The present invention relates to a method for monitoring a hydrocarbon liquid from a hydrocarbon fluid processing system, and to a related system for monitoring a hydrocarbon liquid from a hydrocarbon fluid processing system.

In the field of oil and gas processing, well streams containing hydrocarbon fluids may be supplied to a hydrocarbon fluid processing system where they undergo various stages of processing. The processing system outputs a hydrocarbon gas and a hydrocarbon liquid (i.e. oil), which are then transported to desired locations. Such processing typically includes stages such as gas-liquid separation, heating, cooling, dehydration, etc.

Following this processing of hydrocarbon well streams, heavy components (e.g. long chain molecules) from the hydrocarbon fluids typically end up in the oil, and light components (e.g. short chain molecules) typically end up in the gas. Some light and intermediate components such as propane, hexane, octane, etc. may end up in either the gas or the oil, depending on the processing stages in the system. Altering parameters or conditions in the processing system, such as the temperature or pressure at which various steps are performed, can alter the output of the system. For instance, the light and intermediate components may be more likely to end up in the oil phase rather than the gas phase under certain conditions.

At the inlet of the processing system, it is typical to measure the flowrate of the incoming hydrocarbon streams. The flowrates can be monitored continuously using multiphase meters, or measured less frequently by flowing separate inlet streams through a test separator in which the flow rates are measured. The compositions of the inlet streams are occasionally measured by sampling the hydrocarbon fluids and sending the samples to a specialized laboratory.

At the outlet of the processing system, it is typical to measure the composition and flow rate of the resultant gas produced by the processing system. In respect of the output liquid oil, it is typical to measure the flow rate. Occasionally (e.g. once every 1-2 months), a sample of the produced oil will be extracted from the system and sent to a specialist laboratory for a thorough analysis of the oil.

Since analysis of the liquid oil is only performed occasionally and requires specialist analysis equipment, it is difficult to monitor the oil closely, e.g. to promptly detect and observe changes in the oil. Instead, it is typical to rely upon the measurements of the output gas to monitor the operation of the processing system. However, this does not provide a complete picture of the outputs of the processing system since measurements of the product gas do not provide information about the product oil. Specifically, it is not known which of the hydrocarbon fluid components from the initial well streams end up in the oil versus the gas, nor can it be known what effects variations in the processing stages have on the final oil product.

There is a desire to be able to more closely monitor the hydrocarbon fluid processing system, and particularly the oil which is output from the processing system.

Viewed from a first aspect, the present invention provides a method for monitoring a hydrocarbon liquid from a hydrocarbon fluid processing system, comprising: determining information about the composition of the hydrocarbon liquid, wherein the determination comprises: inserting the hydrocarbon liquid into a closed container; obtaining a gas from the hydrocarbon liquid; allowing the gas to equilibrate with the hydrocarbon liquid in the closed container; analysing a sample of the equilibrated gas to measure the composition of the gas; and determining information about the composition of the hydrocarbon liquid based upon the gas composition measurement; and periodically repeating the determination of the information about the composition of the hydrocarbon liquid to monitor the hydrocarbon liquid composition over time.

By monitoring, i.e. frequently measuring, the composition of the liquid being output from the hydrocarbon fluid processing system, it is possible to observe which hydrocarbon components (particularly intermediate and light components) end up in the oil and in what amounts, and how the oil composition changes over time and in response to changes in the processing system.

The invention is based in part upon the recognition by the inventors that information about the composition of the oil in this situation can conveniently be determined based on measuring the composition of a gas with which the liquid is in equilibrium. The use of the gas composition information in this way means that complex laboratory measurements on the liquid sample itself can be avoided since there is no need to perform direct analysis on the liquid; the liquid phase oil sample does not need to enter the analysis equipment at all. Instead, significantly simpler gas phase measurements are sufficient. Another advantage is that air ingress in the sample will be detected during gas composition analysis and can be filtered from the data if needed.

The invention also extends to a system for monitoring a hydrocarbon liquid based on measuring the gas composition of a gas in equilibrium with the hydrocarbon liquid.

Thus, viewed from a second aspect, the present invention provides a system for monitoring a hydrocarbon liquid of a hydrocarbon fluid processing system, comprising: a closed container for containing the liquid and a gas obtained from the liquid, wherein the container is configured to allow the gas and the liquid to equilibrate; a gas analyser configured to receive a sample of the equilibrated gas and to analyse the sample to measure the composition of the gas; and a processor configured to receive the gas composition data from the gas analyser and to determine information about the composition of the hydrocarbon liquid based on the gas composition measurement.

The inventors have therefore developed an improved way of monitoring a liquid from a hydrocarbon fluid processing system which can be performed using relatively simple components. This means the system can be easily integrated into existing oil and gas processing systems without needing to rely on infrequent and complex oil sample extraction/analysis, making information about the liquid composition a continuously or frequently monitored quantity rather than an unknown or only occasionally known quantity. Thus, a greater understanding of the outputs of the processing system is gained, and the effects that variations in the processing stages have on the outputs of the system can be observed. As a result, more generally, the processing system can be more closely monitored.

The hydrocarbon liquid may be oil, e.g. from one or more produced well streams. The oil may have an oil vapour pressure in the range of 0.5 to 3.0 bara, or in the range of 0.5 to 2.0 bara, or around 1 bara. The hydrocarbon liquid may comprise one or more liquid components which may include heavy hydrocarbons, light hydrocarbons (e.g. methane, ethane, propane, butanes, pentanes, hexanes etc.), and/or a mixture of heavy and light hydrocarbons. The liquid may contain dissolved gases.

The gas may comprise one or more gas components, which may include light hydrocarbons and/or inert gases (e.g. N2, CO2, etc.). Thus the gas may be or comprise a hydrocarbon gas.

Determining information about the composition of the hydrocarbon liquid may comprise identifying one or more chemicals, or groups of chemicals (e.g. based on the number of carbon atoms) present in the liquid. The method preferably also includes identifying the relative amounts of the detected component(s). The method may be particularly useful for identifying light and/or intermediate components in the liquid. The method may therefore determine the “oil light end fingerprint”, that is, the method may include determining composition data relating to one or more light and/or intermediate hydrocarbon components in the liquid. Light and/or intermediate hydrocarbon components may include methane, ethane, propane, butanes, pentanes, hexanes, heptanes, octanes, nonanes and/or decanes. The determined information about the composition of the hydrocarbon liquid preferably comprises the concentrations of at least C1-C6 components (i.e. molecules comprising one to six carbon atoms), and preferably of at least the C1-C10 components.

