WO2017044105A1

WO2017044105A1 - Method and apparatus for well spudding scheduling

Info

Publication number: WO2017044105A1
Application number: PCT/US2015/049490
Authority: WO
Inventors: Ravigopal Vennelakanti; Anshuman SAHU; Yoshiyasu Takahashi; Tatsuhiro Sato; Iwao TANUMA
Original assignee: Hitachi, Ltd.
Priority date: 2015-09-10
Filing date: 2015-09-10
Publication date: 2017-03-16

Abstract

Example implementations described herein create a rich feature set based on observed/recorded attributes as well as attributes derived from those, and models each well as a data vector in this multi-dimensional attribute space. Example implementations then compute composite similarity between wells which provides better insights into their behavior. This composite similarity can be calculated along all dimensions or subsets of dimensions, and serve as input to any clustering algorithm for further analysis. Finally, the similarity can be incrementally computed by incorporating more attributes as required. Such implementations can be used to provide insights into behavior of oil wells, especially horizontal wells by integrating features from multiple upstream processes.

Description

METHOD AND APPARATUS FOR WELL SPUDDING SCHEDULING BACKGROUND Field [0001] The present disclosure relates generally to oil and gas data analytics, and more specifically, to conducting scheduling for well spudding. Related Art [0002] In the related art, oil and gas rigs utilize computerized systems to assist the operators of the rigs throughout the different phases of the oil or gas rigs (e.g., exploration, drilling, production, completions). Such computer systems are deployed for the development of energy sources such as shale gas, oil sands, and deep water resources. In the related art, attention has shifted to the development of shale gas for supplying future energy needs. Related art advances in horizontal directional drilling and hydraulic fracturing technologies have unlocked the potential for recovering natural gas from shale to become a viable energy source. [0003] However, the issue of maximizing output from an oil and gas reservoir, particularly shale gas reservoirs, is not well understood, even with the assistance from present computer systems. The process of making production decisions and sizing top-side facilities is a manual process that depends on the judgment of the rig operator. Furthermore, operators often struggle with real-time performance of support for down- hole gauges, semi-submersible pumps, and other equipment. Non-Productive Time (NPT) for a rig may constitute over 30% of the cost of drilling operations. [0004] One aspect of the issue of output maximization is the lack of effective data processing and data analytics, along with the sheer volume of data received from oil and gas wellsites. The data sets obtained from different upstream processes can be substantial in terms of number of available attributes. Manually developing applications that utilize these attributes can be very time-consuming. [0005] In particular, related art implementations for finding new locations for well drilling have been somewhat limited. In a related art implementation, there is an implementation to perform oilfield operations for an oilfield having a subterranean formation. Such related art implementations utilize business analysis of the oilfield based on business inputs, generating operation analysis of the oil field based on operation inputs and selectively integrating the business analysis with the operation analysis by using the operational output and the business inputs to form an integrated oilfield analysis. SUMMARY [0006] Aspects of the present disclosure include a management server configured to oversee management of a plurality of rig systems, each of the plurality of rig systems having a rig and a rig node. The management server can include a memory configured to store rig system information having rig location and rig production for each of the plurality of rig systems; oil density information relating a plurality of locations with a plurality of oil densities; production decline rate information indicative of a decline of oil production over time; well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; and well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems. The management server may also include a processor, configured to traverse an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determine a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; and estimate well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information. [0007] Aspects of the present disclosure can further include a method for management of a plurality of rig systems, each of the plurality of rig systems including a rig and a rig node. The method can include managing rig system information involving rig location and rig production for each of the plurality of rig systems; managing oil density information relating a plurality of locations with a plurality of oil densities; managing production decline rate information indicative of a decline of oil production over time; managing well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; managing well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems; traversing an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determining a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; and estimating well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information. [0008] Aspects of the present disclosure can further include a computer program for management of a plurality of rig systems, each of the plurality of rig systems including a rig and a rig node. The computer program can store instructions for executing a process, which can include managing rig system information comprising rig location and rig production for each of the plurality of rig systems; managing oil density information relating a plurality of locations with a plurality of oil densities; managing production decline rate information indicative of a decline of oil production over time; managing well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; managing well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems; managing discount rate information indicative of a discount of oil price over a period of time; managing well drilling cost information indicative of a cost for spudding a new well at each of the one or more locations; traversing an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determining a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating the well production of each of the plurality of rig systems within the minimum distance indicated by the well interference distance information of each of the one or more proposed new wells, based on the production decline rate information, the well interference rate information and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating gross margin for each of the one or more proposed new wells based on the estimated well production, the discount rate information and the well drilling cost information; storing the well initiation time, and the one or more locations of the one or more proposed wells that meet at least one of a production requirement and a gross margin requirement; storing the estimated well production for each of the one or more proposed new wells that meet the production requirement and the gross margin requirement; and storing the estimated well production of each of the plurality of rig systems within the minimum distance of each of the one or more proposed new wells that meet the production requirement and the gross margin requirement; wherein the production requirement is a total production requirement for each of the one or more proposed new wells and the plurality of rig systems within the minimum distance of the each of the one or more proposed new wells. BRIEF DESCRIPTION OF THE DRAWINGS [0009] FIG. 1(a) to 1(d) illustrate an example system environment on which example implementations can be implemented, including a plurality of rig systems and a management server, in accordance with an example implementation. [0010] FIG. 2 illustrates an example hardware configuration of management server, in accordance with an example implementation. [0011] FIG. 3 illustrates an overall flow diagram for the management server, in accordance with an example implementation. [0012] FIG. 4 illustrates example input data for production for each wellhead, in accordance with an example implementation. [0013] FIG. 5 illustrates example input data for oil production for a wellhead, in accordance with an example implementation. [0014] FIG. 6 illustrates example input data for mapping drilling costs and oil deposits, in accordance with an example implementation. [0015] FIG. 7 illustrates input parameters for the interface, in accordance with an example implementation. [0016] FIG. 8 illustrates example constraints, in accordance with an example implementation. [0017] FIG. 9 illustrates an example interface for the management server, in accordance with an example implementation. [0018] FIG. 10 illustrates an example input interface, in accordance with an example implementation. [0019] FIG. 11 illustrates an example flow diagram for the management server, in accordance with an example implementation. [0020] FIGS. 12 and 13 illustrate example interfaces for presenting production results, in accordance with an example implementation. [0021] FIG. 14 illustrates example management information for managing potential new wells, in accordance with an example implementation. [0022] FIG. 15 illustrates example management information for estimated oil production, in accordance with an example implementation. [0023] FIG. 16 illustrates the example of management information for new wells, after the filter is applied in accordance with an example implementation. [0024] FIG. 17 illustrates example management information for oil prices over time, in accordance with an example implementation. [0025] FIG. 18 illustrates an estimated production graph interface, in accordance with an example implementation. [0026] FIG. 19 illustrates an example well diagram, in accordance with an example implementation. DETAILED DESCRIPTION

