Patent Application
20250075974
In the oil and gas industry, fluids produced from a hydrocarbon reservoir may include natural gas, oil, and water. For example, as illustrated in
Natural gas that contains a lot of NGLs and condensates is referred to as wet gas, while natural gas that is primarily methane, with little to no liquids, is referred to as dry gas. The methane may then be transported to storage or for use. The mixed NGLs consist of hydrocarbon fractions of ethane, propane, butane, isobutane, pentane, and heavier hydrocarbons contained in natural gas. To refine the mixed NGLs, a Natural Gas Liquids (NGL) plant 7 consists of a series of fractionators to separate the mixed NGLs into individual products (e.g., ethane, propane, butane, isobutane, pentane, and other heavier hydrocarbons) for use. The series of fractionators is commonly referred to as Natural Gas Liquids (NGL) trains or Natural Gas Liquids (NGL) fractionation trains. As a result, the processing plant and NGL fractionation trains have dynamic configurations which are prone to human errors resulting in improper actuation of valves, loss of fluid production, and expensive damage and non-productive time (NPT).
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In general, in one aspect, embodiments disclosed herein relate to a system, comprising a gas processing plant, wherein the gas processing plant comprises a compressor, at least one natural gas liquids train fluidly coupled to the compressor to receive mixed natural gas liquids from the gas processing plant, a valve fluidly coupling the gas processing plant to the at least one natural gas liquids train, and a control system coupled to the gas processing plant, the at least one natural gas liquids train, and the valve, wherein the control system determines when to actuate the valve using a virtual sensing system based on a compressor shutdown condition, a compressor trip condition, a compressor recycle condition, an exclusion switch, a flow rate of the compressor, a running flow capacity of the first compressor, a required bypass flow of the compressor, and bypass flow distribution of the at least one natural gas liquids train.
In general, in one aspect, embodiments disclosed herein relate to a method, comprising receiving, with a control system, a signal from a compressor of a gas processing plant, determining, with the control system, a status of the compressor based on the signal, determining, with the control system, when to actuate a valve coupled on the compressor based a compressor shutdown condition, a compressor trip condition, a compressor recycle condition, an exclusion switch, a flow rate of the compressor, a running flow capacity of the first compressor, a required bypass flow of the compressor, and bypass flow distribution of a natural gas liquids train; and flowing a mixture of natural gas liquids from the compressor to the natural gas liquids train.
In general, in one aspect, embodiments disclosed herein relate to a non-transitory computer readable medium storing instructions on a memory coupled to a processor, the instructions comprising functionality for triggering the processor to initiate the instructions when a turbine flame out trip signal from a compressor of a gas processing plant is received by the processor, determining if the compressor is in a recycle mode or a shutdown mode, calculating an amount of flow reduction from the gas processing plant to a natural gas liquids train, and closing or partially closing, based on the calculated flow reduction, an opening of a valve to natural gas liquids train to restrict a gas feed stream from the gas processing plant to the natural gas liquids train.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.
In the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements. Additionally, as used herein, the term “coupled” or “coupled to” or “connected” or “connected to” “attached” or “attached to” may indicate establishing either a direct or indirect connection and is not limited to either unless expressly referenced as such.
It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. For example, a “subsurface model” may include any number of “subsurface models” without limitation.
Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.
It is to be understood that one or more of the steps shown in the flowcharts may be omitted, repeated, and/or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowcharts.
Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.
In general, embodiments of the disclosure include systems and methods for controlling a processing plant to automatically feed gas into NGL trains. For example, a virtual sensing system may identify optimum values for an opening/closing time and an opening/closing speed of a valve within the processing plant using virtual flow sensing to direct the flow of gas into the NGL trains. Rather than using purely hardware sensors to determine when to open or close valves, the virtual sensing system may use software measurement logic to analyze data utilizing prediction models to predict an optimum time and speed to open or close the valves. In some embodiments, the virtual sensing system may receive signals when various equipment in the processing plant and NGL trains are tripping to determine the optimum time and speed to open or close the corresponding valves to control a flow of gas. For example, the virtual sensing system may provide real-time calculations and monitoring of gas compressor conditions and automatically indicate a trip to calculate a flow required to be reduced from the processing plant and close the corresponding valves to the respective NGL train. In particular, a control system (such as a distributed control system (DCS)) may implement this virtual sensing system in some embodiments.
