EP2368160A1

EP2368160A1 - Fluid transmission control system and method

Info

Publication number: EP2368160A1
Application number: EP09796776A
Authority: EP
Inventors: Richard Greig Clark; Christopher Harding; Gareth Andrew Jones; Lawrence Lambon; Alistair Porter; Mathew James Sims; Alan Shore
Original assignee: BP Exploration Operating Co Ltd
Current assignee: BP Exploration Operating Co Ltd
Priority date: 2008-12-18
Filing date: 2009-12-16
Publication date: 2011-09-28
Also published as: GB0823168D0; WO2010070283A1

Abstract

Embodiments of the invention are concerned with a fluid transmission control system is arranged to control the transmission of fluid through a fluid transmission network. The fluid transmission network comprising a first pipeline having a first end connectable to the output of a fluid processing plant, which is associated with a first fluid source. The fluid transmission network also comprises a second pipeline having a first end connectable to a second fluid source and a second end connectable to the first pipeline at a junction with a second end of the first pipeline. The control system comprises measurement means for measuring one or more characteristics of fluid output at the second fluid source, prediction means for predicting future characteristics of the fluid based on the measured characteristics, said characteristics corresponding to a future time at which the fluid flows through the second end of the second pipeline, and adjustment determining means arranged to receive data regarding said predicted characteristics of the fluid. The adjustment determining means are further arranged to identify an adjustment to the processing of fluid at the fluid processing plant to account for the predicted characteristics. The control system also comprises control means arranged to control the fluid processing plant in accordance with the identified adjustment. A corresponding method of controlling fluid transmission through the fluid transmission network is also provided. Fluctuations or insufficiencies in gas characteristics with respect to a predetermined specification can be predicted and the characteristics can be adjusted accordingly, in order to pre-empt and thus avoid or minimise problems that currently occur upon the delivery of gas having characteristics outside an acceptable range, or which vary over time, to users.

Description

FLUID TRANSMISSION CONTROL SYSTEM AND METHOD

Field of the Invention

The present invention relates to a fluid transmission control system and method for controlling the transmission of fluid through a fluid transmission network. Background of the Invention

Natural gas, for use as a fuel to provide power to industrial and domestic users via grid networks, turbines, etc., can be obtained from natural gas sources around the world, such as from gas fields or from oil fields (gas that is separated from crude oil at a production facility). Demand for fuel is increasing and often cannot be satisfied by local sources; in such situations gas from a remote source is often required to supplement the quantity and/or quality of a local source.

In many processes dependent on natural gas, gas characteristics, such as inherent properties (e.g. gas composition) and supply parameters (e.g. gas flow rate, temperature, etc.) of a supplied fuel such as natural gas, affect the operation or outcome of the process. As demand increases and the components, construction and efficiency of the machinery and systems used by downstream or end users improve, the specifications (required characteristics) of the required gas become more precise, narrowing the range of acceptable gas characteristics and providing a greater variety of characteristic values which must be met for supplies to different users from a certain gas source. The specification of a gas may depend on its calorific value or the rate of change of the calorific value (which is preferably low, providing an approximately constant calorific value), which is linked to the "Wobbe Index". The Wobbe Index is an indicator of the interchangeability of fuel gases and is frequently defined as a requirement specification of gas supplies and transport utilities. The Wobbe Index is used to compare the combustion energy output of different composition fuel gases in an appliance burning such gases.

For example, users may require a rate of change of calorific value of less than 1%, or a calorific value within a range of ±5% of a target value. Outside these parameters, factors such as the operational efficiency of the equipment, safety and cost may be affected. The composition of the gas (that is, the relative amounts of the components of the gas) reaching machinery employed by downstream users is therefore highly important, as the gas energy or calorific value of the gas is dependent upon this composition. In the case where an additional supply originating from a remote source, such as a liquefied natural gas (LNG) supply, is used to supplement a local source, the composition of this additional fuel is typically altered from its original composition by factors such as the quantity and molecular weight of any hydrocarbons extracted during an associated liquefied petroleum gas extraction process, and the amount of any added diluents such as nitrogen gas, which modifies the Wobbe Index. The gas from the LNG source then combines with that of the local source and the combined gas is supplied to end users. The suitability of the gas for downstream users is also dependent upon factors such as the gas export rate (that is, the rate at which downstream users are able to consume the gas), the gas temperature and the gas pressure.

At present, it is possible to buy additional fuel supplies, such as stored LNG, having a composition according to a requested specification; however, this is extremely expensive, and in any event does not necessarily account for variations in the composition of locally sourced gas, in cases where the additional gas acts as a supplement, rather than a replacement, for the locally sourced gas. Summary of the Invention

In accordance with the present invention, there is provided a fluid transmission control system and method in accordance with the appended claims.

The present invention provides a system and method for controlling the processing of fluid, such that the fluid supplied downstream of fuel sources to a user meets a predetermined specification.

According to embodiments of the present invention there is provided a fluid transmission control system arranged to control the transmission of fluid through a fluid transmission network, the fluid transmission network comprising a first pipeline having a first end connectable to the output of a fluid processing plant, said fluid processing plant being associated with a first fluid source, and a second pipeline having a first end connectable to a second fluid source and a second end connectable to the first pipeline at a junction with a second end of said first pipeline, the control system comprising: measurement means for measuring one or more characteristics of fluid output from the second fluid source; prediction means for predicting future characteristics of the fluid based on the measured characteristics, said predicted characteristics corresponding to a future time at which the fluid flows through the second end of the second pipeline; adjustment determining means arranged to receive data regarding said predicted characteristics of the fluid, wherein the adjustment determining means are further arranged to identify an adjustment to the processing of fluid at the fluid processing plant to account for the predicted characteristics; and control means arranged to control the fluid processing plant in accordance with the identified adjustment.

