Lateral gas lift with slugging control

Abstract

Gas lift technologies can produce more oil from longer laterals. By placing gas injection in the lateral well, deep gas lift improves oil production and maintains pressure in the lateral to reduce or prevent sand production and degradation of the lateral well.

Description

Docket No.: 42766WO01LATERAL GAS LIFT WITH SLUGGING CONTROLFIELD OF THE I NVENTION

[0001] The disclosed methods relate generally to producing hydrocarbon liquids from lateral wells.BACKGROUND OF THE INVENTION

[0002] As technology advances, the trend in oil production is longer horizontal wells (Rassenfoss, 2022). Tight reservoir production in fractured lateral wells has created a large number of long lateral wellsfor oil production. As lateral length increases, greater challenges are presented. Some wells are 2-3 miles of horizontal length or longer. From a production standpoint, the use of longer laterals allows greater stimulated rock volume per wellbore. Although these longer wellbores will start with higher flow rates, the longer length also introduces greater dynamic behavior and possibly steeper production declines. The longer extended well trajectories may also have higher dogleg severities, higher gas / oil ratios (GORs), and produce more sand and solids (Whitfield, 2023; Spencer, 2021). Many new developments have focused on improving horizontal well location, drilling, fracturing and completion. Unfortunately, as slugging increases the difficulties of continued production may result in oil resources being left in the ground and the well abandoned. New technologies are required to further improve production throughout the life cycle of longer lateral wells.SUMMARY OF THE I NVENTION

[0003] Addressing these challenges, the present invention uses unique gas lift technologies to produce more oil from longer laterals with fewer workovers and offers better gas / oil ratios. By placing gas injection in the lateral well, deep gas lift improves oil production and maintains pressure in the lateral to reduce or prevent sand production and degradation of the lateral well.

[0004] A novel method has been conceived and demonstrated to control liquid slugging, reduce liquid inventories in the lateral and extend the productive life of wells with long horizontal sections. The invention extends tubing in the lateral section of the well where gas injection is delivered in the lateral versus in the vertical section of the well. This injection can be near the toe, mid-lateral (as was demonstrated in Figure 7) or at the toe. In fact, any location in the lateral will provide benefits for slugging control. The injection gas can be delivered through the tubing stringDocket No.: 42766WO01 and production received from the annular space between the tubing and the casing. Alternatively, one or more cross-over packers can be used to move the gas injection the annuls in the vertical section and then to the tubing in the lateral section. Production would then move in the annular section in the lateral and cross-over the to the tubing in the vertical section.

[0005] The invention more particularly includes gas injection tubing apparatus for producing hydrocarbons from a hydrocarbon reservoirs, the gas injection tubing installed in a lateral casing (e.g. of a lateral well) in a hydrocarbon reservoir, the gas injection tubing having one or more controllable gas injection valves, the gas injection valves controlled by a processor, and a computer memory in which is stored a model for deep gas lift modeling gas injection, oil flow, gas flow, and water flow.

[0006] In one embodiment, a method of producing hydrocarbons from a hydrocarbon reservoirs provided where a lateral casing (e.g. of a lateral well) in a hydrocarbon reservoir is equipped with a gas injection tubing having one or more controllable gas injection valves, the gas injection valves being operated with a processor, modeling deep gas lift to control gas injection rates, oil flow rates, gas flow rates, and water flow rates, and modulating gas injection (optionally based on models produced by said modeling) to improve oil production and reduce the volume of gas injected.

[0007] Multiphase meters are used to monitor gas, oil, and water production during different pressure regimes. Modeling of the expected production can be used to modify injection to improve production. In another example fluctuations in production can trigger increases in gas injection to disrupt slugging. In another example, increased GOR can trigger decreases in gas injection to prevent excess gas maximizing production per volume of gas used.

[0008] The gas injection tubing may have multiple controllable valves located at different features along the lateral well. Valves may include a post-heel valve, heel valve, a pre-heel valve, a mid-lateral valve, a toe valve, a pre-dip valve, dip-valve, post-dip valve, or a combination of valves. Valves may also be placed at different features in the well, such as a pre-dip valve, dipvalve, and post-dip valve, each valve having a different pressure to promote fluid flow through the feature and prevent slugging within the feature. Valves may also be arrayed along upward slopes in the lateral well to promote flow toward the heel of the well.

