Emissions systems and methods

Abstract

A system 100 for managing emission properties of a flare burner 40 comprises a flow management system 110 in line with a hydrocarbon flow 30 and upstream of the flare burner. A data acquisition arrang

Description

TECHNICAL FIELD There is described systems and methods for managing emissions, such as green house gas emissions and / or other potentially harmful emissions, and / or combustion properties, and in particular managing emissions or the like at an oil and gas installation (e.g., at a well site, which may have flares used to burn hydrocarbons). Some particular described examples relate to reducing significantly or otherwise minimising green house gas emissions at oil and gas installations. BACKGROUND During production or other operations at an oil and installation, such as at a well site, unwanted hydrocarbons and other fluid products may be combusted in the atmosphere in order to dispose of those products. Dedicated burners, or so-called flare burners, may be used in order to allow combustion of those fluids at site. The emissions from flares are often released to atmosphere too (e.g., rather than being captured and stored). Further emissions may be released, for example, due to leaks or other gases not being combusted. There can be a desire to minimise green house gas emissions at site and / or to ensure that combustion occurs as efficiently as possible. It may be preferable, for example, to ensure that green house gases, such as methane, or other gases such as hydrogen sulphide or nitrogen dioxide are not released or otherwise fully combusted during flaring or the like. In some cases in particular, such as well test, the composition of the hydrocarbons being produced from a test well may be estimated, but otherwise unknown in advance. Further conditions of the well in questions may be unknown, such as permeability, pressure, etc., which may affect factors such as flow rates, fluid pressures, etc. Together, these factors can have an effect on the overall efficiency and effectiveness of any combustion or removal of any unwanted products at site. Further, environmental conditions at such sites may vary (e.g., from day to day; week to week; month to month; year to year), which can also affect combustion, and other conditions at an oil and gas installation. This is additionally true at permanent or semi-permanent sites, in which conditions can also vary and / or be unknown. There is a desire to improve the way in which emissions are managed and controlled at oil and gas installations. In some cases, it may be desirable to improve the manner with which unwanted products are manged, and for example combusted. It may be true, however, that for any such improvements to be made, any proposed solutions ideally should be easy to adopt, cost effective to use, and / or have a meaningful impact. In other words, marginal improvements for high cost implementations may not be adopted and implemented. That said, significant improvement, and even noticeable improvements, may be more likely to be adopted if the costs are reasonable and / or the adoption can occur without significant complication, and knock-on effect on operations at the site or elsewhere. Further, any solution must be adaptable to varying conditions, given that unknowns may vary overtime and from well site to well site. As such, bespoke solutions may be less desirable, and solutions with wide applicability may be preferable. Further still, in some cases, it may be desirable to consider emissions across an oil and gas installation site (or portion of it), rather than solely at a very targeted area of that installation so that a better assessment and management of potential green house gas emissions orthe like may be managed. There continues to be a need, therefore, for cost effective solutions that are easy to adopt and manage, and which result in reduced unwanted emissions at an oil and gas installation (e.g., during flaring of hydrocarbon products), particular of green house gases, including methane, carbon dioxide, nitrogen dioxide, etc., and / or hazardous gases or conditions. SUMMARY There are described systems and method for managing emissions properties (e.g., at an oil and gas installation). The systems and methods described may help provide cost effective solutions that are easy to adopt and manage, and which result in reduced unwanted emissions at an oil and gas installation (e.g., during flaring of hydrocarbon products), particular of green house gases, including methane, carbon dioxide, nitrogen dioxide, etc., and / or hazardous gases or conditions. In some described examples, the system may comprise a flow management arrangement, which may be configured to positioned in line with a hydrocarbon flow. The arrangement may be configured to be upstream of a flare burner for burning hydrocarbon in the flow. The flow management arrangement may be configured to control introduction of a control fluid to that hydrocarbon flow flowing to the flare burner in order to control the emission properties at the flare. For example, in some cases, the flow management arrangement may be configured to the use fully or partially the flow of fluids in the hydrocarbon flow to control introduction of a control fluid to that hydrocarbon flow flowing to the flare burner in order to control the emission properties at the flare. In some examples, there is described a system comprising a data acquisition arrangement, configured to acquire data relating to fluids flowing in a hydrocarbon flow and / or emission properties at the flare. Such an arrangement may be used to permit the control of a described flow management arrangement, or other such arrangement. The flow management arrangement may comprises one or more intake arrangements. Some or all intake arrangements may comprise a hydrocarbon flow inlet and control fluid inlet. The intake arrangements may comprise a mixing chamber for mixing hydrocarbon flow with control fluid. An flow outlet of the intake arrangement may be configured to outlet mixed hydrocarbon flow. Some or all intake arrangements may be configured to passively control induction of control fluid, using the flow of fluids in the hydrocarbon flow. For example, in some cases, the flow management arrangement may comprise one or more jet pump arrangements. Some or all intake arrangements may comprise one or more controllable valves. The controllable valves may be provided at one or more of: the hydrocarbon inlet; the control fluid inlet, and the outlet. The valves may be configured to control flow rates of fluids one or more of the inlets / outlets (e.g., restrict;, increase; open / close). In any event, the flow management arrangement may be configured to control (e.g., passively) induction of control fluid, using the flow of fluids in the hydrocarbon flow. The system may be configured to introduce oxidant, such as inducting air from atmosphere, to the hydrocarbon flow. The system may additionally or alternatively configured to introduce water into the hydrocarbon flow. The system may be configured to permit adjustable introduction of control fluid, such as introduction from atmosphere. Such adjustment may be based on determined and / or assumed conditions at site. The system may comprise at least a first flow path and a second flow path. The first and second flow paths may be used to control introduction of control fluids to different extents. The system may be configured to allow selective flow of hydrocarbons through the first flow path, the second flow path, or a though combination of flow paths. The first flow path may be configured to introduce a control fluid to a hydrocarbon flow, and the second flow path may be configured substantially not to introduce control fluid. The first flow path may be configured to introduce control fluid to a hydrocarbon flow at a first particular extent, and the second flow path is configured to introduce control fluid at to second particular extent, wherein the first and second rates are selectively different. The system may comprise more than two flow paths. Some or all flow path may be configured to control introduction of control fluids to different extents. At least one of the flow paths may be configured substantially not to introduce control fluid. The system may be configured such that some or all of the flow paths may be fluidly connected to a common source. In some examples, the system may be configured such that some or all the flow paths may be fluidly coupled to alternative sources (e.g., different wells, and / or different separator outlets). The system may be configured such that some or all of the flow paths combine upstream of any burner. In some examples, the system may be configured such that some or all of the flow paths combine at the location of combustion, at a burner. The flow management arrangement may be configured to control one or both of the flow rate of hydrocarbons and the introduction of control fluid to the hydrocarbon flow. The control of the flow rate of hydrocarbons may be controlled independently of the controlled introduction of control fluid to the hydrocarbon flow. The flow management arrangement may be configured to be retrofittable to an existing well structure. The retrofittable flow management arrangement may be configured to be positioned downstream of well test equipment, and upstream of a flare burner. Any well test equipment upstream of the system may comprises one or more separators. The flow management system may be configured to be positioned downstream of any separators. The flow management arrangement may be powered, e.g., at least in part, via the data acquisition arrangement, e.g., when used and in communication. The data acquisition arrangement may be configured to acquire data relating to properties, such as emission properties, at a flare. For example, the data acquisition arrangement may be configured to acquire data using at least one image capture device. Data from the image capture device(s) may permit determination of one or more of properties of that flare. The one or more determined properties may includes one or more of: composition of emissions, such as the composition of green house gas emissions; temperature; combustion efficiencies; and destruction and removal efficiency. The data acquisition arrangement may be configured to acquire data relating to fluids flowing in the hydrocarbon flow. Such data may comprise one or more properties relating to the composition of fluids in the hydrocarbon flow. The system may be configured to use predictive modelling to control introduction of a