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

Abstract

An electrical power plant comprising natural gas production equipment connectable to a production well of a subsurface hydrocarbon reservoir, for extracting natural gas from the reservoir. A power station converts in—situ chemical energy of at least a part of the extracted gas into electrical energy, and outputs electrical power. A gas capture installation captures at least a part of the gasses resulting from the conversion. Injection equipment is connectable to an injection well with a fluid connection to the reservoir, for subsurface injection of at least a part of the supplied captured gasses during at least a part of said extraction. A control unit controls the injection. equipment to maintain reservoir pressure at a desired level during at least a part of the extraction of the natural gas by said subsurface injecting.

Description

Title: POWER PLANT, A GAS FIELD, A METHOD OR EXPLOITATION OR 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 or 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% (full) 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 from 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 or a subsurface hydrocarbon reservoir as described in the accompanying claims.

Specific variants 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 exponent described hereinafter.

Brief description of the drawings

Further details, aspects and terms 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 variant

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 or 0 ° C to 50 ° C. It will be apparent that in some parts of the process stream these gasses may be 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 the dense phase. Likewise, the natural gas may e.g. contain water vapor, 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 including 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 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.

Herehere 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, 000 m2 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 be all 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 natural gas production. 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 be at least partially 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 that 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 staircase, a fault staircase, a staircase on a salt dome flank, a stratigraphic staircase or other suitable type. The gas field may include 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 minimize 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) 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 on 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 or 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 at least 90% (mole) or methane.

The additional gas (ses) may for example be a hydrocarbon gas or other gas or a mixture of hydrocarbon gasses and / or 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 vapor or other vaporized or dispersed liquids. Typically, the heating value is in a range with an upper limit of 50 MJ / normal m3 (ie at 293 K temperature and 100 kPa (ie atmospheric) pressure, such as a limit or 40 MJ / normal m3 and / or a lower limit or 20 MJ / normal m3 such as a limit or 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 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 or injected gas with a higher molar mass than the dominant component or natural gas with the dominant component. For example, CCy has a molar mass or about 44 g / mol whereas CFU (methane) has a molar mass or about 16 g / mol and accordingly mixing or injected CO2 with methane or the natural gas can, at least partially, prevented by injecting the CO2 into the lower region 71.

Other measures may be taken to reduce the degree of mixing or the injected gas with the hydrocarbon gasses in the reservoir. For example, the gas may be injected into 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 provided with equipment which, inhibit or prevent said mixing.

Referring now to the process diagram or 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 or 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 or the unit directly upstream, except for course for the inlet or 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 include 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 or the gas-liquid separator SP1 is connected to the gas outlet 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 or 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 or 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 include 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 driven by combusting. As shown in FIG. 3, the power station 3 may have a line-up or e.g. gas turbine generators GT, heat recovery steam generators HRSG, and steam turbines ST.

In FIG. 3, the TNG is provided for a CMB combustor which mixes the gas with oxygen (or a mixture of gases including oxygen, such as air) provided via a CMP compressor. In parallel with supply from the combustor CMB, oxygen (or a mixture of gases including 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 utilizes residual oxygen in the GT flue gasses to burn a liquid or gaseous fuel. This allows to reduce the oxygen content, and increase the CCh content, or the flue gasses.

In the example of FIG. 3, the stream of hot gasses resulting from the combustion stages passing 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 condensed CND as water to be vaporized in the HRSG.