The virtual sensing system 100 is configured to determine an optimum time and speed to open or close the one or more valves 135 to control NGL flow exiting the processing equipment 130 that passes through the one or more valves 135 to the one or more NGL trains 140. The processing equipment 130 may be a compressor to compress the gas before entering the one or more NGL trains 140. The one or more valves 135 may be a closure element with hardware for opening and closing a conduit connection, such as a gate valve, a shutoff valve, a ball valve, a control valve, etc. the one or more NGL trains 140 may be a series of fractionators (e.g., stripping columns) to separate the mixed NGLs into individual products (e.g., ethane, propane, butane, isobutane, pentane, and other heavier hydrocarbons) for use. Additionally, the plurality of sensors 154 may be coupled, directly or indirectly, to the processing equipment 130, the one or more valves 135, and the one or more NGL trains 140 to measure various gas flow parameters such as flow rates, pressure, temperature, and gas composition. For example, the plurality of sensors 154 may be a flow meter. It is further envisioned that the plurality of sensors 154 may include a transmitter to wirelessly send signals to the control system 125 to alert an operator.
In some embodiments, the control system 125 in the virtual sensing system 100 may describe one or more physical criteria or conditions for determining the optimum time and speed to open or close the one or more valves 135. For example, the control system 125 may specify various input parameters (for example, processing equipment shutdown condition 156, processing equipment trip condition 160, processing equipment recycle condition 165, exclusion switch 170, flow rate 175, running flow capacity 180, required bypass flow 185, and bypass flow distribution 190) to determine the optimum time and speed to open or close the one or more valves 135.
The processing equipment shutdown condition 156 indicates when the processing equipment 130 is running, as a binary 1 or 0 with 1 indicating that the processing equipment 130 is in operation and 0 indicating that the processing equipment 130 is shut down. The sensors 154 on the processing equipment 130 may be used to determine if the processing equipment 130 is running or not. For example, the sensors 154 may identify a speed at which the processing equipment 130 is operating. The processing equipment trip condition 160 indicates when the processing equipment 130 is operated at a predetermined threshold or tripping (i.e., malfunctioning) as a binary 1 or 0 with 1 indicating that the processing equipment 130 is in operation and 0 indicating that the processing equipment 130 has been tripped.
For example, the sensors 154 may identify a signal from the processing equipment 130 that operations are running at or above the predetermined threshold. The processing equipment recycle condition 165 indicates when the processing equipment 130 is being operated or running on recycle mode (i.e., recycling gas through the processing equipment 130) as a binary 1 or 0 with 1 indicating that the processing equipment 130 is in operation and 0 indicating that the processing equipment 130 is in recycle mode. For example, the sensors 154 may measure a flow rate at an outlet of the processing equipment 130. The flow rate at the outlet of the processing equipment 130 will be zero if the processing equipment 130 is on recycle mode. The exclusion switch 170 is determined by the control system 125 multiplying the processing equipment shutdown condition 156 and the processing equipment recycle condition 165. The flow rate 175 is current real-time flow of gas in the processing equipment 130. The running flow capacity 180 is a maximum flow rate that the processing equipment 130 is rated to handle based on the processing equipment trip condition 160. For example, the running flow capacity 180 may change if the processing equipment 130 is tripping and any excess flow may be rejected from entering the processing equipment 130 to ensure the running flow capacity 180 is not exceeded. The required bypass flow 185 is a volume of flow that needs to be bypassed to not overload the processing equipment 130. The control system 125 may determine the required bypass flow 185 by subtracting the running flow capacity 180 from the flow rate 175 and reading any negative result as 0. The bypass flow distribution 190 is the volume of flow that may be reduced from the one or more NGL trains 140. The bypass flow distribution 190 is proportional to a volume of flow currently flowing to the one or more NGL trains 140. For example, the one or more NGL trains 140 with a higher inlet flow rate will have more reduction in comparison to an NGL train 140 with a lower flow rate.
