GB2605778A

GB2605778A - Process

Info

Publication number: GB2605778A
Application number: GB2104944.0A
Authority: GB
Inventors: Johannessen Eivind
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2021-04-07
Filing date: 2021-04-07
Publication date: 2022-10-19
Also published as: GB202104944D0

Abstract

The invention provides a process for treating a liquid oil stream, said process comprising contacting said liquid oil stream with a CO2-lean gas, so as to produce a liquid oil stream with reduced CO2 content and a CO2-rich gas.

Description

Process

Technical field

The present invention relates to a process for treating a liquid oil stream, in particular for reducing the carbon dioxide content of the liquid oil stream. Specifically, the process involves contacting the liquid oil stream with a 002-lean gas stream.

Background of the invention

Oil reservoirs may be 002 rich for a number of reasons. The high levels of 002 may be due to the use of 002 for Enhanced Oil Recovery (EOR) or 002 storage, but it may also result from a naturally CO2 rich reservoir. For example, the use of CO2 for EOR purposes has a potential to increase the oil recovery rate of a reservoir by up to between 5 and 15 percentage points. It is also an effective method to store considerable amounts of CO2 underground, making this process a climate change mitigating measure.

When reservoirs are CO2 rich, there will be 002 breakthrough at some point. This means that the CO2 content in the production well stream increases. High 002 content in the well stream is challenging, especially when the production is routed to an existing production facility which is not prepared for the high CO2 content. Some of the potential challenges include: -High corrosivity of process fluids and lack of sufficient quality of materials in existing process equipment/piping. Replacing (or cladding) existing equipment in the production facility is very costly, and may imply a long modification period with no production.

-Most of the CO2 will end up in the gas phase produced from the gas/liquid separator, which separates the gas phase from a well stream. If the production facility does not have a CO2 handling solution, for instance an amine unit for CO2 removal from the gas, it is likely that the CO2 content in the gas will be too high to export/sell the gas.

One solution to reduce 002 content might be to create a new facility upstream of the existing production facility, which employs a gas/liquid separator operating at reduced pressure to separate the gas phase from a well stream. However, such modifications are not always compatible with existing treatment and production facilities, leading to expensive modifications, Furthermore, it is desirable to carry out the gas-liquid separation at high pressure to limit compression and pumping costs.

The present invention is conceived to solve or at least alleviate the problems identified above. An object of the invention is to provide a process which can be used to reduce the CO2 content in the liquid oil stream in an economical manner. It is also desirable to develop a process which may be utilised in a wide range of applications where it is required to reduce the 002 content of a liquid oil stream.

The present inventors have unexpectedly found that this may be achieved by using a gas stream that has a low CO2 content to strip CO2 from a liquid oil stream. In the context of the treatment of liquid well streams, this CO2-lean gas stream can be used to treat the well stream after the inlet gas-liquid separation at an upstream facility. This enables the use or a high separation pressure and at the same time a low CO2 content in the separated liquids. The purpose of this process is to reduce the 002 content in the feed stream to a level which can be handled by the existing processing facility.

Summary of the Invention

in a first aspect, the invention provides a process for treating a liquid oil stream, said process comprising contacting said liquid oil stream with a 002-lean gas, so as to produce a liquid oil stream with reduced CO2 content and a CO2-rich gas.

in a particularly preferred embodiment, said liquid oil stream is the uid phase of a production well stream from an oil reservoir.

In a second aspect, the invention provides the use of a 002-lean gas in a process for treating a liquid oil stream.

In a further aspect, the present invention provides a purified liquid oil stream obtained or obtainable by any of the processes herein described.

in an additional aspect, the invention provides apparatus arranged to perform the process as herein described, said apparatus comprising a contactor configured to receive a liquid oil stream and 002-lean gas via at least one inlet, so as to produce a liquid oil stream with reduced CO, content arid a 002erich gas, wherein the liquid oil stream with reduced CO2 content exits the contactor via a liquid phase conduit and the CO2-nch gas exits the contactor via a gas phase conduit.

Detailed Description of the Invention

The present invention describes a process for treating a liquid oil stream. The process involves contacting the liquid oil stream with a CO2-lean gas.

