices.




The method on field wide reservoir management incorporates the concept of “closing the loop” wherein actual production data from individual wells and on a field basis.




To obtain an improved level of reservoir performance, downhole controls are necessary to enable reservoir engineers to control the reservoir response much like a process engineer controls a process facility. State of the art sensor and control technology now make it realistic to consider systematic development of a reservoir much as one would develop and control a process plant. An example of state of the art computers and plant process control is described in PCT application WO 98/37465 assigned to Baker Hughes Incorporated.




In the system and method of real time reservoir management of the present invention, the reservoir may be broken into discreet reservoir management intervals—typically a group of sands that are expected to behave as one, possibly with shales above and below. Within the wellbore, zonal isolation packers may be used to separate the producing and/or injection zones into management intervals. An example reservoir management interval might be 30 to 100 feet. Between zonal isolation packers, variable chokes may be used to regulate the flow of fluids into or out of the reservoir management interval.




U.S. Pat. No. 5,547,029 by Rubbo, the disclosure of which is incorporated by reference, discloses a controlled reservoir analysis and management system that illustrates equipment and systems that are known in the art and may be used in the practice of the present invention. Referring now to

FIG. 2

, one embodiment of a production well having downhole sensors and downhole control that has been successfully used in the Norwegian sector of the North Sea, the Southern Adriatic Sea and the Gulf of Mexico is the “SCRAMS™” concept. It will be understood by those skilled in the art that the SCRAMS™ concept is one embodiment of a production well with sensors and downhole controls that may be used in practicing the subject invention. However, practice of the subject invention is not limited to the SCRAMS™ concept.




SCRAMS™ is a completion system that includes an integrated data-acquisition and control network. The system uses permanent downhole sensors and pressure-control devices as well known in the art that are operated remotely through a control network from the surface without the need for traditional well-intervention techniques. As discussed in the background section, continuous monitoring of downhole pressure, temperatures, and other parameters has been available in the industry for several decades, the recent developments providing for real-time subsurface production and injection control create a significant opportunity for cost reductions and improvements in ultimate hydrocarbon recovery. Improving well productivity, accelerating production, and increasing total recovery are compelling justifications for use of this system.




As illustrated in

FIG. 2

, the components of the SCRAMS™ System


100


may include:




(a) one or more interval control valves


110


which provide an annulus to tubing flow path


102


and incorporates sensors


130


for reservoir data acquisition. The system


100


and the interval control valve


110


includes a choking device that isolate the reservoir from the production tubing


150


. It will be understood by those skilled in the art that there is an interrelationship between one control valve and another as one valve is directed to open another control valve may be directed to close;




(b) an HF Retrievable Production Packer


160


provides a tubing-to-casing seal and pressure barrier, isolates zones and/or laterals from the well bore


108


and allows passage of the umbilical


120


. The packer


160


may be set using one-trip completion and installation and retrieval. The packer


160


is a hydraulically set packer that may be set using the system data communications and hydraulic power components. The system may also include other components as well known in the industry including SCSSV


131


, SCSSV control line


132


, gas lift device


134


, and disconnect device


136


. It will be understood by those skilled in the art that the well bore log may be cased partially having an open hole completion or may be cased entirely. It will also be understood that the system may be used in multilateral completions;




(c) SEGNET™ Protocol Software is used to communicate with and power the SCRAMS™ system. The SEGNET™ software, accommodates third party products and provides a redundant system capable of by-passing failed units on a bus of the system;




(d) a dual flatback umbilical


120


which incorporates electro/hydraulic lines provides SEGNET communication and control and allows reservoir data acquired by the system to be transmitted to the surface.




Referring to

FIG. 3

, the electro and hydraulic lines are protected by combining them into a reinforced flatback umbilical


120


that is run external to the production-tubing string (not shown). The flatback


120


comprises two galvanized mild steel bumber bars


121


and


122


and an incolony ¼inch tube


123


and


124


. Inside tube


124


is a copper conductor


125


. The flatback


120


is encased in a metal armor


126


; and




(e) a surface control unit


160


operates completion tools, monitors the communications system and interfaces with other communication and control systems. It will be understood that an interrelationship exists between flow control devices as one is directed to open another may be directed to close.




A typical flow control apparatus for use in a subterranean well that is compatible with the SCRAMS™ system is illustrated and described in pending U.S. patent application Ser. No. 08/898,567, filed Jul. 21, 1997 by inventor Brett W. Boundin, the disclosure of which is incorporated by reference.




