Patent Application
20200399998
This application relates to horizontal and vertical well fluid pumping systems and methods which mitigate heel preferential depletion and stranded reserves in the horizontal section.
It is well known in the art of oil and gas production to use pumps landed in the deepest point of a vertically oriented wellbore, or at the heel of the horizontal wellbore, to lift produced liquids from the reservoir to surface. Traditional vertical artificial lift solutions are well known. Various mechanical pumps such as rod pumps, progressive cavity pumps, electric submersible pumps or hydraulically actuated pumps are in widespread use in the oil and gas industry.
There are many benefits to utilizing a horizontal drilling and completions strategy for completing and producing wellbores. A horizontal wellbore can increase the exposure of the reservoir by creating a hole which follows the reservoir thickness. A typical horizontal wellbore plan also allows for the wellbore trajectory to transversely intersect the natural fracture planes of the reservoir and thereby increase the efficiency of fracture stimulation and proppant placement and therefore total productivity.
The primary advantage of a horizontally oriented wellbore is the exposure of a greater segment of the reservoir to the wellbore using a single vertical parent borehole than is possible using several vertical wellbores drilled into the same reservoir. However, in order to maximize this advantage, well performance must be proportional to the exposed length of reservoir in the producing well. As is commonly known in the industry, the relationship of well exposure to well productivity is not directly proportional in horizontal wellbores.
Generally, the production of horizontal wellbores is initially exploited using reservoir energy. The vast majority of horizontal wellbores are now stimulated using horizontal multi-stage fracturing systems to increase the exposure of the reservoir to the horizontally oriented wellbore. However, this stimulation technique only finitely energizes the reservoir, with the pressure returning quickly to the original in-situ reservoir pressure. If the reservoir drive is insufficient or quickly dwindles, production from the horizontal segment of the wellbore is drawn down utilizing a single pump inlet landed at or near the heel of the horizontal wellbore. Alternately, other conventionally known lift solutions such as plunger lift and gas lift are used to manage the back pressure on the formation through the vertical and transitional section of the wellbore. Other services such as jet pumps are used in an intermittent capacity to unload or clean out the horizontal wellbore section.
Conventional means for producing a horizontal well do not influence the reservoir much past the heel of the wellbore, resulting in heel-preferential depletion where drawdown is localized to the region in the heel.
The drawdown pressure is also limited to the theoretical vapor pressure of the fluid being pumped. A producing oil well, either horizontal or vertical, transitions through its bubble point during its producing life. When this occurs, gas escapes from solution and there exists at least two separate phases (gas and oil) in the reservoir, resulting in a gas cap drive. The efficient production of these types of reservoirs is accomplished by carefully managing the depletion of the gas cap drive, which may be monitored by the produced gas/liquid ratios. In a traditional free-flowing gas cap drive well, fluids will be mobilized by the gas drive and follow the path of least resistance in the journey towards the surface. Again, this results in a disproportionate production of the reservoir in the vicinity of the heel of the wellbore. The onset of premature depletion at the heel is exacerbated by the single drawdown location in the wellbore located near the heel. This production regime is present throughout the producing life until such a time as the heel becomes depleted and the gas cap drive breaks through near the heel. Gas cap drive breakthrough will result in elevated gas/liquid ratios. This can result in gas locking and fluid pounding, overheating, fluctuating torques, increased pump slippage (plunger/barrel or rotor/stator) and lower pumping efficiency, which can lead to significant damage to the vertical pumping solution. Eventually the gas drive will deplete, leaving unproduced fluid (reserves) in the reservoir space, thus leading to low recovery factors and stranded oil in the reservoir.
The concept of preferential depletion of substantially horizontal portions of subterranean wellbores has become more commonly known within the energy industry. The drilling, completion and production practices employed to date have resulted in reserves being trapped deeper in the substantially horizontal portion of these subject wellbores and consequently the expected producing life of these assets is shorter than was originally proposed and therefore the assets become less economically viable. Particularly in the case of solution gas drive type reservoir, the preferential depletion leads to a premature depletion of the available drive energy to support the production of the reserves. Coupled with mixed phase flow in the wellbore, the gas phase flows most readily, thereby leaving saleable liquids behind. This condition manifests as a well which ultimately behaves very differently along its length and therefore produces different results.