The liquid oil stream used in the process of the invention may be any liquid stream comprising oil. It will be understood that, in the context of this invention, by "oil" we mean crude oil. The liquid oil stream may thus comprise the usual components of crude oil, those being hydrocarbons. Typical hydrocarbons which may be present in the liquid oil stream include C6-C10 hydrocarbons and heavy hydrocarbons with more than 11 carbon atoms. The liquid oil stream may also comprise lighter hydrocarbons, such as C3-05 hydrocarbons.

Typically, the liquid oil stream is the liquid phase of a producLi m well stream obtained from an oil reservoir. This liquid phase will be understood to be that which is produced when the well stream is separated using a gas/liquid separator and will generally comprise water (formation water), oil and dissolved 002. Other components may be present, such as salts, acid gases or other gases such as argon and nitrogen.

The content of dissolved CO2 in the liquid phase can vary. Typically, the well stream is choked, generally to a pre-defined pressure, prior to separating the well stream into a liquid phase and a gas phase. This will release a gas from the well stream, which is then separated by the first gas/liquid separator. The pressure to which the well stream is choked determines the partial pressure/content of 002 in the gas-phase, and the content of 002 in the liquid phase. A lower pressure means a lower CO2 content in the liquid. One skilled in the art would readily appreciate how to select a suitable pre-defined pressure dependent on the particular scenario. Moreover, the separation pressure influences the CO2 content. The higher the pressure, the more CO2 there will be in the liquid phase.

In the context of the invention, the term "treating' is intended to cover at least the partial removal of 002 from the liquid oil stream.

By "partial removal" we typically mean that at least 50% of the total amount of 002 is removed, such as at least 70%. Preferably up to 80% of the total amount of CO2 vvili be removed, more preferably up to 85%, even more preferably up to 90%.

The CO2 content of the liquid oil stream, after having been treated using the processes of the invention will ideally be sufficiently low such that it may be transferred to a processing facility without risk of corrosion to pipeline and processing equipment. Typically, this is a CO2 content in the range of less than 30 kg CO2/Sm3 oil.

The processes of the invention employ a CO2-lean gas. It will be understood that by "CO2-lean gas" we mean a gas which contains 002. The term "lean" is intended herein to designate the CO2 content of Gas as being lower than that of the CO2-rich gas stream which is produced following contact of the 002-lean gas with the liquid oil stream.

The actual 002 content of the 002-lean gas will vary depending on the source of the gas and the desired application. The skilled person is able to employ a 002-lean gas with an appropriate 002 content. Typically, the 002 content of the 002-lean gas is in the range Ito 10 mol°,10, such as 2 to 5 ino1%.

The 002-lean gas is typically a hydrocarbon gas, comprising, for example, methane and/or ethane. The gas may also comprise nitrogen, hydrogen sulfide or argon. In a particularly preferred embodiment, the 002-lean gas consists of 002 and hydrocarbons. Typically, the hydrocarbons present in the 002-lean gas include light hydrocarbons such as 01-06 hydrocarbons, especially methane and/or ethane. It is also possible for the 002-lean pas to contain 07-010 hydrocarbons, although these are generally found at much lower levels than the light hydrocarbons.

The source of the 002-lean gas is not limited. It is within the ambit of the invention for the 007-lean gas to be generated from a gas stream at an existing production facility, e.g. from the gas phase produced when the well stream is separated using a gas/liquid separator. In such embodiments, the 002 content of a portion of the gas phase may be adjusted to an appropriate level, if necessary, using, for example, membranes or 002 absorbers, before it is contacted with the liquid oil stream. Such processes may further employ water, seawater or solvents (e.g. amines). Of course, if a 002-lean gas stream is available from the existing production facility which already has an appropriate 002 content, this could be used directly, without further treatment.

Alternatively, an external source of 002-lean gas may be used. It will be appreciated that by "an external source of 002-lean gas" means 002-lean gas not produced from the reservoir, but rather provided from a source external to the production facility.

The processes of the invention involve contacting the liquid oil stream with the 002-lean gas. By "contactina" we mean bringing the liquid oil stream into contact, either directly or indirectly. (e.g. via a membrane contactor) with the 002-lean gas.