As shown, the HRSG comprises a superheater SH, EV evaporator 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 contain 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 for the same time to reduce emissions of undesired gas (ses) into the atmosphere (eg 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 or the power station 3, for outputting electrical power generated by the power station 3. The power output 30 is connectable, and shown in Fig. 2 connected, to a power grid 12 via a cable 13, which in a 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 used as the fuel in a gas turbine. Also, the generator 3 may use oxy-combustion and 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 captured by the gas capture installation 4 and the H2O separated from flue gas eg 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 or 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 the STRP reboiler RB, provided with steam via pump P5, the solvent circulates 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 knockout vessel KOV where the 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 or 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 or 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 include 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 the dense phase when leaving CMP but be compressed further, into the dense phase, due to additional pressure exerted eg 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 not leave the CMP in the dense phase and be compressed by this weight in the 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 with the initial reservoir pressure or hydrocarbon reservoirs at a depth of at least 1,000 meters 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 tasks 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 into 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 eg have a isolation which separate 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 or e.g. CO2 alongside the well and e.g. a control which controls the sliding sleeves to close zones where the concentration or 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 a 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 said 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 or 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 with, 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 for example to avoid excessive 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 or 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, or 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 of the natural gas, e.g. at least half past. For instance, the partial pressure of the gasses injected into the reservoir may be controlled to 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 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 consequently associated risks or 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 or 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 or 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 or 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 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 include a noticeable percentage of hydrocarbons with a higher number of C per molecule, such as ethane, which results in a volume or 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 flow rate.

The shown examples may be used to perform a method of exploitation or a subsurface hydrocarbon reservoir 7. Such a method may 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 has been extracted from the reservoir 7. Chemical energy or the extracted natural gas has been converted into-situ into electrical energy, while at least a part of the gasses resulting from the conversion has been 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 or which mixing with the natural gas in the reservoir can be prevented, at least to a certain extent. 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 than in the mixture of gases resulting from the conversion, and e.g. be predominantly CO2. The injected gas can for example contain at least 90% (full) or CO2.

Assuming an ideal combustion process of natural gas with air, a given volume or natural gas turned into a similar volume or 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 gases include, and in an ideal situation (except for traces or other compounds which are negligible for practical purposes), 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 fixed 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 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 be partially compensated

In the foregoing specification, the invention has been described with reference to specific examples 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 or 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 or 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 stored or processed rather than being released into the atmosphere. Likewise, e.g. a parallel branch from the natural gas production equipment may be 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 for inject gasses, and more specific CO2, into a subsurface reservoir. The injection well may 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 have multiple pressure transmitters, such as at different locations in the reservoir, eg 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 may 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, eg 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 narrower portion of the extracted natural gas can be used to generate electrical power, a larger or narrower portion of the resulting gasses can be captured, and a larger or narrower 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 considered in an illustrative rather than in a restrictive sense.

In the claims, any reference signs placed between parentheses shall not be constructed as limiting the claim. The word 'including' does not exclude the presence of other elements or steps than those listed in a claim. Furthermore, the terms "a" or "an," as used read, 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 described of the invention described are, for example, capable of operation in other orientations than those illustrated or otherwise described.

Also, the use of introductory phrases such as "at least one" and "one or more" in the claims should not be constructed to imply that the introduction or 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 more 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 or reservoir 70 upper region or reservoir 71 well head 90

Claims (28)

