AU2011373946B2

AU2011373946B2 - Recovery methods for hydrocarbon gas reservoirs

Info

Publication number: AU2011373946B2
Application number: AU2011373946A
Authority: AU
Inventors: Kjersti Haland; Lars Hoier; Halvor Kjorholt; Erik SKJETNET
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2011-07-28
Filing date: 2011-07-28
Publication date: 2017-06-01
Anticipated expiration: 2031-07-28
Also published as: AU2011373946A1; MY167145A; WO2013013721A1; AU2011373946B9

Abstract

A process for the enhanced recovery of hydrocarbon gas from an undepleted or partially depleted reservoir combined with carbon dioxide storage therein, the process comprising the steps of injecting carbon dioxide in a supercritical state into a reservoir containing predominantly hydrocarbon gas for sequestration of the carbon dioxide therein and concurrently producing hydrocarbon gas from the reservoir. The carbon dioxide gas is injected at or close to a lowermost part of the gas reservoir or, if an aquifer is present, at a contact point of the water and gas.

Description

1

RECOVERY METHODS FOR HYDROCARBON GAS RESERVOIRS

The present invention relates to improved method for enhanced hydrocarbon gas recovery from undepleted or partially depleted gas reservoirs, particularly but not exclusively for dry natural gas reservoirs having an aquifer water influx.

Gas reservoirs can be divided into two types according to their main recovery mechanism, namely (i) a water drive reservoir and (ii) a gas expansion drive reservoir. The water drive reservoir has a strong aquifer water influx that helps maintain reservoir pressure. Wells are produced at a constant rate plateau for some years and then produced at a decreasing rate until water breaks through. Gas recovery of water drive reservoirs is typically only 40%-70% of the initial gas in place in the reservoir. Gas expansion drive reservoirs are produced at a constant plateau for some years and then produced at a decreasing rate until the reservoir pressure is so low that the rate of production is no longer economic. Gas recovery of gas expansion drive reservoirs is typically 70% - 90%.

The reasons for the lower recovery of water drive reservoirs is that the hydrocarbon gas is microscopically/capillary trapped by water in an amount up to 50% trapped gas saturation. Additionally, the gas is macroscopically bypassed by water and the remaining unproduced gas has a high pressure/density.

Thus, a large proportion of the gas in a water drive reservoir is retained by capillary trapping. It is desirable to be able to recover this trapped gas as it represents a significant gas reserve. The fraction of pore volume with trapped hydrocarbon gas can be as much as 50%. Clearly, methods are required to enable at least 80-90% of the gas reserves to be recovered.

Analyses have suggested that carbon dioxide can be injected into depleted gas reservoirs to enhance methane recovery (SPE 74367 “C02 Injection for Enhanced Gas Production and Carbon Sequestration”. Curtis M. Oldenburg and Sally M. Benson, 2002). However, this has not been implemented commercially due to the concern about mixing of the carbon dioxide gas with native methane gas that would lead to degradation in the value of the remaining natural gas. The pressure exerted by the injection of the gas may also lead to fracturing of the formation, resulting in leakage of 2 carbon dioxide which is clearly undesirable. Carbon dioxide (C02) gas injection into gas fields is therefore generally avoided.

Geologic sequestration of carbon dioxide has also been widely investigated as a way of mitigating carbon dioxide emissions into the atmosphere, thereby leading to a reduction of green house gas effects (SPE 126122 “C02 Enhanced Oil Recovery and Geologic Storage: An Overview with Technology Assessment Based on Patents and Articles” 2010. Christina M. Quintella et al.,). There have been significant investigations and projects into the storage of C02.The Sleipner Project, operated by Statoil in the North Sea, is a commercial scale project for the storage of C02 in a subterranean aquifer. C02 is stored in supercritical state 250 km off the Norwegian coast. About one million tons of C02 is removed from produced natural gas and subsequently injected underground, annually. C02 injection started in October 1996 and by 2010, more than twelve million tons of C02 had been injected at a rate of approximately 2700 tons per day. The formation into which the C02 is injected is a brine-saturated unconsolidated sandstone about 800-1000 m below the sea floor. A shallow long-reach well is used to take the C02 2.4 km away from the producing wells and platform area. The injection site is placed beneath a local dome of the top Utsira formation. No concurrent removal of brine from the reservoir occurs.