The preferential depletion of the heel portion of a horizontal wellbore segment creates a production scenario in which the horizontal section of the wellbore behaves as if it were two distinct wells. One potential solution involves multiple pumps spaced apart in the horizontal section. If the production is isolated from the reservoir, except through the horizontal pumps, each horizontal pump may be controlled to manage drawdown in different zones of the horizontal section.
Producers are experiencing primarily gas production near the heel of a wellbore with progressively more fluid production deeper into the horizontal section of the wellbore. They are seeing the presence of drill cuttings on pumping system components located near the toe of the wellbore upon retrieval to surface, which indicates little to no flow from this region of the wellbore from the original drilling and fracture stimulation. They are seeing elevated water cuts (up to 100%) in regions where the in-situ water cut for a normal reservoir is only 5-10%, which suggests that fracture stimulation fluid remains trapped the reservoir from the original completion and stimulation practices. Evidence of fracture stimulation chemicals in retrieved fluid samples from the horizontal pumps deployed into the test wellbore, segregation of regions of the horizontal wellbore segment from one another, limiting cross-flow communication along the horizontal segment despite there being clear fluid communication between said regions, are all symptoms of inefficient pumping along the horizontal section. There also appears to be rapid fluid separation between oil, water and gas phases, resulting in a “treater” style flow regime along the horizontal, leading to water quickly accumulating in the dip traps, potentially shutting off productivity from deeper in the horizontal wellbore.
Although very little testing or logging in the horizontal wellbore segments is being currently done following fracture stimulation and before the well is placed on production, the limited testing which is being done is proving through instrumentation and spinner surveys that moving beyond the first wellbore trap created by the varying elevations along the horizontal during the drilling program results in a cessation of reservoir productivity beyond this trap.
There remains a need in the art for artificial lift systems including a horizontal pumping system designed to address lifting efficiencies along the entire wellbore length irrespective of the state of depletion evident in a particular region of the substantially horizontal wellbore segment.
This background information is provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention. No admission is necessarily intended, nor should be construed, that any of the preceding information constitutes prior art against the present invention.
In general terms, the invention comprises a pumping system integral to the horizontal tubing string which comprises horizontal pumps, directional flow devices positioned between the horizontal pumps, and configured to prevent the individual pump discharges from interfering with one another, and to improve the quality of the fluids being picked up by the horizontal pumps. In effect, each of the horizontal pumps are isolated from each other, such that they act in parallel, independently contributing to a central flow passage in the production tubing.
In one aspect the invention may comprise a pumping system integral to a production tubing in a horizontal section of the wellbore, comprising a plurality of horizontal pumps, wherein each horizontal pump is associated with a directional flow control device and a fluidseeker configured to preferentially direct liquids into the horizontal pump intake. Preferably, each horizontal pump is also associated with a tubing drain integral to the tubing. The flow control device is intended to direct the pump discharge from each horizontal pump, which operates independently of other horizontal pumps, into the production tubing string and toward the heel of the well, which will prevent the pump discharge from interfering with the fluids discharged from the adjacent pump immediately downhole. Thus, each pumping segment is effectively isolated and independent of the others. In order to facilitate retrieval, the tubing drain is collocated with each directional flow control device, allowing fluid in the production tubing to drain from within the tubing string during a pumping system retrieval.
In another aspect, the invention comprises a method of producing fluids from a horizontal section of a wellbore, having a heel segment and a toe segment, comprising the steps of:
(a) landing a production tubing having a plurality of integrated horizontal pumps into the horizontal wellbore, the tubing defining (i) a central fluid passage which is continuous from a toe end to the heel end and (ii) an annulus between the tubing and a liner or reservoir face; wherein each horizontal pump has an intake located in a lower portion of the annulus and an outlet discharging into the central fluid passage; wherein the central fluid passage is closed to the reservoir except through a pump outlet, wherein one or both of the pump intake and outlet comprises a one-way valve; and wherein the central fluid passage comprises a directional flow control device disposed between adjacent horizontal pumps; and
(b) independently operating each horizontal pump to pump liquids into the central fluid passage, while leaving gases in the annulus.