control fluid to the hydrocarbon flow. For example, any model may use data relating to fluids flowing in the hydrocarbon flow and / or emission properties at a flare. The flow management arrangement may be configured to introduce control fluid to that hydrocarbon flow at the flare burner during combustion, and / or the flow management arrangement may be configured to introduce control fluid into the hydrocarbon flow so as to be mixed with the flow upstream of the flare burner. In some examples, there is described a method for managing emission properties (e.g., at an oil and gas installation). Such examples may comprise positioned a flow management arrangement together with (e.g., in line with) a hydrocarbon flow. The arrangement may be provided upstream of a flare burner for burning hydrocarbons in the flow. In some examples, the method may comprise acquiring data relating to fluids flowing in the hydrocarbon flow and / or combustion at the flare. The method may comprise controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner. For example, the method may comprise controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using fully or partially the flow of fluids in the hydrocarbon flow together with the acquired data in order to control the emission properties at the flare. The method may comprise using one or more intake arrangements. Some or all intake arrangements may comprise a hydrocarbon flow inlet and control fluid inlet. The method may comprise mixing hydrocarbon flow with control fluid. The method may comprise outletting mixed hydrocarbon flow. The method may comprising passively controlling induction of control fluid, using the flow of fluids in the hydrocarbon flow. The method may comprise using one or more jet pump arrangements and controlling introduction of control fluid using the flow of fluids in the hydrocarbon flow. The method may comprising controlling the fluid flow at one or more of: the hydrocarbon inlet; the control fluid inlet, and the outlet. Controlling may comprise controlling flow rates of fluids one or more of the inlets / outlets (e.g., restrict;, increase; open / close). The method may include acquiring image data associated with combustion at the flare. Such data may be used to control introduction of a control fluid. Image data may be acquired at intervals. Controlled introduction of control fluid may be determined at or around those intervals. Example intervals include one of hourly, daily, weekly, monthly or yearly. The method may comprise (e.g., using the flow management arrangement) flowing fluids along a first flow path and a second flow path. The first and second flow paths may passively control introduction of an control fluid to different extents. The method may comprise selecting one of the first flow path, the second flow path, of a combination of flow paths, to flow hydrocarbons through. The method may comprise retrofitting the flow management arrangement upstream of a flare burner. The method may comprise retrofitting the flow management arrangement downstream of a well test equipment, such as downstream of a separator of well test equipment. The method may comprise using the acquired data together with a predictive model to control controlling introduction of a control fluid to the hydrocarbon flow. The method comprising varying the introduction of a control fluid to the hydrocarbon flow over time. The method comprising managing emission properties for non-routine flaring. The method may comprise introducing control fluid to the hydrocarbon flow at the flare burner during combustion, and / or introducing control fluid into the hydrocarbon flow so as to be mixed with the flow downstream of the flare burner. In some examples, there is described a system for managing emission properties, comprising; a flow management arrangement, configured to positioned in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbon in the flow; wherein the flow management arrangement comprises one or more pumps configured to use the flow hydrocarbon flow to control introduction of a control fluid to the hydrocarbon flow flowing to the flare burner in order to control the combustion at the flare. In some examples, there is described a system for managing emission properties, comprising; a data acquisition arrangement, configured to acquire data relating to emissions at an oil and gas installation, wherein the system is specifically configured to acquire data relating to emissions from a flare burner as well as leak emissions from components at an installation. In some examples, there is described a method for managing green house gas emissions, comprising: acquiring data relating to emissions from a flare burner as well as leak emission from components at an oil and gas installation, and using that data to manage green house gas emissions (e.g., the data may be derived from image data). The method may comprise acquiring data relating to emissions from a non-routine flare burner. In some examples, there is described a method for managing emission properties, comprising; positioning a flow management arrangement in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbons in the flow; controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using fully or partially the flow of fluids in the hydrocarbon flow together with the acquired data in orderto control the emission properties at the flare. The method may comprise controlling introduction of a control fluid to different extents across two or more flow paths. The method may comprise combining the flow paths at the location of combustion at the burner. In some examples, there is described a system for managing emission properties, comprising; a flow management arrangement, configured to positioned in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbon in the flow; wherein the flow management arrangement is configured to control introduction of a control fluid to that hydrocarbon flow flowing to the flare burner in order to control the emission properties at the flare; a data acquisition arrangement, configured to acquire data relating to fluids flowing in the hydrocarbon flow and / or emission properties at the flare, and to permit the control of the fluid management system. In some examples, there is described a method for managing emission properties, comprising; positioning a flow management arrangement in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbons in the flow; acquiring data relating to fluids flowing in the hydrocarbon flow and / or combustion at the flare; controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using the acquired data in orderto control the emission properties at the flare. The described examples provide systems and methods for controlling or reducing emissions, which are cost effective, and / or easy to adopt and manage, and which result in reduced unwanted emissions during flaring of hydrocarbon products. The above summary is intended to be merely exemplary and non-limiting, and features may be combined across example as would be understood to a skilled reader without the need to describe in detail those further examples. BRIEF DESCRIPTION OF THE FIGURES Figure 1 shows an example setup of well test equipment and a flare stack; Figure 2 shows an example of the set up of Figure 1, comprising a system for managing emission properties; Figures 3a-3d show flow management arrangements used with the system of Figure 2, and Figure 4 shows a intake arrangement, such as a jet pump, used with the flow management arrangement of Figure 3a-3d; Figures 5a and 5b show further examples of a flow management arrangement; Figure 6 shows the flow management arrangement of Figure 3a-3d together with a data acquisition arrangement; Figure 7 shows parameters and / or data acquired from the data acquisition arrangement of Figure 6; Figure 8 shows an example of managing emissions from multiple flares; and Figure 9 shows a further example of the system at an oil and gas installation. DETAILED DESCRIPTION Figure 1 shows a simplified representation of an oil and gas installation, which in this case is a well site 10, and in particular a well test site. Well test equipment 20 has been deployed at the site 10, and ongoing testing activity is being performed at a well (not shown). In this example, the site may be considered to conduct non-routine flaring. Non-routine flaring may be distinct in some cases from routine flaring, in which the flaring may be considering permanent and perpetual. It will be appreciated that in such circumstances, fluids including hydrocarbons (and often other constituents) may be produced during well test in order to appraise a well in development. Those hydrocarbons, and other constituents, may be flowed from a well, via specific well test equipment 20, to a flare burner 40 for combustion in the atmosphere during well test. The composition of the hydrocarbons and other fluids that may flow through a conduit or other such hydrocarbon flow 30 to the flare burner 40 may be approximated, but otherwise unknown, prior to well test. In some cases, those fluids may be burned off or otherwise vented together, but in other examples the well test equipment 20 (e.g., including separators) may be used to separate out consistent fluids (e.g., oils and gases) to allow selective burning of those separated fluids (e.g., selective burning of gas). A skilled reader will appreciate that the follow described examples may be suitable for either scenario, and can be modified as needed. That is to say that some the following examples are not described specifically in relation to use with separated gases and oils (which then may be combusted separately), or multiphase or mixed flow of gases and oils, which are not separated, but are combusted together. The following examples may be adapted to either scenario, and need not be limited to one or the other. Further, it will be appreciated that in some examples, flow lines (gas and / or oil) from multiple wells may be combined and combusted (e.g., multiple wells flowing to a single burner), and again the following examples may be adapted accordingly. It will be appreciated that well test can often occur in challenging and varying environmental conditions. Further, the potentially unknown (and potentially varying) properties of fluids being produced from a well under test means that combustion at the flare burner 40 may be nonideal, and harmful emissions such as green house gases, e.g., methane, hydrogen sulphide, or the like, may be released to atmosphere, and in some cases without being fully combusted. Other harmful emissions such as such