NL2019056B1 - Power plant, a gas field, a method of exploitation of a subsurface hydrocarbon reservoir. - Google Patents

Description

Title : POWER PLANT, A GAS FIELD, A METHOD OF EXPLOITATION OF A SUBSURFACE HYDROCARBON RESERVOIR.

Description

Field of the invention

The present invention relates to a power plant, a gas field, and a method of exploitation of a subsurface hydrocarbon reservoir .

Background of the invention

Classical gas-fired power plants produce electrical power from natural gas using a process that includes gas combustion in a gas turbine, production of steam using residual heat from the flue gasses and power generation from both the gas turbine and from a steam turbine. The flue gasses typically contain between 3% and 6% (vol) CO2 and significant amounts of N2 and H2O as well as (traces of) SO, SO2, NO, NO2 and CO.

As illustrated in FIG. 1, the known gas-fired power plants are typically situated onshore and connected to a power grid to supply electrical power, indicated with electrical current I in the drawing. These plants are provided via a gas pipeline or a domestic gas grid with treated natural gas TNG from a remote gas production plant which "produces" natural gas NG, i.e. extracts the natural gas from a subsurface hydrocarbon reservoir .

As shown in FIG. 1, it is known that at the onshore gas-fired power station CO2 resulting from the power generation can be captured and transported to store this in a sub-surface facility. This approach is known as an "end of pipe" concept, as the waste from the power generation process, i.e. CO2, is collected at the end of the process stream of natural gas production, gas transportation and power generation.

Typically, the captured CO2 is injected into empty or largely empty former gas reservoirs but other natural or artificial subsurface locations, such as un-mineable coal beds or deep saline reservoirs, are also used.

Summary of the invention

The present invention provides a power plant, a gas field, and a method of exploitation of a subsurface hydrocarbon reservoir as described in the accompanying claims.

Specific embodiments of the invention are set forth in the dependent claims .

These and other aspects of the invention will be apparent from and elucidated with reference to the embodiments described hereinafter .

Brief description of the drawings

Further details, aspects and embodiments of the invention will be described, by way of example only, with reference to the drawings. In the drawings, like reference numbers are used to identify like or functionally similar elements. Elements in the figures are illustrated for simplicity and clarity and have not necessarily been drawn to scale. FIG. 1 shows a schematic view of a known gas-fired power plant. FIG. 2 shows a schematic view of a first example of a gas field with an embodiment of a power plant 1. FIG. 3 schematically shows a process flow diagram suitable for the example of FIG. 2.

Detailed description of the preferred embodiments

In the following, details will not be explained in any greater extent than that considered necessary for the understanding and appreciation of the underlying concepts of the present invention and in order not to obfuscate or distract from the teachings of the present invention.

In this description, the terms "gas" and "gasses" refer to substances which are in the gas phase and the terms "liquid" and "liquids" to substances which are in the liquid phase under atmospheric pressure and at a temperature in the range of 0°C to 50°C. It will be apparent that in some parts of the process stream these gasses may under higher pressure and/or lower temperatures and be in liquid or dense phase and vice versa liquids may be in as phase. For example, captured gasses may be injected into the injection well in dense phase. Likewise, the natural gas may e.g. contain water vapour, which may be condensed to be separated from the hydrocarbon gasses therein as part of the production of natural gas.

The term natural gas refers to a naturally occurring mixture of gasses comprising at least a hydrocarbon gas and which may contain other gasses and/or vaporized or dispersed liquids. The term subsurface hydrocarbon reservoir refers to a naturally occurring reservoir, which contains in untouched condition at least some natural gas.

The term "fluid connectivity" as used herein refers to production time scale connectivity, i.e. to a capability to pass fluid between two communicating spaces, and hence of pressure, which is noticeable within the production time scale of a subsurface hydrocarbon reservoir.

Hereinafter examples are described where natural gas is produced from a subsurface hydrocarbon reservoir. Gasses resulting from the in-situ generation of electrical power involving the produced natural gas, such as CO2 or other greenhouse gasses, are injected into the same reservoir or into a subsurface storage with a fluid connection to the reservoir, during at least a part of the natural gas production .

Said differently, the power plant combines a natural gas production plant, electrical power station, capture plant and injection plant all into a single facility. The mentioned equipment is located within the perimeter of the power plant, which depending on the specific power plant may be less than 100 m apart, although other distances may be suitable as well. Typically, but not exclusively, the facility may have a footprint of less than 10, 000m2 and one or more levels. For example the length may be 20 m or more and/or 50 m or less. For example the width may be 30 m or more and/or 60 m. The facility may have one, two, three or more levels or decks. For example, in case of an offshore plant, this equipment may all be located on the same offshore platform or subsea production rig.

This allows to reduce the investment required for transport and storage facilities. The power is generated in-situ and the captured gas injected into a subsurface network which comprises the hydrocarbon reservoir from which the natural gas is extracted. Thus, the need to provide for extensive pipelines to transport the natural gas to a power plant, to transport the captured gas to injection facilities and to create a suitable storage is obviated.