The In Salah CCS Project is an onshore project for the production of natural gas from a gas reservoir located in a subterranean aquifer. The aquifer is located in the Sahara desert. The reservoir is in a carboniferous sandstone formation, 2000 m deep; it is only 20 m thick, and of low permeability. Natural gas containing up to 10% of C02 is produced. C02 is separated, and subsequently re-injected into the water-filled parts of the reservoir. Again, no brine is removed from the aquifer and no enhancement of natural gas recovery is achieved. EP-A-1571105 describes methods for C02 storage, in which C02 is added at into a water stream, which stream is then pumped into a subterranean geological formation. The method uses chemical reactions with a mineral-forming agent (sulfate/base). The agent is added, unless use is made of particular geological structures, in particular those structures that by nature contain these agents in large quantities. This method requires complex and expensive technical equipment. Since no concurrent removal of brine from the reservoir occurs, high local pressure at the site of injection may lead to 3 fractures in the sealing geological formations. This increases the likelihood of C02 escaping from the reservoir into the atmosphere. JP06170215 describes a method of introducing a mixture of water and C02 into a subterranean geological formation. For this purpose, the C02 is mixed with water above the ground, and thereafter the mixture is introduced into the ground, under high pressure. The method requires a supply of liquid C02, a booster pump, a heat exchanger and a pump to obtain the required pressure. This renders the process energy-intensive and expensive. Injection of the C02/water mixture into a reservoir increases the reservoir pressure and may lead to fractures in the sealing formations. This increases the risk of C02 escaping into the atmosphere.

Any discussion of documents, acts, materials, devices, articles or the like which has been included in the present specification is not to be taken as an admission that any or all of these matters form part of the prior art base or were common general knowledge in the field relevant to the present disclosure as it existed before the priority date of each claim of this application.

Throughout this specification the word "comprise", or variations such as "comprises" or "comprising", will be understood to imply the inclusion of a stated element, integer or step, or group of elements, integers or steps, but not the exclusion of any other element, integer or step, or group of elements, integers or steps.

It is an aim of the present invention to provide an enhanced natural gas recovery process for undepleted and partially depleted natural gas reservoirs.

It is a further aim of the present invention to provide an improved natural gas recovery process that enhances gas recovery whilst storing carbon dioxide with no or minimal contamination of the hydrocarbon gas with the carbon dioxide.

Yet a further aim of the present invention is to provide an improved natural gas recovery process that enhances gas recovery whilst storing carbon dioxide where pressure-induced leakage problems of C02are mitigated.

Accordingly, the present invention provides a process for the recovery of hydrocarbon gas from an undepleted or partially depleted reservoir containing hydrocarbon gas, the process comprising the steps of injecting into the reservoir carbon dioxide gas 4 compressed to a density greater than the density of the hydrocarbon gas and concurrently producing hydrocarbon gas from the reservoir through at least one production well, and further comprising managing the injection and production conditions of the carbon dioxide gas and hydrocarbon gas into and out of the reservoir, wherein the ratio of the volume of carbon dioxide gas injected into the reservoir to the total volume of hydrocarbon gas produced from the reservoir is controlled to be from 0.2 to 1.4.

The injected gas is predominantly carbon dioxide but one or more other gases may be mixed with the carbon dioxide. Examples of other gases include exhaust gas, nitrogen and/or H2S. In instances where the reservoir has an aquifer, the carbon dioxide gas or mixture of gases is preferably compressed to a density greater than the density of the hydrocarbon gas but less than the density of water. More preferably still, the density of the carbon dioxide gas is closer to the density of the water than the hydrocarbon gas

In a preferred aspect of the present invention there is provided a process for the combined recovery of hydrocarbon gas from a reservoir with storage of carbon dioxide gas therein, the process comprising the steps of injecting carbon dioxide gas through at least one injection well into a reservoir containing hydrocarbon gas such that the carbon dioxide enters the reservoir in a supercritical state for sequestration of the carbon dioxide therein and concurrently producing hydrocarbon gas from the reservoir through at least one production well, and further comprising managing the injection and production conditions of the carbon dioxide gas and hydrocarbon gas into and out of the reservoir, wherein the ratio of the volume of carbon dioxide gas injected into the reservoir to the total volume of hydrocarbon gas produced from the reservoir is controlled to be from 0.2 to 1.4.

Supercritical carbon dioxide is injected into the reservoir due to its high density but gaslike viscosity.

The C02 gas is injected into the gas reservoir far away from the gas producers. In contrast to published gas recovery methods, C02 injection is carried out in relation to undepleted and partially depleted gas reservoirs and for both gas expansion drive reservoirs and aquifer water influx reservoirs. The invention benefits from two main drainage mechanisms, (i) water drive mechanisms - replacing otherwise capillary trapped hydrocarbon gas by C02 thereby increasing the microscopic displacement 5 efficiency and (ii) water drive and gas expansion drive reservoirs - full or partial pressure maintenance with increased directed macroscopic sweep efficiency.