[0027] The following detailed description provides further details of the figures and example implementations of the present application. Reference numerals and descriptions of redundant elements between figures are omitted for clarity. Terms used throughout the description are provided as examples and are not intended to be limiting. For example, the use of the term “automatic” may involve fully automatic or semi-automatic implementations involving user or administrator control over certain aspects of the implementation, depending on the desired implementation of one of ordinary skill in the art practicing implementations of the present application. The term“rig” and“well” may also be used interchangeably. “Rig systems” and“wellsites” may also be utilized interchangeably. [0028] In related art implementations, there is no implementation to facilitate the solving of a concrete problem as to where a well should be spud, the predicted economic efficiency of the spudding well, and the position and time to spud a well. In example implementations disclosed herein, there is a well spudding planning apparatus, which calculates the appropriate position and time to spud an oil well by simulation. [0029] In example implementations, there is a system for planning oil well spudding schedules. The system can include a data input apparatus, from which geometric information and a production data can be input to the system from a data provider, a parameter input apparatus, with which parameters can be input into the system, a calculation apparatus for recommended well positions, which calculates the recommended positions of wells with the oil production estimation apparatus, a display apparatus to display the recommended well positions, and in the display apparatus, a display of the interference of nearby oil wells, the production decline by time, the net present total value of gross margins including the discount rate. [0030] FIG. 1(a) to 1(d) illustrate an example system environment on which example implementations can be implemented, including a plurality of rig systems and a management server, in accordance with an example implementation. Specifically, FIG. 1(a) illustrates a system involving a plurality of rig systems and a management server, in accordance with an example implementation. One or more rig systems 101-1, 101-2, 101- 3, 101-4, and 101-5 can each involve a corresponding rig 20-1, 20-2, 20-3, 20-4, 20-5 as illustrated in FIG.1(b) along with a corresponding rig node 30-1, 30-2, 30-3, 30-4, and 30- 5 as illustrated in FIG. 1(c). Each of the rig systems 101-1, 101-2, 101-3, 101-4, and 101-5 is connected to a network 102 which is connected to a management server 103. The management server 103 manages a database 108, which contains data aggregated from the rig systems in the network 102. In alternate example implementations, the data from the rig systems 101-1, 101-2, 101-3, 101-4, and 101-5 can be aggregated to a central repository or central database such as public databases that aggregate data from rigs or rig systems, such as for government compliance purposes, and the management server 103 can access or retrieve the data from the central repository or central database. [0031] FIG. 1(b) illustrates an example rig 20 in accordance with an example implementation. The example implementation depicted in FIG. 1(b) is directed to a shale gas rig. However, similar concepts can be employed at other types of rigs as well without departing from the inventive scope. For example, but not by way of limitation, example implementations described herein can also be applied to horizontal oil wells by integrating features from multiple upstream processes. The well 21 may include one or more gas lift valves 21-1 which are configured to control hydrostatic pressure of the tubing 21-2. Tubing 21-2 is configured to extract gas from the well 21. The well 21 may include a case 21-3 which can involve a pipe constructed within the borehole of the well. One or more packers 21-4 can be employed to isolate sections of the well 21. Perforations 21-5 within the casing 21-3 allow for a connection between the shale gas reservoir to the tubing 21-2. [0032] The rig 20 may include multiple sub-systems directed to injection of material into the well 21 and to the production of material from the well 21. For the injection system 2500 of the rig 20, there may be a compressor system 22 that includes one or more compressors that are configured to inject material into the well such as air or water. A gas header system 22 may involve a gas header 22-1 and a series of valves to control the injection flow of the compressor system 22. A choke system 23 may include a controller or casing choke valve which is configured to reduce the flow of material into the well 21. [0033] For the production system 2600 of the rig 20, there may be a wing and master valve system 24 which contains one or more wing valves configured to control the flow of production of the well 21. A flowline choke system 25 may include a flowline choke to control flowline pressure from the well 21. A production header system 26 may employ a production header 26-1 and one or more valves to control the flow from the well 21, and to send produced fluids from the well 21 to either testing or production vessels. A separator system 27 may include one or more separators configured to separate material such as sand or silt from the material extracted from the well 21. [0034] As illustrated in FIG. 1(b) various sensors may be applied throughout the rig to measure various data or attributes for a rig node, which are described in further detail below. The sensors are identified by an“S” in an octagon in FIG. 2. These sensors provide feedback to the rig node which can interact with the system as illustrated in FIGS. 1(a) and 1(c), and can be fed to the management server 103 for database storage 108, and/or supplied to a central repository or database such as a public database, which can then be harvested by management server 103. [0035] FIG. 1(c) illustrates an example configuration of a rig system 101, in accordance with an example implementation. The rig system 101 includes a rig 20 as illustrated in FIG. 1(b) which contains a plurality of sensors 21. The rig system 101 includes a rig node 30 which may be in the form of a server or other computer device and can contain a processor 31, a memory 32, a storage 33, a data interface (I/F) 34 and a network I/F 35. The data I/F 34 interacts with the one or more sensors 21 of the rig 20 and store raw data in the storage 33, which can be sent to a management server for processing, or to a central repository or central database. The network I/F 35 provides an interface to connect to the network 102. [0036] FIG. 1(d) illustrates an example system environment for the management server 103, in accordance with an example implementation. Management server 103 communicates with one or more data providers 101 over the network 102. As