Referring now to blocks


21


,


22


,


23


of

FIG. 4

, these blocks represent sensors as illustrated in

FIG. 2

, or discussed in the background section (and/or as known in the art) used for collection of data such as pressure, temperature and volume, and 4D seismic. These sensors gather production/injection data that includes accurate pressure, temperature, viscosity, flow rate and compositional profiles available continuously on a real time basis.




Referring to box


38


, in the system of the present invention, production/injection data is pre-processed using pressure transient analysis programs


24


in computer programs such as Saphir by Kappa Engineering or PTA by Geographix to output reservoir permeability, reservoir pressure, permeability-feet and the distance to the reservoir boundaries.




Referring to box


40


, geologic data including log, cores and SDL is collected with devices represented by blocks


25


and


26


as discussed in the background section, or by data sensors and collections well known in the art. Block


25


data is pre-processed as illustrated in block


26


using such computer programs Petroworks by Landmark Graphics, Prizm by Geographix and DPP by Halliburton to obtain water and oil saturations, porosity, and clay content. Block


25


data is also processed in stratigraphy programs as noted in block


26


A by programs such as Stratworks by Landmark Graphics and may be further pre-processed to map the reservoir as noted in block


26


B using a Z-Map program by Landmark Graphics.




Geologic data also includes seismic data obtained from collectors know in the art and represented by block


27


that may be conventional or real time 4D seismic data (as discussed in the background section). Seismic data is processed and interpreted as illustrated in block


28


by such programs as Seisworks and Earthcube by Landmark Graphics to obtain hydrocarbon indicators, stratigraphy and structure.




Output from blocks


26


and


28


is further pre-processed as illustrated in block


29


to obtain geostatistics using Sigmaview by Landmark Graphics. Output from blocks


28


,


29


and


26


B are input into the Geocellular (Earthmodel) programs illustrated by block


30


and processed using the Stratamodel by Landmark Graphics. The resultant output of block


30


is then upscaled as noted in block


31


in Geolink by Landmark Graphics to obtain a reservoir simulation model.




Output from the upscaling program


31


is input into the data management function of block


32


. Production/injection data collected by downhole sensors


21


, seabed production sensors


22


and surface production sensors


23


may be input directly into the data management function


22


(as illustrated by the dotted lines) or pre-processed using pressure transient analysis as illustrated in block


22


as previously discussed. Data Management programs may include Openworks, Open/Explorer, TOW/cs and DSS32, all available from Landmark Graphics and Finder available from Geoquest.




Referring to box


39


of

FIG. 4

, wherein there is disclosed iterative processing of data gathered by and stored in the data management program


32


. The Reservoir Simulation program


33


uses data from the data management function


32


. Examples of Reservoir Simulation programs include VIP by Landmark Graphics or Eclipse by Geoquest. The Material Balance program uses data from the reservoir simulation


33


and data management function


22


to determine hydrocarbon volumes, reservoir drive mechanisms and production profiles. One of the Material Balance programs known in the art is the MBAL program of Petroleum Experts.




The Nodal Analysis program


35


uses data from the Material Balance program


34


and Reservoir Simulation program


33


and other data such as wellbore configuration and surface facility configurations to determine rate versus pressure for various system configurations. Nodal Analysis programs include WEM by P. E. Moseley and Associates, Prosper by Petroleum Experts, and Openflow by Geographix.




Risked Economics programs


36


such as Aries or ResEV by Landmark Graphics determine the optimum field wide production/injection rate which may then be allocated back to individual wells. After production/injection by individual wells is calculated the reservoir management system of the present invention generates and transmits real time signals (designated generally at


50


in

FIG. 4

) used to adjust interval control valves located in wells or adjust subsea control valves or surface production control valves to obtain the desired flow or injection rate. The desired production rate may be input directly back into the data management function


32


and actual production/injection from a well is compared to the target rate on a real time basis. Opening or closing a control valve


37


to the pre-determined position may have an almost immediate effect on the production/injection data collected by sensors represented by blocks


21


,


22


and


33


, however, on a long term basis, the reservoir as a whole is impacted and geologic data collected by sensors represented by blocks


25


and


27


will be affected (see dotted line from control valve


37


). The present invention may be used to perform iterative calculations as illustrated in box


39


using the reservoir simulation program


23


, material balance program


24


, nodal analysis program


25


and risked economics program


26


to continuously calculate a desired field wide production rate and provide real time control of production control devices.





FIG. 4A

is a generalized diagrammatic illustration of one exemplary embodiment of the system of FIG.