Additionally the risk of damage, caused by natural gas production induced seismicity or soil subsidence, can be reduced as well. The captured gas is injected into the hydrocarbon reservoir (or into a subsurface storage with fluid connection to the reservoir) during at least a part of the natural gas production. Accordingly, the pressure in the reservoir can be maintained, at least to a certain extent, and the decline in pressure in the hydrocarbon reservoir, which typically occurs during and induced by the production of natural gas, can at least partially be reduced. Hence, the risk of damage due to e.g. collapse of formations supported by the pressure in the reservoir or other effects resulting in seismicity or subsidence may be reduced.

Referring to FIG. 2, the example of a gas field 8 shown therein comprises a subsurface hydrocarbon reservoir 7 with natural gas. In this example, the reservoir is a naturally occurring reservoir of porous rock which contains the natural gas, covered by one or more layers or strata of non-porous rock which seal off the reservoir and prevent the gas from escaping. The reservoir may be of any suitable type, such as an anticlinal trap, a fault trap, a trap on a salt dome flank, a stratigraphic trap or other suitable type. The gas field may comprise one or more connected reservoirs and/or other subsurface spaces with fluid connectivity to the hydrocarbon reservoir 7, such as aquifers or other geological formations in which fluid can be stored.

An electrical power plant 1 is situated near the reservoir, which allows to minimise or at least reduce the cost of flowlines to the wells connecting it to the reservoir. As explained below in more detail, the power plant uses the natural gas NG from the reservoir 7 to in-situ generate electrical power which is provided to the power grid via a power output 30 of the plant 1.

In FIG. 2, the power plant 1 is located offshore, such as on an offshore platform or subsea production rig 11. This is suitable for e.g. a reservoir (or at least the production well thereof) located underneath the seabed, as in this example. Thereby, the need for expensive offshore to onshore pipelines is obviated and the electrical cable connecting the power output 30 of the power plant 1 to the power grid can be the only offshore to onshore connection.

Alternatively, the power plant 1 can be located onshore, for example when the reservoir is located under land or at least the production well is located on land. In such a case, the power plant 1 allows to avoid, or at least reduce, the risk of damage to infrastructure induced by production of natural gas from subsurface reservoirs, e.g. extending under populated areas .

As further shown in FIG. 2, the gas field 8 comprises a production well 9 to the reservoir 7. Via the production well 9, the natural gas NG can be extracted from the reservoir 7. The natural gas extracted from the reservoir can be an associated or non-associated natural gas. The natural gas can consist of any mixture of methane and additional gas(ses). The natural gas may predominantly comprise methane, and for example comprise at least 90%(mole) of methane.

The additional gas(ses) may for example be a hydrocarbon gas or other gas or a mixture of hydrocarbon gasses and/or of other gas(ses).

The hydrocarbon gasses may be hydrocarbons with a higher molecular weight than methane, such as ethane, propane, butane, isopropane, isobutane, etc. The other gas(ses) may for example be one or more of the group consisting of: COX (CO, CO2) O2, N2,NOx (NO, NO2),SOx (SO,SO2). Additionally, the natural gas may contain (trace quantities of) water vapour or other vaporized or dispersed liquids . Typically, the heating value is in a range with an upper limit of 50 MJ/normal m3 (i.e. at 293 K temperature and 100 kPa (i.e. atmospheric) pressure, such as a limit of 40 MJ/normal m3 and/or a lower limit of 20 MJ/normal m3' such as a limit of 25 MJ/normal m3.

In addition to the production well 9, an injection well 10 can be used to inject fluid, in the examples at least captured gasses, into the network of the reservoir. This injection can be indirect, with the injection well discharging e.g. into a subsurface storage compartment with a fluid connection to the reservoir, such as in or below an aquifer. Alternatively, the injection well 10 can, as shown, terminate in the reservoir 7 itself and inject fluid directly into the reservoir.

The injection well can for example inject into a lower region 71 of the hydrocarbon reservoir 7 below an upper region 70 into which the production well 9 enters and where the natural gas is present. This allows to avoid mixing of injected gasses with a higher molar mass than of the dominant component of natural gas with the dominant component. For example, CCy has a molar mass of about 44 g/mol whereas CFU (methane) has a molar mass of about 16 g/mol and accordingly mixing of injected CO2 with methane of the natural gas can be, at least partially, prevented by injecting the CO2 into the lower region 71.

Other measures may be taken to reduce the degree of mixing of the injected gas with the hydrocarbon gasses in the reservoir. For example, the gas may be injected in the reservoir where the rock exhibits properties (such as but not limited to porosity, permeability, inclination to partly dissolve when immersed in CO2) suitable to inhibit or completely prevent, mixing of the CO2 into the region where the hydrocarbon gasses are present. Also, the gasses may be injected at a pressure and temperature and/or the ambient pressure and temperature in the reservoir, at which the injected gasses are less mobile, such as in the dense phase for CO2. Additionally, the injection wells may be spaced sufficiently remote from production wells to, and be provided with equipment which, inhibit or prevent said mixing.