[0009] The gas injection tubing can contain pressure activated gas injection valves with different activation pressures allowing injection control by changing injection pressure. In one example,Docket No.: 42766WO01 pressure can be cycled to begin injection at the toe and move injection down the tubing string as pressure is increased.

[0010] The gas injection system can be utilized to remove debris from the lateral well by moving gas injection from the toe of the lateral well to the heel of the lateral well. As described in more detail below, a variety of method can be used to create a pressure wave from the toe to the heel of the well moving debris in front of the pressure wave, creating a "sweep."

[0011] The gas injection system may also be used with choke devices to reduce or control fluid flow. Gas injection followed by a choke device can speed fluid flow especially when the choke and gas injection are coordinated with low elevations in the lateral well to move fluid through troughs and prevent back-slip into the trough.

[0012] Production modelling and gas injection provides an active method to reduce or prevent slugging entirely. Identifying key slugging indicators and increasing gas injection at those critical times optimizes gas injection.

[0013] Controlled gas injection provides multiple improvements for lateral production including reducing liquid inventory in the lateral well, deliquefying connected fracture systems, reducing gas slip of reservoir liquids, removing stagnant fluid at the toe of the reservoir, reducing the severity of slugging; improving gas oil ratio (GOR), reducing the volume of gas injected, and improving reservoir economics.

[0014] In another embodiment, using gas injection at or throughout the heel can prevent fluid buildup and slugging in the heel. For toe-up lateral well geometries, slugging at the heel can be effectively controlled by injecting gas through two or more controllable valves in the heel of the reservoir to prevent fluid buildup and reduce or completely prevent severe slugging. Stabilizing flow in the heel can be accomplished on all wells through strategic placement of controllable injectors within the heel.

[0015] In one embodiment, the gas injection system may be used to treat toe-down lateral well geometries, injecting gas at the toe of the lateral to move liquids toward the heel and prevent fluid build up and reservoir congestion at the toe of the reservoir. In longer lateral wells, fluid buildup in the toe, or at low elevations of the lateral can block fractures and reduce fluid production along the saturated portions of the wellbore.

[0016] Additional equipment may be included with the gas injection tubing including a variety of sensors as well as additional strings including distributed acoustic sensing (DAS), capillary strings,Docket No.: 42766WO01 control lines, independent sensor strings that may include multiple sensors, a production tubing, and other well strings.

[0017] A variety of well treatments may be injected through the gas injection system into the well including corrosion inhibitors, scale inhibitors, paraffin treatments, hydrate inhibitors, coatings, surfactants, cleaners, self-assembling monolayers, emulsifiers, sulfur reducers, chelators, biocides, acids, catalysts, tracers, and the like. The benefit to injecting the well treatments with the present system is that the treatment can be isolated to those areas where the injection will provide the most benefit. The controllable gas injection can also be used to inject closer to the toe for whole well treatments or along the lateral providing a more even coverage on both the top and bottom of the lateral well. Wirelines and other treatment methods cannot always reach the entirety of longer lateral wells.

[0018] As used herein the wellbore is described in three portions, the vertical portion which extends from the wellhead to the heel of the well, the heel of the well, and the horizontal also called the lateral portion which extends from the heel of the well to the toe of the well. Although the terms vertical and horizontal are used to describe sections of the wellbore, the vertical and horizontal portions are not always perfectly straight or perfectly vertical or horizontal and may have variation, doglegs, and dips and the like

[0019] As used herein "Gas Lift" (GL) refers to the injection of gas within the wellbore to lift liquids to the surface. Traditionally, vertical gas lift has been injected in the vertical portion of the wellbore above the heel of the well.

[0020] As used herein, Annular Velocity Enhancement (AVE) provides a reduction of the cross- sectional area in a lateral well and the addition of gas lift to long horizontal wells, specifically recommended for toe-down wells (Pohler, 2010). AVE uses a traditional GL apparatus with an extended portion of the gas injection attached to the distal end of the GL equipment and does not provide valves or control of the gas injection in the toe of the well. AVE also uses a larger tubing to occupy most of the internal diameter of the lateral well.

[0021] As used herein "Deep Gas Lift" (Deep GL) refers to controlled injection of gas within the horizontal portion of the wellbore beyond the heel of the well. Deep GL is unique from AVE in that it provides valves and control of gas injection beyond the heel of the well and into the horizontal portion of the well. "Toe Gas Lift" (Toe GL) refers to injection of gas within the toe of the well bore. "Deep Gradient Gas Lift" (DGGL) refers to injection of gas at multiple locations from the toeDocket No.: 42766WO01 to the heel of the well bore at different rates dependent upon the gas injection point and local conditions of the horizontal well within the reservoir.