as nitrogen dioxide, or the like, may also be produced. Further, capture and storage of such gases may be problematic should gases such as methane, or hydrogen sulphide remain, given the volatility or lethality of those products. As such, there may be a desire to minimise or avoid certain emissions, such as green house gas emissions, such as methane, nitrogen dioxide, and / or other gases such as hydrogen sulphide, in such circumstances. In particular, there may be a desire to minimise such emissions cost effectively and / or with ease. There may also be a desire to be able to assess (e.g., for reporting purposes) the effective emissions, such as green house gas emission, and any reductions that have been made, as well as other properties such as combustion efficiency, destruction and removal efficiency (DRE), or the like. It will be appreciated that while the following examples have been described in relation to well test, in other examples the same or similar systems and methods may be used for with alternative permanent or semi-permanent well site arrangements, or indeed other oil and gas installations, and the embodiments need not be limited to well test arrangements. Further, while the examples may be particularly useful for non-routine flaring due to the possibility for varying conditions., nevertheless the systems and methods may be used with routing flaring. Consider now Figure 2, which shows a system 100 for managing emission properties, e.g. at a well site 10, which in this example is undergoing well test, and may use non-routine flaring to dispose of hydrocarbons or the like. Non routine flaring may be used when flaring is not expected to be a permanent solution, and / or where flaring is used only from time to time. The system 100 comprises a flow management arrangement 110, as will be described. In this example, the flow management arrangement 110 is configured to be positioned in line with the hydrocarbon flow 30, and upstream of a flare burner 40 for burning hydrocarbons in the flow. Here, the flow management arrangement 110 is also positioned downstream of any well test equipment 20, e.g., any separators or other such well test equipment 20. In some cases, the flow management arrangement 110 may be retrofit to the hydrocarbon flow path 30, or at least installed together with expected flow tubing or the like that may be used to fluidly couple the well test equipment 20 to the flare burner 40. In that way, the system 100 and / or flow management arrangement 110 may be configured to be agnostic to the existing well set-up and well test equipment 20, which may provide a cost effective solution to allow the system 100 to operate at site with various different equipment and apparatus. In any event, the flow management arrangement 110 is specifically configured such that hydrocarbons flow through the arrangement 110 from the well test equipment 20 to the flare burner 40. It will be appreciated that the flow management arrangement 110 may be mechanically and fluidly connected to tubing or pipework that exists, e.g., that has been installed at the site 10 previously. In some cases, the flow management arrangement 110 may be formed generally as a pipe joint section or the like, so that it can be readily fitted to a existing section of the hydrocarbon flow 30, e.g., by removing and replacing an existing section of pipe work. While not required in all examples, in this case the system 100 further comprises a data acquisition arrangement 120 as is shown in Figure 2. In this particular example, the data acquisition arrangement 120 may be considered to be portable in that is can be relocated to alternative sites or locations. For example, the data acquisition arrangement 120 may not be physically connected (or permanently physically connected) to the flow management arrangement 110. That said, here, the data acquisition arrangement 120 is configured to be communication with the flow management arrangement 110 and configured to communicate data or otherwise information with the flow management arrangement 110. It will be appreciated that any communication may be wired or wireless, or combination thereof. Further, it will be appreciated that the data acquisition arrangement 120 may additionally or alternatively be configured to output data or information readily usable by the flow management arrangement 110 (e.g., rather that being in communication directly). For example, the data acquisition arrangement 120 may be additionally or alternatively configured to output specific instructions (e.g., at a user interface associated with the data acquisition arrangement 120) or other information to permit control of the flow management arrangement 110 such that an operator or the like may then control the flow management arrangement 110. Further still, in some examples, the data acquisition arrangement 120 (or indeed some other additional power supply of the system 100), may be configured to communicate power to the flow management system 110. In some of those examples, the flow management arrangement 110 itself may be unpowered, e.g., not have its own power supply. Power communicated to the flow management arrangement 110 (e.g., from time to time) may be usable to adjust the functionality of the system 100 / flow management arrangement 110, without the need for ongoing power. In that way, the flow management arrangement 110 may be unpowered (or essentially unpowered) when in use at site 10. Of course, it will readily be appreciated that in other examples, the flow management arrangement 110 may not need to receive power from an external source (e.g., is configured to operate passively or otherwise be fully powered itself), or indeed may comprise its own dedicated power supply (e.g., PV cells, and energy storage device) for fully or partially powering the arrangement 110. In any event, the data acquisition arrangement 120 may be configured to acquire data relating to one or more of: fluids or materials flowing in the hydrocarbon flow; emissions, such as combustion at the flare; and / or environmental conditions. For example, the data acquisition arrangement 120 may be configured to measure flow rates, fluid compositions or the like, at one or both of an upstream location and downstream location in the flow path 30, relative to the flow management arrangement 110 (e.g., using strap-on sensors). Additionally or alternatively, the data acquisition arrangement 120 may be configured to acquire environmental data, such as temperatures, wind speeds, RH, etc. Those data, including flow data, may be acquired at site, and / or via communication from further apparatus, e.g., via cellular or other network connectivity (not shown). Some or all data may be acquired in real time. It will be appreciated that the data acquisition arrangement 120 may comprise dedicated hardware, that includes firmware and software (e.g., memory and processors, for example, configured using application specific integrated circuits), and may comprise a plurality of input / outputs and sensor units as needed, configured to communicate data to / from the hardware in order to perform functions. The data acquisition arrangement may comprise a user interface, which may comprise a display. A skilled reader will readily be able to implement such arrangements as appropriate. In this particular example, the data acquisition arrangement 120 comprises an image capture device 125 (e.g., a camera arrangement) specifically configured to acquire image data relating to emission properties, and in this case combustion at the flare 40. In some examples, the image capture device 125 is configured to obtain an image of the flare being combusted and, from that data, particular information such as temperature, gas composition, etc., can be determined by the data acquisition arrangement. This may be achieved by, for example, observing the temperature, intensity and / or wavelength emissions of a particular flare, and correlating that with particular combustion properties. In some examples, the image capture device 125 is configured to determine at least spectral data (e.g., from a flare or the like), across multiple wavelengths. That spectral data may be considered to be hyperspectral data, and may be configured to obtain data across the visible wavelengths as well as at other wavelengths (e.g., ultraviolet and infrared wavelengths). That emission data / information, together with other data / information acquired regarding flow rate, temperatures, etc. if used, may be provided in order to assess the combustion at the flare, and so control or otherwise operate the fluid management arrangement 110.. For examples, particular wavelengths may indicate the completeness of combustion, which may be used together with temperature (e.g., environmental and / or flare), and optionally other factors, such as rH, to assess the emissions (e.g., completeness of combustion, likelihood of harmful emissions, etc.), and any improvement that may be possible. Consider now Figure 3a, which shows an example of the flow management arrangement 110 in more detail. Here, the flow management arrangement 110 is specifically configured to control intake (e.g., introduction, and in this particular example, induction) of a control fluid into the hydrocarbon flow, which flows along the flow path 30 to the flare burner 40. That control fluid may be used to modify or otherwise control combustion properties of the hydrocarbon flow. In other words, the control fluid may be used (or introduced accordingly) in order to manage combustion at the flare 40. In some examples, the control fluid may comprise fluids usable to increase the combustion of the hydrocarbon flow, such as oxidants (e.g., air comprising oxygen, and in some cases water). In some examples, the control fluid may comprise fluids usable to decrease the combustion of the hydrocarbon flow (e.g., water, cardon dioxide, potassium, or other such retardants). Further, in this particular example, the flow management arrangement 110 is configured to mix control fluid with hydrocarbon fluids. Here, such mixing is provided in a manner upstream of the flare burner 40. Such control may provide adjustment and control of the combustion properties at the flare burner 40. In this particular example, the flow management arrangement 110 is specifically configured to use (e.g., fully or partially) the flow of fluids in the hydrocarbon flow to assist with introduction (e.g. induction) of a control fluid into that hydrocarbon flow flowing to the flare burner 40, in order to control the combustion properties at the flare burner 40. In other