The container may be an integrated component of a larger apparatus or system such as an oil and gas processing system. For instance, the container may comprise a separator (e.g. a gas-liquid separator) of an oil and gas processing system. In instances where the oil and gas processing system comprises a series of gas-liquid separators, the container is preferably the final separator in the series. This is because the composition of the oil at the final separator is the composition of the oil which is the resultant product of the processing system (i.e. the processed oil), and so determining the composition of the liquid exiting the final separator provides information about the composition of the product oil output from the processing system.

Thus, there may be provided an oil and gas processing system configured to receive a hydrocarbon well stream and to output a processed oil, comprising: a series of gas-liquid separators each configured to separate a hydrocarbon fluid of the hydrocarbon well stream into a gas phase and a liquid phase; and a system for monitoring the processed oil output from the oil and gas processing system, wherein the system for monitoring the processed oil comprises: a closed container for containing the processed oil and a gas obtained from the processed oil, wherein the container is configured to allow the gas and the processed oil to equilibrate; a gas analyser configured to receive a sample of the equilibrated gas and to analyse the sample to measure the composition of the gas; and a processor configured to receive the gas composition data from the gas analyser and to determine information about the composition of the processed oil based on the gas composition measurement; wherein the closed container is the final separator in the series of gas-liquid separators.

Similarly, the method according to the first aspect may be a method for monitoring a processed oil from an oil and gas processing system, and the method may comprise providing a series of gas-liquid separators each configured to separate a hydrocarbon fluid of the hydrocarbon well stream into a gas phase and a liquid phase, prior to carrying out the other steps described herein (e.g. the steps of determining information about the composition of the processed oil and periodically repeating the determination of the information about the composition of the processed oil to monitor the processed oil composition over time). The closed container is preferably the final separator in the series of gas-liquid separators.

As well as gas composition, the liquid composition calculation may additionally use other parameters, such as the temperature and/or the pressure of the gas at equilibrium. Thus, the system may comprise one or more sensors configured to monitor conditions in the container. These may include a temperature sensor for measuring the temperature of the container, and/or a pressure sensor for measuring the pressure of the container. The method may comprise determining the pressure and/or the temperature of the container when the gas and the liquid are in equilibrium.

The measurements (e.g. pressure and/or temperature) of the equilibrated gas do not necessarily have to be taken while the gas is in the container. Thus, rather than locating the sensor(s) in or at the container, one or more of the sensors may alternatively be located outside the container, for instance in a gas outlet pipe through which the gas outputted from the container flows.

The parameters used in the composition calculation may include volume and/or volume flow of the hydrocarbon liquid and/or the gas. The system may comprise suitable sensors for measuring these parameters, e.g. flow rate sensors and/or liquid level sensors.

The container is enclosed or sealed so as to contain the liquid and gas and prevent leakage therefrom, apart from the presence of any inlets and outlets which permit the controlled entry and exit of fluids as necessary. A closed container allows the gas and the liquid to equilibrate.

The container may comprise an inlet for receiving the liquid, e.g. from an inlet pipe. The container may also include one or more outlets for outputting liquid and/or gas from the container. The inlet and/or outlet pipes preferably comprise a valve for controlling, e.g. selectively preventing or allowing, the passage of liquid or gas therethrough. In some embodiments the one or more valves may comprise a binary valve, i.e. an on-off valve which either prevents or permits the flow of fluid therethrough. This enables the system to perform analysis on discrete samples of liquid, e.g. in a “batch process”. In other embodiments the valve(s) may comprise a variable valve for adjusting or regulating the flowrate of the fluid. This enables the system to perform analysis on a continuous flow of liquid, with the flow of fluids into and out of the container being regulated by the valves to maintain desired flow rates. The valve(s) may be controlled by a controller.

In some embodiments, the gas with which the liquid equilibrates is input into the container, e.g. via an inlet. In this case, obtaining a gas from the liquid may comprise separating the gas from the liquid. The gas may be input into the container using the same inlet as the liquid, and optionally at the same time as the liquid, e.g. by inputting a mixed gas-liquid fluid stream which comprises gas components and liquid components. The method may therefore comprise inputting a hydrocarbon fluid stream comprising a mixture of the gas and the liquid into the container, and separating the hydrocarbon fluid stream into the gas and the liquid in the container. The container may comprise one inlet configured to receive both the liquid and the gas. This is particularly advantageous when the liquid to be monitored, i.e. the liquid whose composition information is desired to be known, is the separated liquid from a gas-liquid separator, since the container in which the gas and liquid equilibrate can be the pre-existing gas-liquid separator and thus the liquid composition determination system can be easily integrated into the existing system.

In other embodiments, the gas may not be input into the container in gaseous form, but instead may be created by expanding the liquid within the container so that gas evaporates therefrom. In this case, obtaining a gas from the liquid may comprise expanding the liquid within the container to form the gas. This is advantageous in instances where only a liquid sample is available, rather than a mixed gas-liquid fluid stream. The liquid monitoring system can then be situated remotely (and downstream) from the oil and gas processing system and configured to receive the liquid oil itself, rather than being situated at the separator from which the oil originated. Expanding the liquid can be done for instance by decreasing the pressure of the container at constant temperature and/or by changing the temperature of the liquid at constant pressure. This will cause some liquid to vaporise until the vapour pressure is reached. The ratio of vapour (i.e. gas) and liquid in the resulting mixture may be designated by V/L, where V is the vapour volume and L is the liquid volume.

In such embodiments, the method may comprise expanding a first portion of the liquid to a first V/L ratio, and expanding a second portion of the liquid to a second V/L ratio. In this case the first and second gases formed by expansion are allowed to equilibrate with the respective portions of the liquid, a sample of each of the equilibrated first and second gas is analysed, and the determination of information about the liquid composition is based on the first and second gas composition measurement.

The method may further comprise expanding further portions of the liquid to further V/L ratios to improve the reliability of the final result.

The V/L ratio(s) may be any suitable value, but must be greater than 0 (i.e. there is at least some gas in the mixture) and are preferably less than 5.0. For instance, suitable values may include V/L = 0.5, 1.0, 1.5, 2.0... 4.0, 4.5, 5.0, or more preferably V/L = 0.1, 0.2, 0.3...4.8, 4.9, 5.0. In one example, the first V/L may be 0.5 and the second V/L may be 1.0.