[0022] As used herein, a "Multiphase Meter" (MPM) is an inline meter that measures the individual flow rates of oil, gas, and water as the multiphase fluids flow through a cross-section of conduit. The volumetric fraction of each phase are calculated as the fluids flow through the meter and those volumetric fractions are recorded in real-time.

[0023] The present invention provides a novel method of DGGL by plotting the liquid flow and slugging properties along the wellbore, differential injection can improve liquid production and GOR by maximizing fluid lift and minimizing excess gas injection. By tracking lifting properties, transition between lift types and globally monitor lifting properties across multiple wells, DGGL gas lift properties can be optimized, identifying production efficiencies and reducing excess gas injection. Improving lift efficiency and maximizing production with minimal gas injection reduces overall emissions and expenses.

[0024] Changing gas injection rate allows stratification of the liquid inventory in the lateral further improving fluid production and reducing slugging. By pushing from the toe, flow is encouraged by stratification and streaming. Keeping a steady stream of gas encourages steady flow, fluctuations in gas can cause slugging and push fluids toward the proximal end of the well.

[0025] Providing injectors at low points coordinated with toe injection can further improve fluid movement in a stratified state. In one embodiment, by pressure activated valves, that open at or above set pressures can be used to coordinate valve opening. In another embodiment, inline regulators can be used to limit or allow pressure to be ramped up moving valve opening up and down the horizontal well bore.

[0026] In yet another embodiment, controlled valves are placed at different locations and opened to varying degrees to improve liquid flow, as production associated with gas volumes at different locations is monitored and production modeling improves, gas flow is further optimized along the wellbore. Controlled valves are installed with techline controlling electric valves or hydraulic controls can be installed along the exterior of the injection tubing. In one embodiment, the injection tubing has pressure, temperature, float, and / or fluid saturation sensors allowing the controlled opening and pressure release at different locations along the lateral injection line. Coordinated gas flow further improves fluid movement and maintains pressure behind fluid slugs as they progress along the well.Docket No.: 42766WO01BRI EF DESCRI PTION OF DRAWI NGS

[0027] The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee. A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings.

[0028] Figure 1 shows Flow Pattern in the Lateral progressing from panel (a) with early production to panel (b) which shows steady flow. Panel (c) shows slugging with fluid followed by gas, and finally panel (d) shows fall back and stratification of the liquid and gas along the entire length of the tubing.

[0029] Figure 2 shows a variable long lateral with dips that cause slugging.

[0030] Figure 3 is a model of Flow in the Lateral under varying conditions. Figure 3A shows gas injection only, while Figure 3B shows gas injection with chemicals to improve stratified flow.

[0031] Figure 4 is a diagram of Annular Velocity Enhancement (AVE).

[0032] Figure 5 shows a diagram of TVD for the selected well.

[0033] Figure 6 shows Multiphase Flow Modeling in the Pre-Pilot Conventional GL (Fig. 6A) and with Mid-Lateral GL (Fig. 6B).

[0034] Figure 7 is a diagram of the pilot well completion showing the casing with gas lift tubing along lateral well.

[0035] Figure 8 is an overview of raw production data showing production with an ESP, Conventional GL, and GL in the lateral.

[0036] Figure 9 the Initial Pilot Results indicate that production is stabilized.

[0037] Figure 10 Shows the initial pilot results with Figure 10A showing Oil Rate, Figure 10B showing Water Rate, and Figure 10C showing the Gas Rate.

[0038] Figure 11 is MPM Rates are shown: Figure 11A provides Liquid Production, Figure 11B Provides Oil Production and Figure 11C provides water production.

[0039] Figure 12 is Multiphase Meter (MPM) Rates where Figure 12A is oil production, Figure 12B shows the percent difference in oil production. Figure 12C shows gas production and Figure 12D shows the percent difference in gas production.

[0040] Figure 13 is Step Rate Testing - Impact of Gas Injection.

[0041] Figure 14, MPM Rates (May-June) provided more consistent rates.

[0042] Figure 15 is Field Data - Bottom Hole Pressure (BHP).Docket No.: 42766WO01

[0043] Figure 16 looking at bottom hole pressure at 12696 ft.

[0044] Figure 17 shows fluctuations in BHP on different production days.