similar words, the flow management arrangement 110 may be considered to be able to operate passively in so far as energy from the flow itself can be used to power the arrangement 110, and provide for introduction (e.g., induction) of any control fluid. In that way, the arrangement can, for example, be easily deployed at site without the need for additional power. In this particular example however, as will be described, the motive force (or otherwise flow) of the hydrocarbon flow itself effectively powers fully the arrangement 110 and causes introduction (e.g., induction) of control fluids into the flow. Here, the arrangement 110 comprises an intake arrangement 130 configured to introduce a control fluid into hydrocarbon flow using the fluids flowing in the hydrocarbon flow. Figure 4 shows one example of an example intake arrangement 130 in more detail. While in this example, the motive force (or otherwise flow) of the hydrocarbon flow itself may effectively power the intake arrangement 130 and cause the introduction or induction of control fluid (e.g., oxidant), it will be appreciated that in other examples, alternative (or additional) means may be used to assist with induction of a control fluid. For examples, power derived from the flow may be used alternatively or additionally to introduce (e.g., pump) control fluid to the hydrocarbon flow. One such example may comprise extracting energy from the flow using one or more turbine arrangements, positioning within the flow, which may then be utilised to power a particular intake arrangement 130 (e.g., comprising a powered pump) instead of, or to supplement, that shown in Figure 4. In any event, the flow may be fully or partially used to introduce control fluid. In some further examples, power derived not from the flow (e.g., and auxiliary power source may additionally or alternatively be used). In this particular example, and with reference to Figure 4, the intake arrangement 130 can be considered to intake (e.g., induct) oxidant (e.g., air, oxygen, etc.) as a control fluid at a second inlet 130b, and to mix that control fluid within a mixing chamber 130c with fluids that have flowed along the flow path 30 to a first inlet 130a. An outlet 130d is used to communicate mixed flow from the arrangement 130. The first inlet 130a comprises a restriction 135 which can be used to cause an effective reduction in pressure in the flow, and provide for introduction of the control fluid at the second inlet 130b. The motive flow of the hydrocarbon flow essentially being used to induct the control fluid. In some examples, the restriction 135 may be controllable in order to control the flow through the arrangement (e.g., more open vs more closed). In this case, a controllable first valve arrangement 140 may additionally or alternatively be provided at the first inlet 130a to the intake arrangement 130, which can be used to restrict the flow through the intake arrangement 130. Additionally or alternatively, a controllable second valve arrangement 150 may be provided at a second inlet 140b to the intake arrangement 130, which can likewise be used to restrict the flow of control fluid. Although not shown, a similar controllable valve arrangement may additionally or alternatively be provided at the outlet 130d. The rate of flow and / or valves may be set such that, in use, the flow management arrangement 110 may require little or no power supply (e.g., external power, but may be powered from energy extracted from the flow). It will be appreciated that although one or both of the first and second valve arrangements 140, 150 (and / or optionally and outlet valve arrangement; restriction) may be implemented, nevertheless the process of introducing (e.g., inducing) and mixing control fluid into the hydrocarbon flow may occur passively. That is to say that no additional power requirements may be needed. In those cases, the values may similar control the extent of flow. As mentioned, the motive force of the hydrocarbon flow itself may effectively power the flow management arrangement 110 / intake arrangement 130. Further, the flow rates and rates or induction / mixing, may be set (e.g., using the valves or otherwise) such that the flare burner 40 does not perceive any change in conditions when the flow management arrangement 110 is installed (e.g., in a retrofit manner from Figure 1 to Figure 2). In other words, in this example (and other examples) there may be no or little perceived pressure change at the flare burner 40 with the system 100 installed compared to without the system installed. In other similar words, the pressure of fluid flow at the burner 40 can be maintained. It will be appreciated that while is may be helpful to describe the arrangement in Figure 3a (and later Figures) comprising first and second valve arrangements 140, 150, it will be appreciate that that need not always be the case. In some cases, one, some or all, of the valves may not be used, as needed. Returning to Figure 3a, and by way of an example only, the system 100 (and in this case the flow management arrangement 110) may be considered to comprise at least a first flow path 30a and a second flow path 30b through the arrangement 110. The first flow path flows through the arrangement 110 to the flare burner 40 such that hydrocarbons are mixed with oxidant to a particular extent (e.g., controlled by the intake arrangement 130, etc.). The second flow path 30b, however, is configured such that hydrocarbons are mixed with oxidant to a different extent and, in this example, no mixing occurs as hydrocarbons flow in the second flow path 30b to the flare burner 40. Here, the second flow path recombines with the first flow path downstream of the intake arrangement 130, but upstream of the flare burner 40, such that the combined flow from the first and second flow paths then travels to the flare burner 40 for combustion. In this example, the second flow path 30b may be considered a bypass flow path. It will be appreciated, however, that this arrangement may be provided differently. In some examples some or all of the flow paths 30a, 30b need not combine prior to the flare burner 40, but rather may combine at the location of combustion (e.g., at the flare tip). In such cases, little or no mixing of the flows may occur prior to combustion. Figure 3b shows such an example in which the second flow path 30b and the first flow path 30a combine at the location of combustion (e.g., at the burner tip itself, rather than upstream of the burner 40). Depending of the system 100 (e.g., fluid being combusted), such an arrangement may allow for improved control of combustion properties at the flare 40. In any event (e.g., Figure 3a or Figure 3b) a selector 160 may optionally be provided upstream of the first and second flow paths 30a, 30b, and can be configured to allow selective flow of hydrocarbons through the first flow path 30a, the second flow path 30b, or a though combination of flow paths 30a, 30b (e.g. proportionally). It will be appreciated that in some examples, the selector 160 maybe configured as a divertor. Further, it will be appreciated that in some examples, the selector 160 may be used without the need for a first valve arrangement 140, whereby restricting flow to the first inlet 130a of the intake arrangement 130 increases flow (e.g., proportion of flow) along the second fluid path 30b (and vice versa). In further examples (e.g., when the fluids from a well have been separated) it may be that a selector is not required, but rather the output of a separator is fed to the system 100 such that one particular flow paths is used for a first fluid (e.g., gases), while the other particular flow path is used for a second fluid (e.g., oil). The first and second fluids may be different. Figures 3c and 3d show examples of the system 100 having a first flow path 35a, and a second flow path 35b, in a similar to Figure 3a and 3b. Here, however, in Figure 3c the firstand second flow paths 35a, 35a may be fluidly connected to different sources (e.g., different separator outlets, and / or different wells, rather than the same source). For example, the first flow path 35a may be fluidly connected to a first source (e.g., first well test arrangement), while the second flow path 35b may be fluidly connected to second oil source (e.g., second well test arrangement). Here, the second flow path 35b combines with the first flow path downstream of flow arrangement, but upstream of the flare 40. In doing so, the fluid flowing in the second flow path 35b is mixed with fluid, which has been mixed with control fluid, in the first flow path, prior to combustion. Such an arrangement may help manage emission at site with multiple sources of different quality, for example. Figure 3d shows an example similar to Figure 3c, but in this case, the second flow path combines at the location of combustion (e.g., rather than upstream of the burner 40). In those cases, it may be possible to introduce control fluid into one or more of the flow paths (e.g. oil), but not others, in order to control emissions, e.g., from multiple sources (e.g., oil or gas, and / or different wells). Such a configuration may allow for efficient controlled combustion during varying conditions during well test, or varying sources, or the like. In use, a well site 10 may be initially appraised for suitability of installing (and optionally retrofitting) the flow management arrangement 110. For example, in some cases, the data acquisition arrangement 120 may be positioned at site and used to acquire data relating to the effective combustion of an existing or possible flare burner 40, and to provide improvement recommendations. The flow management arrangement 110 may then be fitted (or retrofitted) to pipework or the like. Initially, when using the examples shown in Figure 3a or 3b, fluid may be permitting to flow entirely though the second flow path 30b to confirm operations. The data acquisition arrangement 120 may then be able to communicate with the flow management arrangement 110, e.g., either directly or via an operator, in order to configure the flow management arrangement 110 in order to minimise green house gas emissions and / or other emissions. In some cases, power may be supplied at that time to the flow management arrangement 110 (e.g., using external power or via the data acquisition arrangement 120). Once set, flow may then be diverted fully or partially through the first flow path 30a in order to introduce and mix appropriately control fluid (e.g., oxidant) with the hydrocarbon flow, and so control emissions, e.g., minimise green house gas