Online thermal and watercut management

A system, method, and software for optimizing the commingling of well fluids from a plurality of producing subsea wells. The mixing temperature and water content in each header of a collection manifold are calculated for each subsea well and header combinations, responsive to data from sensors at the collection manifold. Combinations with conditions outside operational limits are then discarded. Remaining combinations are ranked based on predetermined optimization criteria. The ranked combinations are provided for the operator for optimizing flow properties and well fluid production. The calculations can restart with new, real-time sensed values from the subsea collection manifold.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates in general to subsea well installations and in particular to a method of managing production from a plurality of subsea wells.

2. Background of the Invention

In a subsea oil field it is common practice to drill a plurality or cluster of subsea wells for the more efficient production of well fluid from an oil field. The well fluid typically contains water, hydrocarbon gas (gas), and hydrocarbon liquid (oil). A subsea collection manifold is sometimes used to collect the well fluid from each of the plurality of subsea wells rather than transporting the well fluid from each of the individual wells to the surface. From the collection manifold, a common riser can transport the well fluid from all of the subsea wells to a vessel at the surface of the sea.

In other situations, a riser extends from each subsea well to a vessel or platform at the surface. The well fluid from each of the wells is then transported through a common conduit to a floating production storage and offloading (FPSO) vessel located away from the platform. In this situation, the well fluid from each of the subsea wells commingle in a collection manifold located topside, on the platform, and are then pumped down to the FPSO. The conduit typically extends from the platform, along the subsea surface, and then back up to the FPSO.

In both situations, the well fluid from each of the subsea wells are commingled in a collection manifold, and then conveyed through a common riser or conduit. When multiple inflows are merged into a smaller number of outflows at a commingling point in a converging production network, the resulting mixing temperature and mixing watercut or water content in each outflow depend on how the inflows are combined. An optimum or desired combination is sometimes determined by mixing temperatures and/or water cuts. For example, an optimum or desired combination could be one that gives the highest mixing temperature in the coldest outflow in order to minimize wax or hydrate problems, or one that ensures a water cut far away from the inversion point in each outflow in order to minimize emulsion problems. In other words, in various situations, the desired or optimized mixing temperature and water content of the mixing well fluid can vary based on the situation, and the operating conditions.

The number of possible combinations can be extremely large. With n inflows and k outflows, where each inflow can be routed to any outflow, the total number N of possible combinations is given as
N=kn

For example, with 20 inflows and 4 outflows, there are more than a trillion combinations. Trying to optimize the commingling by trial and error or offline hand calculations can therefore be cumbersome. Furthermore, flow conditions change continuously and offline calculations based on flow rates measured in the last well tests might become inaccurate, in particular if key events, like water breakthrough, have occurred after the last well tests.

SUMMARY OF THE INVENTION

A system manages production of well fluid from the collection manifold receiving well fluid from a plurality of subsea wells. The system includes calculator software, which determines selected flow rate of well fluid from each of the plurality of subsea wells in order to achieve desired temperatures and water content of the well fluid exiting the collection manifold. The calculator software calculates the selected flow rates by comparing a calculated mixing temperature and a water content of the well fluids collecting in the collection manifold. The calculated mixing temperature and water contents are responsive to a paired combination selected from of the inlet pressure, temperature, and flow rate of the well fluid entering the collection manifold from each of the plurality of subsea wells. The operator has provided a desirous, predetermined water content and a desirous temperature for the well fluid exiting the collection manifold for the calculator software to attempt to achieve.

The system includes a pressure sensor that communicates with the calculator software. The pressure sensor is positioned between the well fluid output of each of the plurality of subsea wells and the collection manifold. The pressure sensor senses the well fluid pressure of the well fluid before entering the collection manifold and commingling with well fluid from other subsea wells. The system includes a temperature sensor that also communicates with the calculator software. The temperature sensor is positioned between the well fluid output of each of the plurality of subsea wells. The temperature sensor senses the well fluid temperature of the well fluid before entering the collection manifold and commingling with the well fluid from other subsea wells by selectively actuating the flow control valves. Alternatively, the system can include a flow meter in place of either the pressure sensor or the temperature sensor.

The system further includes flow control valves positioned between each of the plurality of wells and the collection manifold. The flow control valves control the flow rate of the well fluid entering the collection manifold. The system also includes a controller. The controller selectively controls the flow rate of the well fluid entering the collection manifold from each of the plurality of subsea wells.