illustrated in FIGS. 1(a) and 1(b), the data providers can be one or more individual rig systems 101 sending aggregated data directly to the management server 103, or can a central repository or central database such as public databases that aggregate data from rigs or rig systems, such as for government compliance purposes, wherein the management server 103 can access or retrieve the data from the central repository or central database. Data providers 101 can also be data provided by databases of local governments or other organization that survey oil reservoirs. [0037] Management server 103 is configured to function as a planning system for the oil well spudding schedule, and can include a data input apparatus 104, a control unit 105, an oil production prediction apparatus 106, a recommended well position calculation apparatus 107, a database apparatus 108, and a terminal apparatus 109. Data input apparatus 104 is an apparatus that conducts data collection from data provider 101, which can be, for example, through the internet or other methods. Control unit 105 may involve a server controller having multiple processors and memory to invoke the functions of the management server 103. Oil production prediction apparatus 106 can involve hardware or a combination of hardware and software to perform the prediction operations of oil production for predicting the oil production for proposed new wells as well as present wells. Recommended well position calculation apparatus 107 can involve hardware or a combination of hardware and software to perform a recommendation for the well position as well as the timing to maximize a metric such as production or gross margin. Database apparatus 108 may be internal to the management server 103, or can be implemented by any desired implementation, such as but not limited to an external or internal storage system management by the management server 103. Terminal apparatus 109 provides hardware for an operator to interact with the management server 103, and can include a display, input/output devices, and so on. [0038] Database apparatus 108 may store information such as input data 110, parameters 111, constraints 112, estimated oil production 113, and recommended spudding plans 114. Input data 110 includes data regarding managed wells or reservoirs which is obtained over network 102 from data providers 101. Input parameters 111 include parameters provided by the operator of the management server 103 for determining the location and spudding plan for a new well. Constraints 112 for proposing a new well are generated by the control unit 105 from the input data 110 and parameters 111. Estimated oil production 113 is the calculated result of oil production from oil production prediction apparatus 104. From the estimated oil production 113, the management server can utilize the recommended well position calculation apparatus 107 to generate spudding plans to be stored as recommended spudding plan 114. [0039] FIG. 2 illustrates an example hardware configuration of management server 103, in accordance with an example implementation. In the example configuration illustrated in FIG. 2, there is a central processing unit (CPU) 201, a memory 202, an I/F 203, a network I/F 204, one or more I/O devices 205, a display 206, and one or more storage devices 207. CPU 201 and memory 202 may work in tandem to function as a controller for a management server 103, which can be used to send and receive instructions to the remaining hardware elements of the management server 103 through interface 203. Network I/F 204 may be used to interact with data providers 101 through network 102, which can facilitate the management server 103 to oversee management of rig systems as described above, wherein the management server 103 can obtain the rig system information and oil density information from a data provider associated with the plurality of rig systems. The one or more I/O devices 205 may include devices such as a keyboard, a mouse, a touchscreen, and so forth, to facilitate input from an operator to the management server 103. Display 206 may be utilized to display the interfaces as described herein. Storage devices 207 may store instructions for executing the flow diagrams and interfaces as described herein, which can be loaded into memory 202 and executed by CPU 201. [0040] Storage devices 207 may be configured to facilitate the functionality of database 108 to store management information that can be loaded into memory 202 for use by CPU 201. The memory 202 can be configured to load and store management information from storage devices 207, which can include rig system information indicating rig location and rig production for each of the plurality of rig systems as illustrated in FIGS. 4 and 5, oil density information relating a plurality of locations with a plurality of oil densities as illustrated in FIG. 6; production decline rate information indicative of a decline of oil production over time as illustrated in FIG.7; well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system as illustrated in FIG. 7; and well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems as illustrated in FIG.7. [0041] CPU 201 can execute instructions for the management server 103 to traverse an area for one or more locations for one or more proposed new wells, based on the oil density information of FIG.6. The area can be defined in an interface as illustrated in FIG. 9 and translated into constraints as illustrated in FIG. 8. For each of the one or more locations for the one or more proposed new wells, the CPU 201 may be configured to determine a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information as described, for example, with respect to equations (4) and (5) below. CPU 201 may also be configured to estimate well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information as illustrated, for example, with respect to equations (3) and (6) below. CPU 201 may be further configured to store into the memory 202 the well initiation time, and the one or more locations of the one or more proposed wells that meet at least one of a production requirement and a gross margin requirement as illustrated in FIG.7. [0042] CPU 201 may also be configured to estimate the well production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information of each of the one or more proposed new wells, based on the production decline rate information, the well interference rate information and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information as illustrated in FIG. 7 with respect to equations (1), (2), (3) and (6). Further, the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and subsurface brittleness, as described with respect to FIGS.18 and 19. [0043] In example implementations, the memory 202 is further configured to load and store discount rate information indicative of a discount of oil price over a period of time; and well drilling cost information indicative