By analysing the nature of the fuel before it is supplied to a downstream process, the process can be changed pre-emptively to coincide with a change, or to compensate for an undesired value, in fuel characteristics, such as fuel composition. The process parameters compensate for a change in fuel characteristics such that in some implementations, a product with relatively stable characteristics is exported from a process, despite varying initial fuel characteristics. The invention is particularly applicable to a gas transmission network, in which gas from a local gas source can be combined with fuel that is stored in a liquid state, and is re-gasified before the combination with the local gas.

Fluctuations or insufficiencies in gas characteristics with respect to a predetermined specification can be predicted and the characteristics can be adjusted accordingly, in order to pre-empt and thus avoid or minimise problems that currently occur upon the delivery of gas having characteristics outside an acceptable range to users. Such characteristics may include the calorific value, lower heating value (LHR, defined as the amount of heat released by combusting a specified quantity (initially at 25 °C or another reference state) and returning the temperature of the combustion products to 150⁰C), higher heating value (HHV), rate of change of the calorific value, flow rate, temperature, pressure, and Wobbe Index of the gas exported to users. In addition, the hydrocarbon composition of the export gas may be determined (mole% and molecular weight of the various hydrocarbon components).

The invention allows the management of upstream and downstream conditions to optimise the specification of the delivered gas originating from non-optimal sources. Although it may not be possible to control the local gas source, the characteristics of the delivered gas can be controlled by controlling the characteristics of the gas originating from the additional source.

Further features and advantages of the invention will become apparent from the following description of preferred embodiments of the invention, given by way of example only, which is made with reference to the accompanying drawings. Brief Description of the Drawings

Figure 1 shows a fluid transmission network having a fluid transmission control system according to the present invention;

Figure 2a is a flowchart of the processes performed by the system of the invention when applying a predictive pipeline simulation;

Figure 2b is a flowchart of the processes performed by the system when applying a real time pipeline simulation; Figure 3 is a flowchart of the process performed by a data manager of the control system according to the invention;

Figure 4a is a flowchart showing how time constraints are taken into account by the system of the present invention once a change in a fluid characteristic is measured;

Figure 4b is a flowchart showing the steps taken by the system of the invention in instructing a controller of the system; and

Figure 5 is a flowchart of an example of the invention in which a characteristic of fluid delivered to the downstream users is maintained at a constant value. Detailed Description of the Invention

Referring to Figure 1 , an embodiment of a fluid transmission control system arranged to control the transmission of fluid through a fluid transmission network will be described. The network comprises two pipelines 1 , 2 through which fluid, such as natural gas, can flow. A first pipeline 1 is connected at one end thereof to a first source of fuel in the form of a fluid (liquid or gas), while a second pipeline is connected at one end to a second fluid source, and at another end to the first pipeline, forming a junction 3 at which the two pipelines connect, such that fluid flowing through the pipelines combines at the junction 3 and continues to flow downstream thereof.

The fluid source for the second pipeline 2 may take the form of one or more incoming or upstream gas fields and/or oil fields 4, and typically provides fuel in the form of gas via the second pipeline 2 to downstream users 5, such as grid networks, industrial users or plants and domestic users. This is typically a local gas source or a local

"associated" gas source. By "associated gas" is meant gas that is separated from produced oil and water at a production facility of an oil field. One or more characteristics of the natural gas output from the upstream gas fields and/or oil fields 4, such as gas composition, properties or parameters such as flow rate and temperature, are measurable at one or more measurement devices 6, which preferably include composition analysis equipment, such as gas chromatographic analysis equipment that allows identification of the components of the gas and the relative amounts thereof. The measurement devices 6 are preferably situated in the vicinity of a metering station 7. Samples of the gas may be taken at source or from the gas at an appropriate point as it enters or flows through the pipeline 2 from the upstream gas fields and/or oil fields 4, and such samples may be taken continuously, according to a predetermined schedule, or on demand. Upon sampling and analysing the gas, such gas chromatographic analysis equipment provides information relating to composition, and hence the net calorific value of, and/or rate of change of the calorific value of, the analysed gas. This characteristic is also known as the lower heating value (LHV), which is measured in KJ/kg (energy per unit mass) or MJ/m³ (energy per unit volume), based on which the efficiency of downstream users 5 such as power plants may be calculated.

As mentioned above, one end of the first pipeline 1 is connected to a source of fuel. Referring to figure 1, this source preferably comprises a store or tank 8 of fluid such as liquefied natural gas (LNG) connected to a gas processing plant 9, which comprises a re- gasification facility arranged to convert the LNG from a liquid to a gaseous state. Alternatively, the source can comprise fuel in the form of gas.

LNG tanks 8 can comprise remotely harvested natural gas which is converted into liquid form before being transported to a location where the local natural gas supply from the upstream gas fields and/or oil fields 4 is of insufficient quality and/or quantity, or simply does not met the specific requirements of the downstream users 5. One or more tanks 8 can then be connected to the gas transmission system, via gas processing plant 9, and used to supplement the originally available gas supply.