Still referring to
In one or more embodiments, the one or more NGL trains 140 may have a minimum flow rate. For example, the minimum flow rate may be 650 MMSCFD of gas. If the flow falls below the minimum flow rate, the one or more NGL trains 140 may trip.
The control system 125 may include hardware and/or software that monitors and/or operates equipment, such as at a gas processing plant. In particular, the control system 125 may be coupled to the processing equipment 130, the one or more valves 135, the one or more NGL trains 140, and the plurality of sensors 154 collecting data throughout a facility. For example, facility equipment may include various hardware components, such as heat exchangers, pumps, valves, compressors, production traps, knockout vessels, desalters, loading racks, and storage tanks among various other types of hardware components. In some embodiments, the control system 125 may include a programmable logic controller that may control fluid flow, valve actuation, warning alarms, pressure releases and/or various hardware components throughout a facility. Thus, a programmable logic controller may be a ruggedized computer system with functionality to withstand vibrations, extreme temperatures, wet conditions, and/or dusty conditions, such as those around a refinery or drilling rig. Furthermore, a control system 125 may be a computer system similar to the computer system 500 described in
In some embodiments, the control system 125 includes a distributed control system (DCS). A distributed control system may be a computer system for managing various processes at a facility using multiple control loops. As such, a distributed control system may include various autonomous controllers (such as remote terminal units also known as RTUs) positioned at different locations throughout the facility to manage operations and monitor processes. Likewise, a distributed control system may include no single centralized computer for managing control loops and other operations. On the other hand, a SCADA system may include a control system 125 that includes functionality for enabling monitoring and issuing of process commands through local control at a facility as well as remote control outside the facility. RTUs may include hardware and/or software, such as a microprocessor, that connects sensors and/or actuators using network connections to perform various processes in the automation system.
Turning to
In one or more embodiments, each NGL train of the plurality of NGL trains 140 may include a deethanizer 220, a depropanizer 225, a debutanizer 230, and a deisobutanizer 235 to fractionalize the gas feed stream from the corresponding compressor 215. The deethanizer 220 removes ethane from the gas feed stream such that ethane may be transported via a pipeline to a storage tank or for use while the remaining gas feed stream flows to the depropanizer 225. The depropanizer 225 separates propane from the gas feed stream such that propane may be transported via a pipeline to a storage tank or for use while the remaining gas feed stream flows to the debutanizer 230. The debutanizer 230 separates butane from the gas feed stream such that butane may be transported via a pipeline to a storage tank or for use while the remaining gas feed stream flows to the deisobutanizer 235. The deisobutanizer 235 separates the isomers of the remaining gas feed stream into two product streams for storage or use.
In some embodiments, a valve 135 is positioned on each line from the compressor 215 to the plurality of NGL trains 140. Additionally, the valve 135 may be a closure element with hardware for opening and closing a conduit connection of the corresponding compressor 215 to the corresponding NGL trains 140, such as a gate valve, a shutoff valve, a ball valve, a control valve, etc.
Still referring to
In some embodiments, during operation, the virtual sensing system 100 collects and records data from the plurality of NGL trains 140 and the compressor 215. The data includes, for example, a record of flow rates and volume of gas entering and exiting each compressor 215 and each NGL train 140. In some embodiments, the measurements are recorded in real-time, and are available for review or use within seconds, minutes or hours of the condition being sensed (e.g., the measurements are available within 1 hour of the condition being sensed). In such an embodiment, the data may be referred to as “real-time” data. Real-time data may enable the virtual sensing system 100 to automatically reduce a flow rate upstream of the compressor 215, calculate running compressor flow capacity and maximum running compressor flow capacity, reduce the flow rate on a gas feed stream entering each NGL train 140 in proportion to the flow rate at the compressor 215, and reject a full flow rate on a tripped compressor 215 during a trip scenario. Additionally, the virtual sensing system 100 ensures that each NGL train 140 is receiving a minimum flow to avoid a tripping event occurring. It is further envisioned that the virtual sensing system 100 may cross-correlate a relationship between the valve 135 opening and a flow rate of each NGL train 140.
