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    • 专利摘要:
    A water-alternating gas (WAG) apparatus and associated method of operation, the apparatus being located or locatable in a wellbore that extends from a surface to a subsurface location, the apparatus comprising at least one first channel configured to convey a liquid downhole from the surface; at least one second channel configured to convey a gas downhole from the surface; and wherein the apparatus comprises one or more downhole valve systems for switching the downhole apparatus between alternatingly providing the liquid at the downhole location and gas at the downhole location.
    公开号:DK201671046A1
    申请号:DKP201671046
    申请日:2016-12-23
    公开日:2017-02-27
    发明作者:Soren Mylius Davidsen；John Michael Howell
    申请人:Maersk Olie & Gas；
    IPC主号:
    专利说明:

    ΕΜΗΜάΕΟ RECOVERY METHOD AN D APPARATUS'
    FIELD
    The present invention relates to an apparatus and method for enhanced oil recovery, and specifically relates to a water-alternating gas recovery process and apparatus,
    BACKGROUND
    Various methods are ayaiiable for Improving pi! recovery from reservoirs. One such method" is the water-ai temating~gas (WAG) technique. In the WAG technique, an injection well is drilled into a reservoir in proximity to one or more production welis. Water and gas are then sequentially irfeeted info the injection weii in an alternating manner in order to enhance oil recovery at the nearby production weit(:s). this technique has been used in order to improve the sweep efficiency o! the reservoir.
    Enhanced oil recovery using water aiternating gas injection can increase both, production rates and ultimate recovery from a field. However, traditional WAG techniques present challenges relating to health and safety, operations and DAPEX/OPEX,
    Traditional WAG switch-overs give rise to a safety challenge in that It must be ensured that high pressure gas cannot enter the water injection system. For onshore WAG operations, this problem is overcome by having a WAG skid’ wliere:: one injection system Is physically disconnected, for; example, by removing pipe spools or by mseiflhg blinds arid having a double block and bleed system:. For offshore operations, spools and extensive manual work are often used when executing:: a WAG cycle, These operations are time consuming,: hazardous and expensive,: butrehs:uhS:"th.^t;th^kwafer; and gas injection systems are always physically separated;. For future: developments,: WAG operations could be considered in the design of surface equipment; For example, by providing a fail-safe switch over system that can be operated remotely on an unmanned platform. However, this will add significant expense and complexity to the design.
    An additional issue with traditional WAG switchover techniques, is that pressures at surface are higher when switching from a gas cycle to a water cycle, than vice-versa . This is due to the weight of the hydrostatic column being less on the gas cycle. This means that the pressure at surface at the end of a gas cycle is higher: than, the supply pressure from conventional water Injection systems. This problem is solved In traditional onshore: and: Offshore WAG techniques· by using a ‘kilt pump' to pump: inhibited Water Into the well si high pressures. In order to create a column of water and lower the ipressu reet surface to a level where the regular water injection system can be used., This: is: a manual Operation that requires rig: up of equipment,: several; hours of pumping time and: high pressure operations.
    Hydrate formation at surface is a risk during traditional WAG switchovers due 10 the lower pressure and temperature present at surface, the mixing of hydrocarbon gas and water and temperature reductions due to the Joule™ Thomson effect during surface equipment bleed downs,
    SUMMARY
    An aspect or embodiment relates a downhole water-alternating-gas fW&øj switchover apparatus located: or locatable in a wellbore that extends from a surface to a subsurface location.
    The apparatus may comprise: at least one first channel configured to convey a liquid downhole tom the surface; and at least one second channel configured to convey a gas downhole tom the surface;
    The apparatus may comprise one or more downhole valve or switching systems. The one or more downhole valve or switching systems may be configured to switch the dowohoie apparatus between alternately providing the liquid dcevnhoie and the gas downhole; The one or more downhole valve or switching systems may be configured to selectively provide the isquid or the gas downhole tom the respective first and second channels,
    The apparatus may compose an injection apparatus, which may be configured to aiiernafingiy inject the liquid and/or gas downhole. The -apparatus may comprise water-alternating-gas injection apparatus. The gas may he or comprise natural gas. The liquid may he or comprise water, e.g, the: liquid may be or compriseian aqueous solution.