emissions. Feedback, such as realtime feedback, from the data acquisition arrangement (e.g., via image data) may be used to confirm optimal performance, and control emissions. In some cases, the system may be considered to act autonomously. While in the example described, the control fluid has been described comprising an oxidant, which may help improve the combustion efficiency and allow methane to be combusted (e.g., managing green house gas production), in other examples, there may be a desire to affect combustion in different ways, which may in fact help to reduce harmful emissions. For example, it may be determined that the particular temperature of combustion could give rise to the production of green house gases, such as nitrogen dioxide or the like, or otherwise may be harmful (e.g., excessive temperature being hazardous to surrounding environment or equipment). In such examples, reduction of the temperature of combustion may be desired, e.g., to avoid or minimise any such production (and in fact minimise the effective green house gas emissions). As such, a control fluid that may reduce the temperature of combustion may be used, such as water, carbon dioxide, potassium or the like. In similar words, the control fluid may comprise a retardant. Similarly, in some examples, the production of hydrogen sulphide, or other highly toxic gases, may be identified (or estimated), and management of the combustion may be desired in order to minimise the production of any such gases. In those cases, any control fluid may be used to minimise combustion (e.g., cold vent) and / or avoid hydrogen sulphide production. A skilled reader will readily be able to implement those embodiments. It will be appreciated that in some examples, the data acquisition arrangement 120 may be configured to acquire data for a period of time (e.g., over a day, week, month or the like) over which conditions may likely vary. Based on any observed or expected variations in conditions, the data acquisition arrangement 120 may be configured to provide optimal settings for the flow management arrangement over that particular period (e.g., to provide the least green house gas emissions cumulatively overthat period). For example, it may be that environmental temperature are known or measured to vary over the course of a day, and the flow management arrangement 110 may be set (e.g., set statically overthat period) to provide optimal performance overthat period. In some cases, the data acquisition arrangement 120 may be configured to model or predict expected performance of the flow management arrangement 110 over a period of time, such as over a day, week, month or year, and so communicate instructions or information to the flow management arrangement for that ongoing operations (e.g., on an ongoing basis or once / at intervals even when the data acquisition system is no longer in communication with the flow management arrangement 110). It will be appreciated that any such prediction of control may use predictive models based on present data and / or previous data acquired. Predictive models may be used to initially control (or otherwise set) the performance of the flow management arrangement 110, which then may be validated and / or varied as appropriate. In further examples, of course, the system 100 may be configured to vary in real time the operation of the flow management arrangement 110, and in some cases the data acquisition system 120 may remain in communication with the flow management arrangement 110 during such operations, (e.g., dynamic / real time operations). In any event, the system 100 described may be configured in one example to ensure that green house gas production, and / or other combustible production, or other harmful emissions are minimised or otherwise eliminated. This may be achieved by monitoring data (e.g., flow, image, etc.) and ensuring that appropriate control fluids are provided such that harmful gases or any other such combustible is fully burned, and / or other emissions managed. It will be appreciated however that in some examples using oxidant, adding further oxidant may also result in cold flaring or venting of particular components at the burner 40, without using a retardant. In those cases, green house gases may be released, and so choking oxidant may be required. This may benefit from being dynamically varied in examples, such as well test (or other non-routine flaring examples). Further still, it will be appreciated that in some examples, the emission of gases, such as green house gases, may be controlled collectively to ensure that minimum (or optimal) emissions from the burner 40 may be achieved. For example, green house gas emissions may comprise methane as well as carbon dioxide, nitrogen dioxide, etc. (or indeed other green house gases). Some carbon dioxide, or other gases for example, may be present in the flow already, and so difficult to eliminate. As such, measurement simply of the cardon dioxide at the flare 40 may be misleading as it may suggest combustion, whereas that green house gas was already present in the flow. In some examples, the system 100 may be configured to control combustion such that a balance of green house gases are controlled and minimised (or otherwise reported), with the cumulative effective of green house gas emissions being controlled or minimised (e.g., methane, and other gases, such as CO2). The system may be configured to weigh particular emissions (e.g., based on each component gas’s relative green house effect), and to control overall emissions such that the effective cumulative greenhouse gas emissions, and / or other harmful emissions, are controlled or minimised. While in some of the above example, the system 100 may be described as being retrofittable to an existing well structure, it will be appreciate that that need not always be the case, and that the system 100 may be installed at the same time as the well infrastructure (e.g., for permanent installation). In those cases, or indeed other cases, the flow management arrangement 110 may again be configured to control (e.g., passively) combustion at a flare burner 40 by manging or otherwise controlling the flow and extent of control fluid being introduced to the hydrocarbon flow, e.g., either at the flare burner or that flows to the flare burner 40. It will be appreciated, however, that some arrangements 110 (e.g., permanent install) may need only comprise the first flow path 30a, and introduction of control fluid may be controlled without the option of flowing via a second flow path 30b. That said, utilizing the second flow path 30b may permit a greater control of control fluid use / mix, particularly under varying conditions, as well as - should it be required - the ability to allow flow to pass through the device without additional control fluid. In the example described in relation to Figure 3a and 3b, the second inlet 130b may be fluidly coupled to atmosphere in order to deliver air comprising oxidant to the flow. It will be appreciated that in other examples, however, alternative control fluid sources may be used, such as stored oxidant (e.g., oxygen) and / or retardant (e.g., water). In some examples, the control fluid may be selected or indeed selectively changed between oxidant or retardant at the inlet to the system 100 (e.g., second valve arrangement 150). In the examples in which, for example, air from atmosphere is used, it will be appreciated that flow management arrangement 110 may further comprise a filter arrangement (e.g., media and / or a labyrinthtype flow path) in order to remove unwanted particulates or the like. While in the examples described in relation to Figure 3a-3d two flow paths 30a, 35a, 30b, 35b are described as usable to control introduction (e.g., passively control induction using the flow) of a control fluid to different extents, and wherein the second flow path was configured substantially not to introduce control fluid, it will be appreciated that in further examples additional or alternative flow paths may be provided. Consider now, by way of an example, the system of Figure 5a, which is similar to that shown in Figure 3a, but with multiple units 300a, 300b configured to introduce particular control fluids (e.g., unit similar to Figure 3a, 3b, 3c, 3d and 4, may be used, for example ). Each unit 300a, 300b may comprise a intake arrangement 230a, 230b as before, and may configured along a separate flow path. At least two of the units / intake arrangements 300a, 300b are provided on alternative flow paths 30c, 30d in Figure 5a. By way of an example, a flow path 30e without a intake arrangement (as per 30b in Figure 3) is also shown. This need not always be used, of course. In this particular example, the intake arrangement 230a of the first unit 300a may provide alternative performance characteristics to the intake arrangement 230b of the second unit 300b. In that way, the intake arrangement (or ratio of flow to each intake arrangement) may be operative selected in order to control rate of control fluid introduction. For example, some or all intake arrangements / units 300a, 300b may be configured to operate on different flow rates; different pressures, or different fluid (e.g., oil or mainly oil, versus gas or mainly gas), or indeed may be configured to use different control fluids (e.g., alternative oxidants / retardants, or even a combination of different oxidants and retardants). In that way, the same system 100 can be operatively used for varying conditions, or sets ups, without having to reconfigure the arrangement. As such, the flow management arrangement 110 may be usable across a wide variety of well sites, irrespective of the well in question. Further, the flow management arrangement 110 may be controllable to appropriately minimise green house gas emissions at those various alternative sites or other emissions, with minimal reconfiguration. While in Figure 5a, the flow paths are combined together downstream of the flare burner 40, it will readily be appreciated that this need not always be the case and that, in some examples, some or all of the flow paths comprising control fluid may combine at the location of combustion in order to control emissions (e.g., as per any of Figures 3b, 3c or 3d), without the need to describe those further examples. A skilled reader will readily be able to implement those embodiments accordingly. While in the example in Figure 5a, the system may be considered to control the introduction of control fluids within parallel flow paths (e.g., 30c, 30d, 30e). That is to say that, some of the fluid flow to the system may be