Gravity Assisted Reservoir Drainage Systems and Methods

This application is a continuation-in-part of U.S. patent application Ser. No. 18/638,306, filed Apr. 17, 2024, which is a continuation of U.S. Pat. No. 11,988,081, which claims priority to U.S. Provisional Application No. 63/164,374, filed Mar. 22, 2021, each of which are each incorporated herein by reference.

The following disclosure generally relates to gravity assisted reservoir drainage systems and methods. More particularly, the following disclosure relates to improved reservoir drainage systems and artificial lift methods for enhancing hydrocarbon recovery from mature reservoirs, which have been developed using closely spaced horizontal wells completed with large multi-stage hydraulic fracture treatments from multi-well pads in batch fashion.

The integration of horizontal drilling and multi-stage fracture stimulation technology using large volumes of low viscosity slick water fracturing fluid mixed with proppant (e.g., 40/70 and 100 mesh sand) to extract commercial quantities of natural gas was first demonstrated in the Barnett Shale Play in North Texas during the 1990s. By the end of the next decade, nearly 15,000 horizontal wells were completed in the Barnett Shale Play as operators sought to find other potential hydrocarbon fields to apply the transformational technology. One such area was the Eagle Ford Shale in South Texas, which was first tested in 2008.

Unlike the Barnett Shale Play, the Eagle Ford Shale Play was found to produce significant quantities of hydrocarbon liquids in the up-dip locations of the play. By the end of 2021, approximately 8,800 horizontal oil wells were completed within the most prolific core area of the liquids-rich Eagle Ford Shale Play. This core area is often referred to as the “Eagle Ford Volatile Oil Trend” (EFVOT). The EFVOT, which includes contiguous portions of Lavaca, Gonzales, DeWitt, Karnes, Live Oak, McMullen, and La Salle Counties, typically produces black oil with relatively low quantities of associated natural gas and formation water. In fact, a large percentage of the frac water introduced during the initial completion process in many liquids-rich shale developments, including the EFVOT, is never produced back indicating the rock matrix is likely hydrophilic and undersaturated (i.e., below critical water saturation). The reservoir in this core area is also geopressured (i.e., the reservoir fluids are abnormally over-pressured at a gradient that greatly exceeds hydrostatic pressure of approximately 0.5 psi per foot of depth) and represents the most densely developed area of the Eagle Ford Shale Play. The wells in the EFVOT typically have horizontal sections that extend between one and two miles in length, are spaced closer than 440 feet laterally apart, and were most often completed in simultaneous “zipper frac” batch operations from multi-well surface pad locations.

At its peak in 2015, this EFVOT area produced an average of about 875,000 barrels of oil per day from approximately 5,200 horizontal wells. By the end of 2021, the area was producing about 331,000 barrels of oil per day in aggregate or approximately 38 barrels of oil per day per well. However, due to the mature nature of the play and numerous technical challenges, approximately 7,200 of the 8,800 EFVOT wells were producing less than 20 barrels of oil per day and have only marginally economic remaining reserve potential using current exploitation practices.

By the end of 2021, the roughly 8,800 wells in the EFVOT produced almost 2 billion barrels of oil and 3.9 trillion cubic feet of associated natural gas, but this is generally thought to represent less than ten percent of the original hydrocarbons in place under leases that are fully developed with closely spaced horizontal wells. The main reason for the low recovery efficiency compared to more conventional oil reservoirs is the carbonate-rich shale/siltstone matrix, which has extremely low permeability, and the mixed wet organic pore spaces that are poorly connected. In fact, without massive hydraulic fracture stimulation treatments during the horizontal well completion process, there would be no economic recovery of hydrocarbons from shale and other ultra-low permeability oil reservoirs.

Constructive fracture interference between new closely spaced horizontal wells (e.g., less than 440 feet average lateral spacing) and fracture stages occurs during high-intensity, batch fracturing operations. This dynamic stress alteration phenomenon is thought to result in more productive fracture networks due in large part to the creation of more shear-failure hydraulic fractures, increased fracture complexity, and better fracture network containment in relatively close proximity to the horizontal well being completed.