4


. In particular, the embodiment of

FIG. 4A

includes a controller


400


coupled to receive input information from information collectors


401


. The controller


400


processes the information received from information collectors


401


, and provides real time output control signals to controlled equipment


402


. The information collectors


401


can include, for example, the components illustrated at


38


and


40


in FIG.


4


. The controlled equipment


402


can include, for example, control valves such as illustrated at


37


in FIG.


4


. The controller


400


includes information (for example, data and program) storage and an information processor (CPU). The information storage can include a database for storing information received from the information collectors


401


. The information processor is interconnected with the information storage such that controller


400


is capable, for example, of implementing the functions illustrated at


32


-


36


in FIG.


4


. As shown diagrammatically by broken line in

FIG. 4A

, operation of the controlled equipment


402


affects conditions


404


(for example, wellbore conditions) which are monitored by the information collectors


401


.





FIG. 5

illustrates exemplary operations which can be performed by the controller


400


of

FIG. 4A

to implement the data management function


32


of FIG.


4


. At


51


, the production/injection (P/I) data (for example, from box


38


of

FIG. 4

) is monitored in real time. Any variances in the P/I data are detected at


52


. If variances are detected at


52


, then at


53


, the new P/I data is updated in real time to the Nodal Analysis and Material Balance functions


34


and


35


of FIG.


4


. At


54


, geologic data, for example, from box


40


of

FIG. 4

, is monitored in real time. If any changes in the geologic data are detected at


55


, then at


56


, the new geologic data is updated in real time to the Reservoir Simulation function


33


of FIG.


4


.





FIG. 6

illustrates exemplary operations which can be performed by the controller


400


of

FIG. 4A

to implement the Nodal Analysis function


35


and the Material Balance function


34


of FIG.


4


. At


61


, the controller monitors for real time updates of the P/I data from the data management function


32


. If any update is detected at


62


, then conventional Nodal Analysis and Material Balance functions are performed at


63


using the real time updated P/I data. At


64


, new parameters produced at


63


are updated in real time to the Reservoir Simulation function


33


.





FIG. 7

illustrates exemplary operations which can be performed by the controller


400


of

FIG. 4A

to implement the Reservoir Simulation function


33


of FIG.


4


. At


71


, the controller


400


monitors for a real time update of geologic data from the data management function


32


or for a real time update of parameters output from either the Nodal Analysis function


35


or the Material Balance function


34


in FIG.


4


. If any of the aforementioned updates are detected at


72


, then the updated information is used in conventional fashion at


73


to produce a new simulation forecast. Thereafter at


74


, the new simulation forecast is compared to a forecast history (for example, a plurality of earlier simulation forecasts) and, if the new simulation is acceptable at


75


in view of the forecast history, then at


76


the new forecast is updated in real time to the Risked Economics function


36


of FIG.


4


.




Referring to the comparison and decision at


74


and


75


, a new forecast could be rejected, for example, if it is considered to be too dissimilar from one or more earlier forecasts in the forecast history. If the new forecast is rejected at


75


, then either another forecast is produced using the same updated information (see broken line at


78


), or another real time update of the input information is awaited at


71


. The broken line at


77


further indicates that the comparison and decision steps at


74


and


75


can be omitted as desired in some embodiments.





FIG. 8

illustrates exemplary operations which can be performed by the controller


400


of

FIG. 4A

to implement the Risked Economics function


36


of FIG.


4


. At


81


, the controller monitors for a real time update of the simulation forecast from the Reservoir Simulation function


33


of FIG.


4


. If any update is detected at


82


, then the new forecast is used in conventional fashion to produce new best case settings for the controlled equipment


402


. Thereafter at


84


, equipment control signals such as illustrated at


50


in

FIG. 4

are produced in real time based on the new best case settings.




The following Table 1 includes a suite of tools (computer programs) that seamlessly interface with each other to generate a field wide production/injection forecast that is used to control production and injection in wells on a real time basis.
