Typically, the contacting step is performed such that equilibrium conditions are reached, i.e. the CO2 is in equilibrium between the liquid oil stream and the 002-lean gas. Those skilled in the art will appreciate that the conditions under which the contacting step is performed and the relative amounts of the liquid oil stream and 002-lean gas supplied will be selected such that, under equilibrium conditions, desorption of the 002 into the 002-lean gas will be favoured, i.e. so as to produce a 002-rich gas stream.

Preferably the contacting step occurs at a temperature of 30 to 100 00, more preferably 50 to 90 'C.

It is preferred if the pressure under which the contacting step occurs is at least 15 bar, more preferably at least 20 bar. Typically, the pressure will not exceed 90 bar, preferably 70 bar.

The contacting step may occur in a contactor. By "contactor", we mean an apparatus which facilitates contact between liquid oil stream and the CO2-lean gas, resulting in the at least partial desorption of the 002 into the 002-lean gas. The contactor is typically a desorption column or a membrane contactor. The column may be any suitable column known in the art such as a packed column, a tray column, a falling-film column, a bubble column, a spray tower; a gas-liquid agitated vessel, a plate column, a rotating disc contactor or a Venturi tube.

Contact between the liquid oil stream and the 002-lean gas may also be carried out in a conventional mixer, for example in a co-current mixer, in one embodiment, contact is effected in a co-current mixer or column in which the components (i.e. the liquid oil stream and the 002-lean gas) are both added at the same inlet point (or inlet points which are in close proximity to one another) and removed at the same outlet point. It is preferred that this step is carried out in a single mixing step (i.e. with a single mixer); however, multiple mixing steps may be employed, for example employing a plurality of co--current mixers arranged in series.

Where a plurality of co-current mixers are used, the resulting mixture will usually be separated into separate gas and liquid phases prior to the addition of further CO2-lean gas and further co-current mixing (and separation).

Alternatively, a conventional counter-current contactor may be employed instead of or in addition to the co-current mixer or mixers. Such processes are particularly appropriate in applications where co-current mixing is not sufficient to remove enough of the CO2 gas from the liquid oil stream to reach the desired level for subsequent transfer to existing production facilities.

in some embodiments (e.g. where contacting occurs in a contactor or a mixer), the processes of the invention may further comprise a separation step after the contacting step, to separate the liquid oil stream with reduced CO2 content from the CO2-rich gas. This separation step may be carried out in a separator.

Thus, in one embodiment, the invention may comprise the following steps: (i) contacting a liquid oil stream with a 002-lean gas, so as to produce a liquid oil stream with reduced 002 content and a CO2-rich gas; and (H) separating the liquid oil stream with reduced CO2 content and the CO2-rich gas.

in one embodiment of the invention, steps (i) and (ii) are carried out in a single contactor, such as a counter-current contactor, In such embodiments, the liquid oil stream would typically enter the top of the contactor through one inlet and the 002-lean gas would enter the bottom of the contactor through a second inlet. The liquid oil stream flows in a counter-current direction to the 002-lean gas with separation and mass transfer occurring simultaneously as the liquid and gas phases come into contact with each other. The liquid oil stream with reduced CO2 content exits at the base of the contactor via a first outlet, whilst the 002-rich gas exits at the top of the contactor via a second outlet.

In an alternative embodiment, steps and (ii) are carried out separately. For example, step (i) may take place in a mixer and step (ii) in a separator.

By "reduced CO2 content" we mean that the liquid oil stream exiting the contactor or mixer contains a lower amount of CO2 than the liquid oil stream entering the contactor or mixer. The liquid oil stream with reduced CO2 content will typically contain at least 50% less 002 than the liquid oil stream entering the contactor or mixer, preferably at least 70% less CO2; more preferably at least 80% less CO2, even more preferably at least 85% less 002, such as at least 90% less 002.

The process of the invention may comprise additional processing steps such as cooling or heating, as appropriate. Such steps may be carried out according to conventional methods known to those skilled in the art Other downstream processing steps may also be performed, as desired.

The process of the invention may be carried out on the site of an existing processing facility or at a separate location.