Complex shear-slip fracturing within the upper part of the stimulated reservoir volume (SRV) located above the True Vertical Depth (TVD) of each lateral are often self-propping via dislocation of fracture surfaces, surface asperities/roughness, and hydraulic fractures held open by broken rock fragments. These fractures do not contain proppant and yet contribute significantly to well productivity and ultimate recovery as evidenced by the following facts: (a) larger, higher intensity fracture treatments of modern completions (e.g., post-2016 completions) generally perform significantly better than older completions, which had smaller fracture treatments (assuming all other relevant parameters are the same); (b) proppant represents only a small percentage of the total volume of material pumped in these more recent EFVOT completions (i.e., ˜5%); and (c) sand of various mesh sizes in slick water was found in lab studies, computational fluid dynamics (CFD) analysis, and mine back experiments to propagate from perforation clusters similar to how sand dunes propagate. After a fracture treatment, most of the proppant is known to be in fractures located at or below the TVD of the lateral because the velocity and viscosity of the fracture fluid are insufficient to keep the proppant in suspension after it travels only a short distance from the wellbore. In conclusion, since better wells are resulting from these larger fracture treatments and most of the hydraulic fracture volume is related to fluid rather than the relatively small volume of proppant concentrated in fractures located at or below the TVD of the lateral (˜ 95% water and 5% sand), the self-propped hydraulic fractures located above the lateral are likely contributing significantly to the achievement of higher estimated ultimate recoveries (EURs) of hydrocarbons in these more modern completions.

Another contributory cause for relatively low recovery efficiency in this area relates to the significant operational challenges related to artificially lifting these deep oil wells having long laterals (i.e., greater than 9,000 feet TVD and up to 21,000 feet measured depth (MD)). Current lift systems being used in these wells are predominately gas lift and mechanical rod pump. Gas lift is not optimum for late-life wells due to significant drawdown pressure limitations and is mainly used for deeper wells and for large, multi-well leases where gas lift is less expensive to operate compared to rod pump systems. Rod pumps are typically set around 1,000 feet or more above the base of the of the SRV to avoid rod/tubing wear caused by pumps set significantly below the horizontal well's kick off point. This pump setting configuration leads to stratified flow profiles and excessive back pressure on the reservoir (i.e., greater than 400 psi). Additionally, if the horizontal well is oriented in a downdip direction (i.e., the horizontal section has deeper TVDs as the well's MD increases), the effective backpressure on the SRV is even higher. Also, it is not uncommon for the horizontal well section to have an unintended undulating well path due to difficulties keeping the well trajectory stabilized toward the well's targeted bottomhole location at total depth (TD) during the drilling operation. These tortuous well paths introduce “pee trap” effects, which result in even higher backpressure in the horizontal section, cause the flow regime to become unstable (i.e., alternating slugs of liquids and gas), and lead to plugging of the cased horizontal wellbore from proppant flowback, fines, and completion debris during production operations with current artificial lift methods. Oil/gas slugging together with the associated abrasive solids sometimes contained within the fast-moving fluids also causes damage to the surface and downhole lift equipment.

Relatively constant gas-to-oil ratios (GORs) after the sand face pressure in a well's horizontal section drops below the oil bubble point pressure suggests bubble point suppression in the ultra-low permeability matrix (e.g., less than 10 nanodarcy). Bubble point suppression in the small oil-filled organic pore space of the EFVOT reservoir is thought to be caused by phase behavior changes related to the presence of kerogen and where pore-wall fluid interactions are significant due to confinement. Due to bubble point suppression within the organic pore space, natural gas remains in solution with the oil and therefore, the small gas molecules cannot move freely through the matrix. This effectively prevents depletion of the original reservoir pressure contained within isolated hydrocarbon-filled organic pore spaces during production operations even when they are located relatively close to connected hydraulic fractures. However, it is important to note that the gas quickly breaks out of solution within the open, pressure-depleted fractures and will tend to bypass the oil during production due to the higher mobility of natural gas than the more viscous crude oil.

In the geopressured EFVOT, the ultra-low permeability matrix may become micro-fractured around certain oil-filled organic pores located proximate to hydraulic fractures during production operations as the pressure drop at the interface between an open hydraulic fracture and an isolated hydrocarbon-filled organic pore exceeds the rock strength (e.g., reservoir pressure greater than 9000 psi and flowing bottomhole pressure-FBHP less than 2000 psi results in a pressure drop of more than 7000 psi across a short distance of formation rock). Slight shifting of rock fragments during these ongoing micro-fracturing events may result in persistent hydraulic communication between the “exploded” organic pore space and the complex hydraulic fracture network.