A power plant comprising: natural gas production equipment connectable to a production well of an underground hydrocarbon reservoir, for extracting natural gas from the reservoir, the natural gas production equipment comprising a natural gas outlet for supplying extracted natural gas; an energy station connected to the natural gas outlet for converting chemical energy of at least a portion of the extracted gas into electrical energy, the energy station comprising a power output for outputting electrical power generated by the energy station; a gas capture installation comprising a capture inlet connected to the energy station for capturing at least a portion of the gases resulting from the conversion and a captured gas outlet for supplying at least a portion of the captured gases; injection equipment connected to the captured gas outlet, and connectable to the reservoir with a fluidized connection, for underground injection of at least a portion of the supplied captured gases during at least a portion of the extraction. A power plant as claimed in claim 1, comprising: a control unit for controlling the injection equipment to maintain the reservoir pressure at a desired level through at least a portion of the extraction of the natural gas by said underground injection. A power plant as set forth in claim 2, wherein the injection equipment is controlled to keep the pressure in the reservoir substantially constant from the start of the injection of the captured gases into the reservoir. A power plant as set forth in claim 2-3, wherein the gas capture installation comprises a ventilation to ventilate at least a portion of the captured gases and the control unit is arranged to open the ventilation when a predetermined criterion is met. A power plant as set forth in claim 4, wherein the control unit is adapted to: control the ventilation to open and ventilate the captured gases for a predetermined period of time from the start of the extraction of the natural gas, and the injection equipment to to initiate injection of the captured gases after said predetermined period of time has expired. A power plant as set forth in claim 5, wherein the control unit is adapted to control the ventilation to soak ventilation after said predetermined period of time has expired. A power plant as laid down in one or more of claims 4-6, wherein the control unit is arranged to control the ventilation to ventilate at least one excess part of the captured gases to prevent the reservoir pressure from exceeding the desired level . A power plant as claimed in any one of the preceding claims, wherein: the energy station is adapted to burn the natural gas, and comprises a channel for releasing flue gases into the atmosphere; the gas capture installation is connected to the channel and comprises a filter for filtering selected gases out of the flue gases passing through the channel. A power plant as claimed in one or more of the preceding claims, wherein the injected gas has a greater volume concentration of CO2 than the gases resulting from the conversion. A power plant as claimed in claim 9, wherein the injected gas comprises at least 90% (vol) CO2. A power plant as claimed in any one of the preceding claims, wherein the partial pressure of the gases injected into the reservoir is substantially equal to the partial pressure of the extracted natural gas. A power plant as claimed in any one of the preceding claims, wherein the injection equipment comprises a supercritical phase pump for injecting at least a portion of the captured gases into the injection well in supercritical phase. A power plant as laid down in one or more of the preceding claims, located offshore, such as on an offshore platform or submarine extraction installation, and wherein the power output is connectable to a subsea cable for transporting electricity to an installation on land. A power plant as laid down in one or more of claims 1-12, located on land. A power plant as set forth in any one of the preceding claims, wherein said injection well comprises an injection well for injecting into an underground storage with fluid communication with the reservoir. A power plant as laid down in one or more of claims 1-14, wherein said injection well comprises an injection well for directly injecting into the reservoir. A gas field comprising: an underground hydrocarbon reservoir containing natural gas; a power plant as set forth in one or more of the preceding claims; a production well to the reservoir which is connected to the natural gas production equipment in the power plant; an injection well with a fluid connection to the reservoir which is connected to the injection equipment of the power plant. A gas field as set forth in claim 17, wherein the natural gas is an unassociated gas. A gas field as claimed in claim 17 or 18, wherein the natural gas comprises at least 90% (mol) methane. A method for evacuating an underground hydrocarbon reservoir, comprising: extracting natural gas from the reservoir; in-situ conversion of chemical energy from the extracted natural gas to electrical energy, while capturing at least part of the gases resulting from the conversion; injecting back at least a portion of the captured gases back into the reservoir or into an underground fluid communication storage facility with the reservoir during at least a portion of said extraction. A method as set forth in claim 20, wherein the partial pressure of the injected gases at least partially compensates for the partial pressure of the recovered gases. A method as claimed in claim 20 or 21, wherein during extraction of the natural gas the pressure remains substantially constant over a period of time during which the captured gases are injected into the reservoir. A method as set forth in any one of claims 20-22, wherein during extraction the pressure in the reservoir remains substantially constant. A method as set forth in one or more of claims 20-23, performed offshore. A method as set forth in one or more of claims 20-24, wherein the injected gas is predominantly CO2. A method as set forth in one or more of claims 20-25, wherein the injected gas is in the supercritical phase. A method as set forth in any one of claims 20-26, wherein injection of captured gases back into the reservoir is started some time after the extraction of natural gas from the reservoir is started. A subsurface hydrocarbon reservoir from which natural gas has been extracted and containing gas injected by a power plant according to one or more of claims 1-16 or with a method as laid down in one or more of claims 20-26.