The present invention relates to a method of hydrocarbon production. More specifically, the present invention relates to a method of producing hydrocarbon fluid from a subsea hydrocarbon reserve.

During the production lifetime of a given subsea hydrocarbon reserve (sometimes termed a hydrocarbon asset) the pressure within the reserve reduces in the absence of preventative measures due to the removal of hydrocarbon and other fluids therefrom. This decrease with time in the pressure in the hydrocarbon reserve in turn results in a decrease in a pressure of a wellhead connected to the reserve and from which hydrocarbon fluid is produced. A decreasing pressure under such a scenario (i.e. absent preventative measures) would (as would be understood in the art) result in decreased production rates, which is undesirable. Furthermore, decreasing pressure is undesirable since it is the pressure in the produced fluid that is used to convey the fluid to topside for further processing, transportation and use.

Therefore, conventionally, to avoid this decreasing pressure in the reserve/at the wellhead, injection of water and/or gas is used to maintain pressure within the reserve/well and thereby maintain the pressure of the wellhead. This in turn maintains a high production rate of fluid being removed from the production well and further ensures that the produced fluid can be conveyed topside.

US 9181786 B1 discloses a method of production in which gas injection is used to maintain reserve and wellhead pressure.

Artificial lift, in the form of pumping or otherwise, may be present at a particular production site and may be used in support of the injection to aid in conveying the produced fluid topside. A constant degree of artificial lift is used where it is known from the outset of production at the given reserve that injection in itself will not be sufficient to convey the fluid topside.

US 10774622 B2 discloses a production system in which a topside (i.e. surface) pump is used to help convey hydrocarbon fluid to a surface production facility.

Injection is energy-intensive and is associated with a large ‘carbon footprint’ which in turn results in the overall production process having a large ‘carbon footprint’. There is thus a desire to make the overall production process less energy intensive and thus reduce the ‘carbon footprint’ of the production process. Moreover, the pressure of injection is limited to a maximum pressure above which cracks would form in the reserve. As is well known such irreversible damage to a reserve is disadvantageous and therefore reserve pressure is maintained below this level when using injection. Given this limitation on the pressure of injection, the production rates that can be achieved by virtue of the use of injection are also limited since conventionally production rates are directly dependent on injection. There is thus a desire for production process that enables increased production rates.

In accordance with a first aspect of the invention, there is provided a method of hydrocarbon production at an offshore production facility comprising: a) producing hydrocarbon fluid from a subsea wellhead in communication with a subsea hydrocarbon reserve; b) conveying the produced hydrocarbon fluid to a topside structure by means of the pressure of the produced hydrocarbon fluid; c) allowing the pressure of the produced hydrocarbon fluid at the wellhead to decline during step a) as a result of a declining hydrocarbon reserve pressure due to production of hydrocarbon fluid therefrom; and d) whilst allowing the pressure of the produced hydrocarbon fluid at the wellhead to decline, compensating for the declining pressure of the produced hydrocarbon fluid by introducing or increasing pumping of the produced hydrocarbon fluid (i.e. the produced fluid that has emanated from the wellhead) using a subsea pump to ensure that the produced fluid is conveyed to the topside structure.

The first aspect of the invention allows, and in fact requires, the pressure of the produced fluid at the wellhead and at the reserve to decline. This is contrary to commonly held prejudices in the field where it is understood that in the reserve/at the wellhead a high pressure necessarily has to be maintained, by virtue of fluid injection into the reserve, to ensure a high production rate of produced fluid and to ensure that the produced fluid was conveyed to the topside structure (perhaps with supporting artificial lift). The inventors have realised that by allowing the wellhead pressure to drop, and thereby avoiding or at least minimising the reliance on injection, significant and advantageous energy savings can be made and thereby significant and advantageous reductions in the carbon footprint of the production process can be made.