The gas processing plant 9 typically comprises an extraction facility 10, such as a hydrocarbons or liquefied petroleum gas (LPG) extraction facility, arranged to extract hydrocarbons that are not wanted or required in the export gas leaving the gas processing plant 9. For example, the extraction facility 10 is typically arranged to extract propane, butanes and heavier hydrocarbons, thus leaving ethane and methane present in the gas. The LPG can advantageously be harvested as a separate fuel product. The gas processing plant 9 can also comprise a diluent injection facility 11 for introducing a diluent such as nitrogen into the gas.

After extraction of the LPG and any other necessary processing, the remaining processed gas is sampled and its characteristics, such as its composition, flow rate and temperature, are measured by one or more further measurement devices 12, before leaving the gas processing plant 9. This processed gas is then exported from the gas processing plant 9 along the first pipeline 1 , and combines with the gas flowing in the second pipeline 2 where these gas flows meet at the pipeline junction 3. Such sampling, measurement and analysis can additionally or alternatively be performed on the LNG that is being off-loaded from an LNG carrier to the tank 8, the LNG present in the tank 8 or the LNG passing into the gas processing plant 9. Samples may be taken continuously, according to a predetermined schedule, or on demand.

The analysis and extraction processes are controlled by a controller 13, and the measured and/or determined data is stored in a data store 14. The controller 13 is operably connected to a server 15, which is typically an Openness, Productivity and Connectivity (OPC) server. The controller 13, data store 14 and server 15 are further operably connected to an Advanced Process Controller (APC) unit 16 or an auto-tuner. The APC unit 16 can be used to control parameters of the re-gasification process and/or extraction of LPG, and hence characteristics such as the calorific value or LHV of the gas to be exported from the gas processing plant 9, to ensure that the export gas has characteristics such that, when mixed with the associated gas and delivered to downstream users, the combined gas characteristics match pre-set target characteristics or fall within a target range, as discussed further below. For example, the APC unit 16 can increase or decrease the extent of LPG extraction, including by-passing the LPG extraction facility 10, or rejecting LPG back into the gas by adjusting the LPG extraction facility to recover less LPG. Additionally or alternatively, the APC unit 16 can increase or decrease an amount of nitrogen injected into the gas. The APC unit can be configured with any fixed constraints that are required. In this way, the APC unit 16 can control the characteristics of the export gas transported from the plant into the first pipeline 1. The controller 13 controls all of the functions of the gas processing plant 9 and is a common component in many modern fluid processing plants. When the configuration of a gas processing plant 9 is changed, for example a control valve position is changed, the controller 13 communicates with the valve and makes the change. This is achieved by a set of control loops which use an operator defined set point to control the process function or variable (e.g. a valve position). The main gas processing plant 9 control is achieved by a large number of control loops which control a variable by using a plant function such as a valve, compressor speed, etc. The upstream APC unit 16 determines the most optimum set point for the particular plant function & control loop and then uses the operator interface of the controller 13 to implement this change by writing a new set point into the controller 13 control loop for that function.

In order to allow prediction and monitoring of the gas exported and delivered to users, a process management server 20 and a simulation server 30 are provided. Predictive and real time gas flow models, which are run by the simulation server 30, operate dynamically, and are applied to the gas flowing through the second pipeline 2 from the upstream gas fields and/or oil fields 4.

The predictive model runs simultaneously to, and is an exact copy of, the real time model; however, while the real time model simulates the current characteristics of the gas in the second pipeline and runs in real time, the predictive model is allowed to run at a faster rate, for example, 30 times faster than the real time model, in order to show the predicted characteristics of the gas, preferably at a predetermined time in the future. Such a prediction is provided to the process management server 20, which uses the information to determine whether and to what extent the characteristics of the fluid to be exported from the gas processing plant 9 should be adjusted such that when the export gas is mixed with the associated gas, the combined gas meets a required gas specification upon delivery to a user 5; once this determination is made and any necessary adjustment to the processing performed by the gas processing plant 9 is identified by the process management server 20, an instruction in the form of a characteristic setpoint (such as an LHV setpoint) is sent to the APC unit 16 at an appropriate time. The APC unit 16 then effects the adjustment at an appropriate time to achieve the required adjustment in exported, and delivered, gas characteristics. In addition to providing the gas transmission system with information, downstream users 5 can access the predicted information via the user data interface 40 and request adjustments, such as composition and rate adjustments, for example for transition periods.

The system can therefore determine whether the gas from the upstream gas fields and/or oil fields 4 must be supplemented in some way in the first place; that is, whether gas from an additional source, for example in the form of re-gasified LNG as discussed above, is required, and further can determine whether adjustments to the re-gasification process in the form of an adjustment to the LPG extraction, bypassing the LPG extraction facility 10, or an injection of nitrogen into the export gas, is required, together with the correct time at which to apply this adjustment.

The real time model or live pipeline tracker uses information regarding the associated gas characteristics to provide the system, and optionally downstream users 5, with information about the associated gas flowing through the second pipeline 2. This enables the system and users 5 to monitor the gas composition, calorific value, temperature, pressure, and other characteristics of the associated gas.