The connected pore space of an enhanced permeability region (EPR) adjacent to each stage-fractured horizontal section of a well includes both the hydraulic fracture volume and the nearby “exploded” pores. Initial flush production volumes exhibiting extremely steep exponential declines are believed to be correlative with the pore volume created around the EPR in the EFVOT. Typically, approximately half of each well's oil EUR is produced during the relatively short flush production period soon after the well is brought online. Late in the productive life of a well, the EPR is likely filled with heavier hydrocarbons due to the preferential flow of the lighter gas molecules into the well. The poor efficiency of prior art artificial lift systems coupled with low oil-to-gas mobility of EFVOT hydrocarbon fluids leads to the trapping of relatively “dead” (i.e., low GOR) crude oil, which is currently filling the connected pore volume in the EPR of each well's SRV.

Recovery efficiency in shale plays like the EFVOT using current state exploitation methods is also adversely affected by fracture hits or fracture-driven interference, which commonly occurs when fracture stimulating new infill “child” wells located close to previously produced “parent” wells. It is well known in the industry that fracture hits occur due to the lower stressed reservoir rock adjacent to the fracture networks of parent wells. This lower stressed rock condition is caused by pressure depletion from previous production operations. When conducting fracture stimulation operations on new infill child wells, hydraulic fractures will almost immediately orient themselves toward the fracture networks of parent wells due to the lower stressed rock. Fracture hits typically cause less complex bi-wing hydraulic fractures, which can extend for long distances away from new child wells being completed. These long bi-wing fractures can have relatively high conductivity but are not effective in developing shale and other ultra-low permeability reservoirs. Maximizing fracture complexity and surface area are first order drivers to successfully completing such low permeability reservoirs and are much more important to increasing well productivity and hydrocarbon recovery efficiency than fracture conductivity.

Among other issues, fracture hits are known to inhibit fracture complexity adjacent to the horizontal section of new infill wells due to production induced stress shadowing, thus reducing the effectiveness of child well completions. Fracture hits can also adversely affect the productivity of pressure-depleted parent wells due to interwell (between wells) hydraulic communication, thus dramatically increasing their production stream water cuts, which can increase liquid-loading and backpressure on their horizontal sections.

The subject matter of the present disclosure is described with specificity, however, the description itself is not intended to limit the scope of the disclosure. The subject matter thus, might also be embodied in other ways, to include different structures, steps and/or combinations similar to and/or fewer than those described herein, in conjunction with other present or future technologies. Although the term “step” may be used herein to describe different elements of methods employed, the term should not be interpreted as implying any particular order among or between various steps herein disclosed unless otherwise expressly limited by the description to a particular order. Other features and advantages of the disclosed embodiments will be or will become apparent to one of ordinary skill in the art upon examination of the following figures and detailed description. It is intended that all such additional features and advantages be included within the scope of the disclosed embodiments. Further, the illustrated figures and dimensions described herein are only exemplary and are not intended to assert or imply any limitation with regard to the environment, architecture, design, or process in which different embodiments may be implemented. To the extent that any conditions (e.g., temperatures, pressures) are referenced in the following description, those conditions are merely illustrative and are not meant to limit the disclosure.

The gravity assisted reservoir drainage system disclosed herein is directed toward an improved drainage architecture and artificial lift solution for significantly increasing hydrocarbon recovery from certain liquids-rich shale and other ultra-low permeability reservoirs, which were previously developed using closely spaced horizontal wells that were batch completed with large multi-stage hydraulic fracture treatments and produce with relatively low GORs. A conventional artificial lift system (e.g., using gas lift or a sucker rod mechanical pump) usually must be installed during the first year of production operations due to severe liquid loading causing the wells to stop flowing naturally. Within the first decade after producing these wells, oil and gas rates often have declined to near uneconomic rates in part due to inefficiencies related to the reservoir drainage architecture and the artificial lift systems being used. At this point, the production operation for such wells typically recovers only ten percent or less of the original hydrocarbons in place within the targeted completion zone and drainage area defined by half the distance to the nearest neighbor well on both sides of the well. The gravity assisted reservoir drainage system disclosed herein may be used to increase the recovery efficiency of these late-life, fully developed leases.

Implementation of a gravity assisted reservoir drainage system includes drilling a new, substantially vertical, well within a complex hydraulic fracture network created during the completion process of the preexisting closely spaced horizontal wells. More specifically, the new well may be located in close proximity to at least one of the closely spaced horizontal wells that has already been used for production and whose fracture network is partially pressure depleted compared to the original reservoir pressure.

If the borehole of the new well is located greater than 4 feet away from the outside of the production casing of the closest preexisting horizontal well, the new well may be completed with cemented production casing, perforations and a hydraulic fracture stimulation treatment. The stimulation treatment will be designed to create highly conductive bi-wing fractures that will extend from the new, substantially vertical child well and into the horizontal section of at least the closest offset horizontal parent well. In this manner, the new well completion will be in persistent hydraulic communication with at least the closest preexisting horizontal well.