It will be appreciated that when the gas and the liquid are present together in the container they will equilibrate, i.e. naturally tend to equilibrium. The gas and the liquid may be determined to be in equilibrium when the relative amount of vapour and liquid is constant, i.e., when there is no net evaporation of liquid or condensation of gas. It will be understood that the equilibrium is a dynamic equilibrium since some condensation and evaporation will still occur, but at equal rates.

Allowing the gas and liquid to equilibrate, i.e. to come into equilibrium, may comprise keeping the conditions of the container (e.g. volume, temperature and/or pressure) constant or stable for a predetermined amount of time. This may include not changing the temperature of the container (e.g. not heating it up or cooling it down) and not changing the volume of the container. Some heating or cooling may be required to keep the temperature in the container constant. In embodiments in which there is a continuous flow of fluid into and out of the container, the flow rates may be kept constant to allow equilibrium to be established. This allows the natural process of equilibrium to occur.

The predetermined amount of time may be based on (preferably equal to or longer than) the time in which equilibrium is typically reached, which may be generally known or determined experimentally. For example, in cases where the container comprises a separator, the predetermined amount of time may be equal to or greater than the retention time in the separator. It may be assumed that equilibrium has been reached after the predetermined amount of time, or the method may comprise determining whether equilibrium has been reached, such as by detecting the pressure in the container and/or the gas composition and determining that equilibrium has been reached when the pressure and/or the gas composition stays approximately constant as the feed flow rate of fluid into the container is changed.

The gas analyser may comprise any suitable apparatus which is configured to determine the composition of a gas, e.g. a gas chromatograph, IR or FTIR spectrometer, Raman spectrometer, etc. Gas chromatography is a standard gas analysis method with high accuracy. Gas chromatographs are particularly advantageous in the present system due to their reliability and accuracy. However, other techniques such as IR, FTIR or Raman spectroscopy may offer other advantages such as relatively small size and/or low cost spectrometers, enabling them to be easily integrated into existing systems.

Once equilibrium has been reached, a portion or sample of the equilibrated gas is input into the gas analyser for analysis of the composition thereof. In embodiments in which multiple (i.e. at least two) portions of the liquid are expanded to different V/L ratios, the method may comprise analysing a portion of the equilibrated gas from each expanded mixture.

The gas analyser may be incorporated into or in fluid communication with the container which contains the liquid and gas. For instance the system may be configured to divert at least a portion of an outputted gas stream from the container into the gas analyser, e.g. via a conduit extending between a gas outlet of the container and an inlet of the gas analyser. The system may therefore be able to do the required sampling and analysis in situ, i.e. as a part of a processing plant or production facility.

Alternatively, a sample of the gas can be extracted from the container, e.g. in a pressurized cylinder or other suitable sampling equipment, and the gas analysis can be carried out remotely from the container, such as in a laboratory equipped with the gas analyser. The gas outlet may therefore be connectable to a sampling device, and the gas analyser may be configured to receive the gas sample from the sampling device. This allows the same gas analyser to be used for analysis of liquids from multiple systems.

Analysis of the gas determines information about the equilibrated gas composition, preferably identifying chemicals, or groups of chemicals (e.g. based on the number of carbon atoms) that are present in the gas and the relative amounts of each detected component. The gas composition data may be expressed in terms of mole fractions, i.e. the ratio of the number of moles of a particular gas component relative to the total number of moles of gas.

The gas analyser is configured to transmit the gas composition data to the processor. Thus the processor may receive the gas composition data as an input parameter for the determination of the information about the composition of the hydrocarbon liquid. The processor may comprise any suitable processing means, such as a microprocessor. The determination of gas composition is preferably carried out using numerical calculation methods.

The processor then translates the gas composition data into liquid composition data, as discussed in more detail below.

The amounts of the detected liquid components in the oil may be determined and/or expressed in terms of mole fractions. Alternatively, the amounts may be expressed in terms of mass (e.g. the number of moles or kilograms of a certain component per mass of oil) or in terms of volume (e.g. the number of moles or kilograms of a certain component per volume of oil). For instance, suitable units expressing the amount of the component in question may be ‘kg of component per kg of oil’, or ‘kg of component per Sm ³ (standard cubic metre) of oil’. Mass and/or volume units may be more convenient than mole fractions for practical purposes, since their physical meaning is typically more intuitively understood.

As noted previously, as well as the gas composition, the determination (e.g. numerical processing) for information about the liquid composition may additionally be based on the temperature and/or pressure of the equilibrated gas. Thus the processor may be arranged to receive the temperature and/or pressure measurements from the sensors. The processor may therefore receive, as input parameters, the gas composition data and at least one of the temperature and pressure of the gas at equilibrium. The processor may also receive and process information about the V/L ratio.

The processor may execute an algorithm which relates gas composition data, and optionally other input parameters (e.g. temperature, pressure, V/L ratio), to liquid oil composition. Thus, the algorithm may be based upon data relating gas composition to liquid oil composition and/or mathematical relationships that may be empirical or based upon first principle models.

The particular algorithm used may vary depending on various factors, such as whether the gas was input into the container or generated by expansion of the liquid as described previously. Some example calculation methods will be described below, by way of example.

In a first example, e.g. for embodiments in which a mixed gas-liquid stream is input into the final separator in a series of gas-liquid separators, the calculation may proceed as follows. The measurements taken are the composition of the equilibrated gas from the last stage separator ( y _i,3 ), and pressure and temperature in the last stage separator ( P3 and T3). Here, / represents a particular component and the subscript ‘3’ represents the separator (being the third stage separator in this case); however, the present system is not limited to three-stage separator systems and thus the final separator may generally be the ‘nth’ separator.

The mole fraction of component / in the oil phase, x _i , is related to the gas phase composition y _i,3 , the temperature T3, and the pressure P3 according to the standard relationship: (1) where P _i,3 is the partial pressure of component / in the gas, and K , is the equilibrium constant for component /. The equilibrium constant depends on the temperature T3.

By rearranging equation (1) and converting from a mole basis to a mass basis, the mass fraction of component / in the oil, m _i,3 , becomes where MW, and MW ₀ u are the molecular weights of component / and the oil, respectively. The molecular weight of component / may be known from standard tables/textbooks. The molecular weight of the oil can be determined from other analysis, as described below.