selectively allowed to flow through alternative units 300a, 300b, as shown in Figure 5a. It will be appreciated, however, that in further examples, the system may additionally or alternatively be configured so as to permit different control of control fluids in series, along flow paths. Consider by way of an example, Figure 5b, which shows an arrangement similar to Figure 5a, but in which intake arrangements / units 300c and 300d are arranged in series along a flow path 30f. Here, each arrangement 300c, 300d, may be configured to provide alternative performance characteristics, and may be operatively used in order to control rate of control fluid introduction. For example, some or all intake arrangements 300c, 300d may be configured to operate on different flow rates; different pressures, or different fluid (e.g., oil or mainly oil, versus gas or mainly gas), or indeed may be configured to use different control fluids (e.g., alternative oxidants / retardants, or even a combination of different oxidants and retardants). Here, one, some or all arrangements in series may be selectively operable (e.g., can allow no introduction of control fluids) so to operatively select one or more of the arrangements for use. Further, in the example shown, the second flow path 30e, may be combinable between units 300a, 300d, and / or after units, and / or at the location of combustion. It will be appreciated that the series arrangement may be used together with one or more of the parallelly arranged units in Figure 5a. It will further be appreciated that based on the hydrocarbons being produced, that the system 100 described in Figures 3a, 3b, 3c, 3d and Figures 5a and 5b can be used to supply and mix control fluids with the flow (e.g., passively) so as to control and improve combustion properties, as desired. In some cases, the ratio of control fluid being mixed can be controlled to ensure that methane, and / or other green house gas production is reduced, minimised or even eliminated. It will be appreciated that in some cases, an optimal condition may present whereby too little control fluid may not be sufficient to combust all the methane or the like, whereas too much control fluid (e.g., in the form of air, so also including nitrogen) may lead to cold flaring, or otherwise venting of methane. In the examples described the valve arrangements (and optionally flow paths) may be controlled or otherwise set in order to (e.g., using power from the flow) control the combustion at the flare burner 40. In the example described in relation to Figure 4 in particular, it will be appreciated that alternative arrangement (e.g., different pump geometries) may be implemented and selected with ease. As explained, in some examples, the settings or control of such valves or flow paths may be effected by an operator. It may be that the operator is informed of those settings from the data acquisition arrangement (e.g., via a user interface) or, as shown in Figure 6, the data acquisition arrangement may be in communication with the flow management arrangement so as to permit control of the flow management arrangement. As explained, the data acquisition arrangement 120 may be in continuous communication, but in other examples, the data acquisition arrangement 120 may only be in communication from time to time, for example at intervals, which may be periodic intervals (e.g., daily, weekly, yearly). In particular, the acquisition arrangement 120 may be portable, and relocatable from site to site. In that way, a single data acquisition arrangement 120 may be configured to be usable with multiple flow management arrangements. Further, predictive models developed by the data acquisition system for other sites / flares may be usable with the flow management arrangement (e.g., at least as a first best guess). Figure 7 shows an example of data that may be collected or used by the system 100 / data acquisition arrangement 120, and which may be used as input for a predictive model (either to obtain an output, or as training data). Some or all of that data may be presented at a dashboard or the like, which may provide prompts for an operator to select (e.g., at a user interface). Otherwise, the dashboard may inform the operator of decisions being made by the system. This may allow the operator to observe (and potentially override) operations at site. The dashboard may also permit visual representation for reporting purposes. For example, he dashboard may provide reporting functionality including green house gas reduction, or other harmful emission reduction. Further, the data may include data associated with the flow of hydrocarbons in the flowline, such as composition (e.g., cut), hydrocarbon BTU / LVH, process data. The data may include environmental data. The data may include data associated with the combustion at the flare (e.g., derived from image data), including one or more of: flare CE, flare BTU / LHV, flare temperature, flare colour, etc., methane composition, CO2 composition, nitrogen dioxide composition, hydrogen sulphide composition, destructions and removal efficiency, etc. The data may include effective green house gas emissions at an oil and gas installation (e.g., well site). While in the above example, specific reference has been given to managing or otherwise controlling emissions at a single flare burner 40, it will readily be appreciated that the systems and methods described need not be limited to a single flare burner 40, and some or all aspects may be used across a wider oil and gas installation. Consider now, by way of an example, Figure 8, which shows such an oil and gas installation 300 comprising three burners 40a, 40b, 40c, in a similar manner to as above. In this case, each burner 40a, 40b, 40c is associated with a particular well site or pad, and is in fluidic communication with respective flow management arrangements 110a,110b, 110c as before. In this example, a single data acquisition arrangement 120 is in communication (or can be configured to be in communication, e.g., at different times) with each of the flow management arrangements 110a, 110b, 110c. Here, the image capture device 125 is configured to operatively move or be repositioned so as to obtain image data as above from each of the flares (e.g., relocate, pan, tilt, rotate). In doing so, a single image capture device 125 may be used to collect image data to allow for control and management of emissions across each of the flare burners 40a, 40b, 40c. In some examples, it will be appreciated that the data acquisition arrangement 120 may be configured to wirelessly communicate with one or more of the flow management arrangement 110a-c. Further, it will readily be appreciated that the image capture device 125 may be configured to be moved from time to time between flare burners 40a, 40b, 40c (e.g., periodically, such as every hour, day, week, or the like), or may continuously sweep a particular area (e.g., a region of the well installation). In some examples, the image capture device 125 may be portable and relocated at site in order to capture data. In such a way, multiple flare may be managed with minimum cost. It will be appreciated that while flares provide a source of green house gas emissions at site, nevertheless there are other sources of emissions at site which may affect the overall emissions of oil and gas activity. Therefore, it may be valuable to take a holistic approach to emissions at site in order to control (e.g., minimise) emissions. Consider now, by way of an example, Figure 9, which shows a further example of a system 400, which again comprises a data acquisition arrangement 420 as well as, in this example, a flow management arrangement 410, which can be in communication with one another. That data acquisition arrangement 420 further comprises an image capture device 425 as before. Here, however, while the image capture device 425 is configured to observe properties at or around a flare burner 40 (e.g., measuring composition, combustion efficiency, etc. in order to inform the flow management arrangement 410), in this particular example, the image capture device 425 is further configured to observe (or otherwise identify) emissions from other sources at the oil and gas installation. Such an installation may be a production facility, rig or platform, or any other installation. Such othersources may include unintended emissions (e.g., leaks) at particular components 500. Those components 500 may include well test equipment (e.g., shown as 20 in Figure 1), or other aspect of the infrastructure, such a pipework, valves, etc. The system 400 may be configured to be trained at and observe particular components 500 (e.g., known or potential problem components) in a similar manner to observing a flare, or may be configured to sweep an area across the installation. Either way, the image capture device 425 and the data acquisition arrangement 420 may identify leaks or problems at site. In some cases, the system 400 may be configured to alert an operator or the like in order to schedule maintenance, or otherwise may be configured to take preventative action when identifying leaks or potential leaks. In other cases, the system may additionally or alternatively be used to record such emissions for reporting purposes, or other actions (e.g., using the dashboard arrangement described above). It will be appreciated that in some examples, the data acquisition system (e.g., including image capture device) may be used without the flow management arrangement. In those cases, the data acquisition arrangement be used to identify emissions from one or more flare burners and / or components. Collected data may be used for reporting purposes, and / or may be usable to take particular action at site. It will be appreciated that unwanted emission (e.g., leaks) at site may not only be a potential hazard, but also may result in lost revenue, e.g., due to extended periods of downtime when problems are not identified early, and / or lost hydrocarbons. A skilled reader will readily appreciate that the simple and cost effective nature of the above described solution. It will be apparent to those skilled in the art that various modifications and variations can be made to the disclosed facilities, systems, methods, and apparatus. Other embodiments will be apparent to those skilled in the art from consideration of the specification and practice of the disclosed systems, methods, apparatus, etc. It is intended that the specification and examples be considered as exemplary only, with a true scope being indicated by the following claims and their equivalents.