[0045] Figure 18 is Liquid Volume in Annulus, Figure 18A shows the liquid volume in the annulus while figure 18B compares liquid volume to bottom hole pressure at 8861 ft.

[0046] Figure 19 is Superficial Velocity and Flow Regime.

[0047] Figure 20 is Liquid Holdup and Pressure.DETAI LED DESCRIPTION OF TH E I NVENTION

[0048] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

[0049] As shown in Figure 1, a standard well design, in an ideal world the heel would be the lowest spot in the lateral and all well fluids would naturally drain to the heel. Unfortunately, as shown in Figure 2, lateral wells are not perfectly level slanting gradually over the entire length of the lateral, but rather have dips and variations in elevation that can trap fluids along the length of the lateral well, the lateral, also known as the horizontal portion, of the well must also follow reservoir stratification which can cause the toe to dip or create dips along the length of the horizontal well. Because the horizontal well has variation, the changes in direction and fluid level can create severe slugging. If slugging is generated along the 2-4 mile horizontal section, it can cause dramatic pressure fluctuations that can pull sand from fractures and possibly even damage the reservoir equipment and reduce reservoir reliability.

[0050] Traditionally, GL methods have been mainly limited to vertical section of well. By transferring GL injection to the horizontal portion of the well or even the toe, with Deep GL or Toe GL, pressure can be stabilized along the length of the horizontal well and reduce or eliminate slugging and maintain a steady pressure withing the horizontal portion of the well. Toe GL provides unique opportunities to reimagine lateral well design and provides unique methods to produce fluids from the horizontal portion of the wellbore. DGGL provides a unique opportunity to vary gas pressures along the lateral wellbore correcting imperfections in the lateral design by increasing gas flow where slugging occurs and reducing gas flow where drainage is sufficient toDocket No.: 42766WO01 move the volume of fluid present. By monitoring pressure, drops in pressure and sand production can be reduced, further improving operational efficiency and production.

[0051] By combining Deep GL, Toe GL, and / or DGGL, with flow management regimes, chemical treatment and controlled production chokes, severe slugging can be prevented and production improved. Using controlled valves, chemical treatments can also be strategically delivered to address specific problems, for example if paraffin formation is identified at one location in the well, such as a depression in the horizontal wellbore, warm treatment fluid can be delivered to the nearest valve to break up the paraffin buildup without having to heat the entire length of the wellbore or provide chemicals to the entire length of the wellbore. Treatment can be limited to the section that requires treatment. Treatments can be applied for scale, corrosion, hydrate formation, paraffin buildup, sand deposition, and the like. Sand management can be improved by "sweeping" the wellbore from the toe to the heel. In one embodiment gas or fluid is injected at high pressures at the toe of the well for a period sufficient to push wellbore contents beyond the next valve, once debris is pushed past the valve the next valve is opened, maintaining pressure at the toe and the first valve, pushing debris to the next valve. Once debris is pushed past the next valve, it is opened creating a wave of pressure from the toe toward the heel of the reservoir. The process is repeated for each valve until full pressure is achieved along the length of the well and all debris has been removed to the heel of the well where the debris can be lifted out of the well. In another embodiment, pressure may be reduced in prior valves as subsequent valves are opened, this will maximize pressure at the "pushing valve" while still maintaining pressure behind the sweep. In some cases, prior valves may be closed, although this is typically not recommended as backflow can be created as reduced pressure behind the sweep can pull debris back to the toe of the well.

[0052] In figure 3, Modeling shows how slugging can be modified and driven to a stratified flow. Slug lengths can be calculated in vertical pipe and horizontal pipe as well as through troughs in the horizontal wellbore. Vertical pipe with a length / diameter ratio of 36-64 (L / D = 36-64) will have different slug lengths dependent upon the pipe diameter - for a 2 2 / 8 inch (4.7# 1.995 inch ID) the Ls|Ug is 5-11 ft; for a 2 7 / 8 inch (6.5# 2.441 inch ID) Ls|ugis 6.5-13ft. The horizontal pipe has different slugging characteristics as described by Scott, Brill, & Lee Correlation where a 5 / i inch (20# 4.778 inch ID) has a Ln(Ls|ug) of -26.6 +28.5 [ln(d) + 3.67] 0.1 giving a Ls|ugof 197 ft in the later or Ls|ugof 387 ft at the surface. This is further complicated by severe terrain slugging that can occur in the lateral wellbore dependent on the length of the slugging volume in the lateral wellbore.Docket No.: 42766WO01