Thus, the mass fraction of component / in the oil may be proportional to the molecular weight of component /. The mass fraction of component / in the oil may be proportional to the pressure in the last stage separator. The mass fraction of component / in the oil may be proportional to the fraction of component / in the equilibrated gas from the last stage separator. The mass fraction of component / in the oil may be inversely proportional to the molecular weight of the oil. The mass fraction of component / in the oil may be inversely proportional to the equilibrium constant for component /.

The mass fraction of component / in the oil can be converted to the concentration of component / in the oil (e.g. kg of component / per Sm ³ of oil), c _/, 3, by multiplying with the oil density p ₀ u (e.g. kg oil / Sm ³ oil)

The molecular weight and the density of the oil (MW ₀ u and p ₀ u) can be determined from other analysis. For instance, the oil density can be measured online in the processing system, or offline by analysing an oil sample in a laboratory, e.g. an off-shore laboratory. The molecular weight of the oil can be calculated from infrequent full analysis of oil samples (e.g. taken once every 1-2 months and analysed in a laboratory). The molecular weight of the oil will be approximately constant over time, so it can be assumed to be approximately constant between these relatively infrequent full sample analyses. In addition, the molecular weight correlates with the oil density. Therefore, for a given installation, a prediction model for the molecular weight of the oil based on the oil density measurement can be established to adjust the molecular weight estimate based on the oil density measurement between sample analyses.

The temperature T3 in the separator may typically vary. If the temperature variation is small (i.e. negligible) there may be no need to do any temperature correction. However, if T3 varies significantly with time, then a temperature correction may be introduced to improve prediction accuracy. For instance, a reference temperature T3 ^ref may be introduced. This should be a typical or average value for the temperature T3. As an example, if the temperature T3 varies from 50 to 70°C, then T3 ^ref = 60°C may be reasonable choice.

Introducing the reference temperature, equations (2) and (3) can be rewritten as and respectively. Then, the ratio of the equilibrium constants can be expressed as where equation (1) was used in the first equality, and the Clausius-Clapeyron equation was used in the last equality. The Clausius-Clapeyron equation can be expressed as where H _vap is the molar enthalpy of vaporization of the liquid, and R is the ideal gas constant.

Introducing equation (6) into equations (4) and (5) results in the final equations:

In equations (8) and (9), the only unknown on the right-hand side of the equations at this point is the equilibrium constant Ki(T3 ^ref ). These may generally be determined experimentally. It has been found that the equilibrium constants do not vary much from oil to oil, as long as the total pressure P3 is relatively low (e.g. below 2-3 bara). Thus, the equilibrium constants may be determined experimentally for one particular oil field and then the same values may be applied across different fields.

Thus, equations (8) and (9) can be used to determine the mass fraction and concentration of component / in the liquid oil depending on the gas data y _i , ₃ from the last separator, along with other parameters that can be measured, looked up in reference tables and/or determined empirically. Equations (8) and/or (9) may be stored in the processor so that the input parameters can be input and processed to give a final value for the mass fraction or concentration of a particular oil component.

A second example calculation method may proceed as follows. This method may be particularly for embodiments in which a liquid oil sample is expanded to form the gas. The second example calculation is similar to the first example, with the following differences.

Firstly, in the second example, the temperature T3 can be chosen to be the reference temperature (e.g. by maintaining the temperature of the system at the reference temperature) and so there may be no need for the temperature correction/compensation factors as discussed in the first example (i.e. the exponential factors in equations (8) and (9)).

Secondly, in the second example, the pressure P3 is the pressure at V/L = 0, i.e. the true vapour pressure (TVP). Thus, the factor P3 in equations (8) and (9) should be replaced with an expression for TVP, which can be derived as follows. In the following equations, the superscript values depict the value of V/L, and the subscript values indicate whether the quantity is a component / of the oil (oil, /), a component / of the gas (gas, i) or the total oil amount (oil).

The TVP determination is based on summing partial pressures of each component of the gas. Each partial pressure may be written as: where P, is the partial pressure of component / in the gas, K ,· is the equilibrium constant for component /, x, is the molar fraction of the component / of the oil, n ₀ u is the number of moles of oil (i.e. liquid), and n _{0ii, j} s the number of moles of component / of the oil. n _oil may be calculated as the sum over / of n _0il,i

The TVP is calculated by summing the partial pressures at V/L = 0, since this is the point at which the amount of vapour reaches 0. Since this cannot easily be directly measured, an equation for determining the TVP in terms of measurable quantities may be derived as follows. In this example the values V/L = 0.5 and V/L = 1.0 are used, but other choices of V/L values could be used.

Firstly, the difference in partial pressures at the first and second V/L values is obtained using equation (10):

This equation can be rearranged to give an expression for Ki/n _0i i.

This can be input into equation (10) to obtain an expression for the partial pressure Pi ^V/L for component / at general V/L:

Then, to estimate the TVP (which is based on the sum of the partial pressures at V/L = 0), starting from the partial pressure difference between V/L = 0.5 and V/L = 0:

This can be rearranged to give an expression for the partial pressure at V/L = 0 of component /:

And thus an equation for the TVP can be obtained by summing the partial pressure for each component /:

Thirdly, in the second example, the molefractions in the gas are the gas composition at V/L = 0 which is found by dividing each term in the above equation (16) by p ₃ -

Thus, by modifying equations (8) and (9) using equation (16) in place of P3 and equation (17) in place of yi,3, and removing the temperature compensation factor, an expression for the mass fraction or concentration of component / of the oil can be developed for cases in which the liquid sample is expanded to form the gas. The above equation is based on the example values of V/L = 0.5 and V/L = 1; however other values of V/L could be used. Furthermore, more than two values of V/L can be used in order to increase the reliability of the TVP estimation for the pressure factor. For instance, the above general equation (16) can be repeated with other pairs of V/L values in order to obtain a number of TVP estimations, and an average can be calculated.

The first and second example methods are exemplary only, and other methods for relating gas composition data to liquid composition data may be used.

The calculation device (e.g. processor) may be configured to perform any or all of the above calculation steps.

The system may be configured to output any gas remaining in the system after the gas analysis has been performed. The gas may go to further processing. If the gas is not needed for further processing, the system may be arranged to purge or vent the gas into the atmosphere or surroundings. The container may further comprise an outlet for outputting the liquid. The liquid outlet may be arranged to output the liquid for further processing or transportation elsewhere.