If the borehole of the new well is located less than or equal to 4 feet from the outside of the production casing of the closest preexisting horizontal well and did not physically intercept the steel casing during drilling operations, the new well may be completed by running and cementing production casing prior to creating perforations which extend from the new well in the direction of the closest horizontal well and/or vice versa to create fluid communication between the new well and the closest preexisting horizontal well.

If the new well will physically intercept the steel casing of the closest existing horizontal well during drilling operations, the drill bit may be changed out for a mill in preparation for removing the portion of the closest horizontal well casing which is protruding within the path of the new well's borehole. Prior to commencing milling operations, at least one drillable plug will be run on coiled tubing in the casing of the closest horizontal well to isolate the perforation clusters of the original multi-stage hydraulic fracture treatments. After milling through the protruding horizontal well casing and drilling sufficient rat hole below the casing interception depth, the completion of the new well may begin by running and cementing production casing. After waiting on cement to setup, a mill and mud motor will be run into the production casing of the closest horizontal well on coiled tubing to remove the portion of the new well casing which is protruding within the inside of the closest horizontal well casing to create fluid communication between the new well and the closest horizontal well.

The new well may then be configured with a downhole pump (e.g., instrumented electric submersible or insert rod-driven pump) positioned in a “cased sump” located below or at least very near the perforations. The new well may include hole sections that are directional and a substantially vertical hole section located adjacent to the complex hydraulic fracture network.

The gravity assisted reservoir drainage system disclosed herein leverages and thus, overcomes the disadvantages of interwell hydraulic communication that exist in certain fully developed leases (e.g., EFVOT) as explained more fully below.

Perforation cluster efficiency can be defined as a measure of how the fracture fluid and proppant is distributed among the various perforation clusters in a given pumping stage. A perforation cluster is generally comprised of multiple perforations placed within one or two feet along the length of the casing in the horizontal section of a well and is considered a discrete fracture entry point. A typical single pumping stage in a horizontal completion in the EFVOT can have from four to more than ten perforation clusters along a length of casing in the horizontal section of approximately 250 feet. A higher perforation cluster efficiency value would indicate a more even distribution of fracture materials placed through each discrete perforation cluster of a given pumping stage. For example, 100 percent cluster efficiency for a ten-cluster stage being stimulated at an injection rate of 100 barrels per minute (BPM) would mean that each cluster was being treated at an average rate of 10 BPM during the pumping operation of that stage. In most shale and other ultra-low permeability reservoirs, poor perforation cluster efficiency often occurs in at least a few stages in most horizontal completions. This is particularly the case in older wells completed before 2016.

Contributory causes of poor perforation cluster efficiency may include (a) stress shadowing, (b) proppant settling toward the toe-side clusters as injection rates decrease and carry velocities are insufficient, (c) inertial effects due to density differences between the fracture fluid (e.g., water) and proppant (e.g., sand) causing increasing proppant concentration toward the toe of each stage as the relatively dense proppant bypasses heel-side clusters, (d) natural fractures or other planes of weakness located in close proximity to one of the perforation clusters, (e) minerology or in-situ stress anisotropy across the length of a stage, and/or (f) inadequate entry perforation strategies. Due to the combined effect of the first three causes of poor cluster efficiency listed above and in older completions that utilized inadequate entry perforating strategies, there was often a tendency for “heel-side bias.” In other words, for wells that used less modern completion designs, the clusters of a given stage located closer to the heel of the horizontal section of the well would tend to take a disproportionately large amount of the fracture fluid and proppant than the clusters located closer to the toe of the well.

Poor perforation cluster efficiency may result in “super clusters” that take significantly more than an equal share of the proppant and fluid pumped in a given multi-cluster stage. Super clusters have relatively simple bi-wing fractures and effective fracture half lengths that often greatly exceed the lateral well spacing. Multi-layer propped fractures resulting from “sand dune propagation” located at or below the TVD of the lateral well likely remain open late in the productive life of each well when the in-situ forces acting to close the fracture are greatest. Super clusters that extend between closely spaced horizontal wells and are partially filled with a significant quantity of proppant create persistent hydraulic communication between horizontal wells. This phenomenon is evidenced by interwell hydraulic communication (e.g., shut-in or fracture operations affecting production performance on the adjacent lease, pressure interference testing between wells, and other reservoir diagnostic techniques) and the success of multi-well rich gas injection IOR processes.