In some embodiments, the virtual sensing system 100 may include a control system 125 or other computer device that acquires sensor measurements from the plurality of NGL trains 140, the valve 135, and the compressor 215 with respect to a predetermined processing environment. Based on knowledge of this processing environment, the virtual sensing system 100 may determine when to actuate the valve 135 without using or needing human visual inspection.
Those skilled in the art will appreciate that while
In Block 300, a signal from a processing equipment (e.g., a compressor) fluidly coupled to an a NGL train 140 is received. For example, flow rate data from the compressor may be obtained via a sensor. A flow of gas may pass through the compressor on which the sensor is coupled therein to measure a flow rate.
In Block 305, based on the received signal, the status of the processing equipment is determined. For example, if the flow rate at the outlet of the compressor is zero, then the compressor is indicated as being recycle mode. Additionally, the flow rate at an inlet and the outlet of the compressor is zero, then the compressor is indicated as being in shutdown.
In Block 310, whether a flow adjustment needs to be made to the compressor is calculated. To determine whether a flow adjustment is needed, a required bypass flow is calculated based on the status of the compressor. If the required bypass flow is calculated as a positive value, a flow adjustment is needed. If an adjustment is needed, the method moves to Block 315.
In Block 315, a valve opening is adjusted to control the flow rate in and out of the compressor. For example, the valve may be partially closed to reduce flow into the NGL train 140. After the adjustment is made, the method may repeat Blocks 401-403 to continue monitoring the compressor. However, if an adjustment is not needed, then the method moves to Block 320. In Block 320, the gas feed stream is continuously fed into the NGL train 140. Additionally, Blocks 300-320 may be repeated as needed during the operation of the NGL train 140.
In one or more embodiments, the logic may be activated during a trip of one of the compressors (e.g., sales gas compressors). Once activated, the logic will cut gas flow from one of the NGL processing plants to the NGL trains 140 by utilizing a corresponding master valve to each NGL train 140. The master value is the main inlet feed gas to the NGL train(s), and closing this valve will cut the rate on the NGL train 140. For example, actuating a first master valve to a first NGL train 140, actuating a second master valve to a second NGL train 140, and/or actuating a third master valve to a third NGL train.
One or more steps in
As shown in
In Step 405, the logic determines if the compressors are in recycle or shutdown mode. The compressor is in recycle mode if the flow at an outlet is zero or in shutdown mode if the compressor is turned off, as shown in Step 405A. If any of the compressors is in recycle or shutdown mode, the logic may exclude the corresponding compressor from calculations.
In some embodiments, the logic may comprise switches (with values as 0 or 1) to indicate a condition the compressor is subjected to. For example, the switch may correspond to a condition such as a shutdown condition 156, a trip condition 160, or a recycle condition 165 of the compressor. Based on the condition, the switch may be a shutdown switch, a recycle switch, a trip switch, and/or an exclusion switch.
All combustion gas turbines are equipped with a speed sensor. The speed sensor detects the RPM for the rotating equipment then sends the speed reading to the DCS system. The shutdown switch of the logic indicates a value of 1 when the compressor is running. When the compressor is shut down, the shutdown switch of the logic indicates a value of 0. This may be accomplished by the logic looking at a speed of the compressor indicated by RPM (rotations per minute) sensor on the compressor. Then it will be displayed in the speed tag 6*SI403B.PV. For example, if the compressor speed is less than or equal to 90 rpm, then the shutdown switch is indicated as 0 in the logic. However, if the compressor speed is greater than 90 rpm, then the shutdown switch is indicated as 1 in the logic.