In order to monitor the hydrocarbon liquid over time, the composition information determination method is repeated periodically. Preferably, the method is repeated at frequent intervals or is performed continuously. Frequent intervals may include that the measurement is performed at least once a day, at least once an hour, at least once every 30 minutes, or at least once every 5 minutes. This enables any changes in the composition to be detected rapidly. Furthermore, any changes in the liquid composition can be associated with or linked to particular changes in the processing system which occurred at the same time. Thus, the oil and gas processing system can be monitored more closely because the effect of the processing system on the composition of the product oil is known in detail.

The liquid composition information determination method may be performed alongside measurements of the composition of the gas phase output from the hydrocarbon fluid processing system. Thus, the combination of the gas phase composition data and the liquid phase composition data means that the total amount of particular hydrocarbon components produced by the system can be known and monitored. The processing system can then be operated based on this information. For instance, as a specific example, if it is discovered through the present method that performing a particular processing step at a higher temperature leads to a higher proportion of butane in the product oil, then the processing step can either be maintained or altered depending on whether it is desirable to have more butane in the final oil product. Thus, operation of the processing system can be guided by the liquid composition data and monitoring. Certain preferred embodiments of the present invention will now be described, by way of example only, with reference to the following drawings, in which:

Figure 1 shows a schematic diagram of a typical oil and gas production system;

Figure 2 shows a schematic diagram of a first embodiment of the present invention;

Figure 3 shows a schematic diagram of a second embodiment of the present invention;

Figure 4 shows a schematic diagram of a first implementation of the embodiment of Figure 3;

Figure 5 shows a schematic diagram of a second implementation of the embodiment of Figure 3;

Figure 6 shows graphs of (a) production rate, (b) process temperature, and (c) butane content, each against time, from an embodiment which monitors an oil and gas production system; and

Figure 7 shows a graph comparing the mass fraction in oil of various hydrocarbon components across four different oil fields.

A schematic diagram of a typical oil and gas production system 500 is shown in Figure 1.

The system includes a hydrocarbon fluid processing system generally represented by box 502. As an input, the processing system 502 receives well streams containing hydrocarbon fluids from three fields: Field A, Field B and Field C. The flow rate of the incoming hydrocarbon fluids is measured by sensors 504. The hydrocarbon fluids then undergo processing within the processing system 502, and a gas and an oil stream are output.

At the outlet of the process, it is standard to measure the composition and flow rate of the gas phase using sensors shown generally at 506. This gives useful information about the resultant gas which is produced by the processing system 502. In respect of the output liquid oil, it is typical to measure the flow rate of the outgoing oil using a sensor 508. Occasionally (e.g. once every 1-2 months), a sample of the produced oil is extracted from the system and sent to a specialist laboratory for a thorough analysis of the oil (not shown).

The processing system 500 can be adapted to include a hydrocarbon liquid monitoring system according to the present invention, as will be described below. The hydrocarbon liquid monitoring system measures and monitors the composition of the oil exiting the processing system 502. Thus, changes to the composition of the oil caused by changes to the processing of the well streams from Fields A, B, C can be observed.

Figures 2 to 5 show exemplary embodiments of a hydrocarbon liquid monitoring system according to the present invention which can be implemented as part of an oil and gas production system, e.g. oil and gas production system 500. The systems can perform repeated liquid composition determination measurements to monitor the composition of the oil over time.

Figure 2 shows a schematic diagram of a system 1 for monitoring a hydrocarbon liquid according to a first embodiment of the present invention. The system 1 comprises a gas-liquid separator 2, a gas chromatograph 4 and a processor 6.

The separator 2 comprises a fluid inlet 8 arranged to receive an incoming fluid stream comprising a mixture of gas and liquid components. The separator 2 is configured to separate the fluid stream into a gas and a liquid in a conventional manner, and to allow the separated gas and liquid to come into equilibrium with each other. The separator 2 further comprises a gas outlet 10 arranged to output the separated gas, and a liquid outlet 12 arranged to output the separated liquid.

The separator 2 also comprises temperature and pressure sensors 14 which are arranged to measure the temperature and pressure of the separator, respectively. The sensors 14 are configured to transmit the measurements to the processor 6.

The gas chromatograph 4 is arranged to receive a portion of the outputted gas stream from the separator 2. The gas chromatograph 4 is configured to analyse the portion of the gas to determine the composition of the gas, and to output the gas composition data to the processor 6.

The processor 6 is configured to receive, as input parameters, the gas composition data from the gas chromatograph 4 and the temperature and the pressure measurements from the sensors 14. The processor 6 is further configured to analyse the input parameters to calculate the information about the composition of the liquid, as discussed below.

In use, the system 1 functions as follows. A gas-liquid fluid stream is input into the gas-liquid separator 2 via the inlet 8. The separator 2 separates the fluid stream into a gas phase and a liquid phase, which will naturally come into equilibrium with each other within the separator 2. The sensors 14 measure the temperature and the pressure of the separator 2 when the gas and liquid are in equilibrium and output these measurements to the processor 6. Once the gas and liquid have separated and equilibrated, the gas is output via the gas outlet 10 and the liquid is output via the liquid outlet 12. A portion of the outputted gas is inserted into the gas chromatograph 4 for compositional analysis, and the remaining gas goes to further processing. The outputted liquid is transported elsewhere, e.g. to a consumer via a transport vessel or pipeline.

The gas chromatograph 4 analyses the gas portion to determine the components of the gas and the relative proportions thereof, and outputs the gas composition data to the processor 6.

The processor 6 then determines the composition of the oil using numerical processing of the gas composition data, the temperature and the pressure of the separator 2 at equilibrium. The processor may use equations (8) and/or (9) to relate the gas composition data and other parameters (including temperature and pressure of the separator) to the liquid composition data.

The system 1 therefore enables the determination of the composition of the separated liquid phase by only performing composition analysis on the separated gas phase. No analysis of the liquid phase itself is required. The liquid composition information can then be provided e.g. to the consumer or transporter of the oil, giving them vital information regarding the constituent parts of the oil. The composition information can also be used by a manager of the processing system. The system 1 can provide continuous or periodic (preferably frequent) liquid composition measurements so that the manager can observe and monitor changes in the composition of the liquid over time, and specifically observe variations in the composition caused by particular changes in the processing system. The information may relate to how the proportion of one specific component of the oil (e.g. butane) changes over time, or one or more sub-parts of the oil (e.g. only light components, such as up to C6 or up to C10).