    The ope or more downhole valve systems may comprise one or more first valves or devices (or reguiating flow of the liquid to the downhole location and/or one or more second valves or devices for regulating flow of the gas to the downhole location,
    The: downhole apparatus; may be swifchable between at least first and second configurations:, wherein, in the first configuration,, the first valves or devices may be closed and the second valves or devices may be open such that gas may be injected or injectable to the downhole location via the at least one second channel and the at least one second valve or device and, in a second configuration, the first valves or devices may be open and the second valves or devices may be closed such that the liquid may be injected or injectable to the down hole location via the at least one first channel and the at least one first valves or devices.
    It will be appreciated that a! least some of tie components for switchover between liquid and gas injection may be located downhole. For example, the one or more downhole valve or switching systems (e.g. the first and/or second valves or devices) may be located or Idcaiable downhole, id use, e.g. In a subsurface fixation, such as in thewellbore.
    The apparatus may comprise a tubular or other hollow conduit. The tubular or other conduit may define or comprise the first channel therewithin. The first channel may extend longitudinally Within the tubular or other conduit,
    The apparatus may oomphse one or more hollow: casings, such as tubular casings, at least one or each of:which may define a passage. The tubular or other conduit may be located or comprised within the one or more casings, e.g. within the passage(s) of the one or more casings. The apparatus may comprise a plurality of casings. At least one of the casings may be provided within at feast one of the other casings. The second channei may be at least partially defined between at least one of the casings and the at least one ether casing or the tubular or ether conduit The second flow channel may extend longitudinally aiong and/or between the casing and/or tubular or other conduit.
    The second channel may be composed or located In or at feast partially defined by one or more annuli, which may be provided or at least partially defined between the tubular or other conduit and an inner wall of one of the casings and/or between two casings. The one or more annuli may be provided radially outwardly of the tubular or other conduit
    The second channel may be closed at one end, e,g. a downhole end, for example using one or more packers of other sealing devices or means.
    The flrst channel may comprise an inner or innermost channel. The second channel may be provided radially outwardly of the first channel. The second channel may comprise or be comprised or located in the first annulus out from the innermost channel. The second channel may comprise and/or be comprised in one or more side pocket mandrels (SPIVIs) and may include a hanger device for the innermost channel through which the second channeifluid may flow.
    The at least one second valve or device may comprise a gas injection device such as a gas lift valve. The at least one second valve or device may be operable to control communication from the second channel to the first channel. The at least one second valve or device may be provided on or in the wall pf the tubular or other conduit The at least one second valve may be configured to selectively allow passage of gas ffom the second channel to the first channel or downhpie: location.: The at least one second valve or device may be swilchafcie between a closed configuration in which flow of gas to the: downhole location: and/or first channel Is blocked and ah open and/or partially open configuration in which the gas may pass from the second channel to the downhole location and/or first channel via the at least one second valve or device.
    The at least one second valve or device may be provided or providabie downhole. downstream and/or lower than the at least one first vaive or device.
    The at: least: one first valve or device may comprise a sub-surface safety valve. The at least one first valve: or device may be configured to selectively open and/or close the first channel. The at feast one first valve or device: may be 'configured to he selectively switchable between an open configuration in which the liquid may pass through th© at least one; first valve to the downhole location and a closed configuration in which flow of liquid through the at least one first valve to the downhoie location is blocked. The at least One first valve or device may be provided uphoie or upstream of or higher than the at feast one second valve.
    The apparatus may be adapted to retain a head of liquid in the first channel uphofe or upstream of the at least one first valve when the first valve is closed, &§. during a gas injection operaSon, for exampie, when the second: valve is open.