Referring now to the process diagram of FIG. 3, the power plant 1 comprises: natural gas production equipment 2, power station 3, gas capture installation 4 and injection equipment 5. As explained in more detail below, in the process diagram of FIG. 3, these components are arranged in the listed order, seen in a processing stream direction. Each unit is connected with an inlet to the outlet of the unit directly upstream thereof, except of course for the inlet of the most upstream unit (in Fig. 3 production well 9) and the outlet of the most downstream unit (injection well 10 in Fig. 3) . In FIG. 3, CS indicates coolant supply, CR a coolant return, the letter C with a number, C1,C2 a condenser and the letter P with a number like P1,P2 a pump.

As shown in FIG. 3, the plant 1 comprises natural gas production equipment 2. The production equipment 2 is connectable, and in this example shown connected, to the production well 9 (more specific to well head 90) and in operation extracts natural gas from the reservoir 7. The natural gas may be extracted by a suitable drive mechanism of the reservoir, such as one or more of the group consisting of: expansion, compaction, aquifer drive.

The production equipment 2 comprises a natural gas outlet 20 for supplying extracted natural gas. Depending on the composition of the natural gas in the reservoir, the equipment 2 may comprise a gas treatment unit which processes the natural gas NG to obtain a treated natural gas, TNG, with a predetermined composition e.g. as defined in industry or regulatory standards. In the example of FIG. 3, the equipment 2 comprises for instance a gas-liquid separator SP1 which separates the gasses from liquids in the natural gas. The gas-liquid separator SP1 is connected with a liquid discharge to a liquid-liquid separator SP2 which separates water from other condensates CND and discharges the water separately. The gas outlet of the gas-liquid separator SP1 is connected to the gas outlet 20 via a fuel pre-heater which pre-heats the gasses.

Power station 3 is connected to the natural gas outlet 20 and, in operation, converts in-situ chemical energy of at least a part of the extracted gas received from production equipment 2 into electrical energy by a suitable chemical process. For example, the conversion may be a direct one, and the power station 3 comprises e.g. a line-up of natural gas fuel cells. Alternatively, the conversion may e.g. be an indirect one which converts the chemical energy into electrical energy, via an intermediate conversion, such as mechanical energy and/or heat.

In the example of FIG. 3, the process is a combustion process, i.e. an indirect process. The power station 3 may comprise one or more generators connected to the natural gas outlet 20, such as gas turbines 32 or steam turbines 33, and supplied with the natural gas to be driven by combusting thereof. As shown in FIG. 3, the power station 3 may have a line-up of e.g. gas turbine generators GT, heat recovery steam generators HRSG, and steam turbines ST.

In FIG. 3, the TNG is provided to a combustor CMB which mixes the gas with oxygen (or a mixture of gasses comprising oxygen, such as air) provided via a compressor CMP. In parallel with supply from the combustor CMB, oxygen (or a mixture of gasses comprising oxygen, such as air) is provided by CMP to a gas turbine GT. The GT drives an electrical generator EG.

Flue gasses emitted by the GT are further heated by means of secondary combustion, also referred to as auxiliary firing. The secondary combustion utilises residual oxygen in the GT flue gasses to combust a liquid or gaseous fuel. This allows to reduce the oxygen content, and increase the CCh-content, of the flue gasses.

In the example of FIG. 3, the stream of hot gasses resulting from the combustion stages passes through heat recovery steam generator HRSG which recuperates heat therefrom. The HRSG uses this heat to generate steam which is provided to steam turbine 33 to drive the turbine and thus generate electrical power. The steam turbine comprises in this example a line-up of a high pressure turbine HPT, intermediate pressure turbine IPT and low pressure turbine LPT which cooperate to jointly drive an electrical generator EG. Steam enters the HPT at high pressure and sorts at lower intermediate pressure to enter the IPT where the steam sorts at low pressure, lower than the intermediate pressure, to enter the LPT .

The steam STM from IPT is recuperated and condensed to low pressure condensate CND. As shown, the steam sorting the low pressure turbine passes through first condenser Cl, which is cooled by coolant supplied via pump Pl. The condensate sorting Cl is pumped by pump P2 into the supply of the low pressure condensate CND as water to be vaporized in the HRSG.

As shown, the HRSG comprises a superheater SH, evaporator EV and economiser EC. The SH extracts heat from the flue gas to heat steam coming from the EV to above its saturation temperature and provide the superheated steam to steam turbine 33. The evaporator extracts heat from the flue gas coming from the SH, which is cooler than the gas coming out of the Gas Turbine, to vaporize water into steam. The steam is provided to the superheater. After passing through the EV, the flue gas passes through a pre-heater or economizer EC which uses a part of the remaining heat of the flue gas to pre-heat the water provided to the EV.