In the drawings, like elements are assigned like reference numerals. The drawings are not necessarily to scale, with the emphasis instead placed upon the principles of the present invention. Additionally, each of the embodiments depicted are but one of a number of possible arrangements utilizing the fundamental concepts of the present invention. The drawings are briefly described as follows:
The invention relates to a pump method and system for a horizontal wellbore. The present invention builds on the general configuration and concept of the system and method described in Applicant's co-owned U.S. Pat. No. 9,863,414, entitled Horizontal and Vertical Well Fluid Pumping System”, the entire contents of which application are incorporated herein by reference, where permitted. When describing the present invention, all terms not defined herein have their common art-recognized meanings. To the extent that the following description is of a specific embodiment or a particular use of the invention, it is intended to be illustrative only and not limiting of the claimed invention.
Embodiments of the present invention are described in the context of a wellbore having a vertical section, a horizontal section and an intermediate build section, as schematically depicted in
As used herein, the terms “distal”, “downhole”, “proximal” and “uphole” are used to describe the relative positioning of elements relative to surface equipment, where the distal end of components is farther downhole, away from the surface, while the proximal end is uphole, closer to the surface, regardless of the actual relative vertical or horizontal position of the components.
The horizontal section of the wellbore may comprise a build segment where the inclination transitions from the kick-off point to fully horizontal orientation, followed by a heel segment which includes the first set of fractured perforations, in other words the beginning of the producing interval in the horizontal section, and terminates with the theoretical boundary of preferential depletion; and a toe segment transitioning through the non-depleted interval and terminating at the toe end of the horizontal wellbore section. There may be a plurality of segments throughout the horizontal section, intermediate the heel segment and toe segment. In some embodiments, each segment comprises at least one pump assembly, as described below.
Each segment may coincide with naturally occurring features of the reservoir, such as impermeable features, represented by the darker areas shown in
As shown schematically in
In one embodiment, as shown in
In some embodiments, the vertical lift pump (30) may combine with a fluid flow management system (40) for treating a multi-phase fluid stream, such as that described in Applicant's co-pending Patent Cooperation Treaty application filed on Mar. 12, 2019 and entitled “Horizontal Wellbore Separation System and Method”, the entire contents of which are incorporated herein by reference, where permitted. Generally, the fluid flow management system is configured to pass through high quality liquid flow being pumped from downhole segments of the horizontal section to the vertical lift pump intake, and de-energize disorganized mixed phase flow in the annulus, allowing for accumulation and pickup of liquids, while allowing gas flow to continue through the annulus.
In some embodiments, the fluid flow management system comprises:
(a) a central flow passage (50) which receives production fluid flow from the downhole segments of the horizontal section, and is continuous to the toe end of the system;
(b) a slug mitigation device or wavebreaker (42) disposed in the annulus external the production tubing, adjacent to and proximally located from a centralizer device, which wavebreaker encourages well liquids to accumulate in the lower portion of the annulus, while permitting gas flow to continue around the wavebreaker;
(c) optionally, at least one baffle plate for normalizing the flow conditions of multi-phase stream, leading to phase separation;
(d) an inline fluidseeker (44), which self-orients downwards by gravity, increasing the likelihood that the fluidseeker intake (46) will be immersed in liquids in the lower portion of the annulus.
In preferred embodiments, mixed phases accumulate in the annulus uphole from the fluidseeker (44), which annulus may be considered to be a separation chamber. As the mixed phases are retained in this separation chamber, liquids which condense or coalesce in this section drop to the bottom of the chamber, where the fluidseeker inlet (46) is disposed. A section of pipe in this separation chamber may comprise at least one perforated pipe interval configured to allow gases to escape to the annulus, while having an inner tube forming the central fluid passage (50), which takes high quality liquid flow to vertical pump intake.