    The apparatus may comprise or he connectable to a liquid injection system, The liquid Injection system may be connected or connectable to the first channel, e,g. via a liquid control valve. The liquid injection system may be located or ioeatahie on the surfaco. The at least one first channel may be configured to convey the liquid from the surface to the downhole location.
    The apparatus, may comprise or be connectable to a gas injection system. The gas injection system may be connected or connectable to the second channel, e.g. via a gas control valve. The gas injection system may be located w ioeatabie on the surface. The at least one second channel may be configured to convey gas downhoie from above surface or ground.
    The apparatus may be switchable between configurations in Which the gas and liquid are aiternately injected, The apparatus may be switchable into a liquid injection configuration by opening the liquid control vaive and/or the first valve and closing the gas control vaive and/or the second vaive. The apparatus may be switchable in to a gas Injection configuration by opening the gas control valve and/or the second vaive and closing the liquid contra! valve and/or the first valve
    The apparatus may be configured to provide gas at flow rates of greater than 5 MMscffø preferably greater than: :8: MMscf/d, for example greater than 10 hlPscfd. The apparatus may be configured to provide gas: at flow rates of between 6 and 80; MMscf/d. The apparatus may be configured to provide gas at flow rates Of greater than 12, e.g. greater than 15 MMscf/d
    An aspect or embodiment relates to a method for performing a downhole WA# switchover operation in a wellbore that extends from a surface, the method comprising; conveying a liquid downhole from the surface in a first channel; and conveying a gas downhoie from the surface in a second channel.
    The method may comprise operating one or more downheip valve systems so as to switch the downhole apparatus between aiternafeiy providing the liquid downhofe: and the gas downhole.
    The method may comprise operating the one or more downhole valve systems to selectively provide the liquid or the gas to a downhoie location from the respective first and second channels.
    The method may be or comprise an injection method:, e,g, a method tor aitemalihgly Injecting a gas downhole and a fluid downhole, such as a waterraiterhatihg-gas injection method:. The gas may be or comprise:natural gas. The liquid may be or comprise water, e.g. an aqueous solution.
    The method may comprise using an apparatus as described above in relation to the first aspect. The method may be for operating the apparatus of the first aspect to perform a downhole WAG switchover.
    The method may comprise performing a downhole gas injection to liquid injection switchover. The gas injection to liquid injection switchover may comprise using or closing a gas controi valve and/or using or closing a second vaive. The gas injection to liquid injection switchover may comprise using or opening a liquid controi vaive. The gas injection to liquid injection switchover may comprise using or opening a first valve, which may he performed after the liquid controi vaive has been opened or operated. The gas injection to liquid injection switchover may comprise releasing a head of liquid retained upstream by the first vaive, e.g. by using or opening the first valve.
    The method may comprise performing a downhoie liquid injection to gas injection switchover. The liquid injection to gas Injection switchover may comprise closing the liquid control vaive and/or the first vaive. The liquid injection to gas injection switchover may comprise retaining a head of liquid upstream of the first valve. The liquid injection to gas injection switchover may comprise opening the gas control valve and/or the second valve. The liquid; injection to gas injection switchover may; comprise rarhping Up Or gradually Increasing: pressure of gas, e,g. by gradually opening the gas control valve.
    The method may comprise providing gas at fidw rates of greater than 5 iWvlscf/d, preferably greater than 8 MMscf/d, for example greater than 10 fdMsd/d, such; as between S and 30 MMscf/d, it should be understood that the features defined above in accordance with any aspect of the present invention or below in relation to any specific embodiment of the invention may he utilised^ either alone or in Combination with any other defined feature, in any other aspect or embodiment of the Invention. Furthermore, the present invention is intended to cover apparatus configured to perform any feature described herein in relation to a method and/or a method of using or producing or manufacturing any apparatus feature described herein.