As shown in FIG. 3, the power station 3 may comprise a stack 31 for releasing flue gasses into the atmosphere. A gas capture installation 4 may be connected to the stack 31. The installation 4 comprises a filter system 43 for filtering selected gasses out of the flue gasses passing through the stack 31. The selected gasses may be greenhouse gasses, and more specifically C02 (or a mixture of gasses with predominantly C02) to be injected back into the subsurface network of the reservoir 7. This allows at the same time to reduce emission of undesired gas(ses)into the atmosphere (e.g. to reduce global warming) and to reduce the pressure decline in the reservoir during production.

Although not shown in FIG. 3, the EG's may be connected to a power output 30 of the power station 3, for outputting electrical power generated by the power station 3. The power output 30 is connectable, and in fig. 2 shown connected, to a power grid 12 via a cable 13, which in case of an offshore power plant can be a subsea cable for transporting the electricity to an onshore installation, such as a submarine high power cable as used for offshore wind farms. For example, the power plant may output power in a range with a lower limit of 50 MW, such as e.g. 100 MW and/or an upper limit of 500 MW, such as 250 MW. A typical example may have an output power in a range with a lower limit of 120 MW and/or an upper limit of 200 MW, such as an output power of 175 MW.

The power plant 1 further comprises a gas capture installation 4. The installation 4 comprises a capturing inlet 40 connected to the power station 3 for capturing at least a part of the gasses resulting from the conversion, and a captured gas outlet 41 for supplying at least a part of the captured gasses to equipment downstream of the installation 4. The installation 4 may use any capturing technique suitable for the specific generator 3 and type of gasses to be captured.

For example, the captured gasses may be green-house gasses such as CO2 - In such a case, for example a post-combustion capture may be used, e.g. using a solvent to capture CO2 from the flue gas. Likewise, a pre-combustion capture can be used, e.g. in which hydrocarbons in the natural gas are reacted with air or oxygen to produce a fuel mixture that contains CO and H2. This mixture may then be reacted with steam in a shift reactor to produce a mixture of CO2 and H2. The CO2 can then be separated from the H2 and the H2 be used as the fuel in a gas turbine. Also, the generator 3 may use oxy-combustion and the natural gas be combusted with nearly pure oxygen and recycled flue gas or CO2 and water/steam to produce a flue gas, consisting essentially of CO2 and H2O, which is subsequently captured by the gas capture installation 4 and the H2O separated from flue gas e.g. by condensing. Alternatively, membranes can be used to selectively separate particular compounds from the flue gasses.

In the example of FIG. 3, a post-combustion capture mechanism is used and the capture installation captures CO2. The stack 31 is connected via a flue gas cooler to a flash vessel FLSH where liquid compounds, chiefly H20, are separated from the CO2. The flue gas from the stack passes through the FSLH into an absorber ABS where the selected gasses, are absorbed into a suitable solvent, such as for CO2 an aqueous solution of one or more suitable alkylamines, such as Diethanolamine (DEA), Monoethanolamine (MEA), Methyldiethanolamine (MDEA), or Aminoethoxyethanol (Diglycolamine) (DGA) . The treated flue gas TFG sorting the ABS is vented, e.g. into the atmosphere.

The rich solvent R-SLV with the absorbed gas is pumped by pump P4 via heat exchanger HX into stripper vessel STRP where the gas is stripped from the solvent. As shown, at the bottom of STRP reboiler RB, provided with steam via pump P5, circulates the solvent into the STRP and re-boils it. The fraction of the solvent with a low concentration of gas or lean solvent is circulated through cooler C2 by pump P3 into a feed-tank for ABS, to which fresh or make-up solvent SLV can be added to the extent desired.

The gasses stripped from the solvent in STRP pass through condenser C3 into a knock-out vessel KOV where remaining solvent is removed and circulated back into STRP. The gas sorting the KOV is supplied to the captured gas outlet 41.

Injection equipment 5 of the power plant 1 is connected to the captured gas outlet 41 and connectable, and in the example of FIG. 3 shown connected, to the injection well 10. In operation, the injection equipment performs a subsurface injection of at least a part of the supplied captured gasses during at least a part of said extraction.

The injection equipment 5 may inject the gasses in any manner suitable for the specific injection well and reservoir. For instance, the injection equipment may comprise a compressor or pump which pressurizes the gas to be injected to a pressure appropriate for injection into the injection well. In the example of FIG. 5, as shown, compressor CMP compresses the gas and supplies this to the injection well 10.

The CMP may e.g. compress the gas such that the gas is injected into the reservoir in the dense phase, for example by compressing the gas into the dense phase. Alternatively, the gas may not be in dense phase when leaving CMP but be compressed further, into the dense phase, due to additional pressure exerted e.g. by the weight of fluids in the injection well or the ambient pressure and/or temperature at the point of injection .