The process according to the present invention is particularly applicable for use with reservoirs having aquifer water influx. The injection of the supercritical C02 preferably occurs at or near the contact point of the water and gas. The C02 serves to form a phase between the gas and water thereby capillary trapping C02 within the formation instead of hydrocarbon gas for enhanced recovery thereof, theoretically enabling up to 100% recovery of the natural gas contained within the reservoir. In this embodiment, the amount of C02 gas injected into the formation preferably comprises at most 40% of the total gas volume of the formation, more preferably 20-30% of the total gas volume.

Enhanced recovery of hydrocarbon gas by the injection of C02 into any type of natural gas reservoir is achieved by particular process conditions and defined placement of the C02 within the formation. Preferably, the process includes management of the injection and production conditions of the C02 and hydrocarbon gas into and out of the reservoir, optionally including monitoring of the C02 and/or hydrocarbon gas concentration in the injection and/or production wells.

In an alternative preferred embodiment of the present invention, the ratio of volume of C02 gas injected into said reservoir, at the site of injection, to the total volume of hydrocarbon gas produced from the reservoir is controlled. Preferably, said ratio is controlled to be from 0.2 to 1.4, more preferably from 0.6 to 1.2, especially from 0.9 to 1.1, ideally being substantially 1:1. This results in substantially the same volume of carbon dioxide entering the reservoir as gas is removed from the reservoir, resulting in a near 100% voidage replacement under reservoir conditions.

It is normally not necessary that the above ratio be kept constant within the above defined limits, but it is normally sufficient that the average ratio over a certain period of time is within the defined ranges. For example, the average ratio of C02 injection to natural gas production over 1 month, or over 1 year or over the life of the field are within the above mentioned ranges.

The provision of injection and production volumes of the reservoir conditions being kept substantially equal provides a substantially constant average reservoir pressure over time. 6

The concentration of C02 in the produced gas may also be controlled by one or more steps such as shutting in C02 injection that contributes to C02 breakthrough, shutting in a producer that has C02 breakthrough, stopping C02 injection before the end of the field life, drilling a new C02 injector in an underlying aquifer and removing C02from the produced gas.

In a preferred embodiment, the supercritical C02 is injected into the formation through at least one horizontal injection well or conduit. This assists in providing a uniform distribution of C02 injection into the formation which is important for ensuring enhanced gas recovery and stable storage of the carbon dioxide within the formation. The at least one injection well may comprise a conduit having a proximal portion and a distal portion, at least part of said distal portion extending in a substantially horizontal direction with multiple openings being provided in said distal portion of said conduit for injection of C02 into the formation.

However, the invention may also be used for mainly vertical displacement. Thus, the process is suitable for gas recovery from reservoirs with or without aquifer water drive and with mainly horizontal or mainly vertical displacement.

In another preferred embodiment, the amount of C02 injected per unit time, and the amount of hydrocarbon gas produced per unit time, are controlled to a level such that a local pressure in the reservoir, or the average pressure in said reservoir, remains constant.

The injection of C02 is normally injected concurrently with the production of natural gas during the entire gas recovery process. However, in certain embodiments, the start up of the injection of C02 may be delayed relative to the start of the production of hydrocarbon gas.

The process of the present invention is particularly applicable to the recovery of gas from reservoirs containing predominantly hydrocarbon gas, particularly from dry gas reservoirs wherein only raw natural gas is produced from the reservoir without any associated hydrocarbon liquids. 7

In a further embodiment, the process of the present invention may be employed in relation to a reservoir containing hydrocarbon gas and a thin layer of oil that underlays the gas zone. In the context of this disclosure, a “thin” layer means a layer which is significantly less than the depth of the hydrocarbon gas reservoir, preferably being less than 50% of the depth of the hydrocarbon gas reservoir. In such an embodiment, a blanket of carbon dioxide is produced between the oil and the hydrocarbon gas and then oil may be produced in parallel with the production of hydrocarbon gas. At some point, C02 will break through into the oil and will need to be stripped from the oil, such as via vapourization.

It is to be appreciated that the process according to the present invention is likely to be most economic for fields with a C02 content in the reservoir gas as the field will have already invested in C02 resistant materials and in C02 removal facilities. C02 removal facility mitigates the risk of C02 breakthrough and will have spare capacity after production falls off the constant production plateau when the C02 concentration in the reservoir is increasing. It will also result in low C02 capturing and transport costs. Similar benefits may also be obtained if the C02 source is very close to the gas field.

An additional benefit of the C02 based gas recovery method according to the present invention is that the field may store a substantial amount of C02 at low risk of C02 leakage. Since the gas reservoir initially holds a large amount of gas, the reservoir has proven that it can keep gas in the reservoir over geological time of millions of years. The risk of significant gas leakage at a reservoir pressure that is lower than the initial reservoir pressure is minimal. For fields where C02 gas is already present, the net effect of the new method is to produce hydrocarbon gas from the reservoir whilst allowing C02to stay in the reservoir.