    BRIEF DESCRIPTION OF THE DRAWINGS
    These and other aspects wllt:.fKiW':fee:dest^ib!ed,,liy'way of example only, with reference to the accompanying drawings, in which:
    Figure 1 is a cross-sectional representatibh of aiwelibore System;::
    Figure £ is a, flowchart iSiustrating a method of operating the wellbore system of Figure 1:
    Figure 3 is a cross-sectional representation of the wellbore system of Figure 1 in use;during a water injection: cycle:
    Figure 4 is a cross-sectional representation of the wellbore system of Figure: 1 in use at the and of a water injection cycle;
    Figure 5 is a : cross-sectional representation of the weiioore system of Figure 1 in use during Initiation of gas injection;
    Figure 8 is a cross-sectionei representation of the wellbore system of Figure 1' In use during gas injection;
    Figure 7 Is a eress-seoiional representation of the wellbore system of Figure i in use wherein gas injection has been stopped, the gas Injection system Isolated and the water injection system is also stiii isoiated;
    Figure 8 is a cross-sectional representation of theyirellbøre. :-0f Figure 1 in use during initiation of water injection:;
    Figure s is a cress-sectional representation of the wellbore system of Figure 1 In use with water injection resumed; and
    Figure 10 s: a schematic showing a comparison of the components of the wellbore system of Figure 1 against a conventional WAG wellbore1 system,
    DETAILED DESØRIPTIQN OF THE DRAWINGS
    Figure 1 shows a wellbore system 5 for use in a water-aitemafing-gas enhanced oil recovery' procedure, Hie wellbore system 5 of Figure 1 is advantageously arranged such that switchover of die wellbore system 5 between a gas injection configuration and a water injection configuration is carried out downhole, it will be readily appreciated that use of downhole or downstream herein refers to subsurface positions In a wellbore 10 that are away or further away from the surface and the use of upbole or upstream herein refers to positions that are towards to further toward the surface.
    The weSibore system; 5 extends within the wellbore 10, tom the surface 15 to a subsurface completion locatipn JO, The wellbore system: 5 comprises a hollow metallic or composite casing 25 deflmng a longitudihally extending passage 30 therein. The wellbore system;δ also comprises a hollow conduit in the form of a tubular 35 at least part of which is located within the passage 30 of the casino 25. A longitudinally; extending first flow path or passage 40 is defined within: the tubular 35, An annular space is at least partially defined between the casing 25 and the tubular 35, the annular space forming or comprising a second flow path or passage 50,
    The tubular 35 is supported using a high injection rate tubing hanger 55, The hanger 55 is configured to pass high gas rates, e.g. BIVIMsof/d or higher. As such, the hanger 55 is provided with holes having a sufficient area to make the hanger suitable for high injection rate use. Packers 60 or other seating arrangements known in the art seal between the tubular 35 and the casing 25 in order to close off a downhole end of the second flow path SØ, fer example at between 2500 and 650øftTVDRT (true vertical depth røtaryriabtej·» "which is equivalent to approximately between 1000 mTVDRT and 2000 mTVDRT, However, it will tee appreciated- tftst other pecker depths could be used.
    The tubular 35 is provided with a subsurface val ve system 65 at a d owe hole location for selectively opening and closing the first flow path 40 that runs within the tubuier 35. A subsurface safety valve (SSSV) can be conveniently used for this purpose, it wiii be appreciated that the subsurface vaive system 65 is operabie remotely, e*g, from the surface 15, in order to seleotiyeiy open and close the subsurface valve system 65 and thereby the first flow path 40, for example, using hydraulic, electrical, mechanical or other means teat would be apparent to a skilled person.
    Gas Injection devices 75, such as a high rate gas Sift vaive(s) installed into side pocket mandrels (SPys), are provided in the wail of the tubular 35 such that the gas injection device 75 extends between the first and second flow pates 40, 50. in this way, pressurised gas supplied via the second flow path 50 in the annulus can be selectively and controilably injected into the first flow path 40 within the tubular 35 using the gas injection device; 75. The gas injection device 75 is provided downhole of and/or lower than tee subsurface valve system 66 (e.g. the SSSV), it. will be appreciated that the gas injection device 75 is remotely controllable and/or comprises one or mere cheek valves to permit iow of gas from the second flow path 50 into the first flow path 40 of the tubular 35downstream of the subsurface valve system 65 during gas injection tout prevent fluid #om the fltet flow path 40 of the tubular 35 from flowing into the annular space during the liquid Injection cycle. For example, the gas infection device may be controiiable using hydraulic, electrical, mechanical, pressure or oilier means that would be apparent to a skilled person.
