Patent Application
20180363429
The present disclosure relates to artificial lift systems, and related apparatuses, for use in producing hydrocarbon-bearing reservoirs, and associated methods of manipulating such apparatuses and systems, and, in particular, to plunger lift systems and methods of using such systems.
Gas interference is a problem encountered while producing wells, especially wells with horizontal sections. In producing reservoir fluids containing a significant fraction of gaseous material, the presence of such gaseous material hinders production by contributing to sluggish flow. When plunger lift is required for assisting with production of reservoirs using horizontal wells, slugging of liquid, being supplied for lifting the plunger, can also impede production.
In one aspect, there is provided a reservoir fluid production assembly comprising:
a reservoir fluid inlet for receiving reservoir fluid flow from a downhole wellbore space of the wellbore;
a downhole fluid conductor for conducting the received reservoir fluid flow;
a flow diverter fluidly coupled to the downhole fluid conductor such that the flow diverter receives reservoir fluid flow being conducted by the downhole fluid conductor, and including:
the plunger and the produced gas-depleted reservoir fluid outlet are co-operatively configured such that, while uphole-disposed liquid reservoir fluid is disposed uphole of the plunger, displacement of the plunger, from the downhole position to the uphole position, by pressurized gaseous material is with effect that the uphole-disposed liquid reservoir fluid is displaced uphole by the plunger and discharged through the produced liquid reservoir fluid outlet; and
the plunger is configured for being conducted through liquid reservoir fluid that has accumulated within the liquid accumulator, while being displaced from the uphole position to the downhole position by gravitational force in the absence of gaseous material that is sufficiently pressurized to counterbalance the gravitational force, such that, after the plunger has passed through the accumulated liquid reservoir fluid, at least a fraction of the accumulated liquid reservoir fluid becomes disposed uphole relative to the plunger such that the uphole-disposed liquid reservoir fluid is obtained.
In another aspect a reservoir fluid production system is provided comprising the assembly described above, wherein the assembly is disposed within a wellbore.
The preferred embodiments will now be described with reference to the following accompanying drawings:
As used herein, the terms “up”, “upward”, “upper”, or “uphole”, mean, relativistically, in closer proximity to the surface 106 and further away from the bottom of the wellbore, when measured along the longitudinal axis of the wellbore 102. The terms “down”, “downward”, “lower”, or “downhole” mean, relativistically, further away from the surface 106 and in closer proximity to the bottom of the wellbore 102, when measured along the longitudinal axis of the wellbore 102.
Referring to
The wellbore 102 can be straight, curved, or branched. The wellbore 102 can have various wellbore portions. A wellbore portion is an axial length of a wellbore 102. A wellbore portion can be characterized as “vertical” or “horizontal” even though the actual axial orientation can vary from true vertical or true horizontal, and even though the axial path can tend to “corkscrew” or otherwise vary. The term “horizontal”, when used to describe a wellbore portion, refers to a horizontal or highly deviated wellbore portion as understood in the art, such as, for example, a wellbore portion having a longitudinal axis that is between 70 and 110 degrees from vertical.
“Reservoir fluid” is fluid that is contained within an oil reservoir. Reservoir fluid may be liquid material, gaseous material, or a mixture of liquid material and gaseous material. In some embodiments, for example, the reservoir fluid includes water and hydrocarbons, such as oil, natural gas condensates, or any combination thereof.
Fluids may be injected into the oil reservoir through the wellbore to effect stimulation of the reservoir fluid. For example, such fluid injection is effected during hydraulic fracturing, water flooding, water disposal, gas floods, gas disposal (including carbon dioxide sequestration), steam-assisted gravity drainage (“SAGD”) or cyclic steam stimulation (“CSS”). In some embodiments, for example, the same wellbore is utilized for both stimulation and production operations, such as for hydraulically fractured formations or for formations subjected to CSS. In some embodiments, for example, different wellbores are used, such as for formations subjected to SAGD, or formations subjected to waterflooding.
A wellbore string 113 is employed within the wellbore 102 for stabilizing the subterranean formation 100. In some embodiments, for example, the wellbore string 113 also contributes to effecting fluidic isolation of one zone within the subterranean formation from another zone within the subterranean formation.
The fluid productive portion of the wellbore 102 may be completed either as a cased-hole completion or an open-hole completion.