[0001] A long history with Gas Lift in the lateral, including a toe lift, a Deep GL & AVE, and studies in multiple wells in a variety of formations. Figure 4 shows an early Deep GL project where a cleanout was performed and standard GL used, note the low levels of oil productions and increased water production. A subsequent cleanout and installation of Deep GL allowed improved oil production. In order to further improve production and overcome issues with Annular Velocity Enhancement (AVE) by placing tubing in the lateral to increase annular velocities, Deep Gas Lift placing gas injection point from the heel into the lateral of the wellbore, and Toe GL were proposed.Example 1: Pilot Mid-Lateral (Deep) Gas Lift

[0002] The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.

[0003] To accurately quantify Deep GL, as study was conducted. Pilot well 1 (as depicted in Figure 5) was fitted with mid-Lateral gas injection to allow direct comparison of convention GL with Deep GL (Mid-Lateral GL) in Figure 6. A diagram of a Deep GL system are shown in Figure 7. The purpose of this study was to validate slugging control and gather pressure data in the lateral to improve modeling.

[0004] To demonstrate the production uplift from deeper gas injection and its effects on slugging and inflow as well as liquid velocities and liquid holdup in the lateral. A mid-life well with a production rate of around 400 BLPD was selected as a pilot mid-lateral gas lift trial. Figure 5 shows a diagram of TVD for the selected well. The well was first converted from an ESP to a tubing-flow GL system with gas injection near the heel prior to extending the GL into the lateral for the pilot. The theory behind choosing an older well is to understand how we can pull pressure off the toe half of the lateral to have solutions ready as the longer 3+ mile lateral wells age. Data Collection - A surface Multiphase Meter (MPM) was installed to provide high-resolution real-time data. PrePilot Modeling -Atransient multiphase flow model indicated significant impacts on liquid holdup, slugging and and a production uplift.

[0005] Figure 6 shows Multiphase Flow Modeling in the Pre-Pilot Conventional GL (Fig. 6A) and with Mid-Lateral GL (Fig. 6 B). Mid-Lateral GL reduced slugging as a lower Qinj and increased Oil Rate uplift an estimated 22%. As shown in Table 1, modeling used a Transient Multiphase Simulator Matched to Pre-Pilot GL Data. The Deep GL benefits were confirmed in an observedDocket No.: 42766WO01 approximately 20% uplift provided by injecting deeper and reduced slugging provided by controlling injection rates.TABLE 1:

[0006] Figure 7 is a diagram of the pilot well completion showing the casing with gas lift tubing along lateral well. The casing is ~10,000 ft of 5 / " casing 20#, the gas lift tubing Annular Flow GL, i.e. no Packer, 31 / 2-inch Flush-Joint Tubing in Vertical (a fairly common tubing size that is readily available), 27 / 8-inch Tubing in the Lateral, Redundant Memory Gauges in Lateral, Gas Lift System, Fluid Mandrels in the Vertical Section, i.e. no upset, Conventional 20 / 64" Sonic Flow Venturi Orifice Valves Installed. Key Components - Annular Flow Gas Lift, Novel Use of 3 J -inch Tubing in the Vertical Section to Help with Lift, Redundant Memory Gauges, Some GL Valves in Vertical Wellbore, Redundant Orifice Valves in Lateral.

[0007] Figure 9 the Initial Pilot Results indicate that production is stabilized. Table 2 Initial Performance (test data) were favorable including 21% Higher Stabilized Oil Rate, Higher Gas (50% higher GLR), Lower Water Rate (10%) and a Return to Baseline Oil Rate. Although measurements could be improved, the overall success of the project has been documented.Table 2 Initial Performance (test data)Docket No.: 42766WO01

[0008] As shown in Figure 10, initial pilot results with Figure 10A showing Oil Rate, Figure 10B showing Water Rate, and Figure IOC showing the Gas Rate. Gas Injection Mid-Lateral Seems to be Impacting Water and Gas Rates, perhaps Shifting Inflow to Different Frac Wings in the Lateral

[0009] Figure 11 shows MPM Rates Good agreement seen between Liquid production (Fig. 11A) Oil production (Fig. 11B) and Water production (Fig. 11C), especially when NGL rates are included in the liquid rates.

