Systems and methods of controlling production in a gas-lift well

Abstract

A system may obtain flow gradient survey (FGS) data for a well at a first location in the well. A system may obtain a measured gas-injection rate from a gas-lift orifice valve in the well. A system may calculate a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the first orifice. A system may determine a calculated flowing pressure based on the logarithmic ratio factor. A system may adjust the downhole gas injection pressure based on the calculated flowing pressure.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to and the benefit of Indian Provisional Patent Application No. 202411099830 titled “SYSTEMS AND METHODS OF CONTROLLING PRODUCTION IN A GAS-LIFT WELL” filed Dec. 17, 2024, the disclosure of which is incorporated herein by reference in its entirety.BACKGROUND

[0002] Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.

[0003] Wellbores can extend deep into the earth, often up to several kilometers. Formation conditions can vary in the well, producing a variety of production fluids, such as liquids and gases, which can change in ratio over the lifetime of the well.BRIEF SUMMARY

[0004] In some aspects, the techniques described herein relate to a method of controlling production in a well, the method including: obtaining flow gradient survey (FGS) data for the well at a first location in the well; obtaining a measured gas-injection rate from a first orifice in the well; calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the gas-lift orifice valve; determining a calculated flowing pressure based on the logarithmic ratio factor; and adjusting the downhole gas injection pressure based on the calculated flowing pressure.

[0005] In some aspects, the techniques described herein relate to a method of controlling production from a well, the method including: obtaining flow gradient survey (FGS) data for a baseline well at a first location in the baseline well; obtaining a measured gas-injection rate from a gas-lift orifice valve in the baseline well; calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the entry of gas-lift orifice valve; determining a calculated flowing pressure in a second well based on the logarithmic ratio factor; and adjusting a second downhole gas injection pressure of the second well based on the second calculated flowing pressure.

[0006] In some aspects, the techniques described herein relate to a system for controlling production from a well, the system including: a valve; a sensor; and a controller in data communication with the valve and the sensor, the controller having instructions stored thereon configured to cause the controller, when executed by the controller, to: obtain a logarithmic ratio factor, determine a calculated flowing pressure based on the logarithmic ratio factor and at least one measurement from the sensor, and adjust the valve to change a downhole gas injection pressure based on the calculated flowing pressure.

[0007] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0008] Additional features and advantages of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and advantages of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims or may be learned by the practice of such embodiments as set forth hereinafter.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific implementations thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example implementations, the implementations will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0010] FIG. 1 is a schematic diagram of a gas-lift well located in a formation, according to at least one embodiment of the present disclosure.

[0011] FIG. 2 is a system diagram of a control system for a gas-lift well, according to at least one embodiment of the present disclosure.

[0012] FIG. 3 is a flowchart illustrating a method of controlling production in a gas-lift well, according to a least some embodiments of the present disclosure.

[0013] FIG. 4 is a flowchart illustrating another method of controlling production in a gas-lift well, according to at least one embodiment of the present disclosure.

[0014] FIG. 5 is a graph illustrating a variation in simulated pressure surveys for a single well.

[0015] FIG. 6 is a graph illustrating a comparison of measured gas injection rates to calculated gas injection rates by the logarithmic ratio factor across four wells.

[0016] FIG. 7 is a graph illustrating a comparison of the error rate of the calculated gas injection rates according to the logarithmic ratio factor and at least some embodiments of methods described herein and the error rate of the conventionally calculated gas injection rate.

[0017] FIG. 8 is a set of graphs illustrating the consistent calculations within a single well with varying gas-liquid ratio (GLR) conditions as measured in a series of FGS data sets.

[0018] FIG. 9 is graph comparing a commercially available simulation of flowing pressure versus a simulation according to the present disclosure.DETAILED DESCRIPTION

[0019] This disclosure generally relates to devices, systems, and methods for the production of hydrocarbon products in a production well. More particularly, the present disclosure relates to improving the production of gas-lift wells. In some embodiments, a production well produces fluid hydrocarbons, such as liquid and gas products, which are extracted from a formation out of the well. A production well may passively extract the formation fluids based on a positive fluid pressure within the formation, or the production well may actively extract the formation fluids by applying a negative pressure to the uphole direction of the well tubing, which draws the fluid(s) from the well.

[0020] In some embodiments, a production well is an artificial lift system that relies upon one or more mechanical, hydraulic, or electrical assistance systems to extract a fluid from the well. A gas-lift well is an artificial lift system where gas is injected into a produced well casing to help lift liquids up to the surface through the production tubing. In some embodiments, gas-lift wells require few moving parts and can operate safety and efficiently for extended periods of time. In some embodiments, the gas-lift well is a continuous gas-lift system. In some embodiments, the gas-lift well is an intermittent well system.