A cased-hole completion involves running wellbore casing down into the wellbore through the production zone. In this respect, in the cased-hole completion, the wellbore string 113 includes wellbore casing.
The annular region between the deployed wellbore casing and the oil reservoir may be filled with cement for effecting zonal isolation (see below). The cement is disposed between the wellbore casing and the oil reservoir for the purpose of effecting isolation, or substantial isolation, of one or more zones of the oil reservoir from fluids disposed in another zone of the oil reservoir. Such fluids include reservoir fluid being produced from another zone of the oil reservoir (in some embodiments, for example, such reservoir fluid being flowed through a production tubing string disposed within and extending through the wellbore casing to the surface), or injected fluids such as water, gas (including carbon dioxide), or stimulations fluids such as fracturing fluid or acid. In this respect, in some embodiments, for example, the cement is provided for effecting sealing, or substantial sealing, of flow communication between one or more zones of the oil reservoir and one or more others zones of the oil reservoir (for example, such as a zone that is being produced). By effecting the sealing, or substantial sealing, of such flow communication, isolation, or substantial isolation, of one or more zones of the oil reservoir, from another subterranean zone (such as a producing formation), is achieved. Such isolation or substantial isolation is desirable, for example, for mitigating contamination of a water table within the oil reservoir by the reservoir fluid (e.g. oil, gas, salt water, or combinations thereof) being produced, or the above-described injected fluids.
In some embodiments, for example, the cement is disposed as a sheath within an annular region between the wellbore casing and the oil reservoir. In some embodiments, for example, the cement is bonded to both of the production casing and the oil reservoir.
In some embodiments, for example, the cement also provides one or more of the following functions: (a) strengthens and reinforces the structural integrity of the wellbore, (b) prevents, or substantially prevents, produced reservoir fluid of one zone from being diluted by water from other zones. (c) mitigates corrosion of the wellbore casing, (d) at least contributes to the support of the wellbore casing, and e) allows for segmentation for stimulation and fluid inflow control purposes.
The cement is introduced to an annular region between the wellbore casing and the oil reservoir after the subject wellbore casing has been run into the wellbore. This operation is known as “cementing”.
In some embodiments, for example, the wellbore casing includes one or more casing strings, each of which is positioned within the well bore, having one end extending from the well head. In some embodiments, for example, each casing string is defined by jointed segments of pipe. The jointed segments of pipe typically have threaded connections.
Typically, a wellbore contains multiple intervals of concentric casing strings, successively deployed within the previously run casing. With the exception of a liner string, casing strings typically run back up to the surface 106.
For wells that are used for producing reservoir fluid, few of these actually produce through wellbore casing. This is because producing fluids can corrode steel or form undesirable deposits (for example, scales, asphaltenes or paraffin waxes) and the larger diameter can make flow unstable. In this respect, a production string is usually installed inside the last casing string. The production string is provided to conduct reservoir fluid, received within the wellbore, to the wellhead 116. In some embodiments, for example. the annular region between the last casing string and the production tubing string may be sealed at the bottom by a packer.
To facilitate flow communication between the reservoir and the wellbore, the wellbore casing may be perforated, or otherwise include per-existing ports (which may be selectively openable, such as, for example, by shifting a sleeve), to provide a fluid passage for enabling flow of reservoir fluid from the reservoir to the wellbore.
In some embodiments, for example, the wellbore casing is set short of total depth. Hanging off from the bottom of the wellbore casing, with a liner hanger or packer, is a liner string. The liner string can be made from the same material as the casing string, but, unlike the casing string, the liner string does not extend back to the wellhead 116. Cement may be provided within the annular region between the liner string and the oil reservoir for effecting zonal isolation (see below), but is not in all cases. In some embodiments, for example, this liner is perforated to effect flow communication between the reservoir and the wellbore. In this respect, in some embodiments, for example, the liner string can also be a screen or is slotted. In some embodiments, for example, the production tubing string may be engaged or stung into the liner string, thereby providing a fluid passage for conducting the produced reservoir fluid to the wellhead 116. In some embodiments, for example, no cemented liner is installed, and this is called an open hole completion or uncemented casing completion.