    At thO: surface 15, a water injection system 80: is connected to the tubular 35 via a water control vaive- system 86 for selectively injecting water into the first flow path 40, The water control valve system: 65 is arranged to'selectively isolate: the water injection, system 80 from the first flow path 40. A gas injection system 90 is connected to the annular space via a gas control valve system 95, for selectively injecting gas into the second flow path 60. The gas control valve system 95 is arrsn ged to selectively: isolate the-gas:injection: system 90 from the second How path §0.
    In this wsyj: in contrast to a traditional VVÅG arrangement: in which the water injection system and the gas Injection system are alternately connected to a single: flow path at the surface,, the water injection system 80' of the wellbore system 5 of figure 1 is connected to the first flow path: 40 at the: surface whilst the gas injection system 90 is connected to a different (Le. the: second) flow path 50. Instead of performing switchover between water and geS: injection at the surface (generally by physically disconnecting one injection system and' physically connecting: the required Injection system): both water and: gas are iprovided; down hole using different flow paths 40, 50 and switching; between water add gas; injection is performed downhole by selectively controlling the gas injection device 75 and the subsurface valve system 85.
    The process of performing; downhole switchover of the water-alternating-gas Injection; process;is detailed in Figure 2 and Illustrated in Figures 3 to S.
    The process is initiated by performing water injection (step 205 of Figure 2} into the subsurface completion location with the gas injection system 90 isolated using the gas control valve system 95 arte the gas Injection device 75. In this case, as shown in Figure 3. the water controi vaive system 85 is opened so that wafer Is injected Into the first Sow path 40 within the tubular 35 by fee water injection system 80. The subsurface valve system 65 is also set to the open position suoh that the Injected water passes through the subsurface valve system 65 to the lower completion position 20.
    When it is desired to perform switchover of the wellbore system 5 from water Injection to gas inleotiQii, the water injection system 80 is isolated using the water control valve system 85 and the subsurtece valve system 65 (i.e. the SSSV) is closed in step 210 of Figure 2, and as shown in Figure 4, This has the effect of holding a column of water 100 within the first flew path 40 of the tubular 35 uphole of the subsurface valve system 65,
    Thereafter, as shown in Figure 5, the gas control valve system 95 is operable to de~ isolate the gas injection system 90 in order to siowly increase the pressure of gas being supplied from the gas injection system §0 into the second flow path 50 In step 215 of Figure 2> The gas injection device 75 is operable to inject the gas from the second fiow path 50 into the first flow path 40 at a location downstream or downhole of the subsurface valve system 65. In this way, the water below the subsurface vaive system 65 is gradually displaced by the gas arid forced into the subsurface completion location 20 and thereby into neighbouring geoioglcai formations, the bottom hole pressure (8HF) is monitored to ensure that the formation is not fractured. Since the subsurface vaive system 65 is dosed, the column of water is retained within the tubular 35 Upstream / uphold of the subsurface valve system 65 during the entire gas injection cycle.
    Once the water has been displaced into the formation, the pressure of the gas is rampeU up in step 220 of Figure 2 so that the gasman be injected at high pressure to perform the gas injection portion of the WAG process; as shown in Figure 6. The gas te generaiiy injected at high pressure and could be, for example, in the range of 5 to 3Q million standard eubic feet per day (MblscFdj: eqyhretehffohatvveen 5,909 and 35.400 Mm'".hr1,, preferably above 12 Mfoscf/d (14,150 NmThr4j and even aboveΊ5 blMscØd (17,700 Nms,hr<'}, Thus lire wellbore system may operate at significantly higher pressures than a conventional gas lift arrarsgement. Thus, the thickness of the tubing artd/or casing may be greater than a conventional gas lift arrangement and/or a higher yield strength, e g. stronger, material may be used for the materials of the tubing &amp; casing.