Another aspect of the present invention additionally provides a software located on a server. The software manages well fluid production from plurality of subsea wells feeding into a subsea collection manifold through a plurality of control valves. The software regulates the flow of the well fluid from each of the plurality of subsea wells. The software includes an operating conditions calculator to calculate a plurality of predetermined individual well fluid properties of the well fluid from each of the plurality of subsea wells. The conditions calculator also calculates a plurality of well fluid properties of a mixture well fluid commingling in the collection manifold when the well fluid from each of the plurality of subsea wells enters the collection manifold. The software further includes a flow rate determiner to determine selected flow rates of well fluid from each of the plurality of subsea wells. The software determines selected flow rates responsive to comparing the properties of the mixture of cumulative well fluid in the collection manifold and a predetermined set of values for well fluids exiting the collection manifold entered by an operator.

A method or process for optimizing the commingling of well fluids from a plurality of producing subsea wells. If the number of well combinations is too large for the central processing unit of the server, the number of subsea well (with its associated production lines) and header combinations subject to analysis are reduced by specifying a minimum and/or maximum number of wells to each header. With the reduced list of subsea well and header combinations, the mixing temperature and water cut in each header of the collection manifold are calculated for each subsea well and header combinations. The calculations are based on data from sensors at the collection manifold and production lines and flow monitoring software. Subsea well and header combinations that give conditions outside operational limits specified by the operator are then discarded. As an example, the velocity in each header must be below the erosional velocity.

All well combinations that have not been discarded are then ranked based on optimization criteria defined by the operator. The calculations will restart and the software can then account for subsea wells that were initially reduced in step one due to the calculating capacity of the central processing unit of the server. The process is repeated until all subsea wells have been included in the calculations.

By comparing the current valve settings with the ranked list of possible well combinations, it can be detected if the current combination is not desired. In that case, the operator can manually switch the valves, or the valves can be switched automatically. For automatic switching, the new valve settings are automatically fed back into the software and taken into account in the next calculation loop. The software communicates the valve settings for the achieving the combination to a controller, which can then actuate the valve automatically.

The process can then be repeated online to account for changes in operating conditions that may occur after the valves are actuated. The process can wait until the operator initiates the process again, the process can be set to repeat after a desired interval of time, or the process can run continuously. When the process begins again, the entire process starts over based upon more current measurements from the sensors.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Referring toFIG. 1, a vessel11collects well fluids from subsea wells13situated in a cluster on a sea floor12. Preferably, each subsea well13includes a subsea wellhead15protruding above the sea floor12. A production line17extends from each wellhead15to a collection manifold19situated on the subsea floor12. In the preferred embodiment, the collection manifold19includes a plurality of headers21(FIG. 2) that selectively receive well fluids from each of the subsea wells13. A riser23extends from the collection manifold19to the vessel11for transferring well fluids from the subsea floor12to the vessel11. As will be readily appreciated by those skilled in the art, the riser23can preferably include a plurality of individual the risers23or a bundle of individual tubular structures for supplying segregated streams of well fluid from the collection manifold19to the vessel11.

Referring toFIG. 2, at least one header21is located within the collection manifold19. Preferably, there is a plurality of the headers21situated within the outer casing of the collection manifold19. In the embodiment illustrated inFIG. 2, there are two headers21located within the collection manifold19, however, additional headers21can also be located within the collection manifold19as desired depending upon operating conditions. In the preferred embodiment, there is a plurality of production lines17extending from the plurality of subsea wellheads15to the common collection manifold19.

As shown schematically inFIG. 2, production lines17extend from each subsea wellhead15to the collection manifold19. In the embodiment shown inFIG. 2, there are production lines17extending from eight subsea wellheads15located on the subsea floor12. A valve51is preferably located between the headers21within the collection manifold19and each subsea wellhead15. Each valve51is preferably a one-way valve that can be actuated either by hydraulic pressure or through manual actuation with an ROV as desired. Valve51can be located adjacent the collection manifold19either external to the collection manifold19, or as part of the collection manifold19prior to commingling of the well fluid. In the preferred embodiment, production line17splits into production lines17A and17B before the well fluid reaches valves51. In the preferred embodiment, there is one valve51for each production line17a,17bconnecting to collection manifold19. Preferably, each production line17extending from subsea wellhead15splits into as many production lines17A,17B as there are headers21within collection manifold19. For example, in the embodiment shown inFIG. 2, the production line17splits into two additional production lines17A and17B, which each then connects to its own respective header21within the collection manifold19. If the collection manifold19held three headers21, the production line17will split off into three individual production lines17A–C connecting to the collection manifold19. In the embodiment shown inFIG. 2, production line17A is in fluid communication with one of headers21in the collection manifold19, while production line17B is in fluid communication with the other header21in the collection manifold19.

A pressure sensor53and a temperature sensor55are preferably located between valve51and each of the headers21in the collection manifold19. The pressure and temperature sensors53,55preferably sense and transmit the pressure and temperature of the well fluid passing through their respective production lines17A,17B after the well fluid has flown through the valves51. Placing pressure and temperature sensors53,55between collection manifold19and valve51preferably provides an operator with a measured temperature and pressure value of the well fluid immediately before entering collection manifold19, which accounts for any pressure or temperature drops due to flow through valve51. Therefore, pressure and temperature sensors53,55sense and transmit inlet pressure and temperature valves to the vessel11at the surface of the sea.