The real time model is also used to determine "residence times" for various sections of the gas transmission network, these residence times being the predicted times for gas to flow from one end to another of the sections. For example, the residence time of the first pipeline 1 is the time it takes the export gas to flow from an output of the gas processing plant 9 to the tie-injunction 3, and the residence time of the second pipeline 2 is the time it takes the gas to flow from the associated gas source metering station 7 (or wherever the measurement devices 6 are situated) to the tie-injunction 3. It is important that the residence time of second pipeline 2 is longer than the residence time of first pipeline 1 such that the gas that enters the second pipeline 2 takes longer to reach the junction 3 than the gas flowing through first pipeline 1. The difference in residence time should be great enough to ensure that the system has sufficient time to calculate the required LHV and the appropriate action time at which to instruct the APC unit 16. The difference in residence time should also be great enough to allow for the reaction time of the APC unit 16 upon receipt of the instruction that is to be implemented and to allow for the residence time of the first pipeline 1. Accordingly, the difference in residence time is sufficiently great enough to ensure that the combined gas characteristics continue to match the pre-set target characteristics or continue to fall within a target range.

The components and operations of the process management server 20 and the simulation server 30 will now be described in more detail.

Referring to Figure 2a, gas characteristic measurement and analysis (SlOl) of the gas in the second pipeline 2 is preferably performed continuously, or alternatively is performed at regular intervals, at measurement devices 6. Data in relation to a characteristic, such as the LHV, is routinely passed (S 102) to the controller 13 and is stored or recorded in the data store 14. The process management server 20 comprises a data manager 21, which routinely requests, from the controller 13, data on key gas characteristics (of gas in the first and/or second pipelines) stored in the data store 14. The data manager 21 may request such data at set intervals, for example. This data is then passed (S 103) through the OPC server 15 to the data manager 21. The data manager 21 then compares (S 104) the most recently received value(s) for the LHV stored within an information database 22 of the process management server 20 to assess whether a change has occurred. If the LHV is shown to be unacceptably lower (or higher, as appropriate) than a predetermined threshold value, such as a data tolerance value, stored in the database 22, further action by the data manager 21 is required.

The data manager 21 sends (S 105) the new LHV, together with all other measured gas characteristics (which may not have changed in conjunction with the LHV) to a predictive server 31 of the simulation server 30, and requests a list of critical information that is required by the server in order to run the predictive model. The predictive server 31 feeds (S 106) the new LHV, together with all other measured gas characteristics, into the predictive model. The predictive model runs (S 107) ahead of real time as described above, in order to determine information relating to predicted characteristics of the gas as it passes down the second pipeline 2. This information is then sent to the predictive server 31. Such information is part of the requested critical information requested by the data manager 21 , which may include information relating to time, pressure, temperature, LHV, gas flow rate, etc. The critical information is then sent (S 108) to the data manager 21. The data manager 21 comprises a custom calculation package 23, and uses this to determine (S 109) the type and extent of an adjustment required by the system to counteract the anticipated characteristic value that has been predicted. In the case of a measured change to the LHV, the time and LHV may be used to calculate what adjustment is required by the gas processing plant 9 processes, and the exact time at which this adjustment should be implemented. Such information is determined as setpoints sent as instructions to the APC unit 16, and is described in more detail below in relation to Figure 3.

Continuing to refer to Figure 2a, the results of step S 109 are recorded (Sl 10) in the information database 22 for a "patience time" period, so that this data can be checked or confirmed. The patience time can be defined as a period of time for which the APC unit 16 waits whilst the data manager 21 confirms (Si l l) that any adjustment data determined by the data manager 21 is consistent, and hence may be acted upon. The data manager 21 receives a subsequent set of data sent, as in step S 108, from the predictive server 31 , and compares these data against the adjustment data stored in the information database 22, typically employing an algorithm in order to assess whether the adjustment data is "true" or "false" data. This process can be performed with a number of sets of data such that any number of sets of data are compared in providing the confirmation. If the stored adjustment data is verified, the adjustment data are transferred (Sl 12) into an action list of setpoints for the APC unit 16 stored within the information database 22, for instructing the APC unit 16 at an appropriate time to allow correct implementation of the setpoint. Each of the setpoints in the action list is time stamped with this appropriate instruction time. Alternatively, if the reading is determined to be false, the action is discarded by the data manager 21. Once the implementation time is reached, the data manager 21 sends (Sl 13) the new setpoint for the LHV to the APC unit 16 via the OPC server 15, and the adjustment is implemented (Sl 14) by the controller 13. Steps S105 to Sl 14 are repeated every time a change in excess of a predetermined threshold, to any of the gas characteristics, is determined. The real time modelling is preferably performed in parallel with the predictive modelling. As mentioned above, the real time model simulates the current characteristics of the gas in the second pipeline in real time, while the predictive model runs at a faster rate, ahead of the real time model, in order to determine the predicted characteristics of the gas at a time in the future. Referring to Figure 2b, in the case of real time modelling, the data manager 21 now sends (S205) the new LHV, together with all other measured gas characteristics (which may not have changed in conjunction with the LHV) to a real time server 32 of the simulation server 30, and requests a list of critical information that is required by the server in order to run the real time model. The real time server 32 feeds (S 206) the new LHV, together with all other measured gas characteristics, into the real time model. The real time model runs (S207) with the new information as described above, using a characteristic tracking software element to time stamp the characteristic data. The time stamped characteristic data is then sent via the real time server 32 and the data manager 21 to the information database 22 (S208). Such information corresponds to the requested critical information requested by the data manager 21, which may include information relating to time, pressure, temperature, LHV, gas flow rate, etc. The information database 22 records the time and characteristic information received. The information database 22 can be accessed by system operators and engineers, as well as by downstream users 5 via the internet using user data interface 40, to view the time and gas characteristic information as it is tracked down the pipeline.