[0010] Figure 12, is Multiphase Production Meter (MPM) Rates where Figure 12A is oil production, Figure 12B shows the percent difference in oil production. Figure 12C shows gas production and Figure 12D shows the percent difference in gas production.

[0011] Figure 13, Step Rate Testing - Impact of Gas Injection general trend is Higher Rates with Higher Gas Injection, but some Lag Time.

[0012] Figure 16, the bottom hole pressure at 12696 ft shows good agreement between model predicted and measured BHP. For some days, the reported casing head pressure may be erroneous, but even with changes in casing head pressure, 79 out of 86 days had a relative error less than 10%.

[0013] Figure 17, BHP is depicted on different production days. Severe slugging was predicted at the beginning of pilot, but Severe slugging reduces as production continues, and eventually disappears after April 22nd. However, hydrodynamic slugging may continue to exist.Docket No.: 42766WO01

[0014] Figure 18, Liquid Volume in Annulus, shows changing liquid volumes in the annulus which fluctuates between 35-65 bbls of liquid in the annulus between wellhead and gas injection point.

[0015] The invention provides a "Push - Pull" model for lateral Gas Lift, demonstrating that mid to late life well production benefits from "pushing" liquids from the toe rather or some other location in the lateral than "pulling" them from the vertical section of the wellbore, via conventional GL. Gas injection in the lateral significantly altered the velocity distribution of liquids and, to a lesser extent, the pressure distribution. The increased gas velocities in the lateral versus in the vertical section act to alter the flow pattern, moving from a stratified flow, which gives rise to severe slugging and terrain slugging, to the convention slug flow regime where small "hydrodynamic" slugs are produced. The new Deep GL design more effectively removes liquids from the lateral section than conventional gas lift. The impact of reduced liquid inventories in the lateral wellbore will also improve liquid recovery from the fracture systems connected to the lateral and feeding the lateral further increasing fluid production.Example 2: Improved Control

[0016] DGGL provides a unique opportunity to vary gas pressures along the lateral wellbore correcting imperfections in the lateral by increasing gas flow where slugging occurs and reducing gas flow where drainage is sufficient.

[0017] Lifting in the lateral has provided an economic way to improve production from long laterals with the operational benefit of controlling lateral pressure and improving production consistency. Deep GL, Toe GL, and DGGL can be applied to a variety of reservoir types including unconventional, conventional, SAGD, and tight gas wells to improve production and reduce slugging. Continuing to improve our understanding of flow regime in the horizontal, section of a well, in the heel of the well, and transitioning to the vertical section of the well, will provide consistent transitions and better production. Modeling multiphase flow in horizontal wellbores will allow us to further refine gas lift in the lateral in dramatically improve production. As we continue to validate our assumptions regarding outflow in the toe region, slugging, and potential reserves impairment, we can better refine production practices in long lateral wells.

[0018] Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways toDocket No.: 42766WO01 practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

[0019] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as an additional embodiments of the present invention.Docket No.: 42766WO01REFERENCES

[0020] In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. Each of the references below is incorporated in their entirety for all purposes.US11649704, (Scot, Stuart) “Processes and systems for injection of a liquid and gas mixture into a well,” (2018). US 11746651, (Zhou, et al.) “Integrated Machine Learning Framework for Optimizing Unconventional Resource Development,” (US20230151720, (Scott, S.L. & Williams. A.P.) “System and method for enhanced oil recovery utilizing alternating stacked liquid and gas slugs,” (2020).Brill, et al.. “Analysis of two-phase tests in large-diameter flow lines in Prudhoe Bay field,” SPE J. 21 (03): 363- 378. (1981) doi.org / 10.2118 / 8305-PACope, B. & Gilmore, D. “Gas Lift-Plunger Lift Combination Creates Full Life Cycle Production Solution,” Ortega, E. & Landry, K. “An Innovative Approach to Capture Depletion Impact in Unconventional Reservoir Production Prediction Using Machine Learning and a Time-Dependent Depletion Function,” URTeC June, 2024. doi.org / 10.15530 / urtec -2024-4044069Pohler. et al., “Annular Velocity Enhancement with Gas Lift as a Deliquification Method for Tight Gas Wells with Long Completion Intervals,” SPE Unconventional Gas Conference, Feb. 23, 2010. doi.org / 10.2118 / 130256-MS Rassenfoss, S, “The Trend in Drilling Horizontal Wells Is Longer, Faster, Cheaper,” J. Petr. Tech. Feb. 10, 2022. Contreras, J., & Awny, Z., “Eagle Ford: The Journey from Well Performance to Artificial Lift Optimization,” URTeC, June, 2024. doi.org / 10.15530 / urtec-2024-4029098Spencer, S. “US upstream industry relying on longer lateral drilling to boost cash flows,” S&P Global Natural Gas | Oil 21 May 2021.Whitfield, S. “Going the Distance: Drillers Push Innovations to Drill Extended Laterals.” IADC Drilling Contractor March 15, 2023.Zhou, et al., “Efficient Field Development Decisions Driven by Artificial Intelligence: A Permian Basin Example” URTeC June. 2024. doi.org / 10.15530 / urtec-2024-4044067