The near infinite hydraulic conductivity within the production casing in each horizontal wellbore facilitates movement of hydrocarbons and other subterranean fluids between the single-well complex fracture networks (i.e., SRVs) created from most of the fracture stages during the completion of each closely spaced horizontal well via the overlapping hydraulic fractures resulting from the super clusters. The typical inside diameter of the steel alloy production casing used in EFVOT horizontal wells is approximately 4.5 inches. The casing in the horizontal section has significantly greater conductivity than the connected hydraulic fractures of an SRV, which has much greater conductivity than the reservoir matrix permeability.

Therefore, since the new vertical well completion will be designed to have persistent hydraulic communication with at least the closest preexisting offset horizontal well via high conductivity bi-wing fractures, perforations, and/or a casing-to-casing well interception junction, it is effectively in hydraulic communication with many other closely spaced horizontal wells for a much larger drainage area. The lower take point in the common reservoir shared by the closely spaced horizontal wells enables the drawdown pressures to be significantly higher than conventional methods for artificially lifting horizontal wells. The improved reservoir take point architecture will also deliver benefits related to gravity drainage whereby incompressible liquids are more effectively fed to the pump while more of the natural gas is retained in the reservoir allowing it to expand and drive liquid hydrocarbons out of ancillary fractures and micro pore space, thus increasing hydrocarbon recovery.

In one embodiment, a gravity assisted reservoir drainage method is disclosed, which comprises: i) drilling a new well between two preexisting horizontal wells, wherein each preexisting horizontal well is located within a respective stimulated reservoir volume created during its completion and which includes at least one non-overlapping hydraulic fracture and at least one overlapping hydraulic fracture fluidly connecting the two preexisting horizontal wells; ii) forming at least one of a perforation and a casing-to-casing well interception junction fluidly connecting the new well and at least one of the two preexisting horizontal wells; iii) draining hydrocarbon fluids with gravity assistance from at least one stimulated reservoir volume through the at least one non-overlapping fracture of at least one of the two preexisting horizontal wells, the at least one of the two preexisting horizontal wells, and the at least one of the perforation and the casing-to-casing well interception junction into a bottom of the new well; and iv) pumping the hydrocarbon fluids from the bottom of the new well to a surface.

In another embodiment, a gravity assisted reservoir drainage system is disclosed, which comprises: i) a plurality of preexisting horizontal wells, wherein each preexisting horizontal well is located within a respective stimulated reservoir volume created during its completion and which includes at least one non-overlapping hydraulic fracture; ii) at least one overlapping hydraulic fracture fluidly connecting at least one of the plurality of preexisting horizontal wells to an adjacent one of the plurality of preexisting horizontal wells; and iii) a new well, wherein the new well is completed within a stimulated reservoir volume containing the at least one overlapping hydraulic fracture after completion of the plurality of preexisting horizontal wells and includes at least one of a perforation and a casing-to-casing well interception junction fluidly connecting the new well and at least one of the plurality of preexisting horizontal wells connected by the at least one overlapping hydraulic fracture.

In yet another embodiment, a gravity assisted reservoir drainage system is disclosed, which comprises: i) a plurality of preexisting horizontal wells, wherein each preexisting horizontal well is located within a respective stimulated reservoir volume created during its completion and which includes at least one non-overlapping hydraulic fracture; ii) at least one overlapping hydraulic fracture fluidly connecting at least one of the plurality of preexisting horizontal wells to an adjacent one of the plurality of preexisting horizontal wells; and iii) a new well, wherein the new well is completed within a stimulated reservoir volume containing the at least one overlapping hydraulic fracture after completion of the plurality of preexisting horizontal wells and includes at least one of a hydraulic fracture and a perforation fluidly connecting the new well and at least one of the plurality of preexisting horizontal wells connected by the at least one overlapping hydraulic fracture.

Referring now to, a conceptual plan view of a gravity assisted reservoir drainage systemis illustrated, which includes preexisting closely spaced horizontal wells in a complex hydraulic fracture network and a new, substantially vertical, well. As depicted by the formation dipand the roughly parallel and cased sections (,,,) of each horizontal well, the horizontal wells are drilled in a generally downdip direction. These wells are considered “toe down” well profiles because the TVD is deeper at each well's total depth than the TVD when each horizontal well enters the targeted reservoir near the end of its angle build section (i.e., the “heel” of the well). Each horizontal well includes a heel location (,,,), and a respective bottomhole location (,,,).