The present invention will now be described, by way of example only, with reference to the following Examples in which Example 1 describes a process for the enhanced recovery of hydrocarbon gas from hydrocarbon gas reservoir according to one embodiment of the present invention, Example 2 describes a process for the enhanced recovery of hydrocarbon gas by capillary trapping of carbon dioxide within the reservoir according to another embodiment of the present invention and Example 3 describes the enhanced recovery of gas from a gas-oil reservoir using a process according to a further embodiment of the present invention; and with reference to the accompanying drawings in which: 8

Figure 1 is a schematic diagram of an injection well for use in a process according to the present invention;

Figures 2a to 2c are schematic diagrams illustrating the recovery of hydrocarbon gas using CO2 injection in a reservoir with no aquifer influx;

Figures 3a and 3b are schematic diagrams illustrating the trapping of hydrocarbon gas in a reservoir with aquifer water influx;

Figures 4a to 4c are schematic diagrams illustrating the trapping of carbon dioxide preferentially to hydrocarbon gas in a reservoir with aquifer water influx according to an aspect of the present invention; and

Figures 5 and 6 are schematic diagrams illustrating the recovery of hydrocarbon gas and oil in a gas-oil reservoir using a process according to an embodiment of the present invention.

The present invention relates to methods for storing C02 in geological formations whilst concurrently enhancing recovery of hydrocarbon gas from the formation, particularly but not exclusively from undepleted or partially depleted reservoirs which, optionally, may have a strong aquifer water influx.

The C02 injected is preferably a C02 composition compressed to assume a supercritical state at the site of injection, i.e., at the temperature and pressure of the reservoir. This provides a liquid-like fluid which displaces the natural gas that is in the reservoir. The compressed gas may include C02 and additional gas components, which components preferably amount to less than 50%wt, 40%wt, 30%wt, 20%wt, 10%wt, 5%wt, 2%wt, most preferably to less than 1%wt, based on total compressed gas weight. The term "C02", according to the invention, and depending on the context, may relate to the above described mixtures of C02 and other components. The C02 injected is preferably not mixed with liquids, such as water or an aqueous solution, prior to injection. The C02 thus preferably does not contain liquid components.

The present invention comprises both the injection of a C02 composition into a reservoir, and the production of hydrocarbon gas from the same reservoir. Preferably, C02 is injected into the reservoir concurrently with the production of hydrocarbon gas for the entire production process. In other embodiments, the start of the injection of C02 may be delayed relative to the start up of hydrocarbon gas production. The delay may comprise days, weeks, months, years or even decades after the start up of the 9 hydrocarbon gas production. Once C02 reaches the hydrocarbon gas producers, injection and production is shut down and the wells are sealed in the conventional manner.

Example 1 Enhanced recovery of natural gas by the balanced injection of carbon dioxide gas.

Supercritical carbon dioxide is injected down-flank into a gas reservoir to just above the gas-water contact or, if there is no water in the reservoir, into the lower part of the reservoir. The injection well is placed horizontally within the formation to place the carbon dioxide into the reservoir in an optimal position for hydrocarbon gas displacement by the carbon dioxide, as described in further detail below. The same volume of hydrocarbon gas is produced out up-flank in the gas reservoir. The supercritical carbon dioxide has a liquid-like density and gas-like viscosity resulting in the carbon dioxide density being greater than the hydrocarbon gas density at reservoir conditions, whilst being lower than the water or brine in the reservoir or aquifer.

One or two up-flank gas producers may be provided per injection well, placed symmetrically or asymmetrically around the injection well, depending upon the gas reservoir geology and tilt angle, in the upper part of the reservoir. The area between the down-flank injector and the up-flank producer should be in good pressure communication so that the average reservoir pressure is maintained constant in the gas reservoir during the injection/production period.

Production of natural gas serves to keep the average reservoir pressure at an approximately constant level (over time). In other words, build-up of pressure in the reservoir is effectively avoided. This, in turn, helps to reduce the risk of fractures in the sealing formations above and/or below the aquifer. Thus, it may lead to a safer and more permanent storage of the C02 in the formation via effective displacement of the hydrocarbon gas by the C02.

Ideally, the flow-rate of C02 injected and/or the flow-rate of hydrocarbon gas produced are controlled to maintain the reservoir pressure at a level below the formation fracture pressure, i.e. to prevent any fracturing of the formation 10

In a preferred embodiment, full voidage replacement is performed, i.e., the volume (at the site of injection) of C02 injected is equal to the volume of hydrocarbon gas produced.