The recycle switch of the logic indicates a value of 1 when the compressor is in operation. 6*FI001B.PV represents the outlet flow measurement for the compressor. The reading is taken from the flow transmitter in the field at the outlet of the compressor. When the compressor is running in recycle mode, the recycle switch of the logic indicates a value of 0. This may be accomplished by the logic looking at an outlet flow from the compressor indicated by the output flow sensor on the compressor. In some embodiments, the flow at the outlet will be less than or equal to 50 GPM (gallons per minute) when the compressor is running in recycle mode. For example, if the compressor outlet flow is less than or equal to 50 GPM, then the recycle switch is indicated as 0 in the logic. However, if the compressor outlet flow is greater than 50 GPM, then the recycle switch is indicated as 1 in the logic.
The trip switch of the logic indicates a value of 1 when the compressor is in operation. When the compressor is tripping, the trip switch of the logic indicates a value of 0. This may be accomplished by the logic looking at a turbine flame out signal from a flame detector in the chamber. For example, if the turbine flame out signal is equal to 0, then the trip switch is indicated as 0 in the logic. However, if the turbine flame out signal is a non-zero number, then the trip switch is indicated as 1 in the logic.
The exclusion switch of the logic is a multiplication of the shutdown switch and the recycle switch. For example, if a compressor is in recycle mode, the exclusion switch will indicate a value of 0 (e.g., the shutdown switch is at a value of 1 and the recycle switch is at a value of 0, thus, 1*0=0). The effect of this is that if a compressor is in either recycle mode or shutdown mode, the exclusion switch indicates that the compressor is offline and should be excluded from capacity calculations.
In one or more embodiments, the logic may also calculate a current flow through the compressors. For example, the current flow is calculated by a summation of a flow through each compressor measured by a flow meter at the inlet of the compressor. The reading is taken from the flow transmitter in the field at the inlet of the compressor. 6*FI001A.PV represents the inlet flow measurement for the compressor.
The compressors in recycled or shutdown mode are excluded from the calculations by utilizing the exclusion switch. For example, the current flow is calculated by the summation of each compressor's flow rate multiplied by the corresponding exclusion switch (e.g., current flow=first compressor's flow rate*first compressor's Exclusion switch)+(second compressor's flow rate*second compressor's Exclusion switch)+(third compressor's flow rate*third compressor's Exclusion switch)+(fourth compressor's flow rate*fourth compressor's Exclusion switch).
In one or more embodiments, the logic includes a memory unit with stored data. The stored data includes a maximum flow capacity of each compressor. For example, each compressor may have a maximum flow capacity of 950 MMSCFD of flow. In the event of a trip of a compressor, the logic automatically redirects flow such that the operating compressors take the additional flow from the tripped compressor. Once the operating compressors reach the maximum flow capacity, the logic automatically rejects any excess flow from the NGL trains 140. It is noted that the compressors cannot be subjected to a sudden change in the load as this will lead to a tripping event. Therefore, the logic gradually adjusts the load on the operational compressors not to exceed each compressors maximum load. For example, the logic calculates by amount of flow that the operating compressors can handle by multiplying the maximum flow capacity with a summation of the exclusion switch plus the trip switch of each compressor (e.g., maximum running compressors flow capacity=950*((first compressor exclusion switch*first compressor trip switch)+(second compressor Exclusion switch*second compressor trip switch)+(third compressor Exclusion switch*third compressor trip switch)+(fourth compressor Exclusion switch*fourth compressor trip switch).
In Step 410, the logic calculates how much flow reduction is needed to not overload the compressors. For example, the logic may first calculate a required bypass flow (see Step 410A) and a bypass distribution of a flow on each NGL train 140 (see Step 410B).
In Step 410A, the required bypass flow is an amount of flow that needs to be bypassed by the corresponding NGL processing plant to not overload the running compressors. The amount of flow required to be bypassed during the trip of a compressor is calculated by the logic subtracting the maximum running compressors flow capacity from the current flow (e.g., required bypass flow=(first compressor's flow rate*first compressor exclusion switch)+(second compressor's flow rate*second compressor exclusion switch)+(third compressor's flow rate*third compressor exclusion switch)+(fourth compressor's flow rate*fourth compressor exclusion switch)−950*((first compressor exclusion switch*first compressor trip switch)+(second compressor exclusion switch*second compressor trip switch)+(third compressor exclusion switch*third compressor trip switch)+(fourth compressor exclusion switch*fourth compressor trip switch).