Figure 3 shows a schematic diagram of a system 200 according to a second embodiment of the present invention. The system 200 comprises a gas-liquid separator 202, an expansion container 204, a gas chromatograph 206 and a processor 208. This system and corresponding method may be preferred if equilibrium is not reached in the separator 202, or if there are gas bubbles entrained in the oil from the separator 202.

The separator 202 comprises a fluid inlet 210 arranged to receive an incoming fluid stream comprising a mixture of gas and liquid components. The separator 202 is configured to separate the fluid stream into a gas and a liquid. The separator 202 further comprises a gas outlet 212 arranged to output the separated gas, and a liquid outlet 214 arranged to output the separated liquid.

The system is under temperature control to maintain a constant temperature. The expansion container 204 is arranged to receive a portion (i.e. a sample) of the outputted liquid stream. The expansion container 204 is configured to expand the liquid sample to obtain a mixture of gas and liquid, and to allow the mixture to equilibrate. The expansion container 204 comprises a pressure sensor 216 that is arranged to measure the pressure of the equilibrated gas, and to transmit the measurement to the processor 208.

The gas chromatograph 206 is arranged to receive a portion of the gas from the expansion container 204, analyse the portion of the gas to determine the composition of the gas, and to output the gas composition data to the processor 208.

The processor 208 is configured to receive, as input parameters, the gas composition data from the gas chromatograph 206 and the pressure measurements from the sensor 216. The processor 208 is further configured to numerically process the input parameters to calculate the composition data of the liquid.

In use, the system 200 functions as follows. A gas-liquid fluid stream is input into the gas-liquid separator 202 via the inlet 210. The separator 202 separates the fluid stream into a gas and a liquid. The gas is output via the gas outlet 212 and the liquid is output via the liquid outlet 214.

A portion of the outputted liquid is input into the expansion container 204. The remaining outputted liquid is transported elsewhere, e.g. to a consumer via a transport vessel or pipeline.

The liquid is expanded within the expansion container 204, forming a mixture of gas and liquid. The gas and liquid naturally come into equilibrium with each other since the conditions in the expansion container 204 are stable. The sensor 216 measures the pressure of the equilibrated gas and transmits the measurement to the processor 208.

A portion of the equilibrated gas is inserted into the gas chromatograph 206 for compositional analysis. The gas chromatograph 206 analyses the gas portion to determine the components of the gas and the relative proportions thereof, and outputs the gas composition data to the processor 208.

This process is then repeated with a second sample of the outputted liquid, wherein the second sample is either input into the first expansion container 204 (after the first sample has been purged therefrom) or input into a second separate expansion container 204 to enable simultaneous processing of the liquid samples. A preferred method is to split one liquid sample in two parts.

Thus, a second portion of the outputted liquid is input into an (or the) expansion container 204 and expanded therein to form a mixture of gas and liquid at a second V/L ratio. The gas and liquid naturally come into equilibrium with each other since the conditions in the expansion container 204 are stable. The sensor 216 measures the pressure of the equilibrated gas and transmits the measurement to the processor 208. A portion of the equilibrated gas is inserted into the gas chromatograph 206 for compositional analysis, which is preferably the same gas chromatograph 206 as for the first sample to reduce costs and unnecessary duplication of components. The gas chromatograph 206 analyses the gas portion to determine the components of the gas and the relative proportions thereof, and outputs the gas composition data to the processor 208.

The processor 208 then determines the information about the composition of the liquid using numerical processing of the gas composition data from the sample at the first V/L ratio, the gas composition data from the sample at the second V/L ratio, and the pressure of the expansion chamber(s) 204 at equilibrium for each sample. The processor may use equations (8) and/or (9) modified by equations (16) and (17) to relate the gas composition data and other parameters to the liquid composition data.

This system 200 enables the determination of information about the composition of the separated liquid phase by expanding a sample of the separated liquid phase at two (or more) different V/L ratios and performing composition analysis on the resulting gas phases. This system 200 therefore enables the determination of the composition of the separated liquid phase by only performing physical composition analysis on the separated gas phase. No physical analysis of the liquid phase itself is required.

While this example has been described with reference to the outputted liquid from a gas-liquid separator 202, it will be appreciated that any liquid sample could be used.

Indeed, an advantage of this embodiment over the first embodiment is that the method can be applied to any liquid sample, since the gas is created by expansion of the liquid sample rather than by separating a mixed gas-liquid fluid stream. As described previously, this embodiment may also be preferred if there is not equilibrium in the separator 202, or if there are gas bubbles entrained in the oil from the separator 202.

Figure 4 shows a schematic diagram of a system 300 according to a third embodiment of the present invention.

The system 300 of Figure 4 receives and analyses an oil sample, which could be an oil sample from a gas-liquid separator. Hence the system 300 can be a specific implementation of the embodiment of Figure 3.

The system 300 comprises a first container 302, a second container 304, a gas circulation pump 306 and a gas analyser (e.g. a gas chromatograph) 308.

The system 300 further comprises an inlet pipe 310 for inputting an oil sample. The oil sample may for instance be a sample of a liquid outputted from a gas-liquid separator. The inlet pipe 310 comprises a first binary valve 312a arranged to control the incoming flow of oil.

The first container 302 comprises a first inlet 314 arranged to receive the oil sample from the inlet pipe 310. The first container 302 further comprises a gas outlet 316 and a liquid outlet 318 arranged to output a gas phase and a liquid phase respectively. The liquid outlet 318 is arranged to drain liquid from the first container 302 after the necessary measurements have been completed. Draining of the liquid is controlled by a binary valve 312e. The first container 302 also comprises a liquid level sensor 324a for detecting the level of liquid in the container 302 and a temperature sensor 324c for measuring the temperature in the first container 302.

The second container 304 comprises an inlet 320 that is connected to the gas outlet 316 of the first container 302. A binary valve 312b is arranged to control the flow of gas from the first container 302 to the second container 304. The second container 304 further comprises an outlet 322 arranged to output gas therefrom, a pressure sensor 324b for measuring the pressure of the second container 304, and a temperature sensor 324c for measuring the temperature of the second container 304. A purge gas supply 342 is connected to the second container 304.

The gas circulation pump 306 is connected to the outlet 322 of the second container 304. The pump 306 is configured to receive the gas output from the second container 304 and to pump the gas to circulate the gas through the system 300.