of a cost for spudding a new well at each of the one or more locations as illustrated in FIGS. 7 and 14. Further, the CPU 201 can be further configured to estimate gross margin for each of the one or more proposed new wells based on the estimated well production, the discount rate information and the well drilling cost information as illustrated in FIG. 14. [0044] FIG. 3 illustrates an overall flow diagram for the management server 103, in accordance with an example implementation. The flow begins at 301, wherein the management server 103 receives inputs on parameters and data and stores the parameters and data into database 108. At 304, the management server 304 runs a simulation and estimates oil production. At 305, the management server calculates the recommended position of the new oil well. Further detail of each of the flow processes are outlined with respect to the description of the figures below. [0045] FIG. 4 illustrates example input data for production for each wellhead, in accordance with an example implementation. The input data is received from data providers 101 and stored as input data 110 in database 108 as part of the execution of the flow at 301 of FIG. 3. The data is obtained by data input apparatus 104 from data providers 101 to associate well production data with wellhead positions. In FIG. 4, there is an input data identifier (ID) 401, the x-coordinate of the wellhead 402, the y coordinate of the wellhead 403, and the oil well production data ID 404. [0046] FIG. 5 illustrates example input parameters for oil production for a wellhead, in accordance with an example implementation. The input data is received from data providers 101 and stored as input data 110 in database 108 as part of the execution of the flow at 301 of FIG. 3. In the example implementation of FIG. 5, the data is a drill down of the oil well production data corresponding to oil well production dataID 11 as indicated in the first row entry of FIG. 4. FIG. 5 includes a column for the sequential number of the production data 501, a column for a timestamp of the production value 502, and a column for production values 503. [0047] FIG. 6 illustrates example input data for mapping drilling costs and oil deposits, in accordance with an example implementation. The input data is received from data providers 101 and stored as input data 110 in database 108 as part of the execution of the flow at 301 of FIG.3. In the example implementation of FIG.6, there is a column for a position x0 along an x-axis 601, a column for a position y0 along a y-axis 602, a column for a position z0 along a z-axis 603, a column for another corresponding position x1 along the x-axis 604, a column for another corresponding position y1 along the y-axis 605, a column for another corresponding position z1 along the z-axis 606, the value of oil deposits within the area formed from (x0,y0,z0) to (x1,y1,z1) 607, and the cost for drilling within the area 608. The value of oil deposits 607 can be in terms of density (e.g. some amount of oil per square meter). In example implementations, when the pathway of the proposed new well is determined between coordinates (x0, y0, z0) and (x1, y1, z1), the density value can then be used to estimate the initial oil production at P(0), as described in further detail below. [0048] FIG. 7 illustrates input parameters for the interface, in accordance with an example implementation. The input parameters are parameters received through the interface of the management server as provided by an operator through an interface implemented on a terminal apparatus 109 of FIG. 1(d), and can be stored as parameters 111 in database 108 as part of the flow 301 of FIG. 3. Column 701 contains example parameters that can be received through the interface of the management server, and can include a search range from (x0,y0,z0) to (x1,y1,z1) for the candidate well position (as illustrated with box 906 of FIG. 9), search date from t0 to t1 (e.g., range for the optimization timing), the well interference limit (the distance threshold within which a new well impacts or is impacted by other wells), the well interference rate (the interference ratio when the proposed well is within a threshold distance from another well), the production decline rate (indicative of the production level after one year), the discounted rate of production for existing wells, and other parameters, depending on the desired implementation. Column 702 contains values for the parameters of column 701. [0049] FIG. 8 illustrates example constraints, in accordance with an example implementation. The constraints may be stored as constraints 112 in database 108 and generated by control unit 105 from input data 110 and parameters 111 as part of the flow 301 of FIG. 3. Column 801 contains constraint IDs that associate each of the stored constraints with an ID. Column 802 contains constraints for the management server in determining the placement of a new well. The constraints are derived from the input parameters as illustrated in FIG. 7. For example, FIG. 8 illustrates the conversion of the search ranges as provided in the input parameters of FIG. 7 to the constraints as listed in column 802. [0050] FIG. 9 illustrates an example interface for the management server, in accordance with an example implementation. Interface 901 includes a button to reload input data 902, a button to set parameters 903, a button to estimate production 904, and a map of the reservoir for new well placement 905. The map 905 may be used to select an area 906 within the map for restricting the area for the new well location. The reload input data 902 may cause the management server to refresh data stored in the database 108 by obtaining recent data from data providers 101. The set parameters 903 generates an interface as illustrated in FIG. 10 to take input parameters for the management information of FIG. 7. The area 906 can be utilized to generate the values for the search range in FIG. 7, which is then used to generate constraints for the area used in FIG.8. [0051] FIG. 10 illustrates an example input interface, in accordance with an example implementation. Interface 1001 is generated in response to a selection of the set parameters button 903 of FIG. 9. Interface 1001 includes an input interface to receive input parameters 1002, a button to accept the input parameters 1003, and a button to cancel the present input 1004. Input parameters 1002 are stored as the input parameters as illustrated in FIG.7. [0052] From the management information illustrated in FIGS. 4-8 and from the input received through the interfaces of FIGS. 9 and 10, the flow proceeds to 304 to run the simulation and estimate the oil production when the estimate production button 904 is selected through the interface 901 of FIG. 9. In example implementations, when executing simulations for estimating well production, the well production curve for a well can be generalized by the following equation (1):