For example, the height of the injection well represents a significant weight of fluids, pressure at the bottom of the well will be higher than pressure at the wellhead. Therefore, fluids may be leaving the CMP not in dense phase and be compressed by this weight in dense phase at the point of injection into the reservoir. CO2 is generally in the dense phase above 100 bar pressure, a condition that is typically met by the initial reservoir pressure of hydrocarbon reservoirs at a depth of at least 1,000 metres below surface.

In the reservoir the injected gasses can be kept separated from the natural gas, to avoid recirculation of the injected gasses and the associated reduction of efficiency, as far as practicable .

In addition to the measures which can be taken to inhibit or completely prevent mixing described above, the construction of the wells may be beneficial to maintaining the separation. For example, the injection well may inject at a point of injection in the reservoir in a region where the rock has a capturing capacity sufficient to store the injected gasses for more than production time scale and a permeability sufficiently low to maintain a production time scale separation. Additionally, wells may be placed sufficiently apart to maintain a production time scale separation. Furthermore, wells may be used of a type which can selectively inject into different zones and/or produce from different zones of the reservoir. The well can e.g. have a zonal isolation which separates sections of the well individual zones in the reservoir from each other and be provided with sliding doors or sleeves to and selectively inject (or not) and/or produce (or not) from a respective zone.

Additionally, the well may be provided with sensors which measures the concentration of e.g. CO2 alongside the well and e.g. a control which controls the sliding sleeves to close zones where the concentration of e.g. CO2 is in an undesired predetermined range.

This allows to avoid recirculation of the injected gas and the corresponding reduction in the efficiency of the overall operation .

The example of FIG. 3 further comprises a control unit 6, in this example a pressure controller PC. As shown, the control unit 6 is connected to a pressure sensor, also referred to as pressure transmitter, PT, 61 which senses a parameter representing the pressure in the reservoir 7. The control unit 6 controls the injection equipment 5 and/or units upstream thereof to maintain through said subsurface injection the reservoir pressure at a desired level during at least a part of the extraction of the natural gas. The level may be constant in time or be variable (e.g. determined as a function of production time or geological survey data about reservoir integrity during production).

The control unit 6 may directly control the injection equipment, as shown in FIG. 3 with the line to the CMP, and/or indirectly, e.g. by controlling the flow of gas towards the injection equipment. For example, by opening or closing a vent 42 or other valve upstream of the injection equipment a flow of gas may be diverted away from the installation 4 and/or injection equipment 5, and for example be vented into the atmosphere

Thus, when a predetermined criterion is met, at least a part of the captured gas can be diverted by the control unit 6 into a branch of the processing stream and not injected. This allows to e.g. avoid excess pressure in the reservoir 7.

In this example the pressure transmitter 61 measures the downhole pressure in the injection well and the control unit 6 is a pressure controller which compares the measured value with a pre-set target value. If the measured pressure exceeds the target value, control unit 6 controls the CMP to lower the discharge pressure and opens the valve 42 to vent at least a fraction of the captured gas determined to be in excess of what is required to maintain the pressure. Thus, when the measured pressure exceeds the target pressure the control unit can e.g. stop the injection or reduce the injection flow rate and open the valve 42 to divert all, or a part, of the captured gasses .

The control unit 6 can for example control the injection such that the pressure in the reservoir can remain substantially constant during a production time scale interval of the natural gas, e.g. at least half thereof. For instance, the partial pressure of the gasses injected in the reservoir may be controlled to be substantially equal to the partial pressure of the extracted natural gas during this interval.

The control unit 6 can for example control the injection equipment 5 to maintain the pressure in the reservoir 7 substantially constant as of the start of the injection of the captured gasses in the reservoir. Thereby, the support of the reservoir on the surrounding formations is at least partially maintained and accordingly associated risks of seismicity or subsidence can be reduced.

The control unit 6 can for example be arranged to start injection of the captured gasses only after a predetermined period of time has lapsed after starting injection. This allows to create some margin between initial reservoir pressure and operating reservoir pressure to ensure that the initial reservoir pressure will not be exceeded when injection. Thereby the risk of e.g. cracking the cap rock and releasing natural gas to atmosphere is reduced. In such a case, for instance, the target value for the pressure can e.g. be set to a value below, such as 90% of, the initial reservoir pressure.

The control unit 6 may control the vent 42 to stop venting after said predetermined period of time has lapsed. In such a case, after the predetermined period of time all of the captured gas, except for unintended losses, can be injected.

However, the control unit 6 may control the vent 42 to vent at least an excess part of the captured gasses into the atmosphere to avoid the reservoir pressure exceeding the desired level prior or during the injection. For example, in case the volume of CO2 or other captured gas exceeds the volume of produced natural gas, the excess amount may be vented into the atmosphere or stored elsewhere. For example, the natural gas may comprise a noticeable percentage of hydrocarbons with a higher number of C per molecule, such as ethane, which result in a volume of CO2 larger than the volume of the extracted natural gas. Also, the volume may be different due to a difference in compressibility (z-factor) between natural gas and CO2. At high pressures, a different z-factor means a different volumetric flowrate.