An open-hole completion is effected by drilling down to the top of the producing formation, and then casing the wellbore (with a wellbore string 113). The wellbore is then drilled through the producing formation, and the bottom of the wellbore is left open (i.e. uncased), to effect flow communication between the reservoir and the wellbore. Open-hole completion techniques include bare foot completions, pre-drilled and pre-slotted liners, and open-hole sand control techniques such as stand-alone screens, open hole gravel packs and open hole expandable screens. Packers and casing can segment the open hole into separate intervals and ported subs can be used to effect flow communication between the reservoir and the wellbore.
Referring to
As discussed above, the wellbore 102 is disposed in flow communication (such as through perforations provided within the installed casing or liner, or by virtue of the open hole configuration of the completion), or is selectively disposable into flow communication (such as by perforating the installed casing, or by actuating a valve to effect opening of a port), with the reservoir 104. When disposed in flow communication with the reservoir 104, the wellbore 102 is disposed for receiving reservoir fluid flow from the reservoir 104.
The production string inlet 204 is for receiving, via the wellbore, the reservoir fluid flow from the reservoir. In this respect, the reservoir fluid flow enters the wellbore 102, as described above, and is then conducted to the production string inlet 204. The production string 202 includes a downhole fluid conductor 206, disposed downhole relative to the flow diverter 600 for conducting the reservoir fluid flow, that is being received by the production string inlet, such that the reservoir fluid flow, that is received by the inlet 204, is conducted to the flow diverter 600 via the downhole fluid conductor 206.
It is preferable to remove at least a fraction of the gaseous material from the reservoir fluid flow being conducted within the production string 202, prior to the plunger 300, in order to mitigate gas interference. The flow diverter 600, is provided to, amongst other things, perform this function. In this respect, the flow diverter 600 is disposed downhole relative to the plunger 300. Suitable exemplary flow diverters are described in International Application No. PCT/CA2015/000178, published on Oct. 1, 2015.
In some embodiments, for example, the flow diverter 600 is configured such that the depletion of gaseous material from the reservoir fluid material, that is effected while the assembly 10 is disposed within the wellbore 102, is effected externally of the flow diverter 600 within the wellbore 102, such as, for example, within an uphole wellbore space 108.
The flow diverter 600 includes a reservoir fluid receiver 602 (such as, for example, in the form of one or more ports) for receiving the reservoir fluid (such as, for example, in the form of a reservoir fluid flow) that is being conducted (e.g. flowed), via the downhole fluid conductor 206 of the production string 202, from the production string inlet 204. In some embodiments, for example, the downhole fluid conductor 206 extends from the inlet 204 to the receiver 602 In some embodiments, for example, the reservoir fluid receiver 602 includes one or more ports.
The flow diverter 600 also includes a reservoir fluid discharge communicator 604 (such as, for example, in the form of one or more ports) that is fluidly coupled to the reservoir fluid receiver 602 via a reservoir fluid-conductor 603. The reservoir fluid conductor 603 defines one or more reservoir fluid conductor passages 603A (including, for example, a network of passages). In some of the embodiments described below, for example, the one or more reservoir fluid-conducting passages 603A include the fluid passage 620A, the fluid passage 615A, and the fluid passage 622A. The reservoir fluid discharge communicator 604 is configured for discharging reservoir fluid (such as, for example, in the form of a flow) that is received by the reservoir fluid receiver 602 and conducted to the reservoir fluid discharge communicator 604 via the reservoir fluid conductor 603. In some embodiments, for example, the reservoir fluid discharge communicator 604 is disposed at an opposite end of the flow diverter 600 relative to the reservoir fluid receiver 602.
The flow diverter 600 also includes a gas-depleted reservoir fluid receiver 608 (such as, for example, in the form of one or more ports) for receiving a gas-depleted reservoir fluid (such as, for example, in the form of a flow), after gaseous material has been separated from the reservoir fluid (for example, a reservoir fluid flow), that has been discharged from the reservoir fluid discharge communicator 604, in response to at least buoyancy forces. In this respect, the gas-depleted reservoir fluid receiver 608 and the reservoir fluid discharge communicator 605 are co-operatively configured such that the gas-depleted reservoir fluid receiver 608 is disposed for receiving a gas-depleted reservoir fluid flow, after gaseous material has been separated from the received reservoir fluid flow that has been discharged from the reservoir fluid discharge communicator 604, in response to at least buoyancy forces. In some embodiments, for example, the reservoir fluid discharge communicator 604 is disposed at an opposite end of the flow diverter 600 relative to the gas-depleted reservoir fluid receiver 608.