It is to be understood that both injection and production can occur through one or through multiple conduits or wells. For example a single injection conduit for C02 can be provided, whereas production of natural gas occurs through multiple conduits or wells, preferably arranged radially displaced from the injection conduit or well. Likewise, injection may occur from multiple conduits or wells, while production of natural gas occurs through only a single conduit or well. There may, however, also be multiple injection conduits or wells and multiple production conduits or wells. In these cases, it is to be understood that the volume and flow-rate of C02 injected, and the volume and flow-rate of gas produced, are the combined volumes and flow-rates through all injection conduits and production conduits, respectively. This means that the sum of C02 volume injected is balanced with the sum of hydrocarbon gas volume produced.

Concurrent injection of C02and production of natural gas also leads to a more efficient sweep of the reservoir with C02, i.e., to a more complete replacement of the initially present hydrocarbon gas with C02. It is estimated that capacity of the geological storage will be significantly greater than with conventional storage techniques, with a corresponding increase in gas recovery due to the miscible displacement of hydrocarbon gas by C02. Methods of the present invention also reduce the so-called "fingering phenomenon", i.e., they minimize the size of by-passed areas in the aquifer. Thus, more efficient use of the reservoir capacity can be made. In certain embodiments of the present invention, the volumetric flow-rate of hydrocarbon gas produced (in m3 per hour) is controlled on the basis of the volumetric flow-rate of C02 injected (in m3 per hour, at the site of injection).

In a preferred embodiment, the volumetric flow-rate of C02 injected into the formation, at the site of injection, is substantially equal to the volumetric flow-rate of hydrocarbon gas produced from the formation. In another preferred embodiment, the average volumetric flow-rate of injection of C02 into the reservoir, at the site of injection, is substantially equal to the average volumetric flow-rate of production of hydrocarbon gas from the reservoir. The average volumetric flow-rate may be calculated over a period of e.g. 1 month, or 1 year or the life of the field. 11

In other preferred embodiments, the ratio of the volumetric flow-rate of injection of C02 injected, at the site of injection, to the volumetric flow-rate of natural gas produced from the formation is controlled to lie within the range from 0.2 to 1.4, more preferably from 0.6 to 1.2, most preferred from 0.9 to 1.1, or 1. In yet another preferred embodiment, the ratio of the average volumetric flow-rate of injection of C02into the formation, at the site of injection (over e.g. 1 day, 1 week or 1 month), to the average volumetric flow-rate of production of hydrocarbon gas from the formation (over, e.g., 1 day, 1 week, or 1 month), is controlled to lie within the range of from 0.6 to 1.4, more preferably from 0.8 to 1.2, most preferred from 0.9 to 1.1, or 1.

It is to be understood that flow rates, volumes, temperatures, pressures and compositions mentioned within the context of this invention, unless otherwise stated, are those at reservoir conditions.

Injection of C02 may be achieved by pumping the C02 down into a conduit or well, preferably through a conduit provided in said well. The C02is injected into the reservoir through an injection port provided in said conduit. The C02 is injected close to, or at, the junction of the aquifer and hydrocarbon gas, or, if no aquifer is present, towards the bottom of the gas reservoir. An injection port, according to the invention may comprise multiple openings. The multiple openings are suitably provided in a distal end portion of the conduit. They may be provided in a horizontal portion, or a slanted portion, or a substantially horizontal portion, of the conduit. A preferred embodiment of the present invention enhances the recovery of hydrocarbon gas and storage of C02 by injecting C02 from multiple injection points along the length of a long-reach horizontal well in such a way that the mass flow of C02 into the formation is approximately constant over the entire length of the horizontal well. While previously, a common wish in the art has been to inject large amounts of C02 in as short a time period as possible, the inventors of the present invention have taken a very different approach. By limiting the radial mass flow of C02 to a certain maximum value, the present invention produces a substantially even distribution of the radial mass flow over major parts of the horizontal extent of the injection well. This leads to a reduced radial mass flow [kg/s] into the formation, but this obstacle is more than outweighed by the fact that the total amount of C02, which can be stored in a particular 12 formation, is dramatically increased, along with a corresponding increase in the recovery of hydrocarbon gas.

Figure 1 shows an arrangement suitable for use in the process according to Example 1 above but the invention is not limited to such an arrangement. Arrangement 1 is used to inject large amounts of C02 into the gas reservoir for permanent storage of C02 therein whilst concurrently causing enhanced recovery of hydrocarbon gas present in the reservoir via a production well (not shown). For injection of the C02, there is provided a conduit 3 which extends from a point above surface down into formation 2 in which the C02 is to be stored. The geological formation can be a depleted or non-depleted gas field or an aquifer. The geological formation is preferably more than 500 m under ground. The geological formation is preferably 5 to 1000 m, preferably 20 to 200 m thick. This assists in ensuring that carbon dioxide does not breakthrough to the surface.