TABLE 1












Computer










Program




Source of









(Commercial




Program






Flow Chart






Name or Data




(name of






Number




Input Data




Output Data




Source)




company)











1. Downhole




Pressure,




Annulus








Prod. (across




temp, flow




(between






reservoir




rates




tubing and






interval)





casing)








annular and








tubing








pressure








(psi), temp








(degrees,








Fahrenheit,








Centigrade),








flow rate






2. Seabed




Pressure,




Pressure,






prod. (at




temp, flow




temperature






subsea tree &




rates






subsea






manifold)






3. Surface




Pressure,




Pressure,






prod. (at




temp, flow




temperature






separators,




rates






compressors,






manifolds,






other surface






equipment)






4. Pressure




Pressure,




Reservoir




Saphir




Kappa






Transient




temp, flow




Permeability




PTA




Engineering






Analysis




rates




Reservoir





Geographix








Pressure,








Skin,








distance to








boundaries






5. Logs,





Pressure,






Cores, SDL





temperature






6. Log





Saturations




Petroworks




Landmark






processing





Porosity




Prizm




Graphics






(interpreta-





Clay Content




DPP




Geographix






tion)







Halliburton






6A. Strati-






Stratworks




Landmark






graphy







Graphics






6B. Mapping






Z-Map




Landmark










Graphics






7. Seismic






Data






8. Seismic





Hydrocarbon




Seisworks




Landmark






Processing and





indicators




Earthcube




Graphics






Interpretation





Stratigraphy








Structure






9. Geostatis-






Sigmaview




Landmark






tics







Graphics






10. Geocell-






Stratamodel




Landmark






ular







Graphics






11. Upscaling






Geolink




Landmark










Graphics










Geoquest






12. Data




Outputs from





Finder




Landmark






Management,




other boxes





Open works




Graphics






Data






Open/Explore






Repository






TOW/cs









DSS32






13. Reservoir




Field or





VIP




Landmark






simulation




well





Eclipse




Graphics







production






Geoquest







profile with







time






14. Material




Fluid




Hydrocarbon,




MBAL




Petroleum






Balance




Saturations,




in-place





Experts







Pressure




reservoir







reservoir




drive







geometry,




mechanism,







temp, fluid




production







physical




profile







prop., flow







rate,







reservoir







physical







properties






15. Nodal




Wellbore




Rate vs.




WEM




P.E.






Analysis,




configura-




Pressure for




Prosper




Moseley &






Reservoir and




tions,




various




Openflow




Associates






Fluid




surface




system and





Petroleum






properties




facility




constraints





Experts







configura-






Geographix







tions






16. Risked




Product




Rate of




Aries




Landmark






Economics




Price




return, net




ResEV




Graphics







Forecast,




present







Revenue




value,







Working




payout,







Interest,




profit vs.







Discount




investment







Rate,




ratio and







Production




desired







Profile,




field wide







Capital




production







Expense,




rates.







Operating







Expense






17. Control





Geometry






Production














It will be understood by those skilled in the art that the practice of the present invention is not limited to the use of the programs disclosed in Table 1, or any of the aforementioned programs. These programs are merely examples of presently available programs which can be suitably enhanced for real time operations, and used to practice the invention.




It will be understood by those skilled in the art that the method and system of reservoir management may be used to optimize development of a newly discussed reservoir and is not limited to utility with previously developed reservoirs.




A preferred embodiment of the invention has been illustrated in the accompanying Drawings and described in the foregoing Detailed Description, it will be understood that the invention is not limited to the embodiment disclosed, but is capable of numerous modifications without departing from the scope of the invention as claimed.