The flow diverter 600 also includes a gas-depleted reservoir fluid conductor 610 that includes a gas-depleted reservoir fluid-conducting passage 610A configured for conducting the gas-depleted reservoir fluid (for example, a gas-depleted reservoir fluid flow) received by the receiver 608 to a gas-depleted reservoir fluid discharge communicator 611 (such as, for example, in the form of one or more ports). In some embodiments, for example, the gas-depleted reservoir fluid discharge communicator 611 is disposed at an opposite end of the flow diverter 600 relative to the gas-depleted reservoir fluid receiver 608. The gas-depleted reservoir fluid discharge communicator 611 is for discharging gas-depleted reservoir fluid into a liquid accumulator 210B of the uphole fluid conductor 210.
The assembly 10 also includes a wellbore sealed interface effector 400 configured for interacting with a wellbore feature for defining a wellbore sealed interface 500 within the wellbore 102, between: (a) an uphole wellbore space 108 of the wellbore 102, and (b) a downhole wellbore space 110 of the wellbore 102, while the assembly 10 is disposed within the wellbore 102. The sealed interface 500 prevents, or substantially prevents reservoir fluid, that is being received by the reservoir fluid receiver 608, from being conducted from the uphole wellbore space 108 to the downhole wellbore space 110, thereby preventing, or substantially preventing, bypassing of gas-depleted reservoir fluid receiver 608 by gas-depleted reservoir fluid that has been separated from the reservoir fluid within the uphole wellbore space 108.
In this respect, in some embodiments, for example, the flow diverter 600 and the wellbore sealed interface effector 400 are co-operatively configured such that:
the reservoir fluid is discharged from the reservoir fluid discharge communicator 604 and conducted into the uphole wellbore space 108, such that the received reservoir fluid flow becomes disposed within the uphole wellbore space 108, and, while the received reservoir fluid is disposed within the uphole wellbore space 108, gaseous material is separated from the received reservoir fluid in response to at least buoyancy forces such that the gas-depleted reservoir fluid is obtained and is supplied to the gas-depleted reservoir fluid receiver 608, and the received gas-depleted reservoir fluid is conducted from the gas-depleted reservoir fluid receiver 608 to the liquid accumulator 210B via at least the conductor 610 and the gas-depleted reservoir fluid discharge communicator 611;
while: (a) the assembly 10 is disposed within the wellbore 102 and oriented such that the production string inlet 204 is disposed downhole relative to (such as, for example, vertically below) the production string outlet, and the wellbore sealed interface 500 is defined by interaction between the wellbore sealed interface effector 400 and a wellbore feature; (b) displacement of the reservoir fluid from the subterranean formation is being effected by the such that the reservoir fluid is being received by the inlet 204 (such as, for example, as a reservoir fluid flow) and conducted to the reservoir fluid discharge communicator 604 via the reservoir fluid receiver 602.
The disposition of the sealed interface 500 is such that fluid flow, across the sealed interface 500, is prevented, or substantially prevented. In some embodiments, for example, the disposition of the sealed interface 500 is such that fluid flow, across the sealed interface 500, in a downhole direction, from the uphole wellbore space 108 to the downhole wellbore space 110, is prevented, or substantially prevented. In some embodiments, for example, the disposition of the sealed interface 500 is such that fluid, that is being conducted in a downhole direction within the intermediate fluid passage 112, is directed to the gas-depleted reservoir fluid receiver 608. In this respect, the gas-depleted reservoir fluid, produced after the separation of gaseous material from the received reservoir fluid within the uphole wellbore space 108, is directed to the gas-depleted reservoir fluid receiver 608, and conducted to the liquid accumulator 210B via at least the conductor 610 and the gas-depleted reservoir fluid discharge communicator 611. The gas-depleted reservoir fluid, including a liquid reservoir fluid, collects within the liquid accumulator 210B.