Each of the horizontal wells has been batch completed using a high intensity stage-fracturing operation with slick water to create a complex fracture network or “SRV” around each horizontal well, which is bounded laterally by half the distance to an adjacent well in both directions. The targeted SRV for each well (,,, and) is represented by a dashed rectangular-shaped box. Exemplary non-overlapping hydraulic fractures, which are isolated to a single horizontal well, and exemplary overlapping hydraulic fractures, which extend from one horizontal well to an adjacent horizontal well, are created during the batch stage-fracturing operation of the horizontal wells. The overlapping hydraulic fracturesextending from super clusters, which have multiple layers of proppant and a relatively high fracture conductivity at and below the TVD of the horizontal section of each horizontal well, contribute to the hydraulic communication between the horizontal wells.

A new, substantially vertical, wellmay be positioned about midway between the cased sectionsandat a location that overlies one of the initial fracture stages proximate to the bottomhole locationsand(e.g., near the toe of the cased sectionsand). The spacing between the new welland the adjacent horizontal wells (Well 1 and Well 2), for example, may be less than 220 feet if the spacing between Well 1 and Well 2 is less than 440 feet.

The new wellmay be completed with perforations and a specially designed hydraulic fracture stimulation treatment that will ensure a fracture hit with at least one of the adjacent cased sectionsandand persistent hydraulic communication via a new hydraulic fractureextending from the new wellto at least one of the adjacent cased sectionsand. The new wellthus, takes advantage of interwell hydraulic communication resulting from the original completion of the closely spaced horizontal wells using large, high intensity, multi-stage hydraulic fracturing that may have experienced poor perforation cluster efficiency in at least one stage of each well. The hydrocarbons may be drained into the new wellby gravity and the use of a combination of non-overlapping hydraulic fractures, cased sections (,,,), overlapping hydraulic fracturesand/or the new hydraulic fracturecreated during completion of the new well. For example, any hydrocarbons remaining within the reservoir matrix in targeted SRVcould flow into non-overlapping fractures, which could then flow into the cased sectionof Well 3, which could then flow into overlapping hydraulic fracturesto the cased sectionof Well 2, which could then flow into the new hydraulic fractureand finally into the new wellbefore being pumped to the surface.

illustrates an elevation view of the gravity assisted reservoir drainage systeminat a location near a down-dip fracture stage. Each downhole location (,,,) represents a location near a down-dip fracture stage that is near a total depth (i.e., close to the toe) for a respective horizontal well. The combination of non-overlapping hydraulic fractures, overlapping hydraulic fracturesand horizontal wells are hydraulically connected within a combined SRV. The non-overlapping hydraulic fracturesand the overlapping hydraulic fracturesare bounded vertically at the top of the combined SRVby an upper formation intervalthat is not prone to being hydraulically fractured. Likewise, the combined SRVis bounded at its lower end by a difficult to fracture lower formation interval.

The completed new wellincludes cemented production casingand perforationsthrough which a specially designed hydraulic fracture stimulation treatment may be pumped to create the new hydraulic fracture, which extends to the downhole locationsandfor Well 1 and Well 2, respectively, and provides persistent hydraulic communication between the new welland Well 1, Well 2. Production tubing, sucker rods, and a downhole insert pumpare run in the new wellprior to initiating production. The insert pumpis preferably located below the bottom of the perforationsand the lower formation intervalfor a lower take point in the reservoir.

illustrates a cross-section view of a conventional gas lift systemA for use within one or more of the horizontal wells shown in. A preexisting horizontal wellincludes a horizontal sectionand is completed using cemented production casingwith hydraulic fracturesand. Additionally, a gas lift system has been installed within horizonal well, which includes production tubingset near the beginning of the horizontal section, a packer bypass, which allows for a deeper gas injection point during gas lift operations, and gas lift valves.

During production operations, a high-pressure natural gas is injected down the tubing/casing annulusto an endof the production tubingwhere the gasified crude oil and formation water mixture flows up the production tubingto the surface. Mixing the injected natural gas with oil/water mixture lightens the hydrostatic head of the fluid in the production tubingand uses the available FBHP to facilitate a flowing condition for horizontal well. As the horizontal wellproduces with gas lift, a stratified flowoccurs due to gravity separation whereby substantially liquid-free gas is flowing at the top of the horizontal sectionwhile liquid with a higher water cut is flowing at the bottom of horizontal section. Gravity separation in the horizontal sectionoccurs due to the relatively low fluid velocityof the crude oil, natural gas, and formation water production stream entering the production casingfrom hydraulic fracturesand. The hydraulic fractureshave a higher GOR than the hydraulic fractureslocated below the TVD of the horizontal section.