In Step 410B, the bypass flow distribution on each NGL train 140 is an amount of flow that will be reduced from each NGL train 140. Additionally, the bypass flow distribution may be proportional to the amount of flow currently flowing to the corresponding NGL train 140. For example, a NGL train 140 with a higher inlet flow rate will have more reduction in comparison to a NGL train 140 with a lower inlet flow rate. Further, the logic receives measurements for a total flow to the NGL processing plant and flow on each NGL train 140. The logic will calculate the required bypass flow on each NGL train 140 by multiplying the required bypass flow with the current NGL train flow rate divided by the total flow on all NGL trains 140. In the case of having three NGL trains 140, the logic will calculate the required bypass flow on each NGL train 140 as follows: a first NGL train required bypass flow from a first NGL processing plant=required bypass flow*(flow rate on the first NGL train/total flow rate to the first NGL processing plant); a second NGL train required bypass flow from a first NGL processing plant=required bypass flow*(flow rate on the second NGL train/total flow rate to the first NGL processing plant); and a third NGL train required bypass flow from a first NGL processing plant=required bypass flow*(flow rate on the third NGL train/total flow rate to the first NGL processing plant). It is further noted that a bypass flow rate on the NGL train value can be a positive number or zero. This means that the facility bypassed some flow (+) or no flow (0). In case of a zero value, it is passed through the logic and results in an unreasonable valve opening which may disturb the plant operation.
To ensure a negative bypass flow rate has not been calculated, the logic applies a safety measure by checking that the NGL train required bypass flow 185 from the NGL processing plant is equal to or greater than zero. If a negative value is received, it may be filtered out as unreasonable or filtered out and reported as an irregularity.
In one or more embodiments, after calculating the required flow rate that needs to be bypassed on each NGL train 140, the logic will calculate a flow rate from the NGL processing plant to the corresponding NGL train 140. For example, the flow rate to each NGL train 140 will be the current flow rate minus the required bypass flow. In the case of having three NGL trains 140, the logic will calculate the flow rate to each NGL train 140 as follows: a flow rate to the first NGL train=the first NGL current Flow rate-first NGL train required bypass flow; a flow rate to the second NGL train=the second NGL current Flow rate−second NGL train required bypass flow; and a flow rate to the third NGL train=the third NGL current Flow rate−third NGL train required bypass flow.
In one example, each NGL train 140 may have two gas stream feed rates. One gas stream feed rate is from the first NGL processing plant and the other gas stream feed rate is from the second NGL processing plant. In such an example, each NGL train 140 may have a minimum flow rate (i.e., turndown ratio) of 650 MMSCFD. Any lower flow rate may cause the turboexpanders in the NGL trains 140 to trip. Therefore, the logic stores the minimum total flow to each NGL train 140 as 650 MMSCFD. To ensure the flow to each NGL train 140 does not drop below the minimum total flow, total flow rate to each NGL train 140 from the first NGL processing plant and the second NGL processing plant are transmitted to the logic. Due to the minimum flow constrains on each NGL train 140, the logic applies the equation as follows: if total flow rate to the corresponding NGL train 140 is less than or equal to 650 MMSCFD, then, a flow rate to the corresponding NGL train 140 from the first NGL processing plant equals 650 MMSCFD minus a flow rate to the corresponding NGL train 140 from the second NGL processing plant. In some embodiments, a safety factor of 4 may be applied to the logic such that if 4*the total flow rate to the corresponding NGL train 140 is less than or equal to 650 MMSCFD, then, the flow rate to the corresponding NGL train 140 from the first NGL processing plant equals 650 MMSCFD minus 4*the flow rate to the corresponding NGL train 140 from the second NGL processing plant.