Conduit 3 comprises a proximal end portion 4 and a distal end portion 5. The distal end portion 5 comprises a generally horizontal portion positioned at or near to the junction of the hydrocarbon gas zone and the water zone. The horizontal (distal) portion is preferably provided in form of a long-reach horizontal well, and is preferably between 100 m and 2000 m long. This allows C02 to be injected into the formation at multiple injection points over the entire length of the conduit. C02 storage is thereby distributed over a large area/volume of the reservoir formation.

The arrangement comprises pressure producing means 10, e.g., a pump, for injecting C02 into the geological formation. In other preferred embodiments of the invention, the pressure producing means may be a pressurized C02 container, or a pressurized C02 pipeline. The C02, when injected into the reservoir, is preferably in a supercritical state. Flowever, it is to be appreciated that injection of the C02 into the pump or compressor does not need to be supercritical. Thus, all components of the arrangement must be appropriately designed and constructed such as to be able to sustain the harsh conditions of its operation. Materials must be appropriately chosen to resist the very high pressures and the corrosion, in particular, when the C02 injected is not pure C02, but contains, e.g., water and/or other corrosive contaminants, such as 02 or S02. Pressure producing means preferably are able to produce pressures of more than 73, 100, 200, 500, or 1000 bar in the reservoir. 13

Conduit 3 comprises multiple openings 6a-6z in a distal portion, through which openings C02 is injected into the formation. At least one, but preferably all openings may be provided with outflow limiting means 7a-7z. The outflow limiting means 7a-7z serve to control the radial mass flow of C02 through the individual openings 6a-6z.

Figures 2a to 2c illustrate the recovery of hydrocarbon gas using C02 injection for a reservoir that does not have an aquifer influx. Supercritical carbon dioxide is injected into the reservoir at the initial reservoir pressure (or more or less the initial reservoir pressure) not after reduction of pressure due to gas production over a long period of time. The reservoir pressure may be 321 bar and the temperature around 80SC, although the method is not limited to this pressure and temperature. The injection rate is substantially equal to the gas production rate, full voidage when injecting. As illustrated in Figures 2a to 2c, gas is initially injected towards the bottom of the gas chamber and a mixing zone (C02-FIC gas) forms above the layer of C02 The C02 sweeps the reservoir very well but there is potential for a massive breakthrough of C02 in the end (Figure 2c). This may be overcome by stopping production at an earlier stage to avoid high C02 concentrations, if the amount exceeds the C02 handling capacity.

Example 2 Enhanced Recovery of Natural Gas from a reservoir having an aquifer water influx by capillary trapping of C02in the reservoir.

It has been established that up to 50% of hydrocarbon gas is retained in a reservoir having an aquifer water influx following its production due to the gas being trapped in capillaries that occur above the water level of the aquifer due to vertical aquifer water influx, as schematically illustrated in Figures 3a and 3b of the accompanying drawings. Figure 3a shows a gas reservoir at initial conditions with gas above and water below the gas-water contact. Figure 2b shows the reservoir some time after production. The aquifer has moved upwards as gas is produced from producers at the top of the reservoir. The water sweeps the reservoir, but at the same time traps gas in the water-filled part. This causes the reduction in total amount of gas recovered from the reservoir since a large volume of the initial gas saturation is trapped in the reservoir by the water. The greater the amount of gas contained within a formation, the more trapped gas that is retained by capillary trapping in the produced formation (probably due to capillary pressure hysteresis). This represents a significant gas reserve. 14

An aspect of the present invention injects supercritical C02 into the formation at or slightly above the gas water contact, whilst concurrently producing hydrocarbon gas from the reservoir. Supercritical C02 is heavier than hydrocarbon gas and lighter than water and will naturally stay inbetween the phases, forming a gravity stable C02 layer (Fig. 4a). .Influx of aquifer water from below pushes C02 up. Water and C02 are immiscible so water will capillary trap C02 at the water- C02 contact and push the remaining C02 layer up. Supercritical C02 is miscible with the hydrocarbon gas and will not trap the gas on its way up. The C02 forms a phase between the hydrocarbon gas and the water with the C02 becoming trapped instead of the hydrocarbon gas thereby enabling greater yield (up to 100% of the gas within the formation) of the hydrocarbon gas Thus, the net effect is to capillary trap C02 instead of hydrocarbon gas (Fig. 4b). Additionally, the C02 is trapped within the formation and this capillary trapped sequestration of C02is secure.