The shown examples may be used to perform a method of exploitation of a subsurface hydrocarbon reservoir 7. Such a method can e.g. be performed offshore or onshore, for instance by the examples of power plants shown in FIGs. 2 and 3. In such a method natural gas is extracted from the reservoir 7. Chemical energy of the extracted natural gas is converted in-situ into electrical energy, while at least a part of the gasses resulting from the conversion is captured. At least a part of the captured gasses is injected back into the reservoir .

The injected gas may comprise CO2. This allows to reduce greenhouse gas emissions. In addition, CO2 is a relatively inert gas of which mixing with the natural gas in the reservoir can be prevented, at least to a certain extent. Accordingly, greenhouse gas emissions can be reduced with a limited contamination or dilution of the natural gas in the reservoir.

If the injected gas contains CO2, the volume concentration of CO2 may be higher therein than in the mixture of gasses resulting from the conversion, and e.g. be predominantly CO2. The injected gas can for example contain at least 90 % (vol) of CO2.

Assuming an ideal combustion process of natural gas with air, a given volume of natural gas is turned into a similar volume of CO2: CH4 + 2 O2 + 7.52 N2 -> CO2 + 2 H2O + 7.52 N2 in which reaction scheme the combination (2 O2 + 7.52 N2) represents ambient air, and methane (CH4) is deemed representative of natural gas compositions typically found in North-West Europe.

As follows from the above reaction scheme, the resulting gasses comprise, and in an ideal situation (except for traces of other compounds which for practical purposes are negligible) consist of, CO2, water and N2. Thus, if a sufficiently high percentage of the resulting CO2 is captured and injected, the partial pressure of the injected gasses allows to compensate for the decline in pressure due to the extraction of natural gas .

As explained above in relation to the control unit 6 in the example of FIG. 2, the injection of captured gas may be performed during extraction of the natural gas in a manner that the pressure in the reservoir remains substantially constant over a period of time the captured gasses are injected into the reservoir. If the vast majority of the CO2 is captured and injected into the same reservoir (or another storage with a fluid connection thereto) as the one from which the natural gas is produced, the pressure in the reservoir will remain relatively constant over time. As a result, there is no or at least less residual force driving any soil movements, thus preventing both earth tremors and subsidence at the surface.

Additional gas e.g. extracted from the atmosphere or from other sources, may be mixed with captured gas and injected. This allows to compensate for a decline in pressure which exceeds the partial pressure of the injected captured gas. For instance, the natural gas reservoir may be leaking or a part of the injected gas arriving partly elsewhere, such as in an aquifer below the reservoir. In such a case, the partial pressure of the injected captured gas may be insufficient to compensate for the decline in pressure and by mixing the captured gas with additional gas this insufficiency may at least partially be compensated

In the foregoing specification, the invention has been described with reference to specific examples of embodiments of the invention. It will, however, be evident that various modifications and changes may be made therein without departing from the scope of the appended claims.

For instance, although in the examples only a single production well and a single injection well are shown, the power plant may use several production wells and/or injection wells, e.g. which connect to different locations of the reservoir or the network of the reservoir. For example, additional injection wells discharging in other locations of the reservoir may be provided. This allows to reduce the formation of local pressure spots which may develop around the injection well due to insufficient communication within the reservoir .

In case the power plant comprises more than one injection well, the injection pressure of individual injection wells may be set for each well separately, thus allowing for pressure control for each individual injection.

Furthermore, although in the example the processing stream is an unbranched flow and the units of the plant arranged in series, the processing stream may have branches. For instance, in the example vent 42 serves to vent gasses into the atmosphere, but the vent 42 may e.g. be connected to a secondary storage or other processing and the gasses be stored or processed rather than being released in the atmosphere. Likewise, e.g. a parallel branch from the natural gas production equipment may direct a part of the extracted natural gas to e.g. a chemical processing facility, etc.

Also, the injection well may be any suitable bored, drilled, or driven shaft suitable to inject gasses, and more specific CO2, into a subsurface reservoir. The injection well may for example be a class IV injection well compliant with the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (75 FR 77230, December 10, 2010).

Additionally, although in the example the control unit 6 performs a simple control of the injection, other control schemes are possible as well. For example, more complex controls can be used, such as taking into account the flow rate of the natural gas, variations in the composition of the produced natural gas or otherwise. Likewise other aspects may be controlled as well by the control unit, such as mixing the captured gasses with additional compounds or the separation of the captured gasses from the stream resulting from the energy conversion, or otherwise.

The power plant may e.g. have multiple pressure transmitters, such as at different locations in the reservoir, e.g. in case of multiple injection wells several or all of the injection wells may be provided with their own pressure transmitter (s) which measures the pressure at the location of the respective well. Additionally, an individual injection well may be provided with multiple pressure transmitters located at different positions over the injection well. In such a case, the pressure controller can e.g. aim to keep the (combined average) reservoir pressure at target pressure and/or control based on an individual target pressure for at least some of the pressure transmitters.