The horizontal pumping system may now be described, starting at the toe end of the system. A plug (52) caps and seals the toe end of the production tubing, isolating the central fluid passage (50) from the reservoir, except though the horizontal pumps. At spaced intervals along the central fluid passage (50), directional flow devices (60) comprising one-way valves are inserted into the flow, ensuring that produced fluids do not backup into a downhole segment, but rather progress uphole towards the heel and the artificial lift device to be transported to the surface. The horizontal pumps (18) with downward facing inlets (20) are integrally placed in the production tubing.
One embodiment of a one-way valve (60) is shown in
A pump assembly (70) is shown in longitudinal cross-section in
A clutch assembly (90) is required in the context of deploying downhole devices, or downhole horizontal pumps along the wellbore with common activation strings (99) whether it be capillary lines for a fluid system or electrical lines for an electrically powered pumping system or smaller gauge wire for instrumentation systems and data collection. All of these variations have a common foundational challenge involved in consistently and reliably making connections with the external lines at each of the deployable device locations. Where the tubing string is made up with a specified connection torque and not an aligned rotational position, the angular position of the capillary lines (99) with respect to the tubing below the pump and the rotational position of the lines exiting the local pump may not necessarily be in alignment. Therefore, in some embodiments, a rotatable and sealed tubing deployed clutch (14) allows for installation of multiple pump deployments with capillary lines and electrical conduits.
In such conditions the rotatable, sealed tubing deployed clutch permits conditions whereby the tubing and operational device may be temporarily disconnected in a rotatable sense to allow the external activation conduits to be aligned with the same in the device. Then the clutch may be re-engaged and locked and the subsequent operations continued.
In some embodiments, the rotatable, sealed tubing deployed clutch is comprised of an indexing mandrel (90) disposed within and sealingly enagaged with the clutch body (91). The mandrel and the clutch body are affixed to one another in a rotational sense with the engagement of the castellations (92) located on the outer surface of the indexing mandrel and on the proximal end face of the clutch body. The engagement of the castellations is controllable by the axial position of the lock housing (93), surrounding the castellations (92) disposed between the two bodies.
In the fully locked position, as shown in
Reliable re-engagement of the castellations after the new rotational position has been established is accomplished by way of the indexing alignment slots (95). The slots are transversely aligned with the male castellations of the clutch body and the corresponding female castellations on the indexing mandrel. Therefore, with the castellations being enclosed by the lock housing during normal operations the re-alignment and re-engagement of the castellations is accomplished by visually and/or physically aligning the indexing alignment slots on the distal and proximal ends of the clutch assembly. Once said slots are in axial alignment, the clutch assembly may be closed and locked in the reverse operation which caused the castellations to be dis-engaged initially.
Sealing engagement of the two main bodies is permitted by the seal assembly (96) radially disposed on the outer surface at the distal end of the indexing mandrel. Sealing engagement and seal movement is limited by way of the limit detent ring (97) expanding into the pre-disposed internal groove of the clutch body as the indexing mandrel is permitted to travel towards the proximal end of the same.
The intake section (72) comprises a bottom bulkhead (73), and inner tube (74) which is a continuation of the central flow passage (50) of the system, and outer filter tube (75) which acts as the intake filter. Production fluids pass through the outer filter tube (75) while excluding unwanted solids (sand etc.). Cross-section B-B is taken at the uphole end of the intake filter and the start of the fluidseeker section (100).
As shown in
The fluids in the annulus in the region of the intake section may be disorganized with gas and liquid slugs. Generally, however, the liquids in the annulus will of course settle to the lower section of the annulus. Thus, the fluidseeker (100) is configured to provide a fluid inlet in the lower section. Annular production fluids enter the fluid seeker in the passage between the outer housing (105) and the central inner conduit (101). The inlet extension (103) is rotatably mounted with suitable seals and bearings to the central inner conduit (101) with the weighted keel (104) defining inlet ports (106). The opposing side comprises a barrier (107) which is sealed to the central inner conduit (101) and the inner surface of the inlet block (107), all of which defines the inlet chamber (102).