Claims
  • 1. A method of real time field wide reservoir management comprising the steps of:(a) processing collected field wide reservoir data in accordance with one or more predetermined algorithms to obtain a resultant desired field wide production/injection forecast; (b) generating a signal to one or more individual well control devices instructing the device to increase or decrease flow through the well control device; (c) transmitting the signal to the individual well control device; (d) opening or closing the well control device in response to the signal to increase or decrease the production of one or more selected wells; and (e) repeating steps (a) through (d) on a real time basis.
  • 2. The method of field wide reservoir management of claim 1 further including the steps of:allocating the field wide production/injection forecast to selected wells in the reservoir; calculating a target production/injection rate for one or more selected wells; using the target production/injection rate in step (b) to generate the signal to the individual well control device; and after the well control device is opened or closed in step (d), comparing the target production/injection rate to the actual production/injection rate on a real time basis.
  • 3. The method of field wide reservoir management of claim 1 further including the steps of:pre-processing seismic data and geologic data according to a predetermined algorithm to create a reservoir geologic model; and using the reservoir geologic model in calculating the desired field wide production rate.
  • 4. The method of field wide reservoir management of claim 3 further including the steps of:updating the reservoir model on a real time basis with down hole pressure, volume and temperature data; and processing the updated reservoir data according to a predetermined algorithm to obtain a desired field wide production rate.
  • 5. The method of field wide reservoir management of claim 1 further including the steps of:collecting real time data from one or more down-hole sensors from one or more wells and pre-processing said data using pressure transient analysis; and using the resultant output in calculating the desired field wide production rate.
  • 6. The method of field wide reservoir management of claim 1 further including the steps of:collecting real time data from one or more seabed production installations for one or more wells and pre-processing said data using pressure transient analysis; and using the resultant output in calculating the desired field wide production rate.
  • 7. The method of field wide reservoir management of claim 1 further including the steps of:collecting real time data from one or more surface production installations for one or more wells and pre-processing said data using computerized pressure transient analysis; and using the resultant output in calculating the desired field wide production rate.
  • 8. The method of field wide reservoir management of claim 1 further including the step of using nodal analysis according to a predetermined algorithm on a real time basis in calculating the desired field wide production rate.
  • 9. The method of field wide reservoir management of claim 1 further including the step of performing material balance calculations according to a predetermined algorithm on a real time basis in calculating the desired field wide production rate.
  • 10. The method of field wide reservoir management of claim 1 further including the step of performing risked economic analysis according to a predeterminend algorithm on a real time basis in calculating the desired field wide production rate.
  • 11. The method of field wide reservoir management of claim 1 further including the step of performing reservoir simulation according to a predeterminend algorithm on a real time basis in calculating the desired field wide production rate.
  • 12. The method of field wide reservoir management of claim 1 further including the step of performing nodal analysis, risked economics, material balance, and reservoir simulation according to a predeterminend algorithm on a real time basis in calculating the desired field wide production rate.
  • 13. The method of field wide reservoir management of claim 1 further including the step of performing iterative analyses of nodal analysis, material balance, and risked economic analysis on a real time basis according to a predeterminend algorithm in calculating the desired field wide production rate.
  • 14. The method of field wide reservoir management of claim 13 wherein the step of generating a signal to a production control device comprises the step of generating a signal for controlling a downhole control device and wherein the step of opening or closing the well control device comprises the step of opening or closing the down hole control device.
  • 15. The method of field wide reservoir management of claim 13 wherein the step of generating a signal to a production control device comprises the step of generating a signal for controlling a surface control device and wherein the step of opening or closing the well control device comprises the step of opening or closing the surface control device.
  • 16. The method of field wide reservoir management of claim 13 wherein the step of generating a signal to a production control device comprises generating a signal for controlling a seabed control device and wherein the step of opening or closing the well control device comprises the step of opening or closing the seabed control device.
  • 17. The method of field wide reservoir management of claim 1 wherein the step of generating a signal to a production control device comprises the step of generating a signal for controlling a downhole control device and wherein the step of opening or closing the well control device comprises the step of opening or closing the down hole control device.
  • 18. The method of field reservoir management of claim 1 wherein the step of generating a signal to a production control device comprises the step of generating a signal for controlling a surface control device wherein and the step of opening or closing the well control device comprises the step of opening or closing the surface control device.