Another pair of pressure and temperature sensors57,59are positioned on riser23for sensing the temperature and pressure of the well fluids exiting each of the headers21of the collection manifold19. The combination of inlet pressure and temperature sensors53,55and outlet pressure and temperature sensors57,59provide an operator with inlet and outlet conditions of the well fluids entering and exiting collection manifold19.

Alternatively, pressure sensor63and temperature sensor65can be placed on the production line17before the production line17splits into individual production lines17A,17B for each of the respective headers21. Pressure and temperature sensors63,65provide inlet well fluid conditions before the well fluid passes through the valves51. While this arrangement may have slight pressure and temperature drop-offs as the well fluid passes through the valves51, fewer pressure and temperature sensors63and65are required as they are located upstream of the split from production line17to separate production lines17A,17B.

Sensed temperature and pressure values from inlet sensors53,55, or upstream inlet sensors63,65, allow calculations of various well fluid properties. For example, in a manner known in the art the operator can calculate the volumetric or mass flow rates of the well fluid passing through the production flow line17into the collection manifold19, the specific heat of the well fluid entering the collection manifold19, and the density of the well fluid entering the collection manifold19. One such manner known in the art for calculating inlet conditions such as flow rates, specific heat, and density, is shown in U.S. Pat. No. 4,702,321 issued to Edward E. Horton on Oct. 27, 1987.

In the preferred embodiment and well shown inFIG. 2with inlet pressure and temperature sensors53,55and outlet pressure and temperature sensors57,59, only one set of inlet pressure and inlet temperatures are necessary in order to calculate flow rates, specific heats, and density of the well fluid entering collection manifold19. As desired, an operator can use the inlet pressure and temperature measured with pressure and temperature sensors53,55or the upstream inlet pressure and temperature measured with inlet pressure sensor63, and inlet temperature sensor65.

The measured temperatures and pressures sensed by either inlet pressure and temperature sensors53,55or upstream inlet pressure and temperature sensors63,65are preferably communicated to the surface through an upstream communications line67. The outlet temperature and pressure values sensed by outlet pressure and temperature sensors57,59are preferably communicated to the surface through a downstream communications line69. In the preferred embodiment, upstream and downstream communication lines67,69are mechanically coupled in a common bundle for communications between the vessel11at the surface and the sensors at the collection manifold19on the subsea floor12.

In addition to having outlet pressure and temperature sensors57,59for an operator to monitor outlet values of the well fluid exiting the collection manifold19, an operator may optionally also utilize flow rate sensors73positioned in the production line17upstream of the collection manifold19. The flow rate sensor73can also communicate with the surface through upstream communication line67. The flow rate sensor73option measures volumetric and mass flow rates of the well fluid passing through the production line17into the collection manifold19, and provides a sensed measurement of the flow rates of well fluid passing through the production line17for the operator to compare to the calculated flow rates based upon the inlet pressure and temperature sensed by either pressure and temperature sensors53,55or63,65. In the preferred embodiment, a communication line75preferably extends from the communication bundle71so that the communication line75can communicate desired control functions from the vessel11to the valves51adjacent the collection manifold19.

In the preferred embodiment, a valve actuator77is in electrical communication with the communication line75. The valve actuator77preferably receives communications from the vessel11at the surface of the sea pertaining to the actuation of the valves51. The valve actuator77can be a remote operated vehicle (ROV), or a series of hydraulically actuated valves that are electronically controlled remotely by the operator so as to provide hydraulic fluid to selectively actuate the valves51between opened and closed positions. As will be readily appreciated by those skilled in the art, the valve actuator77can be any known method or assembly used to actuate valves remotely at a subsea location.

FIG. 3illustrates the communication system between the vessel11at the surface of the sea and the subsea structures located at the sea floor12. As illustrated inFIG. 3, an area network111provides a communication system between a server211in each of the plurality of subsea wells12which are grouped together in a single grouping411, and the valve controller511. An operator311communicates with the server211through the area network to receive information from the plurality of subsea wells411and control the functions of the valve controller511. As detailed previously above, a plurality of sensors417measure various values of the well fluid at the sea floor12to be communicated to the vessel11at the surface. Sensor417preferably includes pressure sensor53located at the inlet of the collection manifold19and temperature sensor55also located at the inlet of the collection manifold19. Optionally, sensors417can include a flow sensor73at the inlet to the collection manifold19for communicating the flow rate of the well fluid into the collection manifold19from each of the production lines17A,17B. Flow sensor73is typically a multiphase flow meter. In a manner known in the art, flow monitoring software can be used to provide real-time analysis for estimating the flow rates of the water, oil, and gas in the well fluid.