As may be seen, liquids which enter the fluidseeker accumulate in the lower half of the intake chamber (102), where the weighted keel (104) inlet ports (106) allow passage to the uphole side of the rotatable inlet extension (103). Gases in the upper half do not progress past the rotatable inlet extension barrier (107). Intake ports (109) in the inlet block (108) continue the fluid passage from the intake chamber (102) to the primary pump intake chamber (110). The uphole end of the fluidseeker assembly shown in
In some embodiments, the system may comprise intake float (not shown) disposed on the rotatable inlet extension within the fluidseeker intake chamber (102), with a level switch (not shown) operably connected to the activation system (301). Because the rotatable inlet extension (103) is always oriented vertically, the intake float may be configured to activate the level switch to initiate pumping when the intake float indicates a sufficient liquid level present int the inlet chamber, ensuring that the fluidseeker inlet extension ports (106) are immersed in liquid, and cease pumping when the level switch indicates that the liquid level has fallen below a specified operable lower limit. By the means of the float, the pumping efficiency of the horizontal pump may be managed in such a way that the device may only be active when the intake assembly is full of fluid.
Capillary line passages (99) are shown in the transverse cross-sections of the fluidseeker, as a number of capillary lines must pass through the fluidseeker.
A distal flow sub (201) connects to the uphole end of the fluidseeker assembly, and continues the central fluid passage (50), as may be seen in cross-sections J-J and K-K. The primary pump intake chamber (202) comprises a one-way valve (203), which leads to the pump intake annulus (204), shown in
In preferred embodiments, the diaphragm pump (205) comprises a flow-through passage which is the continuation of the central fluid passage (50), which flows through the pump (200) unimpeded. The pump section (200) comprises the distal flow sub (201) at the downhole end and a proximal flow sub (206) at the uphole end. The production chamber (207) of the pump is disposed between the internal mandrel (208) which internally defines the central fluid passage (50) and an expandable diaphragm (209) disposed between the outer housing (210) and the inner mandrel (208).
In some embodiments, the inner mandrel (208) has a lobed transverse profile (as seen in cross-section L-L) through a middle section. As a result, the production chamber (207) primarily comprises of the space between the lobes (210), of which there are four lobes in the embodiment shown. Activation fluid inlet passages (211) and exhaust passages (212) run axially through the lobes (210), and through ports in fluid communication with the activation chamber which is between the outer housing and the diaphragm (209).
At the uphole end, the production chamber (207) leads to discharge ports (213) through the mandrel (207), which are in fluid communication with the pump outlet and the discharge passage (214) in the proximal flow sub (206). The discharge passage (214) in the proximal flow sub (206) comprises a one-way valve (215). Thus, the diaphragm pump (205) uses one-way valves at the suction end and the discharge end to ensure proper flow of the produced fluids. The pump discharge then merges with the central flow passage (50) in the proximal flow sub (206).
Because of the one-way valve assemblies, the pump output is isolated from the central flow passage, which carries the cumulative output of downhole pump assemblies, except when the pump is active discharging into the central flow passage.
A top bulkhead (300) houses the activation system (301) which receives the activation and exhaust capillary lines, electrical lines, and includes the actuation valves necessary to control operation of the diaphragm pump. The bulkhead (300) then connects to a tubing adapter (400), which may then be connected to regular lengths of tubing (500) which separate the pump assembly (200) from the next uphole pump assembly.
The electrical conduits (98) and capillary lines (99) continue along the entire tubing string, passing through system elements as required, and clamped externally to tubing and system elements as necessary. The clutch assembly permits rotational makeup of the system, while maintaining axial alignment of the conduits and lines.
Efficient retrieval of the substantially horizontal multi-pump artificial lift system requires the fluid within the continuous fluid passage (50) must be drained as the tubing system is retrieved from the well. With several directional control valves integral to the tubing within the wellbore completion, retrieval of the system from the wellbore requires that a means of draining the tubing is collocated with each instance of the proposed directional control valve. This means is accomplished by the installation of tubing drains or burst joints as are well known in the art. When the tubing pressure inside the first fluid flow path is artificially elevated above the burst joint pressure, a drain opening is created such that fluid is permitted to pass into the annular space within the well casing, from within the tubing string. This ensures that the tubing internals are dry as the tubing is tripped toward surface and prevents wet trips with tubing as each joint is surface during the system retrieval.