Furthermore, the natural gas, the captured gas and/or the injected gas can each be a mixture of gasses, e.g. with a gas that is predominantly present (such as methane for the natural gas, and CO2 captured gas and the injected gas) and other gasses. The mixture may contain vaporized or dispersed liquids. The predominantly present gas may e.g. be at least 90% (vol) or (mol) of the mixture. Depending on the specific implementation a larger or smaller portion of the extracted natural gas can be used to generate electrical power, a larger or smaller portion of the resulting gasses can be captured, and a larger or smaller portion of the captured gasses can be injected. Furthermore, it will be apparent that for those, the larger portion may be up to and including 100%, minus unintentional losses.

However, other modifications, variations and alternatives are also possible. The specifications and drawings are, accordingly, to be regarded in an illustrative rather than in a restrictive sense.

In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. The word 'comprising' does not exclude the presence of other elements or steps than those listed in a claim. Furthermore, the terms "a" or "an," as used herein, are defined as one or more than one .

Moreover, the terms "front", "back", "top", "bottom", "over", "under" and the like in the description and in the claims, if any, are used for descriptive purposes and not necessarily for describing permanent relative positions. It is understood that the terms so used are interchangeable under appropriate circumstances such that the embodiments of the invention described herein are, for example, capable of operation in other orientations than those illustrated or otherwise described herein.

Also, the use of introductory phrases such as "at least one" and "one or more" in the claims should not be construed to imply that the introduction of another claim element by the indefinite articles "a" or "an" limits any particular claim containing such introduced claim element to inventions containing only one such element, even when the same claim includes the introductory phrases "one or more" or "at least one" and indefinite articles such as "a" or "an." The same holds true for the use of definite articles. Unless stated otherwise, terms such as "first" and "second" are used to arbitrarily distinguish between the elements such terms describe. Thus, these terms are not necessarily intended to indicate temporal or other prioritization of such elements. The mere fact that certain measures are recited in mutually different claims does not indicate that a combination of these measures cannot be used to advantage.

List of reference numbers: electrical power plant 1 natural gas production equipment 2 power station 3 gas capture installation 4 injection equipment 5 control unit 6 subsurface hydrocarbon reservoir 7 gas field 8 production well 9 injection well 10 offshore platform or subsea production rig 11 power grid 12 power cable 13 natural gas outlet 20 power output 30 stack 31 gas turbine 32 steam turbine 33 capturing inlet 40 captured gas outlet 41 vent 42 filter 43 pressure transmitter 61 lower region of reservoir 70 upper region of reservoir 71 well head 90

Claims (28)

1. Een energiecentrale, omvattende: met een productieput van een ondergronds koolwaterstofreservoir verbindbare aardgasproductieapparatuur, voor winning van aardgas uit het reservoir, de aardgasproductieapparatuur omvattende een aardgasuitlaat voor het aanleveren van gewonnen aardgas; een met de aardgasuitlaat verbonden energiestation, voor het in-situ in elektrische energie omzetten van chemische energie van ten minste een deel van het gewonnen gas, het energiestation omvattende een vermogensuitvoer voor het uitvoeren van door het energiestation gegenereerd elektrisch vermogen; een gas-afvang installatie omvattende een met het energiestation verbonden afvanginlaat voor het afvangen van ten minste een deel van de uit de omzetting resulterende gassen en een afgevangen gasuitlaat voor het aanleveren van ten minste een deel van de afgevangen gassen; injectieapparatuur welke met de afgevangen gasuitlaat verbonden, en met een injectieput met een fluïdum verbinding met het reservoir verbindbaar, is voor ondergrondse injectie van ten minste een deel van de toegevoerde afgevangen gassen gedurende ten minste een deel van de winning.

2. Een energiecentrale als neergelegd in conclusie 1, omvattende: een regeleenheid voor het aansturen van de injectieapparatuur om door genoemde ondergrondse injectie de reservoirdruk op een gewenst niveau te handhaven gedurende ten minste een deel van de winning van het aardgas.

3. Een energiecentrale als neergelegd in conclusie 2, waarin de injectieapparatuur wordt geregeld om de druk in het reservoir hoofdzakelijk constant te houden vanaf de start van de injectie van de afgevangen gassen in het reservoir.

4. Een energiecentrale als neergelegd in conclusie 2-3, waarin de gas afvang installatie een ventilatie omvat om ten minste een deel van de afgevangen gassen te ventileren en de regeleenheid is ingericht om de ventilatie te openen wanneer aan een vooraf bepaald criterium is voldaan.

5. Een energiecentrale als neergelegd in conclusie 4, waarin de regeleenheid is ingericht om: de ventilatie te aan te sturen om te openen en de afgevangen gassen te ventileren voor een vooraf bepaalde tijdsperiode vanaf start van de winning van het aardgas, en de injectieapparatuur aan te sturen om injectie van de afgevangen gassen te starten nadat genoemde vooraf bepaalde tijdsperiode is afgelopen.