The process management server 20 employs suitable software, while methods for configuring a simulation model using the HYSYS application are known to those skilled in the art and can be employed by the simulation server 30 and associated predictive server 31 and real time server 32.

The predictive model may be initiated by the data manager 21. Once the real time model is running, the data manager 21 can instruct the simulation server 30 to record the results of the real time model and initiate the predictive model using these results.

Turning now to aspects of the adjustment process described above with reference to steps S 108 to Sl 14 of Figure 2a, Figure 3 shows a flowchart of the process performed by the data manager 21 in calculating the adjustment data, in terms of a time and a LHV (the LHV characteristic can be replaced by any characteristic that is controllable with respect to time). The data manager 21 preferably runs through the process of Figure 3 continuously; in overview, the process involves the data manager 21 running the predictive model ahead of time and recording the results. The data manager 21 then uses the custom calculations package 23 to work out what to adjust and when, based on the results of the predictive model. The adjustment data is then stored for the patience time before being sent as a setpoint to the APC. Each time a change in a measured characteristic occurs the same predictive actions will occur. An appropriate algorithm in relation to the characteristic will be applied as part of the custom calculations package for the data manager 21.

At step S301, any measurement relating to a change in a characteristic, and real time data, are received by the data manager 21 and are stored in the information database 22. At step S302, the data manager receives the predicted characteristic(s) and critical information from the predictive server 31 (as in step S 108 of Figure 2a). The data manager 21 then checks (S303) whether the predicted characteristic and critical information meet a value (for example, a threshold value), or are within a target range of values, in relation to current target delivery conditions. If this is the case, no action is taken (S304). Alternatively, if the predicted characteristic and critical information do not comply with the target value or range of values, a characteristic adjustment calculation is requested (S305), which involves the input of critical information from the information database 22 and the implementation of a calculation from the custom calculation package 23. A new required LHV value, one which is required to ensure that the combined gas at the junction 3 complies with the target value or range, is calculated at step S306; effecting this change to LHV value necessitates an adjustment to the re-gasification plant process; as a result the LPG extraction process or nitrogen injection level is modified accordingly. At step S307, the custom calculation package 23 is again employed to provide an action time calculation at which the adjustment must be instructed to the APC unit 16. This action time is calculated at step S308, and again critical and/or characteristic data may be accessed from the information database 22 for the calculation. At step S309, the adjustment data is timestamped with the action time at which the instruction is to be sent to the APC unit 16, and at step S310 the timestamped adjustment data is stored in the APC unit action list in the information database 22.

It should be understood that the predictive model is preferably run on the first pipeline 1 as well as the associated, second pipeline 2. The predictive model has two functions when run on the first pipeline 1 ; one is to act as a verification to ensure that the custom calculation package 23 has made the correct adjustments, and the other applies in more complex calculations (for example, when multiples are changing), when the predictive model can be run to help the custom calculations package 23 to achieve the correct change. Essentially the predictive model can provide more resolution to the calculations within the custom calculation package 23.

The current timestamp parameters are then checked (S311) against those used previously in calculating the action time at step S308, and an assessment is made (S312) as to whether or not the timestamp parameters have changed. For example, if the associated gas originating at the upstream gas fields and/or oil fields 4 and flowing in the second pipeline 2 decreases in LHV, the custom calculation package 23, optionally in association with the predictive model, calculates or predicts the required LHV of the export gas together with the time at which the gas processing plant 9 will have to make an adjustment to compensate for the decrease in LHV, in accordance with steps S305 and S307 above. The rate at which this associated gas reaches the tie-injunction 3 is determined by the flow rate of the gas through the second pipeline 2. As mentioned above, this residence time is the time taken for that gas to flow from one end (the upstream gas fields and/or oil fields 4) to another (the tie-injunction 3). Should the gas flow rate into the second pipeline 2 decrease at some point in the future, then the gas with the decreased LHV is already in the second pipeline 2; however the time it will take to move along the second pipeline 2 will change, that is, the residence time will increase. The APC unit 16 will therefore need to make the same change to the gas processing but at a different time, hence there is a requirement to re-run and re-timestamp the setpoint data; this process will be described further in connection with Figure 4b below.

If the timestamp parameters have changed, the process returns to step S307 and the action time calculation is performed again with the changed timestamp parameters. This feedback loop is provided to ensure that the APC unit 16 does not make changes to the gas processing plant 9 process solely based on the change in gas characteristics.

If it is assessed at step S312 that the timestamp parameters have not changed, the process progresses to step S313 where an assessment is made as to whether or not the action time of the timestamp is equal to the actual current time. If the action time has not been reached, the data manager 21 does not send the instruction or setpoint but waits (S314) and returns to perform steps S31 1 onwards again. Alternatively, if the action time is equal to the current time, that is, the action time has been reached in real time, the setpoint is sent by the data manager 21 and executed by the APC unit 16 at step S315, so that the calculated adjustment is implemented at the calculated action time.

Preferably, the system can be programmed to evaluate a predetermined number of measurements and to run the predictive model for each of these before allowing an adjustment to be instructed. For example, ten (eight, five or three) samples can be taken, analysed and used in the predictive model before the system will confirm the adjustment and action time. As additional verifications are made, the error margin of the adjustment data is reduced. If, when performing a verification with a subsequent set of data, it transpires that no action is required (for example, in the case that the previous data was erroneous), the data can be re-timestamped or the setpoint removed, as appropriate. The custom calculations package 23 of the predictive model takes a number of factors into account when calculating predicted gas characteristics for the gas flowing to the downstream users.