In some embodiments, a multi-phase flow measuring instrument may be provided in one or more horizontal or vertical wellbore segments, which measures, acquires and/or processes downhole information from selected wellbore locations. This information may be used by an intelligent control system to vary pump rates or operating states to optimize productivity along the length of the horizontal wellbore.
In some embodiments, the pumping system and method may be configured so as to avoid placing horizontal pumps in sections of the horizontal wellbore which are known to be depleted. For example, if the heel segment and an adjacent segment have both been depleted, the high angle reciprocating rod pump and fluid flow management system may positioned much farther downhole than the heel of the wellbore.
In another aspect, the invention comprises a method of producing fluids from a horizontal section of a wellbore. A system comprising a production tubing having a plurality of integrated horizontal pumps as described herein, such as schematically illustrated in
Gases and mixed-phase flow migrates in the annulus towards the heel segment, where they encounter the fluid management system, which encourages further phase separation. Gases continue to travel up the annulus, in the vertical section of the wellbore. Liquids are picked up by the fluidseeker inlets along the system, and delivered to the intake of the vertical lift pump.
In preferred embodiments, the system further comprises a plurality of sensors deployed in the different wellbore segments, which collect and transmit data to a control system. The control system operates each of the horizontal pumps, either by turning the pump on or off, or increasing or decreasing the pump rate, in response to the downhole conditions reported by the sensors. The sensors may include pressure, temperature, flow rate, fluid level, sensors or the like. Thus, embodiments of the invention include methods of data collection, assembly, presentation and subsequent research, preparation and analysis as situationally required in order to present an artificial lift system design to systematically and orderly pump a substantially horizontal wellbore segment along the horizontal and thereby efficiently delivering liquids to the intake of the operable high angle lift intake.
One aspect of the invention include methods of reviewing wellbore data, analyzing operating and reservoir conditions and presenting a system design which is unique to a given wellbore and designed to present the best potential results for the same. The desired result is to access previously undrained reserves within the well reservoir by placing a pumping system along the previously undrained reservoir section.
Therefore, in some embodiments, the method may comprise one or more of the following. Some or all relevant and pertinent data surrounding a potential wellbore application may be collected, which data may include:
(a) wellbore pressure/reservoir pressure (which may be ascertained by way of analog well sensors, historical data or by means of a down hole pressure survey);
(b) wellbore temperature (which may be ascertained by way of analog well, historical data or by means of a down hole temperature survey);
(c) wellbore directional survey data;
(d) historical production data: GOR, GLR, Water Cut, Oil Cut, Water Rate, Oil Rate, Gas Rate, etc, (ascertained either historically with the subject wellbore or by way of an analog well or group thereof);
(e) annular liquid levels, preferably of the de-gassed (or depressed column) as a means of estimating the available reservoir pressure;
(f) reservoir quality logs, such as gamma ray;
The data may be assembled or processed in a meaningful way so as to allow logical predictions as to the producing capability of the subject reservoir. In some embodiments, the assembled data may be used:
(a) to inform the placement of each of the horizontal pumps along the substantially horizontal wellb ore segments;
(b) for comparison of the data against a database of known reservoir data and performance and to select an analog which may inform the design of said pumping system and the pump placement within the same;
(c) in concert with empirically discovered pressure and friction loss data to estimate the required pumping pressures along the length of the substantially horizontal wellbore segments;
(d) to inform the required surface pumping horsepower of the systems design;
(e) to size the capillary tubing to match the required system pumping rates;
(f) to size the electrical conduits designed to power the horizontal pumps strategically placed along the length of the substantially horizontal wellbore;
(g) to size the tubing string required at each stage or segment of the system;
(h) to predict requirement of friction reducing lining disposed internally to the production tubing, which tubing is in fluidic communication with the discharge portion of each horizontal pump;
(i) to predict the required pumping rate for the subject wellbore/reservoir;
(j) combined with a method such as a material balance calculation as is well known in the art to predict the remaining reserves in place and the expected lifetime performance of said horizontal and vertical well fluid pumping system;
(k) to predict the well fluid pumping device or combination thereof which may be deployed into the subject wellbore, including without limitation, a reciprocating rod pump, a diaphragm pump, an electric submersible pump, a hydraulic submersible pump, a jet pump, a pneumatic drive pump, a gas lift pump, a gear pump, a progressive cavity pump, a vane pump or combinations thereof;
(l) in combination with a predictive calculation tool such as: computational fluid dynamics, gas volume (void) fraction, OLGA flow modelling software, or any other tool of the like, in order to predict flow conditions along the horizontal section, which flow conditions may inform the placement of the pumps and their future performance or to predict the improvement to the net present value of the producing asset with the horizontal and vertical well fluid pumping system being installed and operable to pump the fluids along the substantially horizontal wellbore segments towards the intake of the high angle lift solution.