As mentioned previously, following the process of the present invention; the liquid phase (the liquid oil stream with reduced 002 content) may be transported to an oil processing facility. Generally, this will be an existing oil processing facility. Ideally, the CO2 content of the liquid phase will have been reduced to a level low enough to allow for the use of non-corrosion resistant piping to transport the liquid phase, e.g. carbon steel piping.

As discussed above, a preferable embodiment of the invention is wherein the liquid oil stream is the liquid phase of a production well stream from an oil reservoir. In such embodiments, the 002-lean gas employed in the process of the invention may be generated from the gas phase produced when the well stream is separated using a gas/liquid separator, i.e. is produced in situ.

The invention also provides apparatus arranged to perform the processes of the invention. Preferable aspects discussed in the context of the processes of the invention apply equally to the apparatus embodiments.

Thus, in a further embodiment, the invention provides apparatus comprising a contactor configured to receive a liquid oil stream and 002-lean gas via at least one inlet, so as to produce a liquid oil stream with reduced CO2 content and a CO2-rich gas, wherein the liquid oil stream with reduced 002 content exits the contactor via a liquid phase conduit and the 002-rich gas exits the contactor via a gas phase conduit.

As hereinbefore described, the contactor may be a single contactor or it may comprise two or more contactors connected in series. Where two contactors are present and connected in series, the liquid phase conduit in which the liquid oil stream with reduced 002 content exits the first contactor is in fluid communication with at least one second inlet of the second contactor so as to allow the liquid oil stream with reduced 002 content to flow from the first contactor to the second contactor.

The invention also provides the use of a 002-lean gas in a process for treating a liquid oil stream. Preferable aspects for each of the features in this embodiment are as hereinbefore defined.

in a further aspect; the present invention provides a purified liquid oil stream obtained or obtainable by any of the processes herein described. By "purified" in this context we mean a liquid oil stream with reduced CO? content. Typical CO2 contents in the purified liquid oil stream may be in the range of less than 50 kg 002/Sm3 oil, preferably less than 30 kg CO2/Sm2 oil. Preferable aspects for each of the features in this embodiment are as hereinbefore defined.

Description of Figures

Figure 1: Context for the Calculations Figure 2: Base case process solution.

Figure 3: The quantity of CO2 exported from Processing facility B to Processing facility A. The quantity of CO2 is given both as ktonnelyr = 1 million kg / year (a) and as 002 content relative to the oil production (b).

Figure 4: The quantity of internal dilution gas with 1.0 mai% CO2 required to export gas with 2.5 mo19/0 002 from Processing facility A to the transport pipeline.

Figure 5: The quantity of external dilution gas with 2.0 mol% CO2 required to have 2.5 mid% 002 in the transport pipeline.

Figure 6: The simplest version of a process solution with CO2 stripping separation.

The 002 stripping separation is done with a co-current contactor comprising 3 mixer, a separator and the piping in between. Except for the occurrent contactor, the process solution is identical to the base case process solution Figure 7: The effect of stripping gas rate on the quantity of CO2 exported from Processing facility B to Processing facility A and on the required quantity of dilution gas (internal or external). The stripping gas contains 5 mol% CO, and the conditions in the gas-liquid separator on Processing facility B are 901; and 40 bara (a) and 90°C and 15 bara (b).

Figure 8: The effect of separation conditions on the quantity of CO2 exported from Processing facility B to Processing facility A when 1MSm3id of stripping gas containing 5 rnol% CO2 is used. The effect is given as °./0 reduction in the figure (a) and as absolute reduction in figure (b).

Figure 9: The effect of separation conditions on the required quantity of internal (a) and external (b) dilution aas when 1MSrthd of stripping gas containing 5 mol% CO2 is used.

Figure 10: The effect of CO2 concentration in the stripping gas on the reduction of exported CO2.

Figure 11: The effect of the number of stripping stages and the separation conditions on the reduction of exported CO2. The stripping gas is 1MSrn2id containing 5 more° CO,. 2'0

Examples

The following simulation data has been obtained to demonstrate the invention.