  • 19. The method of reservoir management of claim 1 wherein the step of generating a signal to a production control device comprises the step of generating a signal for controlling a seabed control device and wherein the step of opening or closing the well control device comprises the step of opening or closing the seabed control device.
  • 20. A system for field wide reservoir management comprising:a CPU for processing collected field wide reservoir data in real time, generating a resultant desired field wide production/injection forecast in real time and calculating in response to the desired forecast a target production rate for one or more wells; one or more sensors for obtaining field wide reservoir data; a data base accessible by the CPU for storing the field wide reservoir data; said one or more sensors coupled to the data base for transmitting thereto the field wide reservoir data for use by the CPU in real time processing; and a down hole production/injection control device that receive from the CPU a signal indicative of the target production rate.
  • 21. The system for field wide reservoir management of claim 20 further including a surface production control device that receives a signal from the CPU.
  • 22. The system for field wide reservoir management of claim 20 further including a sub sea sensor.
  • 23. The system of field wide reservoir management of claim 22 further including a sub sea production control device that receives a signal from the CPU.
  • 24. The system of field wide reservoir management of claim 20 further including a surface production control device that receives a signal from the CPU.
  • 25. The system of field wide reservoir management of claim 20 wherein the one or more sensors includes a downhole sensor to collect data for pressure and temperature.
  • 26. The system of field wide reservoir management of claim 20 wherein the one or more sensors includes a downhole sensor to collect data for fluid volumes for multiphase flow.
  • 27. The system of field wide reservoir management of claim 20 wherein the one or more sensors includes a downhole sensor to collect data for 4D seismic.
  • 28. The system of field wide reservoir management of claim 20 wherein the one or more sensors includes a surface sensor to collect data for fluid volumes for multiphase flow.
  • 29. The system of field wide reservoir management of claim 22 wherein the subsea sensors collect data for fluid volumes for multiphase flow.
  • 30. The method of field wide reservoir management of claim 11 further including the step of selecting additional well locations based on the reservoir simulation model.
  • 31. The system of claim 20, wherein the one or more sensors includes a down hole sensor.
  • 32. The system of claim 31, wherein the one or more sensors includes an above ground sensor.
US Referenced Citations (12)
Number Name Date Kind
5531270 Fletcher et al. Jul 1996
5547029 Rubbo et al. Aug 1996
5597042 Tubel et al. Jan 1997
5636693 Elmer Jun 1997
5662165 Tubel et al. Sep 1997
5706892 Aeschbacher, Jr. et al. Jan 1998
5706896 Tubel et al. Jan 1998
5721538 Tubel et al. Feb 1998
5730219 Tubel et al. Mar 1998
5732776 Tubel et al. Mar 1998
5767680 Torres-Verdin et al. Jun 1998
5992519 Ramakrishnan et al. Nov 1999
Foreign Referenced Citations (6)
Number Date Country
2320731 Jul 1998 GB
9741330 Nov 1997 WO
9749894 Dec 1997 WO
9807049 Feb 1998 WO
9812417 Mar 1998 WO
9837465 Aug 1998 WO
Non-Patent Literature Citations (17)
Entry
Safley et al.: “Projects implement management plans” The American Oil & Gas Reporter, vol. 41, No. 9, Sep. 1998, pp. 136-142, XP000957690.
Vinje: “Reservoir control using smart wells” 10th Underwater Technology Conference Proceedings. Mar. 25-26, 1998. XP000957692, pp. 1-9.
Beamer et al.: “From pore to pipeline, filed scale solutions” Oilfield Review. vol. 10, No. 2, pp. 2-19, XP000961345.
Smith et al.: “The road ahead to real-time oil and gas reservoi management” Trans. Inst. Chem. Eng. vol. 76, No. a5, Jul. 1998, pp. 539-552. XP000957748.
Copy of International Search Report dated Nov. 14, 2000 for PCT/US00/19443.
Halliburton Energy Services, Inc., “SmartWell Technology Asset Management of the Future” 8/98.
Clark E. Robison, “Overcoming the Challenges Associated With the Life-Cycle Management of Multlateral Wells; Assessing Moves Toward the ‘Intelligent Completion’”, SPE 38497, paper prepared for presentation at the 1997 Offshore Europe Conference held in Aberdeen, Scotland, Sep. 9-12, 1997, pp. 269-276.
G. Botto et al., Synopsis of “Innovative Remote Controlled Completion for Aquila deepwater Challenge”, JPT, Oct./1997, originally presented at the 1996 SPE European Petroleum Conference, Milan, Italy, Oct. 22-24, 1996.
Sheila Popov, “Two Emerging Technologies Enhance Reservoir Management”, Hart's petroleum Engineer International, Jan. 1998, pp. 43-45.
Dick Ghiselin, “New Technology, New Techniques, Set the Pace for Success”, Hart's Petroleum Engineer International, Jan. 1998, pp. 48-49.
Ken R. LeSuer, “Breakthrough Productivity—Our Ultimate Challenge”, Offshore, Dec. 1987.
Thomas R. Bates, Jr., “Technology Pace Must Accelerate to Counter Oilfield Inflation”, Offshore, Dec. 1987.
Bjarte Bruheim, “Data management—A Key to Cost Effective E&P”, Offshore, Dec. 1987.
David M. Clementz, “Enabling Role of Information Technology: Where are the Limits?”, Offshore, Dec. 1997, p. 42.
George R. Remery, “Reshaping Development Opportunities”, and Davidi Hararis, “Training and Cooperation Critical to Deepwater Future”, Offshore, Dec. 1997, p. 44.
Ian C. Phillips, “Reservoir Management of the Future”, pp. 1-15, Halliburton M&S Ltd., Aberdeen, Scotland, Paper Presented at EU Thermie Conference 4/97 in Aberden, Scotland.
Related U.S. Application Serial No. 08/898,567, Inventors Brett W. Bouldin and Napoleon Arizmendi, “Flow Control Apparatus for use in a Subterranean Well and Associated Methods”, Attorney Docket No. 970031 U1 USA.