As discussed previously, an operator may also desire to receive measurements of the temperature and pressure of the well fluid before the well fluid flows through the valves51leading into collection manifold19. In such a situation, the sensors417can optionally include upstream pressure and temperature sensors63,65. The sensors417also include pressure and temperature sensors57,59for the operator to receive measured values of the pressure and temperature of the well fluid exiting the collection manifold19. In the preferred embodiment, the plurality of subsea wells411preferably includes output means413. The output means413includes at least the upstream communications line67for communicating pressure and temperature values from either inlet pressure and temperature sensors53,55or pressure and temperature sensors63,65located upstream of valve51. Output means413can also include the downstream communications line69for communicating pressure and temperature values of the well fluid exiting the collection manifold19from the pressure and temperature sensors57,59. Through area network111, measured values of well fluid entering and exiting the collection manifold19from the plurality of wells411can be communicated to the vessel11located at the surface where the operator311and the server211can utilize these measurements.

The valve controller511advantageously provides means for actuating the valves51leading into the collection manifold19. The valve controller preferably includes input means513for receiving signals from the vessel11at the surface of the sea through area network111. Input means513can include the communications line75previously described inFIG. 2. The valve controller511also includes a processor515for receiving control signals from area network111through communications line75of input means513. The processor515advantageously receives signals and controls a valve actuator517, which physically actuates each of the valves51controlling the well fluid flow into the collection manifold19and each of the respective headers21. The valve actuator517preferably comprises the valve actuator77previously discussed inFIG. 2. As discussed with respect toFIG. 2, the valve actuator77can comprise an ROV remote operated vehicle, or a series of hydraulic controls for sending hydraulic fluid to each of the individual valves for actuation. The operator311preferably sends control commands to the server211, which then communicates those control commands through area network111to valve controller511.

The operator311preferably includes input/output means313that communicates with the server211in a manner known in the art. The operator311preferably also includes a processor315for receiving and communicating data between display means317and server211. Display means317can be a keyboard and monitor, a PDA, a touch-screen monitor or any other known method or assembly manner for interfacing with a computer system. The processor315is preferably a central processing unit of a computer. As will be readily appreciated by those skilled in the art, the operator311can be located on the vessel11at the surface of the sea, or at a remote location that is in communication with the server211located on the vessel11at the surface of the sea.

The server211preferably includes input/output means213for communication with the area network111and the operator311. The server211includes a processor215which can be any known central processing unit as used by those skilled in the art for server technologies today.

The server211also includes server memory217. The memory217preferably includes calculator software219programmed within memory217. Calculator software219calculates the well fluid properties, like specific heat, density and flow rates of the well fluid passing through production lines17, from the measured values transmitted from sensors417at the plurality of wells411. Calculator software219also calculates mixing temperatures and water content of the well fluid within each of the respective headers21of collection manifold19. Calculator software219advantageously determines the proper flow rate through production lines17A,17B into each of respective headers21of collection manifold19for desired properties of the well fluid exiting collection manifold19. Server211also includes a database221for storing measured and calculated values of the well fluids entering and exiting collection manifold19. Database221also advantageously provides storage space for input data from an operator for desired operating conditions.

Calculator software219preferably includes operating conditions calculator223. Operating conditions calculator223preferably includes well fluid inlet property calculator225. Well fluid property calculator225is a submodule of calculator software219for calculating flow rates of the gases, oil, and water passing through production line17into collection manifold19at the sea floor12. Well fluid inlet property calculator225can alternatively utilize flow rate sensors73, instead of one of the measured values from the inlet pressure and temperature sensors53,55or upstream inlet pressure and temperature sensors63,65. Well fluid property calculator225also advantageously calculates the density of the gas, oil, and water within the well fluids passing through lines17A,17B. Well fluid property calculator225advantageously also calculates the specific heat capacity of the gases, oils, and waters within the well fluid passing through production lines17A,17B. Well fluid property calculator225preferably utilizes the manners as previously taught in the art in U.S. Pat. No. 4,702,321 for calculating the flow rates, density, and specific heat capacities of the oils, gases, and waters passing through production lines17into collection manifold19. Operating conditions software223of calculator software219also preferably includes mixture calculator227for calculating the temperature of the well fluids combining within the collection manifold19. In the situation of multiple headers21within the collection manifold19, mixture calculator227advantageously calculates mixing temperatures within each of the specific headers21of the collection manifold19. Mixture calculator227also calculates the water content of the well fluid mixtures either within the collection manifold19or within each respective header21. Mixture calculator227can use a number of calculating formulae for determining the mixing temperature and water content of the mixture of well fluids within the collection manifold19. For example, for calculating mixing temperatures of the well fluids mixing within each header21or simply within the collection manifold19, mixture calculator227can utilize the following formula:

For each of these formulas the temperature and pressure of the inlet conditions are provided from the sensors417, while the values for the flow rates, density, and specific heat capacity of the oil, gas, and water of the well fluid entering the collection manifold19from each of the plurality of the subsea wells13is provided from calculated values supplied by well fluid property calculator225.