Fluid (e.g. gas or water) injection, as discussed above, is an energy intensive process and thus, by virtue of the hydrocarbons utilised in the production of the energy, is associated with a large carbon footprint. Moreover, over the production lifetime of a given reserve where injection is used, the proportion of desired hydrocarbons (e.g. oil and/or heavier gas phases) within the reserve declines due to the increasing degree of injected fluid in the reserve and in view of the hydrocarbons being removed. Thus, the proportion of desired hydrocarbons in the fluid produced from the reserve similarly declines over the production lifetime of the reserve until such a point in time where injection fluid is effectively being cycled into and out of the reserve with little useful hydrocarbons being produced. Despite the decreasing proportion of desired hydrocarbons in the fluid being produced, the injection utilised to produce the fluid from the reserve remains highly energy intensive however. As such, the ratio of desired hydrocarbons produced to the energy input for their production (and thereby carbon dioxide emitted) declines over the production lifetime of the well.

By allowing the pressure of the produced fluid at the wellhead to decline in response to the fluid being removed from the reserve, injection to the hydrocarbon reserve can be avoided, or at the very least minimised in the method of the first aspect. That is to say, in step c) of the method, injection to the hydrocarbon reserve is avoided, reduced and/or minimised, which in turn allows for the declining hydrocarbon reserve pressure due to production of hydrocarbon fluid therefrom to be realised. If injection were not avoided, reduced and/or minimised when producing hydrocarbons then a declining hydrocarbon reserve pressure could not be realised since the injected fluid would necessarily maintain (or even increase) the pressure of the first. Given the absence or at least reduction/minimisation of injection, the method of production is made significantly less energy intensive and has a greatly reduced carbon footprint.

Whilst the avoidance of injection is advantageous in terms of energy savings, without this preventative measure (and in absence of any further compensatory measure) to maintain the pressure within the produced fluid eventually the pressure would decline such that the produced fluid would not be able to be conveyed topside. To counteract this issue, the inventors have realised that pumping of the produced fluid with a subsea pump can either be introduced (if not previously present) or increased (if previously present) to compensate for the declining pressure at the wellhead and thereby the declining pressure of the fluid emanating from the wellhead. Pumping using a subsea pump (herein also termed subsea pumping) is in itself not a new measure; however, in the prior art subsea pumping is typically used as a constant support to provide lift to produced fluid and is typically used from the outset of production at a given reserve. There is no disclosure in the prior art of introducing subsea pumping after production at a given reserve has already commenced or increasing the degree of subsea pumping in response to declining pressure of the produced fluid at the wellhead. The inventors have realised that by introducing/increasing the degree of subsea pumping to compensate for a declining pressure of the produced fluid at the wellhead (which is allowed to occur) the produced fluid can still be conveyed topside whilst still making significant energy savings (and thereby reducing the carbon footprint of the production process). The energy associated with the subsea pumping that is introduced/increased and which is required to convey the produced fluid topside is significantly reduced as compared to the energy associated with the injection that would otherwise (and conventionally) be required for conveying the fluid topside.

The invention of the first aspect therefore resides in the realisation that by allowing for pressure of the produced fluid at the wellhead to decline and by compensating for the decline in this wellhead pressure by introducing or increasing subsea pumping of the produced fluid to the degree necessary to ensure the fluid is conveyed topside as required, that the production process can be carried out with a significantly reduced reliance on injection and thereby a significantly reduced carbon footprint.

Moreover, it has been realised that increased production rates of hydrocarbon fluid can be achieved by introducing or increasing subsea pumping of the produced hydrocarbon fluid and reducing or avoiding the reliance on injection as compared to prior art production processes reliant on reserve injection. As noted above, injection is limited to a maximum pressure since above this maximum pressure damage to the reserve can occur. Thus, given that production rates from a reserve solely reliant on injection are directly dependent on the pressure of the injection, production rates from such reserves are limited. The production rates attainable using the method of the first aspect are not limited in the same way, however. This is because the subsea pumping employed in the method of the first aspect does not increase the pressure within the reserve (instead it actually permits a decrease of pressure in the well/reserve). As such, the maximum pressure which limits injection based production methods is not a concern for the method of the first aspect. As such, the method of the fist aspect may optionally be used to withdraw produced fluid from the well at a rate greater than would be achievable via injection alone. Optionally, the subsea pumping is introduced/increased only (or substantially only) to the extent that ensures the produced fluid is conveyed topside as required.