[0053] In equation (1), P(t) is the production of the well at time t, and parameter b is production decline rate as obtained from FIG. 7. With added input values of the example implementations, based on the input values, the production values can be estimated for a proposed new well in example implementations with the following equation (hereby referred to as equation (2)):

[0054] where P(t) is the production of the well at time t, parameter a is the well interference rate from FIG.7, and parameter b is production decline rate from FIG. 7. P(0) can be determined from the location of the proposed new well based on the information in FIG. 6. [0055] FIG. 11 illustrates an example flow diagram for the management server, in accordance with an example implementation. Specifically, the flow diagram illustrates an example implementation for the flow at 304 and 305 of FIG. 3 for the simulation of oil wells and estimation of oil production, as well as the calculation of a location for a new well. At 1101, the management server initiates the iteration loop for conducting the search for a new well based on position and time from utilizing oil production prediction apparatus 106. Specifically, the oil production prediction apparatus 106 will traverse a selected area from coordinates (x0, y0, z0) to (x1, y1, z1) based on the oil deposit density from FIG. 6, in any manner according to the desired implementation (e.g., traverse only areas with oil deposit density exceeding a threshold, conduct well placement in set space increments, etc.), and terminates the loop once the selected area is traversed according to the desired implementation. In the iteration, the oil production prediction apparatus 106 may select (x, y, z) tuple within the region of (x0, y0, z0) to (x1, y1, z1), by stepping x, y, z, respectively; 1^st (x0,y0,z0), 2^nd (x0+ǻx, y0, z0), 3^rd (x0+2ǻx, y0, z0), and so on. Then after surpassing x1, the oil production prediction apparatus may iterate from (x0, y0+ǻy, z0), and so on, where ǻx, ǻy, (and ǻz) are predefined constant values and may be given by system’s configuration parameters. After surpassing (x1,y1,z1), the iteration will be terminated. At 1102, the management server determines the true vertical depth of the new well for a configuration where the estimated maximum production is relatively high. The determination is made based on traversing the constrained area as provided in FIG. 7 and comparing the area to the oil deposit density of FIG. 6 for establishing P(0). At 1103, the management server determines the depth of the new well including the horizontal part of the well, by satisfying the depth constraint as illustrated in FIG. 7. The horizontal pathway of the new well can be determined through any desired methods known to one of ordinary skill in the art based on the locations of current wells. At 1104, the management server calculates the estimated well production by conducting a summation of the oil deposits from FIG. 6, based on the pathway of the decided well trajectory versus the depth, and from equations (1) and (2). [0056] At 1105, the management server initiates a loop to iterate calculations for the new well based on all of the nearby wells within the well interference limit. To initiate the loop, the management server may search the input data for production for each wellhead (FIG. 4). By calculating the distance between the new well’s position and the searched one’s wellhead position (402, 403), the management server can enumerate all the nearby wells within the well interference limit. After iterating all the enumerated wells, the loop may be terminated. To determine the production values for a new well and another well within the range of the well interference limit, the following equation can be utilized (hereby referred to as equation (3)).