Context for the calculations Figure 1 describes one possible context where the invention could be applied. Processing facility A has been producing from several CO2 lean reservoirs/wells for some time. The facility is producing export oil and export aas. Produced water is injected, and there is some additional seawater injection. The oil may be exported in any way (pipeline, ship etc.). The gas is exported to a large pipeline which transports gas, from many processing facilities in the area, to further processing onshore (rich gas) or to the customer (sales gas). Processing facility A imports power from the shore or elsewhere.

The production at Processing facility A is declining, and there is capacity for production of some more oil and gas. There is a CO2 rich well or reservoir nearby with good potential. Nearby in this context could be very close, as for instance a well that has been producing to Processing facility /-k earlier, but has been shut because it has become CO, rich due to CO2 for EOR or 002 storage. It may also be a reservoir which has never produced to Processing facility A before. In that case the distance from Processing facility A is probably significantly longer. The reservoir may be CO2 rich due to 002 for EOR or 009 storage, but it may also be a 002 rich reservoir which has never been produced or manipulated in any way (naturally CO2 rich reservoir) One or both of the following fundamental challenges make 1 difficult or impossible to produce the 002 rich well/reservoir directly to Processing facility A: 1 The metallurgy of the process equipment and piping in Processing facility A was chosen based on the 002 lean nature of the reservoir(s) the facility was designed to produce from. Upgrading the metallurgy in most of the water-wetted parts of the process would be required in order to produce a 002 rich well stream. This would be very costly, especially because a long production stop would be required.

2 There is no amine unit or another technology for removal of 002 from the gas at Processing facility A. And there are not space or weight reserves on the facility to add such processing. Since almost all the 002 follows the gas, a large increase in the 002 content in the well streams will result in a significant increase of CO2 concentration in the export gas This will increase the 002 concentration in the gas in the transport pipeline, which is a mix of gas production from many facilities in the area. There is almost always an upper limit for the 002-concentration in that gas, typically 2-2.5 mol% 002, and, equally common, the 002-concentration in the transport pipeline is already close to that upper limit. A significant increase of CO2 in the export gas from Processing facility A is therefore not feasible.

In order to produce the 002 rich well or reservoir to Processing facility A, CO2 must be removed from the well stream. This means that more processing must be added upstream of Processing facility A. If there are space and weight reserves at Processing facility A this could be a new processing module which is lifted onboard and tied into the existing process. In this example, it is assumed that such reserves are not available. This is very often the case. Furthermore, it is assumed that the 002 rich well/reservoir is not located very close to Processing facility A, thus making it advantageous to move the new processing close to the source in order to minimize pressure drops in production flowlines, and/or to minimize the need for pumping/compression. Thus, it is assumed that the required upstream processing is located at a new facility, Processing facility B. Processing facility B can be a conventional topside installation or an unmanned or low manned topside installation. It may be also be a subsea installation, but that is less likely. The minimum functional requirements of Processing facility B are: 1. Separate gas and the liquids (oil + produced water).

2. inject the gas, which will be 002 rich, in a well for disposallstorage.

3. Export the liquids to Processing facility A. Pumping may be required, depending on the separation pressure.

It is important to understand that Processing facility B is not a stand-alone facilit y. It is doing minimum processing, just "filling the gaps" which are not feasible to do at Processing facility A. Processing facility B does not produce stabilized oil and produced water which meet typical specs. It is doing pre-processing for, and it is highly integrated in the operation of, Processing facility A. Processing facility B receives power and utilifies (for instance chemicals like MEG for hydrate inhibition) from Processing facility A. There are also communication cables which connect the process at Processing facility B to the control system at Processing facility A. Overview of the calculations Simulation data for a base case process solution at Processing facility B is presented in Part 1 below. The base case process fulfils the minimum functional requirements, and is not within the scope of the present invention. Simulation data for optimized process solutions is within the scope of the present invention and is presented in Part 2 below.

The main advantage of the optimized process solutions is that the 002-content in the oil and produced water flowing from Processing facility B to Processing facility A is significantly reduced. The effects are: a The corrosivity of the fluids at Processing facility A will be reduced.