The pumping of the produced hydrocarbon fluid using a subsea pump provides the produced fluid with the necessary impetus such that it is conveyed to the topside structure.

Alternatively, a surplus of subsea pumping above that which is required to ensure that the produced fluid is conveyed topside may be utilised. For example, where it is desired to maximise production rates. However, even in such a scenario, the energy input associated with the subsea pumping would necessarily be significantly reduced as compared to the injection that would otherwise be used for this purpose.

Optionally, as discussed above, no injection of fluid into the hydrocarbon reserve occurs. Thus, the energy intensiveness and carbon footprint of the production process can be greatly reduced.

Optionally, the method may comprise e) injecting fluid (e.g. gas and/or water) into the hydrocarbon reserve (and/or a well connected to the reserve) during step a) to lessen the decline in hydrocarbon reserve pressure and thereby lessen the decline in the pressure of the produced hydrocarbon fluid at the wellhead, but whilst still allowing a decline to take place. This is because, in some instances, it may not be possible to entirely omit the need for injection whilst still ensuring that the produced hydrocarbon fluid is conveyed topside or whilst still ensuring a desirable production rate. Thus, the method of the first aspect may utilise injection, but to a lesser extent than with conventional arrangements. Optionally, injection may only be used to the extent that is absolutely necessary to ensure the produced fluid can be conveyed to the topside structure. That is to say, the method may comprise minimising injection of fluid in step e) whilst still ensuring that the produced fluid is conveyed to the topside structure.

Injection would certainly not be used to completely prevent the decline in pressure at the reserve as a result of hydrocarbon fluid being produced therefrom. If injection is used, it would only be used to reduce the degree of decline of pressure, with compensation for the rest of the decline in pressure being provided for by subsea pumping, which as above is far less energy intensive than injection. The subsea pump may be installed before production commences, i.e. before step a). However, the method may alternatively comprise installing the subsea pump prior to step d) of the method but after step a) of the method.

The method of the first aspect may comprise a step f) of separating the produced fluid using a subsea separator once the pressure of the produced fluid falls below a first predetermined level.

The pressure of the fluid produced at the wellhead declines in step c). Whilst this is advantageous since it results from the avoidance (or reduction) of energy intensive injection, it can also be problematic if the pressure of the produced fluid decreases to a large enough degree.

As is known in the field of the invention, the produced hydrocarbon fluid will typically comprise a mix of constituents including oil phases, hydrocarbon gas phases and water. As is also known in the field, a fluid comprising both hydrocarbon gas phases and water is susceptible to hydrate formation, particularly when the pressure of said fluid is sufficiently low. Hydrates are ice-like crystalline solids which, when formed in hydrocarbon production equipment and associated conduits/piping, can cause blockages and damage that are/is undesirable.

Another issue that may arise if the pressure of the produced fluid is allowed to decline sufficiently is that the ‘boiling off’ (i.e. rapid vaporisation) of certain, lighter phases in the produced fluid can occur, which can again be problematic for the production equipment and associated conduits and piping.

The method of the first aspect of the invention can optionally deal with these issues by, as above, introducing subsea separation, optionally at least once the pressure of the produced fluid falls below a first predetermined level. This first predetermined level may be selected to avoid hydrate formation and/or to avoid vaporisation (i.e. boiling off) of phases from the produced fluid.

The method may comprise drawing down the pressure of the subsea separator in response to the declining pressure of the produced fluid at the wellhead. In that way, separation is enabled for the produced hydrocarbon fluid despite its declining pressure.

The separation in step f) may comprise separating water from the produced hydrocarbon fluid.