    After the gas injection cycle is complete, the gas injection via the gas injection device 75 is stopped and the gas injection system 90 is Isolated using the gas control valve system 96 ih step 225 of Figure 2S and as shown In Figure 7,
    The wafer control valve system: 85 is then opened In step 230 ef Figure 2 such that water is supplied by the water injection system 80 to the first flow 43 path in the tubular: 35 such that pressure is applied to the water column 100 in the tubuiar 35. Thereafter, the subsurface valve system 65 is opened as shown in Figure 8 and step 235 of Figure 2. and the water column 100 in the tubular 35 above the: subsurface: valve system 65 travels down towards the bottom of the welt The head of pressure of the water column 100 combined with the pressure applied by the water injection system 80 results in a pressure that is high enough to displace most of the gas downwards and Into the lower completion location 20 and thereby into the formation. The well head pressure then decreases as tile water column 100 applies a hydrostatic head to the Well,
    In this base, the hydrostatic head provided by the water column ISO above the subsurface vaive system 65 should be sufficient to compensate for differences In pressure between the gas injection pressure and the water injection pressure. For example» it the gas injection system 9Q operales at a maximum pressure of ISObarg, and the water injection system BO operates at 120barg, a hydrostatic head of 80 bar (870 psi) is required, This is equivalent to a water coiumn 100 of approximately 1930 ft 088m). Since the sub-surfeiee safety valve (SSSV) is typically located at arou nd 1900-2000 ft TVDRT (680-810m total vertical depth rotary table or TVDRT), this makes the SSSV a convenient mechanism tor use as the subsurface valve system 85 whilst providingsufficient hydrostatic head in the column to allow down 'hoi©' switch over from gds to water.
    The behaviour of the well can be held: tested, for example, in order to ensure that tee formation fracture pressure is not exceeded When the column; of wafer iq dropped by Opening the subsurface valve system 65.
    The water injection part of the MAG process can then be carried out, as shown in Figure 9, after which the process can then return back to step 205 of Figure 2 if required in order to carry out additional alternations between water and gas injection as part of the WAG process,.
    By using downhole WAG switchover, the welibore system 5 of the present invention may require less components than some conventional WAG systems. For example*, since any mixing of gas and water occurs downhole and: at high temperature, hydrate formation may be less of an issue, such! that systems designed to avoid hydrate formation such as Triethyiene glycol (TEG) injection systems may not be required.
    Furthermore,: prior art systems often provide a “kill pump* in order to allow1 switching from: gas cycle to wafer cycfe. The kill pump is fegutred because: fee hydrostatic pressure of the gas column is low, and results at pressures at surface which are higher than standard water injection systems, the kill pump is used to inject high pressure inhibited water or brine and build a water coiumn which lowers the pressure at surface te a level where the regular water injection system can be used. This operation is manual and requires rig up and several hours of pumping time, it also requires higher pressure operations at surface. The WAG system 5 of embodiments of the present Invention retains the column of liquid 100 above the subsurface valve system 86 during the gas injection part of the WAG process; This coiumn of liquid 100 can function as the kill fluid, which allows the well to cycle from gas to liquid; This mayalso allow tee: number of components to be further reduce#, e# by dispensing with the kit pump, in addition, in the ease of breakthrough from the injector well 10 &amp;> a- producer weii, embodiments of the present invention allow the Injector to be quickly switched over from gas to water injection,.leading to é reduced overall gas compression requirement and Increased recovery due to a;faster response;
    Even In the event that the column of water 1001s lost due to opening of the Sybsurfede valve system 65 during a gas in}epSfon operation, It Is still possible to kill the weii and: allow switchover either by employing a kill pump or by dosing the subsurface valve system 65. bleeding: off gas In the tubular 35 and refilling the tubular 35 with water. in addition:, the simpler downhole 'switching of embodiments of the present Invention may . allow simpler optimisation of the WAG process and more frequent switchover, which may lead to Improved recovery
    Furthermore, since embodiments ¢51 the present invention have less components and a simpler switching mechanism relative to some traditionai WAG methods, the embodiments of the present invention may be particularly suitable for automation of the WAG process.