Dilution of 002: 0 Reduced 002-content in the oil and water from Processing facility B may make it feasible to dilute the CO, with COrlean gas produced at Processing facility A (from the CO2-lean wells/reservoirs), and have max 2.5 mol% CO2 in the gas exported from Processing facility A to the transport pipeline. In Parts 1 and 2, it is assumed that the other gas produced at Processing facility A contains 1.0 mol% 002, and the flow rate of such gas required to export gas from Processing facility A with max 2.5 mol% CO2 is presented. It will be shown that the quantity of such dilution gas is significantly reduced. 002-lean gas with 1.0 mol%, available from the other producers at Processing facility A, is called internal dilution gas hereinafter.

a Another scenario is that the 002-lean gas produced at Processing facility A from the CO2-lean vvells/reservoirs (without production from Processing facility B), already contains 2.5 mol% 002. In this case, it is not possible to do "internal dilution" of the additional CO2 coming from Processing facility B. The gas exported from Processing facility A to the transport pipeline will then contain more than 2.5 mol% 002. In this case, one must rely on the other gas in the transport pipeline for dilution of the additional CO2 coming from Processing facility B. In Parts 1 and 2, it is assumed that the gas in the transport pipeline contains 2.0 mol% 002, and the flow rate of such dilution gas required in order for the mix of all gas in the pipeline to contain max 2.5 inol% 002 is presented. It will be shown that the quantity of such dilution gas is significantly reduced. 002-lean gas with 2.0 mol°,10, present in the transport pipeline, is called External dilation gas hereinafter.

Other dilution scenarios, for instance with some internal dilution and some external dilution of the additional 002 corning from Processing facility B may of course be equally likely. For simplicity, only the two limiting 002 dilution scenarios are discussed herein.

Another issue is that CO2 dilution most likely will be less attractive in the future as the focus on reduction of Scope 3 002-emission increases (Scope 3 = CO2 emissions when the hydrocarbons are burned/used). Diluting the 002 into the gas increases the 002 emissions per unit of energy in the gas. In this context, the optimized process solutions will reduce the Scope 3 0O-emissions compared to the base case process solution. This will be discussed in Part 2.

In addition to these main advantages, the present invention may reduce the power requirement of Processing facility B because the gas--liquid separation may be done at a higher pressure; thus reducing pumping and compression. This is discussed in Part 2.

As basis for the calculation, an existing oil field well stream fluid was used Water and CO2 was added to the well stream in order to make it 002 rich with some produced water. The resulting well stream contains 75 mol% CO2 (total when all phases are combined). The oil production is H4000 Sim31d, and the water production is -2500 Sm3Id. The production of 002 rich gas at Processing facility B, which is injected in a disposal/storage reservoir, is 15-16 rilSinsid. This gas contains up to 83 mol% 002. The flow rate of gas and the 002 concentration vary from case to case in Parts 1 and 2.

The size of the oil production at Processing facility B which is used in this example is so large that it may actually support a separate, stand-alone development instead of a development tied in to Processing facility A. For a lower oil production rate at Processing facility B, all flow rates and quantities presented in Parts I and 2 can be scaled down proportionally.

1. Base case process solution

Process description

Figure 2 shows the base case process solution for Process facility B. The well stream is separated into gas and liquids (oil+water) in the gas-liquid separator. In this example, it is assumed that the conditions in this separator will be 15-40 bar and 50-90°C.

The gas is cooled to 30°C in the compressor suction cooler and condensed liquids are separated in the compressor suction scrubber. From the scrubber, the condensed liquids are routed to the oil; and the gas is routed to the compressor. In Figure 2, one compressor stage is shown. In reality, more than one compressor stage may be required. This wiil depend on parameters like the pressure in the gas-liquid separator; the pressure in the disposal/storage well, the composition of the gas, etc. For instance, it is likely that 15 bar in the gas-liquid separator will require one more compressor stage than 40 bar in the gas-liquid separator. One compressor stage consists of a suction cooler, a suction scrubber and the compressor.

The liquid from the gas-liquid separator is transported to Processing facility A. If the pressure in the gas-liquid separator is low (for instance 15 bar) it is very likely that an oil and water export pump is required in order to meet the inlet pressure at Processing facility A. If the pressure in the gas-liquid separator is high (for instance 40 bar), it is much more likely that the pump is not required.