By separating water from the produced fluid subsea, pumping of water to the topside using the subsea pump can be avoided as the water can be discarded or utilised subsea (e.g. for injection purposes). Thus, the energy used in the subsea pumping of the hydrocarbon fluid to the topside can be reduced and the carbon footprint of the overall production process can yet be further reduced.

Optionally, step f) of the method may comprise separating the produced hydrocarbon fluid into a gas phase and an oil phase. This may occur in addition to, or as an alternative to, the separation of water as discussed above. The separation of the gas phases from the oil phases may occur in a two phase separator or, where water separation also occurs, may occur in a three phase separator. If water and gas separation are optionally employed, they need not occur within a three phase separator but may instead occur in a series of sequential, two phase separation processes.

The subsea pump may pump the (separated) oil phase to the topside structure after separation thereof.

The gas phase may not require artificial lift (e.g. pumping and/or compression) to convey it to the topside structure after separation thereof. The inherent pressure of the separated gas may be sufficient to convey itself topside.

Alternatively, the gas phase may require artificial lift to convey it to the topside structure or to convey it to the topside structure at the desired rate, or it may not initially require artificial lift to convey it to the topside structure but may require artificial lift over time as the pressure of the separated gas phase reduces, for example, as a result of the decreasing pressure in the separator. As such, the method may comprise, when the pressure of the gas phase drops below a second predetermined level, introducing a subsea compressor to provide artificial lift to the gas phase.

Step c) of the method may be controlled by controlling the degree of opening of a choke valve associated with the subsea wellhead.

The topside structure of the invention may be any structure that is conventionally situated topside (i.e. above or at sea level) within a production facility and that would receive produced hydrocarbon fluid therefrom. For instance, the topside structure may be an offshore platform, for instance a production platform or vessel (e.g. a floating, production storing and offloading (FPSO) vessel).

The topside structure may be an offshore structure.

The topside structure may be an unmanned structure, for example an unmanned production platform (UPP).

In this context, unmanned may require at least one of: no permanent personnel at the topside structure; no provision of facilities for personnel to stay on the structure, for example there may be no shelters for personnel, no toilet facilities, no drinking water, no personnel operated communications equipment and/or no lifeboat; and/or that personnel be present for fewer than 10,000 maintenance hours per year at the structure.

An unmanned structure may have no permanent personnel and may only be occupied for particular operations such as maintenance and/or installation of equipment. The unmanned structure may be a structure where no personnel are required to be present for the structure to carry out its normal function, for example day-to-day functions relating to handling of oil and/or gas products at the structure.

An unmanned structure may alternatively or additionally be defined as unmanned based on the relative amount of time that personnel are needed to be present on the structure during operation. This relative amount of time may be defined as maintenance hours needed per annum, for example, an unmanned structure may be a structure requiring fewer than 10,000 maintenance hours per year, optionally fewer than 5000 maintenance hours per year, perhaps fewer than 3000 maintenance hours per year.

The topside structure may be a low-manned structure, for example a low- manned production platform. For a given structure, the skilled person would be aware of what constitutes a ‘low-manned’ structure. Whilst a low-manned structure comprises some permanent crew/personnel (which distinguishes it from an unmanned structure), the low-manned structure has a relatively small number of personnel (i.e. a skeleton crew) and thus it is distinguished from a ‘manned’ or ‘fully-manned’ structure.

In another aspect of the invention, there is provided a method of hydrocarbon production at an offshore production facility comprising: a) producing hydrocarbon fluid from a subsea wellhead in communication with a subsea hydrocarbon reserve; b) conveying the produced hydrocarbon fluid to a topside structure by means of the pressure of the produced hydrocarbon fluid; c) allowing the pressure of the produced hydrocarbon fluid at the wellhead to decline during step a) as a result of a declining hydrocarbon reserve pressure due to production of hydrocarbon fluid therefrom; and d) compensating for the declining pressure of the produced hydrocarbon fluid by introducing or increasing artificial lift of the produced hydrocarbon fluid to ensure that the produced fluid is conveyed to the topside structure. This aspect of the invention may avail of any compatible features set out above in connection with the first aspect of the invention. An embodiment of the invention will now be described by way of example only, and with reference to the accompanying drawing, in which:

Figure 1 is a schematic of an offshore production facility carrying out a method of hydrocarbon production in accordance with an embodiment of the invention.