The amount of C02 injected into the reservoir should be sufficient to provide a layer of the gas that moves upwardly through the formation without early C02 breakthrough. Preferably, a maximum of 40% of the total gas volume in the formation comprises injected C02, more preferably being 20-30% of the total gas volume. Thus, C02 injection is approximately 0.4 gas production rate.

Eventually, hydrocarbon gas with a small C02 concentration will be trapped close to the top of the reservoir at which point production will be stopped (see Fig. 4c).

It is clear that this process would normally be carried out on non-depleted gas fields with the specific purpose of capillary trapping C02. Previously, C02 has only been used for pressure support of a depleted gas reservoir to force more gas out of the reservoir. In the present invention, the C02is injected in non-depleted reservoirs which do not require pressure support to trap C02 thereby ensuring more efficient recovery of the hydrocarbon gas.

An example of suitable reservoir pressure is 321 bar and reservoir temperature is 80SC, although the process is not limited to these conditions. The process may be carried out for both weak aquifers (reservoir permeability approx. 60mD) and strong aquifers (reservoir permeability above lOOOmD). 15

Reservoir simulations have shown an increased recovery of 14% compared to a model without C02 injection. The C02 concentration in the produced gas reached a maximum of 5.4%, compared to an initial C02 concentration of 0.5%.

The amount and pressure of carbon dioxide injected specifically for capillary trapping in a reservoir having a strong or weak aquifer influx need not be constant or substantially equal to the production of the hydrocarbon gas, albeit in certain situations this may provide the best results. Such conditions would result in prevention of aquifer influx into the reservoir due to the pressure being maintained. The C02 may be injected later in the production cycle. Injection of C02 should be halted prior to its breakthrough beyond the fields removal capacity.

Whilst the example above discusses the injection of C02 into a reservoir from an external source, it is to be appreciated that in many formations, C02 is already present in the natural gas recovered from the reservoir. In such circumstances, the carbon dioxide may be removed, cleaned and then re-injected into the reservoir as described above for combined storage and enhanced production of the hydrocarbon gas.

Around 40% of the world’s remaining gas reserves are too sour or acid (H2S and C02). Worldwide at least 2*1013Sm3 of the remaining gas reserves have C02 content of 10% or more. The present invention may be particularly suitable for production of hydrocarbon gas from such reservoirs. For such field developments, investment will already have been made into C02 removal facilities to make a commercial gas product. As a result, these reservoirs have a built-in risk mitigation for C02 breakthrough so that the process of the present invention has limited additional cost compared with a standard C02 storage in aquifer. If C02 breakthrough takes place late in the field’s life (i.e. when the field is off plateau production), the removal facility will have spare removal capacity that may partly or fully remove the additional C02from the produced gas. Thus, in this situation, the enhanced gas recovery is approximately net profit.

The described invention may also use other injection gases in addition to C02, such as nitrogen, exhaust power plant gas and H2S, although the enhanced gas recovery effect may not be as superior compared with C02. The gases should be compressed to a density between the density of the natural gas and the water, more preferably being closer to the density of the water. 16

Example 3 Enhanced recovery of hydrocarbon gas from a gas-oil reservoir.

The process according to the invention may also be applied to reserves containing hydrocarbon gas 100 with a thin layer of oil 102 underlaying the gas zone with an aquifer 104 beneath the oil, as shown schematically in Figure 5. The oil layer is significantly shallower than the depth of the hydrocarbon gas zone 100. C02 is injected under balanced conditions with the removal of hydrocarbon gas (HcGas) and, once a blanket of C02 108 has been established between the oil zone 102 and the hydrocarbon gas zone 100, oil production OP is commenced from long horizontal wells in parallel to the hydrocarbon gas production, as schematically illustrated in Figure 6 of the accompanying drawings.

Depending upon reservoir pressure, temperature and oil composition, the combined C02 injection and oil production results in a miscible or near miscible displacement (coning). The resulting flow (stimulated coning) of C02 into the oil producers will both displace additional oil and produce additional components stripped out from the oil by C02, mainly by vapourization. It is then necessary to strip out the C02 topside before it is re-injected into the formation. Once the C02 content in the oil producers exceeds economical values, oil production is closed whilst hydrocarbon gas recovery continues.