The FBHP at the midpointof horizontal sectionfor a typical gas lifted horizontal wellcan be estimated by summing the flowing tubing pressure (FTP), the hydrostatic head of the oil/gas/water mixture contained within the vertical section of the tubing, fluid friction caused by the fluid mixture flowing up the tubing, and the hydrostatic head of the oil/gas/water mixture contained in the horizontal sectionof the well due to formation dip (applicable to toe down well profiles) and the thickness of the SRV. For a typical 12000 feet TVD horizontal oil well with a producing GOR of less than 2500 standard cubic feet per barrel of oil (SCF/BBL), a 6000 lateral feet toe down well profile, formation dip of 3°, 100 feet of SRV thickness, and 0.85 gravity fluid, the FBHP is estimated to range from 300 to 1000 psi depending on the FTP resulting from local gas compression facilities.

illustrates a cross-section view of a conventional rod pump lift systemB for use within one or more of the horizontal wells shown in. A preexisting horizontal wellincludes a horizontal sectionand is completed using cemented production casingwith hydraulic fracturesand. Additionally, a rod pump lift system has been installed within horizonal well, which includes production tubingset substantially above the horizontal sectionnear a directional kickoff pointwhere the well inclination begins to increase from ˜ 0° (vertical) to ˜ 90° (horizontal), a downhole insert pump, and sucker rods.

During production operations, the sucker rodsreciprocate with the insert pumpand are designed to lift gas-free crude oil and waterfrom the TVD where the pumpis set to surface while dry natural gas flows up the tubing/casing annulusdue to the configuration of the pump intake and gravity separation. Mechanical pumps like insert pumpare designed to pump incompressible fluids, however, it is not uncommon for natural gas to be inadvertently sucked into the intake of the insert pump, which significantly reduces the pump efficiency as the compressible gas simply expands and contracts as the insert pumpreciprocates without passing through the traveling valve in the insert pump. Less gas would enter insert pumpif it were possible to locate the insert pumpbelow the reservoir, but that is not possible for horizontal wells using prior art reservoir drainage architectures and artificial lift methods. Immediately below the intake of insert pump, an area of unstable flow with alternating slugs of liquid/gas and frothy fluid exists, which contributes to the problem of natural gas entering insert pump.

As the horizontal wellproduces with rod pump lift, a stratified flowoccurs due to gravity separation whereby substantially liquid-free gas is flowing at the top of the horizontal sectionwhile liquid with a higher water cut is flowing at the bottom of horizontal section. Gas channelingoccurs along the top of the production casingin the horizontal sectiondue to the significantly higher mobility of natural gas compared with crude oil or formation water (i.e., natural gas has much lower viscosity than formation liquids). Gravity separation in the horizontal sectionoccurs due to the relatively low fluid velocityof the crude oil, natural gas, and formation water production stream entering production casingfrom hydraulic fracturesand. The hydraulic fractureshave a higher GOR than the hydraulic fractureslocated below the TVD of the horizontal section.

For typical horizontal wells in liquids-rich shale and other ultra-low permeability reservoirs, the distance from the TVD of the directional kickoff point(where insert pumpis typically set) to the average TVD of the base of the SRV is greater than 1000 feet. With this well/reservoir architecture, the available FBHP (i.e., remaining reservoir pressure in the SRV less fluid friction) is required to lift the formation liquids approximately 1000 feet to the intake of insert pump. Also, because of gas channeling, a significant amount of the available FBHP is bled off because the higher mobility natural gas bypasses formation liquidson their way up to the intake of insert pump. It would be better if the production tubingand insert pumpsetting depth was deeper in the horizontal wellbut doing so would introduce costly damage to the sucker rodsand production tubingdue to abrasion wear as the sucker rodsreciprocate in an up and down cycle more than 10,000 times per day.

Also, if the FBHP and/or SRV and reservoir matrix is not feeding a sufficient volume of liquid to the intakeof the insert pump, the horizontal wellis in a pumped-off condition. A pumped off condition occurs when the fluid level in the casing/tubing annulusis at or below the intake. Conventional rod pump lift systems are designed to have the intake always submerged completely in liquid and when they are not, significant damage can occur to the insert pump, the sucker rods, and other artificial lift equipment. Similarly, gas/liquid sluggingnear the intakecan also damage the artificial lift equipment. Tortuous and/or downdip intervals of the horizontal sectiontypically increase backpressure on hydraulic fracturesandand contribute to damaging erratic slug flow.