Firstly, a "LHV balance" calculation is performed as described above to calculate the required LHV (or other required gas characteristic) to be exported by the gas processing plant 9 in order that, when mixed with the associated gas, the combined gas flowing downstream of the tie-injunction 3, and therefore delivered to a downstream user 5, has a specific LHV (or other required gas characteristic).

Another of the possible characteristics upon which such a prediction can be made is the flow rate of the gas, in which case a "flow balance" calculation is performed. This calculates the Standard Volumetric Flowrate of gas to be exported by the gas processing plant 9 in order that, when mixed with the associated gas, the combined gas flowing downstream of the tie-injunction 3, and therefore delivered to a downstream user 5, has a specific flow rate.

A further LHV balance calculation can be performed to aid the prediction of the rate of change of the LHV of the gas that is delivered to a downstream user 5.

Additionally, as mentioned above, a "residence time" is calculated (typically by the real time model) for each section of the pipeline. These residence times are the predicted times for gas to flow from the export of the gas from the gas processing plant 9 to the tie-in junction 3; from the associated gas source metering station 7 (or wherever the measurement devices 6 are situated) to the tie-injunction 3; and from the tie-injunction 3 to a downstream user 5 inlet. The residence times allow the system to consider how many times the predictive model can be run (factoring in the patience time) to verify the adjustment data and hence reduce the error margin.

For example, if the associated gas is predicted to take 45 minutes to flow down the second pipeline 2 to the end of this pipeline and reach the tie-in junction 3, and it takes 30 minutes for gas exported from the gas processing plant 9 to flow along the first pipeline 1 , the system has a 15 minute time window before which the adjustment data must be implemented by the APC. However, if the patience time is 3 minutes, and the predictive model is run for as many times as is required within the time window to verify the adjustment data, the system will then have 12 minutes, upon verification, before which the adjustment must be implemented.

The predictive model runs in a stepping mode, therefore each time the model is re- run (in theory for the same gas as it flows along the pipeline), the results from the previous predictive model are used as an input into the model re-run.

Figure 4a shows how time constraints are taken into account by the system once a change in the LHV is determined by the data manager 21. In step S401 , the system determines whether the residence time of the second, associated pipeline 2 (P2RT) is greater than the residence time of the first pipeline 1 (PlRT) of the system plus any additional time that must be factored in by the system, such as a reaction time of the APC unit 16 (ART) and a safety margin time (SMT). The safety margin time includes the time that it takes the system to calculate the required LHV of the export gas output from the gas processing plant 9 based on the results of the predictive model. If this is the case, there is sufficient time for the system to calculate, instruct, react to and implement the adjustment and for the export gas to flow along the first pipeline 1 to the tie-injunction 3, and the process moves to step S402. If there is insufficient time to perform these actions, no action is taken and the process is repeated when a further change to the gas characteristics is determined.

Assuming there to be sufficient time, at step S402, the system starts a run of the predictive model, based on a copy of the real time model. At step S403, the system determines whether a predictive model simulation time (PMST) is greater than the residence time of the first pipeline 1 (PlRT) of the system plus the reaction time of the APC unit 16 (ART) and the safety margin time (SMT). If this is not the case, the process returns to step S402 and the predictive model is re-started; alternatively, if this is the case, this step ensures that the results of the predictive model will allow an adjustment at an appropriate time to counteract the determined change in the characteristic of the associated gas. The process proceeds to step S404, where the predictive model is stopped and the calculated characteristic adjustment, for example in the form of a required LHV of the export gas, is read. In step S405, an original timestamp (OTS) representing the time at which the required LHV should be sent to the APC unit 16 is calculated as the predictive model simulated end time (PET) (i.e. the predicted time at which the export gas should reach the junction to combine with the associated gas), minus the residence time of the first pipeline 1 , minus the reaction time of the APC unit 16 (OTS = PET - P 1 RT - ART); this timestamp is then stored alongside the required LHV in the information database 22, for example in an APC action table. The entire process is repeated each time a change to a characteristic of the associated gas is determined.

Referring to Figure 4b, the steps taken in writing an instruction to the APC unit 16, following the process of Figure 4a, will be described. At step S406, the data manager 21 reads the action data from the action table of the information database 22. The action table may include a flag field indicating the status of an action to be "true" if it has already been written to the APC unit 16 but is still stored in the database 22, or "false" if the action is yet to be written to the APC unit 16; in this case the data is only read if the status flag is false. The current residence time of the first pipeline 1 (ClRT) is identified by running the real time model on the first pipeline 1 in step S407. At step S408, a "reconciled timestamp" (RTS) is calculated, by subtracting the difference between the residence time calculated during the process of Figure 4a and the current residence time, from the original timestamp calculated in the process of Figure 4a: RTS = OTS - (PlRT - ClRT). The reconciled timestamp is then stored in a relevant field in the action table. This reconciled timestamp is the new time at which the adjustment data needs to be written or instructed to the APC unit 16, owing to the change in the residence time of the first pipeline 1 from the time at which the predictive run took place, to the current time; such a change could occur due to a change in the flow rate of the gas.