No details of Processing facility A are included in Figure 2. It is likely that the process will be a standard oil and gas process on an offshore installation, comprising the usual building blocks (One or more separation trains, with 2 or more separators in each, Recompressor train(s), Gas treatment, Gas compression train(s), Water treatment etc.). In order to do a detailed analysis of the impact on Processing facility A, the whole process on Processing facility A must be simulated, and an the well streams going to that facility must be defined. This level of detail is far beyond the scope of this example. More importantly, in order to show the most important benefits of the invention, it is sufficient to calculate the quantity of CO2 (as kg/hr, moles/hr. or similar) coming from Processing facility B. Almost all this 002 will end up in the gas exported from Processing facility A. Simulation results The quantity of 002 exported from Processing facility B to Processing facility A is presented in Figure 3. This quantity of 002 will end up in the export gas from Processing facility A, and finally most likely end up as Scope 3 002 emission when the gas is burned. Figure 3 has three curves with different temperatures in the gas-liquid separator on Processing facility B, and the pressure in that separator is the x-variable. Figure 3 shows clearly the advantage of doing the separation at low pressure and high temperature in order to minimize the export of 002. But this reduction in 002 export comes at the cost of increased compression and pumping, and possibly also increased heating, on Processing facility B. Figures 4 and 5 show how much internal dilution gas and external dilution gas, respectively, which will be needed to dilute the exported 002. As in Figure 3, the effect of separation temperature is illustrated with separate lines, and the effect of separation pressure is shown alone the x-axis. It is no surprise that the quantity of dilution gases in Figures 4 and 5 vary in the same way as the exported quantity of CO2 in Figure 3, Low separation pressure and high temperature will minimize the need for dilution gas.

The quantities of dilution gas in Figures 4 and 5 are very large, significantly larger than one may expect to be available. If there is not enough dilution gas available, this base case solution will not be feasible. As discussed above, the basis for the calculations is a very large production rate at Processing facility B. IF this production rate is reduced, the required dilution gas rates will decrease proportionally. In other words, the feasibility of the base case process solution will depend on the size of the production at Processing facility B compared to the production at Processing facility A and/or the size of other production facilities in the area.

2. Process solution with CO2 stripping separation Process description Figure 6 shows the simplest version of a process solution with 002 stripping separation and has the same function as for the base case process solution in Figure 2. The function is described as for Part 1. The size of the equipment items may be different though, and as discussed in Part 1, the number of compressor stages and the need for an oil and water export pump will depend on the separation pressure in the gas-liquid separator.

The equipment items and piping which have been added to enable CO2 stripping separation are one mixer, one separator and the connected piping. This is the simplest of all possible process solutions with CO2 stripping separation. There is one co-current contactor comprising a mixer, a separator, and the piping in between. CO; lean stripping gas is input to the process without any details about where it comes from, This gas stream may come from somewhere else (for instance Processing facility A) or it may be produced internally on Processing facility B. In this work, it is assumed that the CO2 lean gas contains 5 mei% CO2. The effect of the CO2-concentration on the potential of the technology is discussed below. Another optimization is to add more contactor stages, and the effect of this also discussed below.

Simulation results a) The effect of the stripping gas rate Figure 7 shows how much the exported 00; and the required dilution gas rate (internal or external) can be reduced when the stripping gas rate is increased. The base case process, Figure 2, corresponds to no stripping gas (0 MSm3id) in Figure 7. The conditions in the gas-liquid separator on Processing facility B are 9000 and 40 bar (a) and 90°C and 15 bar (b). Figure 7 shows that the 002 export and dilution gas requirement can be reduced by more than 85% in both cases. In Part b), results are shown for a stripping gas rate of 1 MSmald. With this rate, most of the potential reduction has been achieved.

b) The effect of separation pressure and temperature Figure 8 shows the effect of the conditions in the gas-liquid separator on the quantity of 002 exported from Processing facility B to Processing facility A when 1MSm3fd of stripping gas containing 5 mol% 002 is used. The effect on the required internal and external dilution gas rates are essential equal (as shown for two cases in Figure 7).