Figure 1 depicts an offshore production facility 1 situated at an offshore hydrocarbon reserve. The production facility 1 comprises a plurality of production wells 3, each associated with a respective wellhead 5. The wellheads 5 are each connect to a common header 7, which in turn is connected to a two-phase subsea separator 9. The subsea separator 9 has a first outlet connected to a gas riser 11 and a second outlet connected to a subsea pump 13, which itself has an outlet connected to a liquid riser 15. The gas riser 11 and liquid riser 15 extend from the subsea separator 9 and pump 13, respectively, to an offshore production platform 17 that is situated topside and represented by a dashed line in Figure 1.

The production platform 17 comprises two sequential separators 19a, 19b. A pump 25 is connected to a second outlet of the second separator 19b. A conduit links the liquid riser 15 to the inlet of the first sequential separator 19a.

The production platform 17 further comprises five sequential compressors 21a- 21e, with a dehydration unit 23 situated between the fourth 21d and fifth 21e sequential compressors. A conduit links the gas riser 11 with the inlet of the fourth compressor 21 d.

A first outlet of the first separator 19a feeds a conduit that leads to the inlet of the third compressor 21c, whilst a second outlet of the first separator 19b feeds a conduit leading to the inlet of the second separator 19b. A first outlet of the second separator 19b feeds a conduit that leads to the inlet of the first compressor 21a.

In use, fluid is produced at the hydrocarbon production facility 1 from the plurality of production wells 3. The fluid flows to the wellheads 5, and in turn passes to the header 7. From the header 7, the produced hydrocarbon fluid passes into the subsea separator 9.

The subsea separator 9 is a two phase separator, and separates the fluid into a hydrocarbon gas phase and a liquid phase comprising oil phases.

The gas phase is outlet from the subsea separator 9 to the gas riser 11 , where it flows to the production platform 17 and into the inlet of the fourth compressor 21d.

The liquid phase is outlet from the subsea separator 9 where it is passed to the subsea pump 13. The subsea pump 13 pressurises the liquid phase sufficiently such that it can be conveyed to the topside offshore production platform 17 via the liquid riser 15 and into the inlet of the first separator 19a.

On the production platform, a number of sequential separation processes of the liquid phase occur using separators 19a, 19b. Gas is drawn off during these separation processes and is fed into third 21c and first 21a compressors, dependent on the stage at which the gas has been separated. The liquid product, including oil phases, is outlet from the second outlet of the second separator 19b and is transferred to a pump 25 for pressurisation such that it can be conveyed as desired.

Additionally, on the production platform 17, a number of sequential compression processes of the gas phase occur using compressors 21a-21d. Prior to reaching the final, fifth compressor 21e the gas is dehydrated by passing through the dehydration unit 23. The gas is then passed to the final compressor 21 d, and is then conveyed for use elsewhere (e.g. for use as an injection fluid in an injection well).

As fluid is produced from the wells 3, the pressure in the reserve from which the fluid is produced declines. In response to this, the pressure of the fluid emanating from the wellheads 5 is allowed to decline by controlling the opening of choke valves (not shown) associated with the wellheads 5. This in turn results in the decline in pressure of both the gas phase and liquid phase output from the subsea separator 9.

To compensate for the declining pressure of the produced fluid which results from the declining pressure at the wellheads 5 and the reserve, the degree of pumping by the subsea pump 13 is increased. In that way, the decreased pressure liquid phase output from the subsea separator 9 can be provided with sufficient impetus to convey it topside to the offshore platform 17.

In addition to increasing the degree of pumping at subsea pump 13 in response to the declining wellheads 5 pressure, the subsea separator 9 pressure can also be decreased to match the declining pressure of the wellheads 5 and thereby continue to enable separation of the fluid therein.