The FBHP at the midpointof horizontal sectionfor a typical rod pump lifted horizontal wellcan be estimated by summing the flowing casing pressure (FCP), the hydrostatic head of the dry gas contained within the vertical section of the tubing/casing annulus from the insert pumpto the surface, the hydrostatic head of the oil/water/gas mixture flowing up the production casingin the angle build section of the horizontal wellfrom the TVD of the directional kickoff pointto the TVD of the horizontal section, and the hydrostatic head of the oil/gas/water mixture contained in the horizontal sectiondue to formation dip (applicable to toe down well profiles) and the thickness of the SRV. For a typical 12000 feet TVD horizontal oil well with a producing GOR of less than 2500 SCF/BBL, a 6000 lateral feet toe down well profile, formation dip of 3°, 100 feet of SRV thickness, and 0.85 gravity fluid, the FBHP is estimated to be greater than 400 psi depending on the FCP resulting from local gas compression facilities.

In, a cross-section view of a gravity assisted reservoir drainage systemC is illustrated, which includes a preexisting horizontal wellin a complex hydraulic fracture network and a new, substantially vertical, well. The horizontal wellis configured without any production tubing or artificial lift system and feeds crude oil and formation water to the new wellvia new hydraulic fracturescontained within the complex hydraulic fracture network of the combined SRV, which also includes non-overlapping hydraulic fractures.

The new wellis completed with cemented production casingand perforationsthrough which a specially designed hydraulic fracture stimulation treatment is pumped to create new hydraulic fractures, which extend to the horizontal sectionof the horizontal well. The new hydraulic fracturesare filled with proppant, permeable grout, or other permeable media to ensure they remain open and conductive throughout the productive life of the new well. Alternatively, the new hydraulic fracturesmay be treated with acid to enhance their conductivity. Production tubingand an instrumented downhole electric submersible pump (ESP)are run into the production casingof the new wellprior to initiating production. The intake for the pumpis preferably positioned below a bottom of the perforationsand a lower formation intervalof the combined SRVfor a lower take point in the reservoir.

During production operations, the pumpmechanically lifts crude oil and water up the production tubingwhile dry gas is produced up the tubing/casing annulusof new well. The pumpis instrumented with downhole electronic sensors to allow the liquid levelin the tubing/casing annulusto be regulated such that the pumpis always submerged in liquid and never pumps off. In the horizontal sectionof horizontal well, crude oil and formation waterflows into hydraulic fracturesand, which are hydraulically connected with the new hydraulic fracturesthrough the combined SRVto feed into perforationsand down through the tubing/casing annulusto the intake of the pump. If the horizontal wellis shut-in, the dry gaswill enter hydraulic fracturesand migrate up toward an upper formation intervalof the combined SRVwhile displacing oil in pore space/ancillary fractures to enhance crude oil recovery via the pump. If the horizontal wellis open to production, dry gasis produced up the production casingof the horizontal wellbecause of the density difference between formation liquids and natural gas. In this case, the FBHP at the midpointof horizontal sectioncan be estimated by summing the FCP of horizontal welland the hydrostatic head of the dry gas contained within the vertical section of the production casingfrom the midpointof horizontal sectionto the surface. For a typical 12000 feet TVD horizontal oil well with a producing GOR of less than 2500 SCF/BBL, a 6000 lateral feet toe down well profile, formation dip of 3°, 100 feet of SRV thickness, and 0.85 gravity fluid, the FBHP is estimated to be less than 80 psi depending on the FCP resulting from local gas compression facilities.

Referring now to, a perspective view of a gravity assisted reservoir drainage systemis illustrated, which includes preexisting closely spaced horizontal wells, the complex hydraulic fracture network created during the completion of those horizontal wells, and a new, substantially vertical, well. A surface padprovides the surface location for preexisting, closely spaced horizontal wellsthat were used to produce liquids-rich hydrocarbons from the complex hydraulic fracture network of a combined SRV. The horizontal wellswere drilled in a downdip direction.

A new, substantially vertical, wellincludes a downhole instrumented ESP or other mechanical pumpin a cased sump near or below a lower formation interval of the combined SRVand is positioned about midway between two of the horizontal wells. The horizontal wellsare in hydraulic communication because of overlapping hydraulic fractures created during their original completion using batch multi-stage fracturing. The horizontal wellsare also in hydraulic communication with the new wellbecause of one or more overlapping hydraulic fractures created during completion of the new well.