In such embodiments, for example, the disposition of the sealed interface 500 is effected by the combination of at least: (i) a sealed, or substantially sealed, disposition of the wellbore string 113 relative to a polished bore receptacle 114 (such as that effected by a packer 240A disposed between the wellbore string 113 and the polished bore receptacle 114), and (ii) a sealed, or substantially sealed, disposition of the downhole production string portion 206 relative to the polished bore receptacle 114 such that reservoir fluid flow, that is received within the wellbore 102 (that is lined with the wellbore string 113), is prevented, or substantially prevented, from bypassing the reservoir fluid receiver 602, and, as a corollary, is directed to the reservoir fluid receiver 602 for receiving by the reservoir fluid receiver 602.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the downhole fluid conductor 206 relative to the polished bore receptacle 114 is effected by a latch seal assembly. A suitable latch seal assembly is a Weatherford™ Thread-Latch Anchor Seal Assembly™.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the downhole fluid conductor 206 relative to the polished bore receptacle 114 is effected by one or more o-rings or seal-type Chevron rings. In this respect, the sealing interface effector 400 includes the o-rings, or includes the seal-type Chevron rings.
In some embodiments, for example, the sealed, or substantially sealed, disposition of the downhole fluid conductor 206 relative to the polished bore receptacle 114 is disposed in an interference fit with the polished bore receptacle. In some of these embodiments, for example, the downhole fluid conductor 206 is landed or engaged or “stung” within the polished bore receptacle 114.
The above-described disposition of the wellbore sealed interface 500 provide for conditions which minimize solid debris accumulation in the joint between the downhole fluid conductor 206 and the polished bore receptacle 114 or in the joint between the polished bore receptacle 114 and the casing 113. By providing for conditions which minimize solid debris accumulation within the joint, interference to movement of the separator relative to the liner, or the casing, as the case may be, which could be effected by accumulated solid debris, is mitigated.
In some embodiments, for example, the space, between: (a) the gas-depleted reservoir fluid receiver 608 of the flow diverter 600, and (b) the sealed interface 500, defines a sump 700 for collection of solid particulate that is entrained within fluid being discharged from the reservoir fluid outlet ports 606 of the flow diverter 600, and the sump 700 has a volume of at least 0.1 m3. In some embodiments, for example, the volume is at least 0.5 m3. In some embodiments, for example, the volume is at least 1.0 m3. In some embodiments, for example, the volume is at least 3.0 m3.
By providing for the sump 700 having the above-described volumetric space characteristic, and/or the above-described minimum separation distance characteristic, a suitable space is provided for collecting relative large volumes of solid debris, such that interference by the accumulated solid debris with the production of oil through the system is mitigated. This increases the run-time of the system before any maintenance is required. As well, because the solid debris is deposited over a larger area, the propensity for the collected solid debris to interfere with movement of the flow diverter 600 within the wellbore 102, such as during maintenance (for example, a workover) is reduced.
Referring to
In some embodiments, for example, the wellbore 102 includes a wellbore fluid conductor 102, such as, for example, the wellbore string 113 (such as, for example, the casing 113), and the flow diverter 600 and the wellbore fluid conductor are co-operatively configured such that, while the assembly 10 is disposed within the wellbore 102 and oriented such that the production string inlet 204 is disposed downhole relative to the production string outlet 208, an intermediate fluid passage 112 is defined within the wellbore 102, between the flow diverter 600 and the wellbore fluid conductor 102 for effecting the flow communication between the reservoir fluid discharge communicator 604 and the gas-depleted reservoir fluid receiver 608. In some embodiments, for example, the intermediate fluid passage 112 is an annular space disposed between the flow diverter 600 and the wellbore fluid conductor 114.
Referring to
Again referring to
In some embodiments, for example, the uphole wellbore space 108 extends uphole from the discharge communicator 604, between the production string 202 and the wellbore fluid conductor 102, to a sealed interface 800 within the wellbore to define a gaseous material accumulator 802 for accumulating gaseous material. In some operational implementations, for example, the accumulated gaseous material may be used for displacing the plunger 300 in an uphole direction, as described below.
In some embodiments, for example, the minimum cross-sectional flow area of the uphole wellbore space is greater than the maximum cross-sectional flow area of the intermediate fluid passage. In some embodiments, for example, the ratio of the minimum cross-sectional flow area of the uphole wellbore space to the maximum cross-sectional flow area of the intermediate fluid passage is at least 1.2, such as, for example, at least 1.3, such as, for example, at least 1.5, such as, for example, at least 2.