    In addition, in many prior art systems, both high pressure gas injection and Sower pressure water injection must be conhedted to the same Weil This may resuit in safety issues in ensuring that high pressure gas cannot enter the Sow pressure wafer injection system. This can be addressed by physically disconnecting and connecting the relevant injection systems or by using spools. However, each of these approaches are time consuming, hazardous expensive. In the downhole apparatus of embodiments of the present invention, the water injection and gas injection are not directly connected at surface tevei and can be Isolated Individually, in addition^: the subsurface safety valve (SSSV), hydraulic master valve (HMV), water control valve jWCV) and the column of liquid 100 maintained above the subsurface valve system: 65 may also act as additional barriers for segregating the two injection systems 60, 90. Therefore, embodiments of the present invention may provide a simpler and safer WAG switchover arrangement. it should be understood that the embodiments described herein ere merely exemplary and that various modiications may bo made thereto without departing from the scope of the invention.
    For example, aifebUih the space between fee radially outward walls of the tubular and/or conduit and/or one or mom further conduits is described in., examples as a annular space, it will be appreciated that the space need not be annular, and that the invention is also effective with other, hon-annu la r spaces. in addition, although water Is given as an example of a liquid and natural gas is given as an example of a gas, it will be appreciated feat other fluids and/or liquids may be used.
    Furthermore,although the second low' path is described as being comprised in or-defined by an annular space between the tubular and a single easing, it will be appreciated that the downhole system may comprise a pluralityOf casings and that the second flow path may be composed or defined between two casings, such as an outer two.casings.
    权利要求:
    Claims (15)
    [1] 1. A waier^lfernatjng gas {WAG} apparatus located or locatabie In a wellbore that emends from a surface to a subsurface location, the apparatus com prising: at least one first channel configured to convey a iiguid downhole from the surface; at least one second channel configured to convey a gas downhole from the surface: and one or more downhole valve systems: ior;swtcbingfbe:: downhole apparatus between altefnatingly providing the liquid downhole and the gas downhole.
    [2] 2. The WAG. apparatus of claim 1, wherein the one dr more downhole valve systems are adapted to selectively provide the liquid or the gas downhole from the respective first andseeond channels.
    [3] 3. The WAG apparatus of claim 1 or claim % Wherein the one or mere;dgwnhdte valve systems comprise one dr more first valves or devices for regulating flow of the liquid downhole åndfor one or more second valves or devices for regulating flow of the gas downhole; wherein the downhole apparatus is swltchable between a first configuration in which the first valves or devices are closed and the second valves or devices are open such that gas Is injected ør injectable downhole via the at least one second charme! and the at least one second valves or devices and a second configuration Ih-which the first valves or devices are open and the second valves or devices are closed such that the liquid Is -injected or injectable downhole via the at least one first channel and the at least one first valves or devices, 4k The WAG apparatus according to any preceding claim, composing: a tubular or other hcilow conduit defining or comprising the first channel therewith in; and one or more hollow casings each defining a passage; wherein the tubular or other conduit is located or comprised within the passagefs) of the one or more casings and the second channel is compnsed in or at least partially defined by one or more annuli provided or al least partially defined between the tubular or other conduit and an inner wail of one of the casings and/or between two casings.