At step S409, the data manager 21 determines whether there is a reconciled timestamp entry stored in the action table that is within a certain time, for example within one minute, of the current time. If there is such a reconciled timestamp entry, the corresponding adjustment data, such as a new LHV, is written (S410) to the APC unit 16 and the entry is marked as "true" accordingly. If no such entry is present in the action table, the system waits, at step S41 1, for an appropriate predetermined time, such as 30 seconds, and then returns to the start of the process. Preferably, the adjustment is instructed as a single instruction of a specified rate of change, rather than instructing the APC 16 with a plurality of staged or stepped discrete value changes, which results in the desired overall adjustment, as typical gas processing plants 9 deal with a "rate of change" adjustment more effectively; however, both implementations are possible. The system and method of the invention may be applied in a number of scenarios, one of which will now be described in relation to Figure 5.

Figure 5 shows a flowchart of a simplified example in which a characteristic of gas delivered to the downstream users 5 is maintained at a constant value. In step S501, a change in the LHV value of the associated gas measured by the measuring devices 6 is determined by the data manager 21. This data is sent to the predictive server 31 and the predictive model is run (S502) with this new LHV value as an input, and as a result LHV of the associated gas in the second pipeline 2 is predicted to reduce in step S503. The results are sent to the data manager 21, which determines, in step S504, the type, extent and action time of one or more adjustment(s) required to the exported gas from the gas processing plant 9 in order to counteract the reduction in the LHV of the associated gas in the second pipeline 2 when the pipelines meet at the tie-injunction 3. The APC unit 16 is instructed to implement the adjustment (S505) at the appropriate action time, and may implement the instruction after an associated patience time. In such a case, any sharp variation in the LHV of the gas delivered at a downstream user's pipeline inlet is avoided, and a steady LHV is maintained.

Other scenarios in which the gas transmission control system and method may be applied are: in order to maintain steady flow rate and LHV to a downstream user; to maximise LPG production whilst managing minimum rate of change of LHV to a downstream user; to maintain flow rate and LHV to match downstream user demand; and to maximise LPG production whilst managing a maximum rate of change of LHV to a downstream user. The gas transmission control system may be implemented where gas is supplied to multiple users situated downstream of the junction 3 at which the first pipeline 1 and the second pipeline 2 converge. For example, the transmission network may supply three or four power stations, all of which have specific gas characteristic requirements, and one of which has a narrower acceptable range for the LHV of rate of change of the LHV than the other stations. In this case, gas having characteristics that meet the narrower specification, and which therefore meets all of the stations' specifications, can be produced. Adjustments can be made to the gas characteristics depending on which power stations are on or require a supply at a certain time, in order to manage gas transmission network and control system efficiency and costs. It is also possible to supplement the local gas supply using multiple additional sources, such as multiple LNG tanks 8 which are all connected to the gas processing plant 9. In this case, each tank 8 may contain LNG originating from a different remote source (for example, LNG originating in different countries) having different characteristics, so the fluid characteristics may be measured and analysed when transferred to the tanks 8 for storage, so that the system is aware of the characteristics of the LNG in each tank 8 and can use the supplies accordingly. Further measurement and analysis can then be performed upon feeding LNG from a particular tank 8 to the gas processing plant 9, as a confirmation of the characteristics or to detect any changes, for example due to contamination, that may have occurred during storage.

As the LNG originates at a remote source and may be transported to the LNG tank 8 location for storing in the tanks 8, LNG from multiple original sources may be stored in each of the LNG tanks 8. In this case, as LNG from different original sources does not necessarily mix well, the characteristics of the LNG can be measured and analysed when passing from the tank 8 to the gas processing plant 9.

In a preferred embodiment in which multiple LNG tanks 8 are employed, the gas characteristics of each are measured and analysed whilst remaining in storage, such that the results thereof can be considered by the system and the LNG can be released and, if necessary, mixed in appropriate quantities to minimise alterations to the composition of the mixed LNG stream that is fed to the gas processing plant 9. Such pre-emptive analysis of the LNG can be performed relatively quickly by the system, advantageously minimising gas processing time, effort and cost at the gas processing plant 9. The invention provides significant advantages for downstream gas users in reliability, maintainability and efficiency of combustion. For example, gas fired turbine power stations are particularly sensitive to gas quality changes, particularly in LHV and Wobbe Index. The range of both of these characteristics is required to be within a defined range of values to ensure acceptable operation, while failure to adhere to this can lead to poor power station availability.

Plants which burn natural gas can suffer the problem of turbine rumble depending on the rate of change of composition of the supplied gas. However, the composition of gas from one source is rarely the same as that from another source. Thus, when gas from multiple sources is combined or processed consecutively, a gas composition that varies over time can result. This variation can lead to turbine rumble since the plant's operating parameters are not matched to the variation in gas characteristics over time. The gas transmission control system and method described above avoid such situations, by predicting the variation in characteristics and responding to this prediction by preemptively adjusting the processing of the incoming gas supply.

The above embodiments are to be understood as illustrative examples of the invention. Further embodiments of the invention are envisaged. It is to be understood that any feature described in relation to any one embodiment may be used alone, or in combination with other features described, and may also be used in combination with one or more features of any other of the embodiments, or any combination of any other of the embodiments. Furthermore, equivalents and modifications not described above may also be employed without departing from the scope of the invention, which is defined in the accompanying claims.