The methods of the present invention may be applied in conjunction with unconventional or enhanced recovery techniques, such as steam assisted gravity drainage, miscible flood, steam (continuous or cyclic), gas or water injection.
Thus, in aspects of the invention, the horizontal pumping system may be schematically understood to have a first fluid path which is the central flow passage (50) and a second flow path which is along the annulus, each of which paths are separate and differentiable in the wellbore. The system, with each fluidseeker, takes a portion of the second fluid path in the annulus which is primarily liquid and adds it to the first fluid path by means of the horizontal pump. The remaining fluids in the second flow path is transported to the heel segment, where continued separation provides liquids to add to the first flow path, and remaining gases continue up the annulus.
The two paths remain distinct as they exchange dominance providing preference to the dominant flow in time by way of the directional flow control devices, valve which ensures advancement of the flow towards the high angle lift intake only. In some embodiments, production from a preferentially depleted horizontal segment is lifted using only the high angle lift solution located adjacent to the flow management and separation system. Where mixed phase slugging flow exists in the annulus, initiating from a preferentially depleted heel wellbore segment, it is de-energized by the wavebreaker and then passes through the separation system, undergoing retention time and phase separation. This process properly conditions the fluids in order to present the highest possible liquid quality to the high angle lift system intake.
Each horizontal pump adds higher quality liquid to the first fluid flow which eventually is directed into the high angle rod pump solution. Such higher quality liquid is a product of the phase separation taking place at the fluidseeker intake of the at least one horizontal pump. The first fluid path flow is controlled passively by the dominant fluid, where the first and second fluid paths exchange dominance in time, influenced by the discretely differentiable pressure conditions in the source rock reservoir.
As the flow in the annular space (second fluid flow path) becomes dominant over the flow first fluid flow path, the weighted keel intake of the fluidseeker assembly permits flow into the high angle lift solution intake from the preferentially depleted region of the subject wellbore. This configuration permits an unbiased drainage of the entire wellbore despite the depletions status of any particular region, by way of the high angle lifting solution.
In a wellbore which has substantially horizontal segments which are substantially undepleted in nature, the condition of the fluid and the behavior of the reservoir along the wellbore length may behave similarly, therefore this well may behave as a single congruent entity. In this condition, the wellbore is configured with at least one horizontal pump whose discharge is directed to along the first flow path to the high angle lift solution intake. In this case, there is little flow in the second fluid path.
The weighted keel configuration of the fluidseeker tends to mobilize the most readily mobile fluid medium preferentially toward the pump system intake.
The nature of the multi-flow in the substantially horizontal wellbore segments tends to be unorderly and disorganized in nature. This type of flow can be expected in the fluid flow path one and in the annular region between well casing ID and OD of the tubing which surrounds the central fluid passage (first fluid path). The changing elevations, pressures and proportions of each fluid phase along the horizontal all contribute to disorganized, intermittent and unpredictable flow regimes and production results. An additional layer of complexity is present when inside the tubing which surrounds the central fluid passage since the tubing is isolated everywhere along its length except at the intake through each horizontal pump. When pumping multi-phase liquids with at least one horizontal pump the fluid conditions on the discharge side of the horizontal pumps may also include gasses which introduce compressibility into the first fluid flow path from its distal end at the discharge of the at least one horizontal pump to the proximal end at the inlet to the fluidseeker, or adjacent to and in fluidic communication with the intake to the vertical pumping solution.