For a given flow rate of stripping gas, the relative reduction obtained with 002 stripping separation (figure (a) in Figure 8) increases when separation pressure is reduced, and when the separation temperature is increased, But, as for the base case process, decreasing pressure and increasing temperature will increase compression and pumping, and possibly also heating, on Processing facility B. Moreover, the absolute reduction in ktonne/yr obtained with 002 stripping separation (figure (b) in Figure 8) is largest at high pressure and low temperature. Thus, the selection of separation conditions and stripping gas rate is a tradeoff; and it must be decided on a case by case basis.

Figure 9 show the effect of separation conditions on the required quantity of internal (a) and external (b) dilution gas when 1MSm3/d of stripping gas containing 5 mol% CO2 is used. The quantities are significantly reduced compared to the base case process solution (Figure 4 and 5). The rates are in a range of flows which may be realistic both for internal and external dilution gas, or with a combination of internal and external dilution gas. And, as discussed above, the basis for the calculations is a very large production rate at Processing facility B. If this production rate is reduced, the required dilution gas rates will decrease proportionally.

It should be noted that the reduction in exported 002 (figure (b) in Figure 8) results in an equally large reduction of the Scope 3 002 emissions when the gas is burned. The reductions are between 50 and 210 ktonnelyr in Figure 8, and the reduction can be made larger if more stripping gas, possibly with lower 002 content is available. Furthermore, a more complex CO2 stripping separation process with two or more stages would also give an additional reduction of the 002 export.

c) The effect of stripping gas quality Figure 10 shows the effect of the CO, concentration in the stripping gas on the reduction of exported CO2. As expected, the reduction is larger when the CO2 content in the stripping gas decreases. But, if a certain reduction is targeted, for instance 70% reduction, a higher 002 content in the stripping gas can be compensated with a slightly higher stripping gas rate.

d) The effect of more stripping stages Figure 11 shows the effect of the number of stripping stages and the separation conditions on the reduction of exported 002. The effect of more stripping stages is significantly larger than the effect of the separation temperature, and it is comparable to the effect of separation pressure. The effect of increasing from two to three stripping stages (not shown) is significantly smaller than the effect of increasing from one to two stages. Since the complexity of the 002 stripping separation process increases significantly when the number of stripping stages increases, it is likely that one or maximum two stripping stages are preferred. As mentioned earlier, the best solution must be found for the case considered, and the number of stripping stages is one of the parameters to vary and decide.

Claims

CLAIMS: 1 A process eating a liquid oil stream, said process comprising contacting said liquid oil stream with a 002-lean gas, so as to produce a liquid oil stream with reduced 002 content and a CO2-rich gas.
A process as claimed in claim 1, wherein said liquid oil stream is the liquid phase of a production well stream from an oil reservoir.
3. A process as claimed in claim 1 or 2, wherein the 002-lean gas is a hydrocarbon gas
4. A process as claimed in any of claims 1 to 3, wherein said CO2-lean gas comprises 1 to 10 mol% 002, preferably 2 to 5 mark 002.
5. A process as claimed in any of claims 1 to 4, wherein said contacting step occurs at a temperature of 30 to 100 D0, preferably 50 to 90 00.
6. A process as claimed in any of claims 1 to 5; wherein said contacting step occurs at a pressure of at least 15 bar.
7. A process as claimed in any of claims 1 to 6, wherein said liquid oii stream comprises oil; water and 009.
8. A process as claimed in any of claims 1 to 7, wherein said contacting step occurs in a contactor or mixer.
9. A process as claimed in any of claims 1 to 8, further comprising separating the liquid oil stream with reduced 002 content and the 002erich gas
10. Use of a 002-lean gas in a process for treating a liquid oil stream as defined in any of claims 1 to 9.
11. Purified liquid oil obtained or obtainable by a process as claimed in any of claims 1 to 9.
12. Apparatus arranged to perform the process as claimer in any of claims 1 to 9; said apparatus comprising a contactor configured to receive a liquid oil stream and 002-lean gas via at least one inlet, so as to produce a liquid oil stream with reduced 002 content and a CO2-rich gas, wherein the liquid oil stream with reduced 002 content exits the contactor via a liquid phase conduit and the CO2-rich gas exits the contactor via a Gas phase conduit.