[0057] where P_T is the total production value for a new well and another well, parameter a and b is the same as equation (2), and parameter c is discounted rate of production for existing wells. [0058] To determine the time T for which the production value P_T is maximized, the time T is solved based on equation (3) such that P_T‘ is zero. P_T‘ is given by equation (4) below:

[0059] Solving for T when P_T‘ is zero, the time at which maximum production occurs is solved based on equation (5) below:

[0060] In an example where more than one well is placed within the well zone limit, the total production can be calculated by equation (6) below:

[0061] In the example illustrated in equation (6), parameter a can be made as a function to more accurately model the well interference ratio, in accordance with the desired implementation. For example, example functions a(x,y) can be:

[0062] and so on depending on the desired implementation. In the example function which involves brittleness of the subsurface, brittleness(x) can be defined as: if the subsurface of x includes quartz levels above a desired threshold, brittleness(x) = 100%, if the subsurface of x includes clay levels above a desired threshold, then brittleness(x)=50%. The equations provided herein are examples, and other equations can be utilized depending on the desired implementation. For example, another equation that can be utilized is

[0063] which can be an example equation for two wells running parallel to each other. Thus, in example implementations, the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and at least one of a parallel fracture length between the proposed new well and the at least one rig system from the plurality of rig systems and a number of fractures. [0064] At 1106, the management server calculates the estimated production based on well interference as described above in equations (3) to (6). In an example implementation, the management server derives and multiples the parameter a as described above to the estimated production for wells placed near each other within the well interference limit. At 1107, the management server stores the estimated production values into the database 108 as estimated production values 113. The flow diagram proceeds to 305 to select a position and time that meets the desired production values (e.g., select the wells beyond the threshold or the highest producing well) with each of the wells ranked by position and time through a normalized score. The results can then be displayed by utilizing the normalized rate as illustrated in FIG. 12. [0065] FIG. 12 illustrates an example interface for presenting estimated production results, in accordance with an example implementation. The interface 1201 is generated based on the flow of FIG.11 and when the estimate production button 904 is selected from the interface 901 of FIG. 9. The interface 1201 contains a map 1202 of the wells, a button to display the estimated production 1203, and a button to close the interface 1204. Results can be presented in the form of zones on the map 1202 of potential locations for new wells as illustrated at 1205. The zones can indicate production values that are within specified ranges for a desired parameter (e.g., oil production, gross margin, etc.). For example, the outer zone can indicate areas for drilling a new well that meet a“good” standard (i.e., within a first production range as set by the user), the middle zone can indicate areas for drilling a new well that meet an“excellent” standard (i.e., higher than the first production range and within a second production range as set by the user), and the inner zone can indicate areas for drilling a new well that meet the“best” standard (i.e., higher than the second production range as set by the user). When the button to display the estimated production 1203 is pressed, the interface can then proceed to the interface as illustrated in FIG. 13 to display results. [0066] FIG. 13 illustrates an example interface for presenting estimated production results, in accordance with an example implementation. Specifically, FIG. 13 illustrates an interface 1301 resulting from pressing the estimated production button 1203 on the interface 1202 of FIG. 12. Panel 1302 illustrates example results for production, cost and gross margin. Results may also be presented in graph form as illustrated at 1303 and plotted out based on equations (3) and (4). Close button 1304 exits the interface 1301 and proceeds back to the interface 1201 of FIG. 12. [0067] FIG. 14 illustrates example management information for managing potential new wells, in accordance with an example implementation. Specifically, FIG. 14 illustrates example results from conducting a simulation of oil production for potential well locations. The management information for managing potential new wells can be stored as estimated oil production 113 in database 108. The management information can include a column 1401 for the well position on the x-axis, a column 1402 for the well position on the y-axis, a column 1403 for the well position on the z-axis, a column 1404 for indicating the drilling time, a column 1405 for the cost of drilling, a column 1406 for an identifier for the estimated oil production, and a column 1407 for the estimated gross margin. An example of the formula for the estimate gross margin can be