Claims

Docket No.: 42766WO01Claims1. An apparatus for producing hydrocarbons from a hydrocarbon reservoirs, said apparatus comprising: a lateral casing in a hydrocarbon reservoir, a gas injection tubing comprising one or more controllable gas injection valves, a processor for controlling said gas injection valves, and a model for deep gas lift comprising gas injection, oil flow, gas flow, and water flow.

2. The apparatus of claim 1, comprising a multiphase meter to monitor gas, oil, and water production.

3. The apparatus of one of claims 1-2, wherein said gas injection tubing comprises a post-heel valve, heel valve, a pre-heel valve, a mid-lateral valve, a toe valve, a pre-dip valve, dip-valve, post-dip valve, or a combination of valves.

4. The apparatus of one of claims 1-3, wherein said gas injection tubing comprises pressure activated gas injection valves with different activation pressures and said injection point is controlled by increasing injection pressure.

5. The apparatus or method of one of claims 1-4, wherein the lateral well comprises one or more choke devices to reduce or control fluid flow.

6. The apparatus of one of claims 1-5, wherein said gas injection tubing is used to convey one or more additional strings selected from: a distributed acoustic sensing string, a capillary string, a control line, a sensor string comprising one or more sensors, a production tubing, and other well strings7. A method of producing hydrocarbons from a hydrocarbon reservoir, said method comprising: providing a lateral casing in a hydrocarbon reservoir, installing a gas injection tubing comprising one or more controllable gas injection valves, controlling said gas injection valves with a processor, modeling deep gas lift comprising gas injection rates, oil flow rates, gas flow rates, and water flow rates, and modulating gas injection to improve oil production and reduce the volume of gas injected.Docket No.: 42766WO018. The method of claim 7, wherein debris is removed from the lateral well by moving gas injection from the toe of the lateral well to the heel of the lateral well.

9. The method of one of claims 7-8, wherein slugging is reduced or removed by modulating gas injection.

10. The method of one of claims 7-9, wherein gas injection improves oil production through one or more of the following mechanisms selected from: reducing liquid inventory in the lateral well; deliquefying connected fracture systems; reducing gas slip of reservoir liquids; removing stagnant fluid at the toe of the reservoir; reducing the severity of slugging; and improving gas oil ratio (GOR).

11. The method of one of claims 7-10, wherein said lateral well is a toe-up geometry and gas is injected through two or more controllable valves in the heel of the reservoir to stabilize severe slugging.

12. The method of one of claims 7-10, wherein said lateral well is a toe-down geometry and gas is injected at the toe of the lateral to move liquids toward the heel and prevent fluid build up and reservoir congestion at the toe of the reservoir allowing production along the entire length of the lateral well.

13. The method of one of claims 7-12, wherein said gas injection tubing is used to inject well treatment fluids into said lateral well.

14. The method of claim 13, wherein said gas injection tubing is used to inject one or more well treatment fluids selected from: corrosion inhibitors, scale inhibitors, paraffin treatments, hydrate inhibitors, coatings, surfactants, cleaners, self-assembling monolayers, emulsifiers, sulfur reducers, chelators, biocides, acids, catalysts, tracers, and other well treatments.

15. The method of one of claims 7-14, wherein said gas injection tubing is used to convey one or more additional strings selected from: a distributed acoustic sensing string, a capillary string, a control line, a sensor string comprising one or more sensors, a production tubing, and other well strings; and wherein said capillary string is used to inject one or more well treatment fluids selected from: corrosion inhibitors, scale inhibitors, paraffin treatments, hydrate inhibitors,Docket No.: 42766WO01 coatings, surfactants, cleaners, self-assembling monolayers, emulsifiers, sulfur reducers, chelators, biocides, acids, catalysts, tracers, and other well treatments.

Images