Database221preferably includes sensed pressure value storage241for sensed pressure values transmitted from sensors53or63at the plurality of subsea wells411through area network111. Database221also includes sensed temperature value storage243for sensed temperature values transmitted by either temperature sensors55or65. Database221also preferably includes calculated flow rates storage247as provided from well fluid property calculator225and transmitted into database221through server processor215. Database221also preferably includes calculated specific heat storage249which also receives values from well fluid property calculator225within memory217. Database221also preferably includes calculated density storage251as provided by well fluid property calculator225within memory217, and communicated via server processor215. Mixture calculator227advantageously receives values for the inlet pressure, inlet temperature, calculated flow rates, calculated specific heats, and calculated densities of the well fluids entering each respective header21of the collection manifold19from storage241,243,247,249, and251within database221. After mixture calculator227calculates the mixing temperatures and water content of mixture of well fluid within the headers21of the collection manifold19, the calculated mixing temperature value as calculated by mixer software227is transmitted through processor215into database221within calculated mixing temperature per header storage253. The value for water content of mixture as calculated by mixture calculator227is also transmitted through server processor215to database221within calculated water content of mixture per header storage255.

Calculator software219also preferably includes a flow rate determiner229. Flow rate determiner229advantageously provides flow rate software231for optimizing and controlling the properties of the well fluids exiting the collection manifold19from each of the headers21. Flow rate control software231helps control the amount of well fluids entering the headers21of the collection manifold19from each of the production lines17A,17B from each of the respective subsea wells13. Flow rate software231preferably includes a discarder233, a ranker235, and an optimizer237which calculates the most optimized inlet conditions of the well fluids into the respective headers21of the collection manifold19for desired flow rates of well fluid from collection manifold19.

The values for flow rate software231come from the calculated flow rates of the gas, water, and oil stored within database storage247, the calculated specific heats of the gas, oil, and water stored at database storage249, and the calculated density of gas, oil, and water of the well fluids in database storage251. Flow rate software231also receives the calculated mixing temperatures and calculated water content of the mixtures from database221storage modules253and255as calculated by mixture calculator227. Database221also provides values to flow rate software231which are inputted from operator311, communicated to server211, and stored in database221within an operational limits storage257, for the desired operational limits of the well fluid exiting collection manifold19. Operational limits can include the water content, flow rate, pressure, and temperature as inputted and desired from the operator for proper flow of the well fluids through the riser up to the vessel11at the surface of the sea. Operational limits stored in database storage257provide outer boundaries by which flow rate determiner229and flow rate software231discard subsea well13and header21combinations that are unacceptable.

Flow rate software231also preferably includes a ranker235which compares calculated mixing temperature and water content conditions of the well fluid exiting each of the respective headers21of the collection manifold19against inputted values stored in optimization criteria module259of database221, as entered by operator311. The ranker235advantageously compares and ranks various subsea well13and header21combinations based on mixing temperatures and water content values as calculated by mixture calculator227. Various subsets of open and closed control valves51define the various combinations or arrangements being ranked by the ranker235. The rankings created by the ranker235are for the operator311to observe, or for an optimizer237(discussed below) to evaluate various combinations of subsea well inlets. Ranked combinations of well inlets calculated by ranker235are preferably stored within database221at ranked combination from ranker storage261. Ranked combinations from ranked combination from ranker storage261can be transmitted via input/output means213to operator311for display on interface means317.

Flow rate software231also advantageously includes an optimizer237for automatically determining whether any of the ranked subsea well13and header21combinations are more efficient compared to current operating conditions at the plurality of subsea wells411. Current valve settings at the plurality of subsea wells411are advantageously conveyed to database221and stored in the current valve settings storage263for retrieval by the optimizer237. If the current valve settings are not the most efficient or closest to the optimized criteria from the operator311in storage259, optimizer237communicates necessary valve51setting changes to the operator311. The operator311can utilize the suggested changes for communication with the valve controller511for valve actuator517to actuate valve51until the desired well fluid flows are entering headers21of collection manifold as prescribed by optimizer237.