With no biasing means present along the first fluid flow path, the pressure elevation introduced by the at least one horizontal pump is permitted to travel in both directions (uphole or down-hole) along the horizontal tubing segment between the horizontal pumps. This condition can present as sustained pressure elevation at the discharge end of the adjacent horizontal pumps which condition will cause an escalation in the required discharge pressure at adjacent pumps and may in some circumstances entirely prevent the adjacent pumps from discharging into the common and substantially horizontal tubing string. Therefore, the solution is to provide directional flow control devices placed immediately down-hole of each horizontal pump to ensure that the direction of flows of the pump discharge is directed only from the distal end of the first fluid flow path towards the proximal end of the same.
Pump placement along the horizontal wellbore section and particularly in relation to the fracture intervals and the troughs of the trajectory has proven to be an important factor in overall system operation and as such is captured within this improved system application. To that end and further a method and system for collecting data for subject wells and potential analog wells and then assembling the data for presentation is presented here. Further, the assembled data is used to present an artificial lift system design for the betterment of the well's production and ultimately to access stranded reserves from the deepest portion of the substantially horizontal segment of the subject wellbore.
The description of the present invention has been presented for purposes of illustration and description, but it is not intended to be exhaustive or limited to the invention in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the invention. Embodiments were chosen and described in order to best explain the principles of the invention and the practical application, and to enable others of ordinary skill in the art to understand the invention for various embodiments with various modifications as are suited to the particular use contemplated. To the extent that the following description is of a specific embodiment or a particular use of the invention, it is intended to be illustrative only, and not limiting of the claimed invention.
The corresponding structures, materials, acts, and equivalents of all means or steps plus function elements in the claims appended to this specification are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed.
References in the specification to “one embodiment”, “an embodiment”, etc., indicate that the embodiment described may include a particular aspect, feature, structure, or characteristic, but not every embodiment necessarily includes that aspect, feature, structure, or characteristic. Moreover, such phrases may, but do not necessarily, refer to the same embodiment referred to in other portions of the specification. Further, when a particular aspect, feature, structure, or characteristic is described in connection with an embodiment, it is within the knowledge of one skilled in the art to combine, affect or connect such aspect, feature, structure, or characteristic with other embodiments, whether or not such connection or combination is explicitly described. In other words, any element or feature may be combined with any other element or feature in different embodiments, unless there is an obvious or inherent incompatibility between the two, or it is specifically excluded.
It is further noted that the claims may be drafted to exclude any optional element. As such, this statement is intended to serve as antecedent basis for the use of exclusive terminology, such as “solely,” “only,” and the like, in connection with the recitation of claim elements or use of a “negative” limitation. The terms “preferably,” “preferred,” “prefer,” “optionally,” “may,” and similar terms are used to indicate that an item, condition or step being referred to is an optional (not required) feature of the invention.
The singular forms “a,” “an,” and “the” include the plural reference unless the context clearly dictates otherwise. The term “and/or” means any one of the items, any combination of the items, or all of the items with which this term is associated.
As will be understood by one skilled in the art, for any and all purposes, particularly in terms of providing a written description, all ranges recited herein also encompass any and all possible sub-ranges and combinations of sub-ranges thereof, as well as the individual values making up the range, particularly integer values. A recited range (e.g., weight percents or carbon groups) includes each specific value, integer, decimal, or identity within the range. Any listed range can be easily recognized as sufficiently describing and enabling the same range being broken down into at least equal halves, thirds, quarters, fifths, or tenths. As a non-limiting example, any range discussed herein can be readily broken down into a lower third, middle third and upper third, etc.
As will also be understood by one skilled in the art, all ranges described herein, and all language such as “up to”, “at least”, “greater than”, “less than”, “more than”, “or more”, and the like, include the number(s) recited and such terms refer to ranges that can be subsequently broken down into sub-ranges as discussed above.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/CA2019/050302 | 3/12/2019 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62641886 | Mar 2018 | US |