Claims

1. A system for managing emission properties, comprising;a flow management arrangement, configured to positioned in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbon in the flow; wherein the flow management arrangement is configured to use fully or partially the flow of fluids in the hydrocarbon flow to control introduction of a control fluid to that hydrocarbon flow flowing to the flare burner in order to control the emission properties at the flare;a data acquisition arrangement, configured to acquire data relating to fluids flowing in the hydrocarbon flow and / or emission properties at the flare, and to permit the control of the flow management system.

2. The system according to claim 1, wherein the flow management arrangement comprises one or more intake arrangements comprising a hydrocarbon flow inlet, and control fluid inlet, a mixing chamber for mixing hydrocarbon flow with control fluid, and a flow outlet for outletting mixed hydrocarbon flow, and wherein the intake arrangement is configured to passively control induction of control fluid, using the flow of fluids in the hydrocarbon flow.

3. The system according to claim 1 or 2, wherein the system is configured to introduction oxidant, such as inducting air from atmosphere, to the hydrocarbon flow, and / or introduce water into the hydrocarbon flow.

4. The system according to any preceding claim, wherein the system is configured to permit adjustable introduction of control fluid, such as introduction from atmosphere, based on determined or assumed conditions at site.

5. The system according to any of the claims 1 to 4, wherein the system comprises at least a first flow path and a second flow path, wherein the first and second flow paths are used to control introduction of control fluids to different extents, and where the system is configured toallow selective flow of hydrocarbons through the first flow path, the second flow path, or a though combination of flow paths.