In operation, well fluids flow from each of the subsea wells13through the production line17toward the collection manifold19. Optionally, pressure and temperature sensors63,65located upstream of the inlet to collection manifold19sense the temperature and pressure of each of the well fluid feeds flowing through each production line17extending from each of the subsea wells13. Sensed values from the temperature and pressure sensors63,65are transmitted through the upstream communications line67to the vessel11at the surface of the sea. Before reaching the collection manifold19and valves51, each production line17extending from each individual subsea well13divides into an equal number of individual production lines17A,17B as the number of headers21located within the collection manifold19. The well fluid from each of the subsea wells13flows through each of the individual collection lines17A,17B to the valves51located between the subsea wells13and the collection manifold19. The valves51regulate flow through each of the individual production lines17A,17B into each of the individual headers21of the collection manifold. After the well fluid flows through the valves51, inlet pressure and temperature sensors53,55sense the inlet temperature and pressure of the well fluid entering the collection manifold19. The sensed pressure and temperature values from pressure and temperature sensors53,55are transmitted through upstream communications line67and the area network111to the vessel11at the surface of the sea.

The inlet pressure and temperature values sensed by either the inlet pressure and temperature sensors53,55, or the upstream inlet pressure and temperature sensors63,65are collected and stored in the database221of the server211after being communicated through the area network111. The operator311uses the user interface317and the processor315to communicate operational parameters for well fluid flowing out of the collection manifold19into the riser23. The operational parameters entered by the operator311are communicated through input/output means313electronically to the server211and stored within the database221for later use by the memory217. The processor215of the server21f utilizes calculator software219found on the memory217to calculate various well fluid characteristics based upon the inlet temperature and pressures sensed by the pressure and temperature sensors53,55or63,65.

As detailed before, such well fluid properties include the density, the specific heat capacity, and the flow rates of the gas, oil, and water found within the well fluid entering the collection manifold19. Alternatively, when the flow meters73are utilized, the well fluid properties include the density, the specific heat capacity, and either the temperature or the pressure of the well fluid (whichever is being replaced in calculations by the flow rates from flow meters73). Furthermore, when flow meters73are utilized, in addition to inlet pressure and temperature sensors53,55or upstream inlet pressure and temperature sensors63,65, the well fluid properties only include the density, the specific heat capacity of the well fluid entering the collection manifold19, as the temperature, pressure, and flow rates are sensed values. For the ease description, a flow rate value from a flow rate sensor73is interchangeable within the processes of calculator software219with either or both inlet temperature and pressures sensed by the pressure and temperature sensors53,55or63,65.

The calculated values for the density, specific heat, and flow rates of the water, oil, and gas of the well fluids are communicated through the processor215and stored within the database221of the server211. Mixture calculator227located on the memory217is utilized by the processor215to calculate the temperature of mixing well fluids within each of the specific headers21of the collection manifold19, and the water content of the mixtures within each of the specific headers21. The mixing temperature and water content of the mixing well fluids within the headers21of collection manifold19are communicated from the processor215to the database221of the server211.

In operation, several calculations are made for various combinations of well fluid production streams flowing into the specific headers21of the production manifold19of mixing temperature and water content of mixtures and stored within the database221. The flow rate determiner229utilizes flow rate software231to discard certain well fluid inlets for optimum calculating capabilities of the processor215. The flow rate determiner229uses the ranker235to arrange various combinations in an order for understanding which subsea well13and header21combination is most in line with the operational parameters as set forth by the operator311. The flow rate determiner229also utilizes the optimizer237for suggesting which combination is most in line with the operational parameters provided by the operator311, and for adjusting the inlet settings at the valves51leading into the collection manifold19. The process utilized by the flow rate determiner229is detailed further inFIG. 4and will be discussed below.

Should the operator311select to change the current valve settings from current operational settings to suggested settings of the valves51from the optimizer237, the server211sends a command through the area network111to the valve controller511for actuation of the various valves51that correspond with the suggested subsea well13combination from the optimizer237. The actuation commands communicated through the area network111to the valve controller511are received through input means513and processed by the processor515. The processor515communicates the actuation commands to the valve actuator517for actuating the valves51into the valve51settings of subsea well13and header21combination.

The process for determining and selecting the optimized combination of well fluid inlets from the subsea wells13to headers21of the collection manifold19is illustrated inFIG. 4. As discussed above, the numerous combinations of well fluid inlets and headers create large numbers of possible combinations of well fluid inlets and headers21or outlets for the well fluid to pass through the collection manifold19. Because of the strain that such calculations could have on the processor215of the server211in some operating systems, the number of inlet production lines17from various subsea production wells13can be reduced at the initial stages to accommodate the calculating capacity of the processor215. Therefore, the first step of the process must be to select the subsea wells for calculations. The operator can manually select the subsea wells13for initial calculations, or the server211can select a first set of initial wells13to calculate combinations with the headers21of the collection manifold19for initial calculations of the process. Preferably, the number of subsea wells13, selected in conjunction with the number of headers21utilized by the collection manifold19, will be within the operating capacity of the operator's processor215.