where c(t) is discount rate and P(t) is estimated oil production. The cost of drilling can be provided, for example, from the input data for mapping drilling costs and oil deposits as illustrated in FIG. 6 based on the pathway of the proposed new well throughout the x, y and z-axis. [0068] FIG. 15 illustrates example management information for estimated oil production, in accordance with an example implementation. The management information for the estimated oil production can be stored as estimated oil production 113 in database 108. In the example of FIG. 15, there is a column 1501 for the well ID, a column 1502 for the time for drilling the well, and a column 1503 for the estimated oil production. The values for the estimated oil production can be determined from equation (2), with P(0) being set, for example, from the value of the oil deposits as illustrated in FIG. 6, and then iterated over a time value as illustrated in column 1502. In the example of FIG. 15, new well having well ID of 9001 is spudded at time t=2, and interferes with well ID 1002 and well ID 1001, which is disposed within the well interference limit of well ID 9001. The estimated oil production 1503 list values for the three wells that are based on a well interference rate of a = 0.7, and a production decline rate of b = 0.6. The values are for the estimated oil production detailed data ID 5 of FIG. 14, which has an estimated gross margin of 9610. [0069] FIG. 16 illustrates the example of management information for new wells, after the filter is applied in accordance with an example implementation. Specifically, FIG. 16 illustrates the results from FIG. 14 after a threshold is applied for selecting the potential new wells that meet the threshold. The results after the filter can be stored, for example, in the recommended spudding plan 114 of the database 108. Similar to FIG. 14, the management information can include a column 1601 for the well position on the x-axis, a column 1602 for the well position on the y-axis, a column 1603 for the well position on the z-axis, a column 1604 for indicating the time at which drilling begins (e.g., what month), a column 1605 for the cost of drilling, a column 1606 for an identifier for the estimated oil production, and a column 1407 for the estimated gross margin. Examples of thresholds can be top 10% production or margin values of all proposed wells, top 20% production or margin values of all proposed wells, top 5 selections, and so on. [0070] FIG. 17 illustrates example management information for oil prices over time, in accordance to an example implementation. The information for the oil prices can be downloaded from the data provider(s) 101 as described with respect to FIG. 1(d). The management information can include a column for time 1701, and a column for oil prices 1702, which can be utilized to estimate the gross margin. [0071] FIG. 18 illustrates an estimated production graph interface, in accordance with an example implementation. Similar to FIG. 13, panel 1802 illustrates an example estimation for production, cost and gross margin, for a new well and neighboring wells based on the results as illustrated in FIG. 15. Results may also be presented in graph form as illustrated at 1803. Close button 1804 exits the interface 1801 and proceeds back to the interface 1201 of FIG. 12. The example in graph 1803 is calculated by utilizing equation (6) for two proposed new wells. [0072] FIG. 19 illustrates an example well diagram, in accordance with an example implementation. Specifically, FIG. 19 illustrates an interface 1901, which illustrates the well diagram for a proposed well selected from 1205 of FIG.12. Interface 1901 includes a panel 1902 which indicates distance between a new proposed well 1906 and a current well 1905, the number of fractures (indicated by X on the well diagram 1903), the sediment type, and the parallel fracture length. In example implementations, the panel 1902 can be used to select the parameters utilized for determining the well interference rate. For example, the sediment type can be selected so that the sediment equations as described above can be utilized. Other factors can include the parallel fracture length, the distance between wells, and the number of fractures running in parallel, depending on the desired implementation. [0073] Thus, through example implementations, the operator or manager of the rigs can determine not just a location for drilling a new rig, but also the timing of the drilling of the new rig to maximize a desired metric such as production or gross margin. With the values provided in the example implementations, the manager of the rigs can create plans to drill a new rig at a certain time to maximize the metric. [0074] Some portions of the detailed description are presented in terms of algorithms and symbolic representations of operations within a computer. These algorithmic descriptions and symbolic representations are the means used by those skilled in the data processing arts to convey the essence of their innovations to others skilled in the art. An algorithm is a series of defined steps leading to a desired end state or result. In example implementations, the steps carried out require physical manipulations of tangible quantities for achieving a tangible result. [0075] Unless specifically stated otherwise, as apparent from the discussion, it is appreciated that throughout the description, discussions utilizing terms such as “processing,”“computing,”“calculating,”“determining,”“displaying,” or the like, can include the actions and processes of a computer system or other information processing device that manipulates and transforms data represented as physical (electronic) quantities within the computer system’s registers and memories into other data similarly represented as physical quantities within the computer system’s memories or registers or other information storage, transmission or display devices. [0076] Example implementations may also relate to an apparatus for performing the operations herein. This apparatus may be specially constructed for the required purposes, or it may include one or more general-purpose computers selectively activated or reconfigured by one or more computer programs. Such computer programs may be stored in a computer readable medium, such as a computer-readable storage medium or a computer-readable signal medium. A computer-readable storage medium may involve tangible mediums such as, but not limited to optical disks, magnetic disks, read-only memories, random access memories, solid state devices and drives, or any other types of tangible or non-transitory media suitable for storing electronic information. A computer readable signal medium may include mediums such as carrier waves. The algorithms and displays presented herein are not inherently related to any particular computer or other apparatus. Computer programs can involve pure software implementations that involve instructions that perform the operations of the desired implementation. [0077] Various general-purpose systems may be used with programs and modules in accordance with the examples herein, or it may prove convenient to construct a more specialized apparatus to perform desired method steps. In addition, the example implementations are not described with reference to any particular programming language. It will be appreciated that a variety of programming languages may be used to implement the teachings of the example implementations as described herein. The instructions of the programming language(s) may be executed by one or more processing devices, e.g., central processing units (CPUs), processors, or controllers. [0078] As is known in the art, the operations described above can be performed by hardware, software, or some combination of software and hardware. Various aspects of the example implementations may be implemented using circuits and logic devices (hardware), while other aspects may be implemented using instructions stored on a machine-readable medium (software), which if executed by a processor, would cause the processor to perform a method to carry out implementations of the present application. Further, some example implementations of the present application may be performed solely in hardware, whereas other example implementations may be performed solely in software. Moreover, the various functions described can be performed in a single unit, or can be spread across a number of components in any number of ways. When performed by software, the methods may be executed by a processor, such as a general purpose computer, based on instructions stored on a computer-readable medium. If desired, the instructions can be stored on the medium in a compressed and/or encrypted format. [0079] Moreover, other implementations of the present application will be apparent to those skilled in the art from consideration of the specification and practice of the teachings of the present application. Various aspects and/or components of the described example implementations may be used singly or in any combination. It is intended that the specification and example implementations be considered as examples only, with the true scope and spirit of the present application being indicated by the following claims.