6. Een energiecentrale als neergelegd in conclusie 5, waarin de regeleenheid is ingericht om de ventilatie aan te sturen om ventilatie te soppen nadat genoemde vooraf bepaalde tijdsperiode is afgelopen.

7. Een energiecentrale als neergelegd in één of meer der conclusies 4-6, waarin de regeleenheid is ingericht om de ventilatie aan te sturen om ten minste een overtollig deel van de afgevangen gassen te ventileren om te voorkomen dat de reservoir druk het gewenste niveau overschrijdt.

8. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, waarin: het energiestation is ingericht om het aardgas te verbranden, en een kanaal omvat voor het vrijlaten van rookgassen in de atmosfeer; de gas-afvang installatie is verbonden met het kanaal en een filter omvat voor het uit de door het kanaal gaande rookgassen filteren van geselecteerde gassen.

9. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, waarin het geïnjecteerde gas een grotere volumeconcentratie van CO2 heeft dan de uit de omzetting resulterende gassen.

10. Een energiecentrale als neergelegd in conclusie 9, waarin het geïnjecteerde gas ten minste 90% (vol) CO2 omvat.

11. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, waarin de partiële druk van de in het reservoir geïnjecteerde gassen in hoofdzaak gelijk is aan de partiële druk van het gewonnen aardgas.

12. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, waarin de injectieapparatuur een superkritische fase pomp omvat, voor het in superkritische fase in de injectieput injecteren van ten minste een deel van de afgevangen gassen.

13. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, offshore gelegen, zoals op een offshore platform of onderzeese winningsinstallatie, en waarin de vermogensuitvoer verbindbaar is met een onderzeese kabel voor het transporten van elektriciteit naar een installatie op land.

14. Een energiecentrale als neergelegd in één of meer der conclusies 1-12, op land gelegen.

15. Een energiecentrale als neergelegd in één of meer der voorgaande conclusies, waarin genoemde injectieput een injectieput omvat voor het injecteren in een ondergrondse opslag met fluïdum verbinding met het reservoir.

16. Een energiecentrale als neergelegd in één of meer der conclusies 1-14, waarin genoemde injectieput een injectieput voor het direct injecteren in het reservoir omvat.

17. Een gasveld, omvattende: een ondergronds koolwaterstof reservoir welke aardgas bevat; een elektriciteitscentrale zoals neergelegd in één of meer van de voorafgaande conclusies; een productieput naar het reservoir welke is verbonden met de aardgasproductieapparatuur in de elektriciteitscentrale; een injectieput met een fluïdum verbinding naar het reservoir welke is verbonden met de injectieapparatuur van de elektriciteitscentrale.

18. Een gasveld als neergelegd in conclusie 17, waarin het aardgas een niet-geassocieerd gas is.

19. Een gasveld als neergelegd in conclusie 17 of 18, waarin het aardgas ten minste 90% (mol) methaan omvat.

20. Een werkwijze voor het ontgingen van een ondergronds koolwaterstof reservoir, omvattende: winnen van aardgas uit het reservoir; in-situ omzetten van chemische energie van het gewonnen aardgas in elektrische energie, onderwijl ten minste een deel van de van de omzetting resulterende gassen afvangend; terug in het reservoir of in een ondergrondse opslag met fluïdum verbinding met het reservoir injecteren van ten minste een deel van de afgevangen gassen gedurende ten minste een deel van genoemde winning.

21. Een werkwijze als neergelegd in conclusie 20, waarin de partiële druk van de geïnjecteerde gassen ten minste deels compenseert voor de partiële druk van de gewonnen gassen.

22. Een werkwijze als neergelegd in conclusie 20 of 21, waarin gedurende winning van het aardgas de druk in hoofdzaak constant blijft over een tijdsperiode waarin de afgevangen gassen in het reservoir geïnjecteerd worden.

23. Een werkwijze als neergelegd in één of meer van conclusies 20-22, waarin gedurende winning de druk in het reservoir in hoofdzaak constant blijft.

24. Een werkwijze als neergelegd in één of meer van conclusies 20-23, offshore uitgevoerd.

25. Een werkwijze als neergelegd in één of meer van conclusies 20-24, waarin het geïnjecteerde gas overwegende CO2 is.

26. Een werkwijze als neergelegd in één of meer van conclusies 20-25, waarin het geïnjecteerde gas in de superkritische fase is.

27. Een werkwijze als neergelegd in één of meer van conclusies 20-26, waarin terug in het reservoir injecteren van afgevangen gassen wordt gestart enige tijd nadat het winnen van aardgas uit het reservoir gestart is.

28. Een ondergrond koolwaterstofreservoir waaruit aardgas is gewonnen en bevattende gas geïnjecteerd door een elektriciteitscentrale volgens één of meer van conclusies 1-16 of met een werkwijze als neergelegd in één of meer van conclusies 20-26.