The gas analyser 308 is arranged to receive a portion of the gas output by the pump 306 and to analyse the gas composition thereof.

The system 300 comprises a gas outlet pipe 326 for purging gas from the system after the measurement is complete, and a return pipe 328 for circulating gas back to the first container 302. The gas outlet pipe 326 and the return pipe 328 comprise binary valves 312c, 312d to control the flow of fluid therethrough. A vacuum pump 340 is arranged on the gas outlet pipe 326.

Operation of the system 300 proceeds as follows. Throughout the process, the shaded region (e.g. the first and second containers 302, 304 and the pump 306) is kept at constant specified temperature by a temperature regulation system (not shown).

In an initial starting condition, the system 300 is cleaned by purging the system 300 with inert gas from the purge gas supply 342, typically argon or nitrogen, and then evacuated to very low vacuum with the vacuum pump 340. All valves are then closed.

The oil sample is input into the first container 302 through valve 312a. It is assumed that the oil comes from a source with enough pressure to cause the oil to enter the container 302. Oil is filled to a predefined level in the first container 302, with the predefined level being determined by the desired V/L for that measurement. The level of oil is monitored by the liquid level sensor 324a. Upon entry into the first container 302, gas will flash from the oil and fill the head space within the first container 302.

When enough oil has filled the container 302, the valve 312a is closed. As soon as the liquid level measurement is stable enough, the valve 312b is opened. This will cause more gas to flash from the oil, and the second container 304 will be filled with gas. The pressure within the second container 304 is monitored by the pressure sensor 324b.

When the liquid level as measured by liquid level sensor 324a is stable enough again and the pressure measurement as measured by the pressure sensor 324b does not vary too much, the valve 312d is opened and the gas circulation pump 306 is started. The purpose of the pump 306 is to circulate the gas within the system 300 and bubble it through the oil in order to make sure that the gas phase is homogenous, and that true equilibrium between the gas and the oil is achieved. While the gas is circulating, the temperature of the oil and gas is monitored by temperature sensors 324c. The gas circulation continues until the temperature is as specified by the temperature regulation system and the pressure 324b is constant enough. When this is achieved, the valves 312b, 312d are closed in order to separate the oil from the gas. This is necessary because pressure in the second container 304 will decrease when the gas is sampled, and if the oil were in contact with the gas in the second container 304 when the pressure decreases, more gas would flash from the oil and the equilibrium would be disturbed.

The gas is then sampled by the gas analyser 308. Several samples of the gas may be taken in order to improve the statistics of the measurement.

Once the gas has been sampled and analysed, the valves 312e, 312b are opened and the oil is drained from the system 300. The first container 302 may then be cleaned with a solvent in order to ensure all oil is removed.

The system is then back at the initial starting point, where the system 300 is purged with gas from the purge gas supply 342 and evacuated with vacuum pump 340. If the vacuum pump 340 is powerful enough, purging with gas may be unnecessary.

As described above, all valves are then closed and the system is ready to perform a new measurement.

The process is then repeated with a second oil sample. The level of oil in the first container 302 is adjusted to expand the second liquid sample to a different V/L ratio so as to obtain gas composition and pressure measurements relating to a different V/L ratio.

A processor (not shown) then receives the gas composition data and the pressure data relating to the samples at different V/L ratios and numerically processes the data to determine composition data of the initial oil sample. The processor may use equations (8) and/or (9) modified by equations (16) and (17) to relate the gas composition data and other parameters to the liquid composition data.

It will be recognised that the system of Figure 4 depicts a “batch process” implementation. In other words, in a temperature controlled environment, a discrete oil sample is input into the first container 302, the expansion and analysis process is carried out, the sample is then drained/purged, and then the process repeats in cycles with further samples.

Alternative implementations involve a “continuous” type process. Figure 5 shows an example “continuous” process embodiment of the present invention.

The system 400 comprises a container 402, a temperature adjustment device (e.g. heater or cooler) 404, and a gas chromatograph 406.

The system 400 is arranged to receive a continuous flow of oil via an inlet pipe 408. The inlet pipe 408 comprises an adjustable valve 410a arranged to regulate the flow of the incoming oil to obtain a desired flow rate of oil through the system 400. The adjustable valve 410a may be controlled by a controller (not shown).

The container 402 comprises an inlet 412 that is arranged to receive the incoming oil flow from the inlet pipe 408, a gas outlet 414 for outputting gas and a liquid outlet 416 for outputting liquid. The container 402 further comprises a liquid level sensor 418a arranged to measure the level of liquid in the container 402, and a pressure sensor 418b arranged to measure the pressure in the container 402.

The liquid outlet 416 is connected to a liquid outlet pipe 420 comprising an adjustable valve 410b for regulating the flow of liquid therethrough. The adjustable valve 410b may be set to achieve a desired liquid level in the container 402: too low of a liquid level will give a shorter oil residence time and a risk of gas blow-by to the oil outlet, and too high of a liquid level will give a shorter gas residence time and a risk of flooding container 402. The target level of liquid in container 402 is one which allows enough residence time to reach equilibrium. The liquid outlet pipe 420 also comprises a temperature sensor 418c for measuring the temperature of the liquid, and a flow rate sensor 418d for measuring the flow rate of the liquid. The adjustable valve 410a in the inlet pipe 408 may be controlled or set based on obtaining a desired flow rate of liquid in the outlet pipe 420.

The gas outlet 414 of the container 402 is connected to a gas outlet pipe 422 comprising an adjustable valve 410c for regulating the flow of gas therethrough. The adjustable valve 410c may be set to achieve a desired pressure in the container 402. The gas outlet pipe 422 also comprises a temperature sensor 418e for measuring the temperature of the gas, and a flow rate sensor 418d for measuring the flow rate of the gas. The heating or cooling by the temperature adjustment device 404 may be set or controlled in order to achieve a desired output gas temperature.

The gas analyser 406 is connected to the gas outlet pipe 422 and arranged to receive a portion of the output gas. The gas analyser 406 is configured to analyse the gas portion to determine the composition thereof.

Operation of the system 400 proceeds as follows.

An oil sample, in this case a continuous flow of oil, enters the system 400 via the inlet pipe 408. The first adjustable valve 410a is controlled to regulate the flow rate of the incoming flow of oil. The oil flow passes through a temperature adjustment device 404 where it undergoes heating or cooling as desired. The heated or cooled oil then enters the container 402, wherein some gas flashes out of the liquid.