In some embodiments, for example, the gas-depleted reservoir fluid receiver 610 is disposed downhole relative to (such as, for example, vertically below) the reservoir fluid discharge communicator 604, while the assembly 10 is disposed within the wellbore 102 and oriented such that the production string inlet 204 is disposed downhole relative to (such as, for example, vertically below) the production string outlet 208. In this respect, in some embodiments, for example, the flow diverter 600 and the sealed interface effector 400 are co-operatively configured such that, while: (a) the assembly 10 is disposed within the wellbore 102 and oriented such that the production string inlet 204 is disposed downhole relative to (such as, for example, vertically below) the production string outlet 208, (b) the flow diverter 600 is integrated into the assembly such that, while the assembly 10 is disposed within the wellbore 102 and oriented such that the production string inlet 204 is disposed downhole relative to (such as, for example, vertically below) the production string outlet 208, the flow diverter 600 is oriented such that the gas-depleted reservoir fluid receiver 608 is disposed downhole relative to the reservoir fluid discharge communicator 604, and the wellbore sealed interface 500 is defined by interaction between the wellbore sealed interface effector 400 and a wellbore feature, and (c) displacement of the reservoir fluid from the subterranean formation is being effected such that the reservoir fluid is being received by the inlet 204 (such as, for example, as a reservoir fluid flow) and conducted to the reservoir fluid discharge communicator 604:
the reservoir fluid is discharged from the reservoir fluid discharge communicator 604 and into the uphole wellbore space 108, such that the received reservoir fluid becomes disposed within the uphole wellbore space 108, and, while the received reservoir fluid is disposed within the uphole wellbore space 108, gaseous material is separated from the received reservoir fluid in response to at least buoyancy forces such that the gas-depleted reservoir fluid is obtained, and the gas-depleted reservoir fluid is conducted downhole to the gas-depleted reservoir fluid receiver 608, and the gas-depleted reservoir fluid, received by the gas-depleted reservoir fluid receiver 608, is conducted from the gas-depleted reservoir fluid receiver 608 to the gas-depleted reservoir fluid discharge communicator 611 via at least the conductor 610.
As above-described, the uphole fluid conductor 610 extends from the gas-depleted reservoir fluid discharge communicator 611 to the outlet 608 for effecting flow communication between the discharge communicator 611 and the outlet 608. In some embodiments, for example, downhole fluid conductor 206 defines a fluid passage 206A that has a maximum cross-sectional flow area that is less than the minimum cross-sectional flow area of the fluid passage 210A defined by the uphole fluid conductor 210. In some embodiments, for example, the ratio of the maximum cross-sectional flow area of the fluid passage 206A of the downhole fluid conductor 206 to the minimum cross-sectional flow area of the fluid passage 208A of the uphole fluid conductor 210 is less than 0.85, such as, for example, less than 0.75, such as, for example, less than 0.65, such as, for example, less than 0.5, such as, for example, less than 0.25.
As alluded to above, the liquid accumulator 210B is fluidly coupled to the gas-depleted reservoir fluid discharge communicator 611 for accumulating liquid reservoir fluid of the gas-depleted reservoir fluid that is being discharged from the gas-depleted reservoir fluid discharge communicator 611.
Referring to
The plunger 300 and the outlet 208 are co-operatively configured such that, while uphole-disposed liquid reservoir fluid is disposed uphole of the plunger 300, displacement of the plunger 300, from the downhole position to the uphole position, by pressurized gaseous material is with effect that the uphole-disposed liquid reservoir fluid is displaced uphole by the plunger 300 and discharged through the outlet 208. In this respect, while the plunger 300 is being displaced uphole by the pressurized gaseous material, the moving plunger 300 displaces the uphole-disposed liquid reservoir fluid in an uphole direction through the uphole fluid conductor 210 to the outlet 208.