Claims

What is claimed is: 1. A management server configured to oversee management of a plurality of rig systems, each of the plurality of rig systems comprising a rig and a rig node, the management server comprising: a memory configured to store: rig system information comprising rig location and rig production for each of the plurality of rig systems; oil density information relating a plurality of locations with a plurality of oil densities; production decline rate information indicative of a decline of oil production over time; well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; and well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems; and, a processor, configured to: traverse an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determine a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; and estimate well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information.

2. The management server of claim 1, wherein the processor is further configured to store into the memory the well initiation time, and the one or more locations of the one or more proposed wells that meet at least one of a production requirement and a gross margin requirement.

3. The management server of claim 1, wherein the processor is configured to estimate the well production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information of each of the one or more proposed new wells, based on the production decline rate information, the well interference rate information and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information.

4. The management server of claim 1, wherein the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and subsurface brittleness.

5. The management server of claim 1, wherein the memory is further configured to store: discount rate information indicative of a discount of oil price over a period of time; and well drilling cost information indicative of a cost for spudding a new well at each of the one or more locations; wherein the processor is further configured to estimate gross margin for each of the one or more proposed new wells based on the estimated well production, the discount rate information and the well drilling cost information.

6. The management server of claim 1, wherein the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and at least one of a parallel fracture length between the proposed new well and the at least one rig system from the plurality of rig systems and a number of fractures.

7. The management server of claim 1, wherein the processor is configured to obtain the rig system information and oil density information from a data provider associated with the plurality of rig systems.

8. A method for management of a plurality of rig systems, each of the plurality of rig systems comprising a rig and a rig node, the method comprising: managing rig system information comprising rig location and rig production for each of the plurality of rig systems; managing oil density information relating a plurality of locations with a plurality of oil densities; managing production decline rate information indicative of a decline of oil production over time; managing well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; managing well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems; traversing an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determining a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; and estimating well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information.

9. The method of claim 8, further comprising storing the well initiation time, and the one or more locations of the one or more proposed wells that meet at least one of a production requirement and a gross margin requirement.

10. The method of claim 8, further comprising estimating the well production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information estimating the well production of each of the plurality of rig systems within the minimum distance indicated by the well interference distance information of each of the one or more proposed new wells, based on the production decline rate information, the well interference rate information and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information.

11. The method of claim 8, wherein the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and subsurface brittleness.

12. The method of claim 8, further comprising: managing discount rate information indicative of a discount of oil price over a period of time; managing well drilling cost information indicative of a cost for spudding a new well at each of the one or more locations; and estimating gross margin for each of the one or more proposed new wells based on the estimated well production, the discount rate information and the well drilling cost information.

13. The method of claim 8, wherein the relationship of the well interference rate information is determined from a function involving the distance between the proposed new well and at least one rig system from the plurality of rig systems, and at least one of a parallel fracture length between the proposed new well and the at least one rig system from the plurality of rig systems and a number of fractures.

14. The method of claim 8, further comprising obtaining the rig system information and oil density information from a data provider associated with the plurality of rig systems.

15. A computer program for management of a plurality of rig systems, each of the plurality of rig systems comprising a rig and a rig node, the computer program storing instructions comprising: managing rig system information comprising rig location and rig production for each of the plurality of rig systems; managing oil density information relating a plurality of locations with a plurality of oil densities; managing production decline rate information indicative of a decline of oil production over time; managing well interference distance information indicative of a minimum distance at which a proposed new well affects production of at least one rig system; managing well interference rate information indicative of a relationship between oil production and distance between a proposed new well and at least one rig system from the plurality of rig systems; managing discount rate information indicative of a discount of oil price over a period of time; managing well drilling cost information indicative of a cost for spudding a new well at each of the one or more locations; traversing an area for one or more locations for one or more proposed new wells, based on the oil density information; for each of the one or more locations for the one or more proposed new wells, determining a well initiation time that maximizes production, based on the production decline rate, the well interference rate information, and the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating well production for each of the one or more proposed new wells based on the well interference rate information, the rig location for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information, and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating the well production of each of the plurality of rig systems within the minimum distance indicated by the well interference distance information of each of the one or more proposed new wells, based on the production decline rate information, the well interference rate information and the rig production for each of the plurality of rig systems within the minimum distance indicated by the well interference distance information; estimating gross margin for each of the one or more proposed new wells based on the estimated well production, the discount rate information and the well drilling cost information; storing the well initiation time, and the one or more locations of the one or more proposed wells that meet at least one of a production requirement and a gross margin requirement; storing the estimated well production for each of the one or more proposed new wells that meet the production requirement and the gross margin requirement; and storing the estimated well production of each of the plurality of rig systems within the minimum distance of each of the one or more proposed new wells that meet the production requirement and the gross margin requirement; wherein the production requirement is a total production requirement for each of the one or more proposed new wells and the plurality of rig systems within the minimum distance of the each of the one or more proposed new wells.