In Step 415, based on the calculated flow reduction, a valve to the corresponding NGL train 140 is either closed or partially closed to restrict the gas feed stream from the gas processing plant to the NGL train 140. By closing or partially closing the valve, the gas stream feed from the NGL processing plant is reduced. As shown in Step 415A, the logic calculates the size the valve opening needs to be to achieve the calculated flow reduction. For example, the amount the valve needs to be closed may be calculated by multiplying 9.4% with a flow rate to the NGL train 140 from the NGL processing plant and adding 1. In the example of three NGL trains 140 teaching being feed a gas stream from the first and second NGL processing plant, the valve opening may be calculate by the logic as follows: the size of the valve opening to the first NGL train=9.4%*a flow rate to the first NGL train 140 from the second NGL processing plant+1; the size of the valve opening to the second NGL train=9.4%*a flow rate to the second NGL train from the second NGL processing plant+1; and the size of the valve opening to the third NGL train=9.4%*a flow rate to the third NGL train from the second NGL processing plant+1.
Embodiments may be implemented on a computer system.
The computer 500 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the disclosure. The illustrated computer 500 is communicably coupled with a network 540. In some implementations, one or more components of the computer 500 may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
At a high level, the computer 500 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 500 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
The computer 500 can receive requests over network 540 from a client application (for example, executing on another computer 500) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 500 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
Each of the components of the computer 500 can communicate using a system bus 505. In some implementations, any or all of the components of the computer 500, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 510 (or a combination of both) over the system bus 505 using an application programming interface (API) 612 or a service layer 535 (or a combination of the API 530 and service layer 535. The API 530 may include specifications for routines, data structures, and object classes. The API 530 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 535 provides software services to the computer 500 or other components (whether or not illustrated) that are communicably coupled to the computer 500. The functionality of the computer 500 may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 535, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or other suitable format. While illustrated as an integrated component of the computer 500, alternative implementations may illustrate the API 530 or the service layer 535 as stand-alone components in relation to other components of the computer 500 or other components (whether or not illustrated) that are communicably coupled to the computer 500. Moreover, any or all parts of the API 530 or the service layer 535 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
The computer 500 includes an interface 510. Although illustrated as a single interface 510 in
The computer 500 includes at least one computer processor 515. Although illustrated as a single computer processor 515 in
The computer 500 also includes a memory 520 that holds data for the computer 500 or other components (or a combination of both) that can be connected to the network 540. For example, memory 520 can be a database storing data consistent with this disclosure. Although illustrated as a single memory 520 in
The application 525 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 500, particularly with respect to functionality described in this disclosure. For example, application 525 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application 525, the application 525 may be implemented as multiple applications 525 on the computer 500. In addition, although illustrated as integral to the computer 500, in alternative implementations, the application 525 can be external to the computer 500.
There may be any number of computers 500 associated with, or external to, a computer system containing computer 500, each computer 500 communicating over network 540. Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer 500, or that one user may use multiple computers 500.
In some embodiments, the computer 500 is implemented as part of a cloud computing system. For example, a cloud computing system may include one or more remote servers along with various other cloud components, such as cloud storage units and edge servers. In particular, a cloud computing system may perform one or more computing operations without direct active management by a user device or local computer system. As such, a cloud computing system may have different functions distributed over multiple locations from a central server, which may be performed using one or more Internet connections. More specifically, cloud computing system may operate according to one or more service models, such as infrastructure as a service (IaaS), platform as a service (PaaS), software as a service (SaaS), mobile “backend” as a service (MBaaS), serverless computing, artificial intelligence (AI) as a service (AIaaS), and/or function as a service (FaaS).
In addition to the benefits described above, the virtual sensing system may improve an overall efficiency and performance at the plant while reducing cost and risk of non-productive time (NPT), and many other advantages. Further, the virtual sensing system may provide further advantages such as being able to decrease maintenance and operating cost, automatic flow reduction, prevent any unwanted flow fluctuations, reduce human errors, prevent overload on gas compressors, enhance responses to equipment failures, and is not limited to any type of fluid (e.g., hydrocarbon, water, steam, nitrogen, and other fluids in either vapor or liquid phase).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, any means-plus-function clauses are intended to cover the structures described herein as performing the recited function(s) and equivalents of those structures. Similarly, any step-plus-function clauses in the claims are intended to cover the acts described here as performing the recited function(s) and equivalents of those acts. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” or “step for” together with an associated function.