The gas exits the container 402 via the gas outlet 414, and the liquid exits the container 402 via the liquid outlet 416. The adjustable valve 410b on the liquid outlet pipe 420 is set to maintain a desired liquid level within the container 402, and the adjustable valve 410c on the gas outlet pipe 422 is set to maintain a desired gas output flowrate. The conditions within the container 402 (i.e. the temperature, the volume, and the rate of entry and exit of fluids) are stable, and hence the gas and liquid are in equilibrium with each other within the container 402. The pressure in the container 402 and the temperature of the equilibrated gas are measured using sensors 418a, 418b.

A portion of the output gas is inserted into the gas analyser 406, where the composition thereof is analysed.

The process is repeated at a second V/L ratio by adjusting the flow rates of the outgoing oil and gas streams as measured by flow rate sensors 418f, 418d.

A processor (not shown) then receives the gas composition data and the pressure and temperature data relating to the samples at the different V/L ratios, and numerically processes the data to determine composition data of the oil. The processor may use equations (8) and/or (9) modified by equations (16) and (17) to relate the gas composition data and other parameters to the liquid composition data.

Advantages of the system 400 as compared to the system 300 include avoiding the need to clean and purge the system between measurements, and the absence of pumps required to circulate the gas and/or evacuate the system between measurements.

However, there are also some disadvantages. For instance, it may be more challenging to be sure that equilibrium is reached in system 400, so it may be necessary to have good range on the flow control valves/sensors and to have good methods to tune the required residence time in the container. It may also be more challenging to keep a constant temperature in the entire system downstream of the temperature adjustment device 404.

The systems 300, 400 described with reference to Figures 4 and 5 could for instance be connected directly to the liquid outlet of a gas-liquid separator, e.g. the gas- liquid separator 202 shown in Figure 3. Thus the systems can be integrated into existing oil processing equipment.

Figure 6 shows three graphs which depict a fictional scenario to demonstrate how liquid composition data obtained using the present system and method can be used to monitor a hydrocarbon fluid processing system. The graphs are arranged with their time axes aligned so that changes in one parameter can be compared to corresponding changes in another parameter.

The upper graph shows how the production rate of three oil and gas Fields A, B and C varies with time. The units of time are not specific and could represent days, weeks, months etc. As shown, the production rate of Field A and Field B remains stable throughout the relevant time period, whereas the production rate of Field C increases instantaneously at time = 12.

The middle graph shows how the temperature at which process X is carried out varies with time. Again, the units of time are not specific and could represent days, weeks, months etc., as long as they correspond to the units of the upper graph. Process X is also not specific and could be, for instance, dehydration of a gas phase carried out by a scrubber. As shown in the graph, the temperature of the process X is constant until time = 5, at which point the temperature decreases suddenly and remains constant at the lower temperature for the remainder of the relevant time period.

The lower graph shows how the butane content of the gas and the liquid output from the processing system and the total amount of produced butane varies with time. Again, the units of time are not specific and could represent days, weeks, months etc., as long as they correspond to the units of the upper and middle graphs for comparative purposes. As shown in the graph, at time = 5 the butane content of the liquid suddenly increases and the butane content in the gas suddenly decreases by an equal amount such that the total butane amount does not change. At time = 12, the butane content in the gas decreases further by a small amount, and the butane content of the liquid increases by a larger amount such that the total produced butane also increases.

By comparing these three graphs, it can be seen that changing the temperature of process X leads to an increase in the butane content of the liquid and an equal decrease in the butane content in the gas, but no overall change in the amount of butane produced. It can also be seen that an increase in the production rate of Field C leads to an increase in the total amount of butane produced, and specifically to an increase of butane in the liquid and a decrease of butane in the gas.

In typical hydrocarbon fluid processing systems, only the composition of the output gas is regularly monitored. With reference to the lower graph in Figure 6, this corresponds to only the bottom line of data being known. In this case, knowing only the butane content of the final gas does not provide a direct indication of the butane content of the liquid, nor of the total butane produced. Therefore, in general, there is less knowledge of the total amount produced of particular hydrocarbon components, and specifically how it is distributed between the final gas and the final liquid.

Using the hydrocarbon liquid monitoring system and method of the present invention, the liquid composition becomes a known factor and thus the hydrocarbon fluid processing system can be monitored to determine which hydrocarbon components end up in the final oil product. Combined with information about the gas composition as is more typically known, it is then also possible to monitor the total amounts of these hydrocarbon components. Furthermore, changes to conditions/parameters (e.g. temperature) of various stages in the processing system can be associated with corresponding changes in the relative amounts of various hydrocarbon components. As a result, the processing system can be operated based on this information. Figure 7 shows a graph which depicts the mass fraction in oil of various hydrocarbon components in a range of oils produced from different fields A, B, C and D.

The small solid circles on the graph show composition data of various oils from a first Field A. The data points represent hydrocarbon components in oil samples from a range of operating conditions and a range of mixes of oil from reservoirs. The properties of the oils produced in Field A vary significantly, from light oils to heavy waxy oils. The lines passing through these circles are regression lines, which are forced to extend from the origin (0, 0). Each regression line corresponds to a different component: methane, ethane, propane, i-butane, n-butane, i-pentane and n-pentane. The x-axis comprises all of the parameters on the right-hand side of equation (8) except the equilibrium constant factor, and the y-axis comprises the parameter on the left-hand side of equation (8), i.e. the mass fraction in oil. Thus, the gradient of each regression line gives the equilibrium constant of the corresponding hydrocarbon component (more specifically, the gradient is 1/K,).

The oil component data from Fields B, C and D are overlaid on the results from Field A. Field B is a high gas-to-oil ratio (GOR) field, Field C is a medium GOR field with light oil, and Field D is a low GOR field with production from several reservoirs.

It can be seen that the regression lines developed based on the samples from Field A are a good match for the other fields as well, since the data points from the Fields B, C and D lie along the regression lines from Field A. This demonstrates that the equilibrium constants determined based on samples from one field can be applied to other fields as well. Therefore, for instance, equations (8) and (9) can be used to estimate the unknown mass fraction of components in an oil sample based on known measured parameters (e.g. temperature, pressure and equilibrated gas composition) and known estimated parameters (e.g. equilibrium constants calculated from other oil samples).