Claims

Claims:

1. A fluid transmission control system arranged to control the transmission of fluid through a fluid transmission network, the fluid transmission network comprising a first pipeline having a first end connectable to the output of a fluid processing plant, said fluid processing plant being associated with a first fluid source, and a second pipeline having a first end connectable to a second fluid source and a second end connectable to the first pipeline at a junction with a second end of said first pipeline, the control system comprising: measurement means for measuring one or more characteristics of fluid output from the second fluid source; prediction means for predicting future characteristics of the fluid based on the measured characteristics, said characteristics corresponding to a future time at which the fluid flows through the second end of the second pipeline; adjustment determining means arranged to receive data regarding said predicted characteristics of the fluid, wherein the adjustment determining means are further arranged to identify an adjustment to the processing of fluid at the fluid processing plant to account for the predicted characteristics; and control means arranged to control the fluid processing plant in accordance with the identified adjustment.

2. The system according to claim 1, wherein the adjustment determining means are further arranged to identify the adjustment in order to adjust the characteristics of the fluid at the fluid processing plant, such that, upon combination with fluid from the second fluid source, the combined fluid comprises specified characteristics.

3. The system according to claim 1 or 2, wherein the control means are arranged to control re-gasification means of the fluid processing plant, said re-gasification means being arranged to re-gasify liquefied natural gas, in accordance with the identified adjustment.

4. The system according to any preceding claim, wherein the control means are arranged to control one or both of hydrocarbons extraction means and diluents injection means of the fluid processing plant, in accordance with the identified adjustment.

5. The system according to any preceding claim, wherein the measurement means comprise fluid chromatographic analysis means.

6. The system according to any preceding claim, further comprising fluid tracking means arranged to simulate fluid characteristics of the fluid flowing through the second pipeline in real time.

7. The system according to any preceding claim, wherein the adjustment determining means are further arranged to verify the identified adjustment.

8. The system according to any preceding claim, further comprising additional measurement means for measuring one or more characteristics of fluid originating at the first fluid source.

9. The system according to claim 8, wherein the additional measurement means is arranged to measure one or more characteristics of each of a plurality of receptacles of fluid of the first fluid source.

10. The system according to any of claims 2 to 9, wherein the specified characteristics comprise a target characteristic value, or a target range of characteristic values, with which the characteristics of the combined fluid must comply.

1 1. The system according to any of claims 2 to 10, wherein the adjustment determining means are arranged to assess whether values of the specified and predicted characteristics differ by more than a predetermined amount and, in the case that the values differ by more than the predetermined amount, to identify the adjustment as a required value of a said characteristic of fluid exported from the fluid processing plant.

12. The system according to any preceding claim, wherein the adjustment determining means are further arranged to calculate an action time at which to instruct the adjustment to the control means.

13. The system according to claim 12, wherein the system is arranged to instruct the control means with the adjustment at the action time.

14. The system according to claim 12 or 13, wherein the adjustment determining means are further arranged to verify the action time.

15. A method of controlling fluid transmission through a fluid transmission network, the fluid transmission network comprising a first pipeline having a first end connectable to the output of a fluid processing plant, said fluid processing plant being associated with a first fluid source, and a second pipeline having a first end connectable to a second fluid source and a second end connectable to the first pipeline at a junction with a second end of said first pipeline, the method comprising the steps of: measuring one or more characteristics of fluid output from the second fluid source; predicting future characteristics of the fluid based on the measured characteristics, said characteristics corresponding to a future time at which the fluid flows through the second end of the second pipeline; receiving data regarding said predicted characteristics of the fluid; identifying an adjustment to the processing of fluid at the fluid processing plant to account for the predicted characteristics; and controlling the processing in accordance with the identified adjustment.

16. The method according to claim 15, further comprising the step of identifying the adjustment in order to adjust the characteristics of the fluid at the fluid processing plant, such that, upon combination with fluid from the second source, the combined fluid comprises specified characteristics.

17. The method according to claim 15 or 16, wherein controlling the processing comprises controlling re-gasification of liquefied natural gas, in accordance with the identified adjustment.

18. The method according to any of claims 15 to 17, wherein controlling the processing comprises controlling one or both of the extraction of hydrocarbons from, and the injection of diluents into, the fluid, in accordance with the identified adjustment.

19. The method according to any of claims 15 to 18, wherein measuring one or more characteristics comprises performing chromatographic analysis of the fluid.

20. The method according to any of claims 15 to 19, further comprising the step of simulating fluid characteristics of the fluid flowing through the second pipeline in real time.

21. The method according to any of claims 15 to 20, further comprising the step of verifying the identified adjustment.

22. The method according to any of claims 15 to 21 , further comprising the step of additionally measuring one or more characteristics of fluid originating at the first fluid source.

23. The method according to claim 22, wherein the additional measuring step comprises measuring one or more characteristics of each of a plurality of receptacles of fluid of the first fluid source.

24. The method according to any of claims 16 to 23, wherein the specified characteristics comprise a target characteristic value, or a target range of characteristic values, with which the characteristics of the combined fluid must comply.

25. The method according to any of claims 16 to 24, further comprising the steps of assessing whether values of the specified and predicted characteristics differ by more than a predetermined amount and, in the case that the values differ by more than the predetermined amount, identifying the adjustment as a required value of a said characteristic of fluid exported from the fluid processing plant.

26. The method according to any of claims 15 to 25, further comprising the step of calculating an action time at which to instruct the adjustment.

27. The method according to claim 26, further comprising the step of instructing the adjustment at the action time.

28. The method according to claim 26 or 27, further comprising the step of verifying the action time.