The plunger 300 is also configured for being conducted through liquid reservoir fluid that has accumulated within the liquid accumulator 210B, while being displaced from the uphole position to the downhole position by gravitational force in the absence of gaseous material that is sufficiently pressurized to counterbalance the gravitational force. The downhole conduction of the plunger 300 is such that, after the plunger 300 has passed through the accumulated liquid reservoir fluid, at least a fraction of the accumulated liquid reservoir fluid becomes disposed uphole relative to the plunger 300 such that the uphole-disposed liquid reservoir fluid is obtained for being displaced by the plunger 300 that is displaced by supplied pressurized gaseous material. In this respect, while the plunger 300 is being conducted downhole, by gravity, through the uphole fluid conductor 210, the accumulated liquid reservoir fluid is displaced uphole relative to the plunger 300 and becomes disposed uphole relative to the plunger 300 as uphole-disposed liquid reservoir fluid.
In this respect, in some embodiments, for example, the plunger 300 and the uphole fluid conductor 210 are co-operatively configured such that spacing between the plunger 300 and the uphole fluid conductor 210 are sufficiently small such that the uphole-disposed liquid reservoir fluid does not, or does not appreciably, fall back downhole relative to the plunger 300 (for example, because the gaseous material being flowed in an uphole direction prevents, or substantially prevents, such egress of the uphole-disposed liquid reservoir fluid.
Alternatively, in some embodiments, for example, the plunger 300 includes a selectively openable fluid passage, extending therethrough, for permitting the accumulated liquid reservoir fluid to be conducted through the plunger 300, as the plunger 300 is being conducted downhole through the accumulated liquid reservoir fluid, and also includes a one-way valve, such as, for example, a check valve, for preventing, or substantially preventing such liquid reservoir fluid, once disposed uphole relative to the plunger 300, from returning downhole relative to the plunger 300.
As alluded to above, in some embodiments, for example, the pressurized gaseous material, communicated to the plunger 300, and displacing the plunger from the downhole position to the uphole position, originates from the gaseous material accumulator 802. Gaseous material being received within the uphole wellbore portion 108 accumulates within the gaseous material accumulator 802 such that the accumulated gaseous material becomes disposed at a pressure sufficient to effect the uphole displacement of the plunger 300, and, in response, the plunger 300 is displaced uphole. To prevent, or substantially prevent, the accumulated gaseous material from bypassing the plunger 300, a one-way valve 302, such as, for example, a check valve, is provided downhole of the flow diverter within the downhole fluid conductor 206.
Alternatively, in some embodiments, for example, the pressurized gaseous material is provided from an independent source 806. In this respect, in some embodiments, for example, a valve 804 is provided for controlling supply of pressurized gaseous material into the uphole fluid conductor 210 (such as, for example, via the flow diverter 600) for effecting the uphole displacement of the plunger 300. In some embodiments, for example, a controller is provided for controlling operation of the valve to effect the necessary supplying of the pressurized gaseous material as required. In some embodiments, for example, the pressurized gaseous material is supplied to the uphole fluid conductor 210 via the flow diverter 600, and the one-way valve 302, such as, for example, a check valve, is provided within the downhole fluid conductor 206, downhole of the flow diverter 600, for preventing the pressurized gaseous material from bypassing communication with the plunger 300.
In some embodiments, for example, an additional one-way valve 304 is disposed between the liquid accumulator 210B and the gas-depleted reservoir fluid discharge communicator 611 for preventing fall-back of liquid reservoir fluid that has collected within the liquid accumulator 210B.
In some embodiments, for example, the assembly 10 is disposed within a wellbore 102 including a vertical portion and a horizontal portion, and the plunger 300 is disposed within the vertical portion. In this respect, by virtue of one or more features of the flow diverter 300, gas interference is mitigated such that it becomes possible to disposed the plunger within the vertical portion. In some of these embodiments, for example, the horizontal portion has a length, measured along a longitudinal axis of the horizontal portion, of at least 100 metres, such as, for example, at least 250 metres, such as, for example, at least 500 metres.
In the above description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the present disclosure. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the present disclosure. Although certain dimensions and materials are described for implementing the disclosed example embodiments, other suitable dimensions and/or materials may be used within the scope of this disclosure. All such modifications and variations, including all suitable current and future changes in technology, are believed to be within the sphere and scope of the present disclosure. All references mentioned are hereby incorporated by reference in their entirety.
This application claims benefit of and priority to U.S. Provisional Patent Application No. 62/518,845 filed Jun. 13, 2017, the contents of which are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 62518845 | Jun 2017 | US |