Upon selection of the subsea wells13, the well fluid property calculator225calculates the flow rate, the density, and the specific heat capacity of the oil, gas, and water found in the well fluids entering the headers21of the collection manifold19from each of the production lines17A,17B extending from each of the subsea wells13. As discussed above, the well fluid property calculator225calculates these values based upon the sensed pressure and temperatures transmitted from the pressure and temperature sensors53,55or63,65located upstream of the collection manifold19. Calculated values of the flow rate, density, and specific heat capacity of the oil, gas, and water in the well fluid are communicated to the database221for storage modules241,243, and247. In the event the operator311chooses to utilize flow sensors61, the operator311can compare the calculated flow rates stored in247with the sensed flow rates stored in sensed flow rate storage245in the database221for accuracy purposes.

The mixture calculator227then retrieves the calculated values of the flow rate, density, and specific gravity of the oil, gas, and water in the well fluids entering the collection manifold19, as well as the sensed pressure and temperature values from the sensors53,55or63,65located adjacent the collection manifold19. The mixture calculator227then calculates the mixing temperature and the water content of the mixture of well fluids entering each individual header21of the collection manifold19based upon various combinations of headers21and production lines17A,17B from the subsea wells13. The mixing software calculates the mixing temperature and water content for each header21through each combination of the production lines17A,17B from the selected subsea wells13feeding into each of the headers21. As discussed above, in the situation of four subsea wells13feeding into a collection manifold19with two headers21, there are 256 possible combinations of subsea well13and header21combinations. The calculated temperature and mixing water content for each of the headers21is communicated and stored in the database221within the mixing temperature per header storage253and the water content per header storage255. The flow rate determiner229retrieves the mixing temperature and mixed water content calculations for use by the flow rate software231.

The discarder233of the flow rate software231found within the flow rate determiner229compares operational limits from the database221to the calculated temperature and water contents from the mixture calculator227. The operational limits located in the database221were previously entered by the operator311and stored within operational limits storage257. The discarder233then removes combinations of subsea wells13feeding into the headers21having mixing temperature or water content values outside of the operational limits as determined by the operator311. In the preferred embodiment, the removed subsea well13and header21combinations are no longer part of the process performed by the flow rate determiner229once the discarder233has removed the values outside of the operational parameters as determined by the operator311.

Within the flow rate software231, the ranker235then receives the mixing temperature and water content values of well fluid mixtures within the headers21for each of the subsea well13and header21combinations that were within the operational limits set by the operator311. The ranker235compares the individual subsea well13and header21combinations and ranks them in an order corresponding to optimization criteria inputted by the operator31and stored within optimization criteria259at the database221. As will be readily appreciated by those skilled in the art, the desired operating exit conditions criteria can vary for specific operational needs. For example, in systems producing well fluids in colder waters, it may be desirous for the outlet mixing temperature of the well fluids exiting the collection manifold19to be higher to prevent the formation of hydrates within the riser23extending up to the vessel11. Alternatively, in shallow waters the temperature of the well fluids exiting the collection manifold may not be as large of a factor due to the short distance that the well fluids have to travel through the riser23to the vessel11.

The optimizer237receives the remaining subsea well13and header21combinations from the ranker235and communicates the ranked combinations to the operator311for viewing. The optimizer237also communicates to the operator311whether the current settings of valves51are not the same as the highest ranked subsea well13and header21combination valve settings. At this step, the optimizer237accounts for whether the subsea wells13were initially not selected for computational purposes at the beginning of the program. The optimizer237asks whether there are additional subsea wells13that were discarded and not yet used for calculation purposes. If there are subsea wells13that were not used for computational purposes to this point, the process proceeds along the yes arrow and the optimizer237sets the highest ranked subsea well13and header21combination from the ranker235as an equivalent subsea well13and header21input. The equivalent subsea well13and header21input is placed as a required fixed value in the operational limits storage257found within the database221. In this manner, the highest ranked subsea well13and header21combination from the initial calculations provide a subsea well13and header21combination equivalent that is not altered due to further calculations with subsea wells13that were not previously calculated entering into the headers21of the collection manifold19.

After setting the equivalent subsea well13and header21combination as a set value for calculational purposes with additional subsea wells13, the calculator software219then returns to the subsea well13selector step for calculating various mixing temperature and water content of subsea well13and header21combinations with the equivalent subsea well13and header21combination and the additional subsea wells13that have not yet been selected. The process discussed above is repeated until all subsea wells13feeding into the collection manifold19are used for calculational purposes and ranked by the ranker235before entering the optimizer237.