Regardless of the specific type of gas reservoir, the process according to the present invention enables a better sweep of the storage area by stabilized injection fronts. It reduces fingering phenomenon and minimizes the size of bypassed areas in the gas reservoir for C02 storage. The preferred balanced injection and production conditions results in a relatively constant average reservoir pressure over time, avoiding pressure-induced fracturation of overlaying sealing formations. The ideal use of long horizontal wells for the C02 injectors, placed close to the gas-water contact, strongly favours a gravity-stable miscible gas-gas displacement for the hydrocarbon gas by C02,

The substantially balanced production-injection volumes of the reservoir conditions which are preferably employed for the process secures limited water influx into the reservoir thus minimizing hydrocarbon gas trapped by the water and leading to enhanced gas recovery. 2011373946 30 Mar 2017 17

The above factors enable the capacity of the geological storage of C02 to be several orders of magnitude larger than current estimates in aquifers whilst simultaneously reducing the amount of lost (trapped) hydrocarbon gas retained in the reservoir. Furthermore, the pressure-induced leakage problems are almost completely removed. 2011373946 30 Mar 2017

Claims

CLAIMS:

1. A process for the recovery of hydrocarbon gas from an undepleted or partially depleted reservoir containing hydrocarbon gas, the process comprising the steps of injecting into the reservoir carbon dioxide gas compressed to a density greater than the density of the hydrocarbon gas and concurrently producing hydrocarbon gas from the reservoir through at least one production well, and further comprising managing the injection and production conditions of the carbon dioxide gas and hydrocarbon gas into and out of the reservoir, wherein the ratio of the volume of carbon dioxide gas injected into the reservoir to the total volume of hydrocarbon gas produced from the reservoir is controlled to be from 0.2 to 1.4.
2. A process for the combined recovery of hydrocarbon gas from a reservoir with storage of carbon dioxide therein, the process comprising the steps of injecting carbon dioxide through at least one injection well into a reservoir containing hydrocarbon gas such that the carbon dioxide enters the reservoir in a supercritical state for sequestration of the carbon dioxide therein and concurrently producing hydrocarbon gas from the reservoir through at least one production well, and further comprising managing the injection and production conditions of the carbon dioxide gas and hydrocarbon gas into and out of the reservoir, wherein the ratio of the volume of carbon dioxide gas injected into the reservoir to the total volume of hydrocarbon gas produced from the reservoir is controlled to be from 0.2 to 1.4.
3. A process according to claim 1 or claim 2 wherein the hydrocarbon gas reservoir has an aquifer water influx.
4. A process according to claim 3 wherein the carbon dioxide gas is compressed to a density greater than the density of the hydrocarbon gas but less than the density of water.
5. A process according to claim 4 wherein the density of the carbon dioxide gas is closer to the density of the water than the density of the hydrocarbon gas.
6. A process according to any one of claims 3 to 5 wherein the carbon dioxide gas is injected at or close to a contact point of the water and gas.
7. A process according to any one of claims 3 to 6 wherein capillary trapping of the carbon dioxide gas occurs in the reservoir to prevent capillary trapping of the hydrocarbon gas.
8. A process according to claim 7 wherein the amount of carbon dioxide gas injected into the formation comprises at most 40% of the total gas volume of the formation.
9. A process according to any one of the preceding claims further comprising monitoring the carbon dioxide gas and/or hydrocarbon gas content of the injection and production wells.
10. A process according to any one of the preceding claims wherein the ratio of the volume of carbon dioxide gas injected into the reservoir to the total volume of hydrocarbon gas produced from the reservoir is controlled to be from 0.6 to 1.2.
11. A process according to claim 10 wherein injection and production volumes are kept substantially equal to each other to provide a substantially constant average reservoir pressure over time.
12. A process according to any one of the preceding claims wherein the carbon dioxide gas is injected into the formation through at least one horizontal well.
13. A process according to claim 12 wherein the at least one injection well comprises a conduit having a proximal portion and a distal portion, at least part of the distal portion extending in a substantially horizontal direction with at least one opening being provided in said distal portion for injection of carbon dioxide gas..
14. A process according to any one of claims 2 to 13 for the recovery of hydrocarbon gas from an undepleted or partially depleted hydrocarbon gas reservoir.
15. A process according to any one of the preceding claims for recovery of hydrocarbon gas from a dry gas reservoir.
16. A process according to any one of the preceding claims wherein the gas reservoir includes a thin layer of oil underlaying the hydrocarbon gas.
17. A process according to claim 16 wherein injection of the carbon dioxide gas and production of hydrocarbon gas is commenced to provide a blanket of carbon dioxide gas between the oil and the hydrocarbon gas, following which production of oil is commenced in parallel with the hydrocarbon gas recovery.
18. A process according to any one of the preceding claims wherein the gas reservoir includes C02, and the C02 is removed with the produced gas and reinjected into the reservoir.
19. A process according to claim 18 wherein the gas reservoir also includes H2S.
20. A process according to any one of the preceding claims further comprising mixing another gas with carbon dioxide for injection into the reservoir.
21. A process according to claim 20 wherein said other gas is selected from the group consisting of nitrogen, exhaust gas from a gas power plant and H2S or mixtures or combinations thereof.