    [5] 5. The WAG apparatus according to ciaim 3 or any claim dependent thereon, wherein the at least one second valve comprises a gas injection device for providing selective communication from the second chance! to the first channel
    [6] 6. The WAG apparatus according to claim 3 or any ciaim dependent thereon, wherein the at least one second valve is provided or providahie downhole, downstream and/or Sower than the at ieast one first valve, . The WAG apparatus according to ciaim 3 or any claim dependent thereon, wherein the at least one first vaive comprises a sab-surface safety valve configured to selectiveiy open and/or close the first channel
    [8] 8, The WAS apparatus according to ciaim 3 or any claim dependent thereon, wherein the apparatus Is adapted to retain a head of iiggid Id thefirst change! uphoie or upstream of the at ieast one first vaive when the first vaive is closed during an injection operation. Q. The WAG apparatus according to a try preceding cla im> wherei n : the apparatus comprises or is connectable to a liquid injection system, the liquid injection system being oonnactedi or connectabia to the first channel via a iiquid control valve and/or the apparatus comprises or is connectable to a gas injection system, the: gas injection system being connected or connectable to the second channei via. a gas control vaive.
    [10] 10. The WAG apparatus according to claim 9, wherein the apparatus is swifchebte between configurations in which the gas and iiquid are alternately injected, wherein the apparatus is switch able into a liquid Injecti on Configuration by opening the iiquid control valve and/or the first vaive and closing the gas controi vaive and/or the second valve; and/or the apparatus is switphabie Into a gas injection configuration by opening the gas control Valve and/or the second valve and dosing the liquid control vaive and/or the first vaive.
    [11] 11. The WAG apparatus /according to any preceding claim:, wherein the apparatus is configured to provide gas at flow rates between 6 and 30 MMsof/d (between 5,800 Mmihr*' and 38,4(1 NmV, 12, : A method for (jwrforming a vrøter~a!ternafihg~gaS: injection operation in a wellbore that extends from a suifsce,: the method comprising::: conveying a liquid downhole from the surface:in: a fi rst channel:; conveying a gas downhole trom the surface in a second channel: and operating one or mere downhole valve systems so as to switch fh# downhole apparatus between alternately providing the lipoid downhpte and the gas downhofe.
    [13] 13, The method of claim 12, comprising operating the one or more downhole valve systems to selectively provide the liquid or the gas to a downhole location from the respective first and second channels-
    [14] 14, The method according to claim T2 or claim 13, comprising using an apparatus according to any of claims 1 to it,
    [15] 15, The method of any of claims 12 to. 14, wherein the method comprises performing a downhole gas injection to liquid injection switchover.
    [18] 18. The" method of claim 15« wherein the gas injection to liquid injection switchover comprises: closing a downhole gas control valve for eon trolling gas supplied by a gas injection system and/or using a second valve for regulating flow of the gas downhole; and opening a downhole liquid valve for control Sing liquid supplied by a liquid injedtipn system and/or using la first valve for regulating flow of the liquid downhole.
    17. The method of claim 16, wherein the method comprises retaining a head of liquid upstream by the first valve and the gas Injection to liquid injection switchover comprises releasing the head of liquid by opening the first valve,
    18. The method acbording to any of claims 12' to IT, wherein the method comprises: performing a liquid injection to gas Injection switchover.
    [19] 19. The method according to claim 18, wherein the liquid injection to gas Injection switchover comprises' closing the liquid controi valve and/or the first valve; and opening the gas controi valve and/or the second valve.
    [20] 20. The method according to claim 18, wherein the liquid injection to gas injection switchover comprises ramping up or gradually increasing pressure of gas, e.g. by gradually opening the gas control valve,
    [21] 21. The method according to any of claims 12 to 20, wherein the method. comprises providing gas at flow rates between 8 and 3Q MMsei/d,
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    同族专利:
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    US20170145800A1|2017-05-25|
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    法律状态:
    2019-03-13| PME| Patent granted|Effective date: 20190313 |
    2021-01-14| PBP| Patent lapsed|Effective date: 20200615 |
    优先权:
    申请号 | 申请日 | 专利标题
    GB1411213.0|2014-06-24|
    GBGB1411213.0A|GB201411213D0|2014-06-24|2014-06-24|Enhanced oil recovery method and apparatus|
    PCT/EP2015/063409|WO2015197422A2|2014-06-24|2015-06-16|Enhanced recovery method and apparatus|
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