When all subsea wells13have been considered, and there are no additional subsea wells13that were not yet used for calculational purposes, then the process follows the “no” arrow that leads to a decisional step of the process. The decisional step is whether to change the subsea well13and header21combination to the highest ranked combination from the ranker235. If the answer is “yes,” then the server211communicates the changes to the settings of the valves51that are needed through the area network111to the valve controller511for actuation of the valves51by the valve actuator517. After transmitting the command, the process then continues to another decisional box as to whether to run a continuous loop on the calculator software219. If the answer was “no” to the decisional box of whether to change the subsea well13and header21combinations to the highest ranked combination, then it immediately proceeds to the decisional box of whether to run a continuous loop of the calculation software219. If the answer is “no” then the processor215waits for a signal from the operator311whether to proceed with a continuous loop or not. If a signal is received then it will proceed back to the selection of initial subsea wells13for calculational purposes at the beginning of the process. If the signal is not received then it will continue to wait for a signal until such signal is received. If the answer to run continuous loop is “yes” then it will immediately proceed back to the beginning of the calculator software219process. A continuous loop can advantageously comprise repeating the process immediately upon completion of the prior process, or waiting a preselected amount of time before repeating the process.

The system and method described above allows real-time analysis of commingling flows of well fluids entering and exiting the collection manifold19. The real-time analysis is possible based upon merely the inlet pressure and temperatures of the well fluids entering the collection manifold19. Additionally, with inlet flow meters and corresponding software, real-time information about inflow conditions becomes available. This includes total mass flow rate, gas fraction, water cut, pressure and temperature in each inflow. A computer program can then calculate mixing temperature and water cut in each outflow for all possible well combinations. The system provides the operator with a continuously updated list ranking the different subsea well and header combinations based on criteria defined by the operator. If the program detects that the current subsea well and header combination gives mixing temperatures and/or water cuts outside acceptable limits, the operator can be warned and recommended to switch to another combination.

With this system, the risk of encountering flow assurance problems is reduced. For an existing field with a given design, this can reduce the OPEX. For a new field, CAPEX can be reduced if the reduced risk of flow assurance problems is incorporated into the design. The system can be used both subsea and topsides.

Referring toFIG. 5, an alternative embodiment is shown for using the system topside. A vessel11′ floats on the surface of the sea, above a cluster or plurality of subsea wells13′. While vessel11′ is shown as a tension leg platform (TLP), this is merely for illustrative purposes. Vessel11′ can be any number of vessels known and available to those skilled in the art, such as a mini-tension leg platform (Mini-TLP), a fixed platform (FP), a compliant tower (CT), a spar platform (SP), or a marine buoy such as that shown inFIG. 1. A wellhead15′ is shown positioned on each of the subsea wells13. A production line17′ extends from each of the wellheads15′ to the vessel11′ at the surface of the sea. Well fluid flows through each of the individual production lines17to the vessel11′ unlike the embodiment shown inFIG. 1.

At the vessel, the production lines17′ are in fluid communication with a collection manifold19′. The well fluid from each of the individual production lines17′ commingles within collection manifold19′. Collection manifold19′ is substantially the same as the collection manifold19ofFIGS. 1 and 2, except for its location being topside. Sensors (not shown) are preferably located along production lines17′ in a manner substantially similar to the pressure, temperature, and flow rate (flow meter) sensors discussed above. Each of the sensors also communicate with the server to calculate the mixing temperature and water content of the well fluid mixing in the collection manifold19′.

A conduit23′ connects to collection manifold19′ for conveying well fluid from the collection manifold19′. The conduit23′ can convey the well fluid through one passage when the collection manifold acts as a single header, or through a plurality of passages bundled together when the collection manifold comprises a plurality of segmented headers discharging into conduit23′. The conduit23′ conveys the well fluid from the vessel11′ to a floating production storage and offloading vessel (FPSO)81. Typically, the FSPO81is a large distance away from the vessel11′ such that it is not advantageous to have the well fluid from each of the subsea wells13′ flow directly to the FSPO81. Conveying the well fluid from each of the plurality of subsea wells13′ allows an operator to pump the well fluid, as needed, in order to convey the well fluid to the FSPO81. Typically, the FPSO81will also be receiving well fluid from another cluster or plurality of subsea wells83through a plurality of production lines or risers85.

The alternative embodiment illustrated inFIG. 5advantageously allows collection, treatment, and storage of well fluid from a plurality of spaced-apart clusters at a single FSPO81. Having the well fluid from the plurality of subsea wells13′ stored at the FSPO81allows a smaller transport tanker (not shown) to only have to collect well fluid from one vessel located above one of the cluster or plurality of subsea wells rather than going to both clusters. Due to the distance that the well fluid may travel within the conduit23′, the process described with respect toFIGS. 3,4A and4B is utilized in order to attempt to achieve a desired temperature and water content of the well fluid exiting the collection manifold19′ into the conduit23′. Maintaining the temperature and water content of the well fluid within a range of the desired temperature and water content helps prevent the formation of hydrates and waxes within the conduit23′.