6. The system according to claim 5, wherein the first flow path is configured to introduce a control fluid to a hydrocarbon flow, and the second flow path is configured substantially not to introduce control fluid.

7. The system according to claim 5, wherein the first flow path is configured to introduce control fluid to a hydrocarbon flow at a first particular extent, and the second flow path is configured to introduce control fluid at to second particular extent, wherein the first and second rates are selectively different.

8. The system according to any of the claims 5 to 7 comprising more than two flow paths, each flow path being configured to control introduction of control fluids to different extents, and wherein at least one of the flow paths is configured substantially not to introduce control fluid.

9. The system according to any of the claims 5 to 8, wherein each of the flow paths are fluidly connected to a common source, or wherein each of the flow paths are fluidly coupled to alternative sources.

10. The system according to any of the claims 5 to 9, wherein some or all of the flow paths combine upstream of any burner, or some or all of the flow paths combine at the location of combustion, at a burner.

11. The system according to any preceding claims, wherein the flow management arrangement is configured to control both the flow rate of hydrocarbons and the introduction of control fluid to the hydrocarbon flow.

12. The system according to claim 11, wherein the control of the flow rate of hydrocarbons can be controlled independently of the controlled introduction of control fluid to the hydrocarbon flow.

13. The system according to any preceding claim wherein the flow management arrangement is retrofittable to an existing well structure.

14. The system according to claim 13, wherein the retrofittable flow management arrangement is configured to be positioned down stream of well test equipment, and up stream of a flare burner.

15. The system according to claim 14, wherein any well test equipment upstream of the system comprises one or more separators, and the flow management system is configured to be positioned down stream of any separators.

16. The system according to any of the preceding claims wherein the flow management arrangement is powered, at least in part, via the data acquisition arrangement, when in communication.

17. The system according to any of the preceding claims wherein the data acquisition arrangement is configured to acquire data relating to emission properties at a flare using at least one image capture device, and wherein data from the image capture device permits determination of one or more of properties of that flare.

18. The system according to claim 17, wherein the one or more determined properties includes one or more of: composition of emissions, such as the composition of green house gas emissions; temperature; combustion efficiencies; and destruction and removal efficiency19. The system according to any of the preceding claims wherein the data acquisition arrangement is configured to acquire data relating to fluids flowing in the hydrocarbon flow, and wherein the data comprises one or more properties relating to the composition of fluids in the hydrocarbon flow.

20. The system according to any preceding claim, wherein the system is configured to use predictive modelling to control introduction of a control fluid to the hydrocarbon flow, the model using data relating to fluids flowing in the hydrocarbon flow and / or emission properties at a flare.

21. The system according to any of the claims 1 to 20, wherein the flow management arrangement is configured to introduce control fluid to that hydrocarbon flow at the flare burner during combustion, and / or the flow management arrangement is configured to introduce control fluid into the hydrocarbon flow so as to be mixed with the flow downstream of the flare burner.

22. A method for managing emission properties, comprising;positioned a flow management arrangement in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbons in the flow;acquiring data relating to fluids flowing in the hydrocarbon flow and / or combustion at the flare;controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using fully or partially the flow of fluids in the hydrocarbon flow together with the acquired data in order to control the emission properties at the flare.

23. The method according to claim 21, wherein the method comprising using one or more intake arrangements comprising a hydrocarbon flow inlet, and control fluid inlet, a mixing chamber for mixing hydrocarbon flow with control fluid, and a flow outlet for outletting mixed hydrocarbon flow, and wherein the method comprises controlling introduction of control fluid using the flow of fluids in the hydrocarbon flow.

24. The method according to claim 22 or 23, wherein the method includes acquiring image data associated with combustion at the flare, and wherein that data is used to control introduction of a control fluid.

25. The method according to claim 24, wherein the image data is acquired at intervals, and wherein controlled introduction of control fluid is determined at or around those intervals.

26. The method according to claim 25, wherein the intervals include one of hourly, daily, weekly, monthly or yearly.

27. The method according to any of the claims 22 to 26, wherein the flow management arrangement comprises at least a first flow path and a second flow path, wherein the first and second flow paths passively control introduction of an control fluid to different extents, and where the method comprises selecting one of the first flow path, the second flow path, of a combination of flow paths, to flow hydrocarbons through.

28. The method according to any of the claims 22 to 27, wherein the method comprises retrofitting the flow management arrangement upstream of a flare burner, and downstream of a separator of well test equipment.

29. The method according to any of the claims 22 to 28, wherein the method comprise using the acquired data together with a predictive model to control controlling introduction of a control fluid to the hydrocarbon flow.

30. The method according to claim 29, wherein the method comprising varying the introduction of a control fluid to the hydrocarbon flow overtime.

31. The method according to any of the claims 22 to 30, wherein the method comprising managing emission properties for non-routine flaring.

32. The method according to any of the claims 22 to 31, wherein the method comprising introducing control fluid to the hydrocarbon flow at the flare burner during combustion, and / or introducing control fluid into the hydrocarbon flow so as to be mixed with the flow downstream of the flare burner.

33. A system for managing emission properties, comprising;a flow management arrangement, configured to positioned in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbon in the flow; wherein the flow management arrangement comprises one or more pumps configured to use the flow hydrocarbon flow to control introduction of a control fluid to the hydrocarbon flow flowing to the flare burner in order to control the combustion at the flare.

34. A system for managing emission properties, comprising;a data acquisition arrangement, configured to acquire data relating to emissions at an oil and gas installation, wherein the system is specifically configured to acquire data relating to emissions from a flare burner as well as leak emissions from components at an installation.

35. A method for managing green house gas emissions, comprisingacquiring data relating to emissions from a flare burner as well as leak emission from components at an oil and gas installation, and using that data to manage green house gas emissions.

36. The method according to claim 35, wherein the data derived from image data.

37. The method according to any of the claims 35 or 36, wherein the method comprises acquiring data relating to emissions from a non-routine flare burner.

38. A method for managing emission properties, comprising;positioning a flow management arrangement in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbons in the flow;controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using fully or partially the flow of fluids in the hydrocarbon flow together with the acquired data in order to control the emission properties at the flare.

39. The method according to claim 38, wherein the method comprising controlling introduction of a control fluid to different extents across two or more flow paths.

40. The method according to claim 39, comprising combining the flow paths at the location of combustion at the burner.

41. A system for managing emission properties, comprising;a flow management arrangement, configured to positioned in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbon in the flow; wherein the flow management arrangement is configured to control introduction of a control fluid to that hydrocarbon flow flowing to the flare burner in order to control the emission properties at the flare;a data acquisition arrangement, configured to acquire data relating to fluids flowing in the hydrocarbon flow and / or emission properties at the flare, and to permit the control of the fluid management system.

42. A method for managing emission properties, comprising;positioning a flow management arrangement in line with a hydrocarbon flow, and upstream of a flare burner for burning hydrocarbons in the flow;acquiring data relating to fluids flowing in the hydrocarbon flow and / or combustion at the flare;controlling introduction of a control fluid to the hydrocarbon flow flowing to the flare burner using the acquired data in order to control the emission properties at the flare.

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