[0021] In some examples, a gas-lift well operates by inserting a pressurized gas into an annular region inside the well casing of the production well. A production tubing is located inside the casing with the annular space substantially surrounding the tubing. The pressurized gas enters displaces fluid in the annular space and enters into the production tubing through one or more gas-lift valves. The pressurized gas rises in the production fluid. In some embodiments, the production fluid is a liquid, and the pressurized gas rises through the column of liquid in the production tubing. The fluidic drag on the liquid and the lessened density of the fluid in the production tubing allows extraction from the production tubing. The amount and / or rate of pressurized gas that is injected into the production tubing, therefor, alters the velocity and density of the fluid in the production tubing. Too much or too little pressurized fluid can inhibit or otherwise adversely affect the production rate of the well.

[0022] In some embodiments, the production fluid is a mixture of liquid and gas, and the pressurized gas flows into the production tubing with the production fluid(s). A production fluid that is a mixture of liquid and gas has a density that is less than a fully-liquid production fluid. The amount and / or rate of pressurized gas needed to flow production fluid from the well is, therefore, reduced, and continued injection of pressurized gas can inhibit or otherwise adversely affect the production rate of the well.

[0023] In a conventional system, one or more sensors are positioned proximate the bottom of the well to measure a bottomhole pressure. In some embodiments, the sensors collect a static gradient survey (SGS) of fluid pressures within the static column of fluid in the well, from which a bottomhole pressure and / or fluidic pressure elsewhere in the column of fluid can be calculated. In some embodiments, the sensors collect a flow gradient survey (FGS) of fluid pressures within the column of fluid in the well while the production fluid flows through the well, from which a bottomhole pressure and / or fluidic pressure elsewhere in the column of fluid can be calculated.

[0024] The bottomhole pressure, the SGS, and / or the FGS vary with the gas-to-liquid ratio (GLR) of the production fluid in the well. However, the GLR in the well may vary over time during production, requiring a change in gas injection pressure and / or gas injection rate at the gas-lift valve. During production, a direct measurement of the bottomhole pressure, the SGS, and / or the FGS may not be possible. In some embodiments, systems and methods according to the present disclosure provide for the measurement and calculation of a robust and resilient metric for adjusting gas injection pressure across the gas-lift valve in a gas-lift well with varying GLR.

[0025] FIG. 1 is a schematic diagram of a gas-lift well 100 located in a formation 102. In some embodiments, the gas-lift well 100 includes a wellbore 104 with a casing 106. In some embodiments, the casing 106 has one or more perforations 108 or other openings therein that allow a production fluid 110 to enter the casing 106 from the formation 102. In some embodiments, the production fluid 110 is a liquid. In some embodiments, the production fluid is a gas. In some embodiments, the production fluid 110 includes a mixture of liquid and gas. Production tubing 112 is located inside the casing 106. In some embodiments, a packer 111 is positioned between the production tubing 112 and the casing 106 to isolate an opening of the production tubing 112 and the perforations 108 from an annular space substantially around the production tubing 112 within the wellbore 104.

[0026] In some embodiments, one or more gas-lift valves 114 are positioned in the annular space substantially around the production tubing 112. In some embodiment, the gas-lift valve 114 allow a pressurized gas 116 to enter the production tubing 112. In some embodiments, the pressurized gas 116 is a formation gas, such as collected from the formation 102 and recycled for use in the gas-lift system. In some embodiments, the pressurized gas 116 is from a tank of supplemental gas.

[0027] In some embodiments, the pressurized gas 116 is provided into the annular space of the casing 106 of the wellbore 104 by a control valve 115. In some embodiments, the control valve 115 controls a fluid pressure in the annular space of the wellbore 104. In some embodiments, the control valve 115 controls a fluid pressure of the pressurized gas 116 entering the production tubing 112. For example, the gas-lift valve 114 may allow the pressurized gas 116 from the annular space into the production tubing 112 at the fluid pressure of the annular space. In some embodiments, the control valve 115 controls a fluid pressure of the annular space, and the gas-lift valve 114 further controls an injection pressure of the pressurized gas 116 entering the production tubing.

[0028] In some embodiments, the injection pressure of the pressurized gas 116 is the pressure drop from the fluid pressure of the annular space to the fluid pressure in the production tubing 112. The injection pressure, therefore, is at least partially based on the fluid pressure in the production tubing 112 at the vertical position of the gas-lift valve 114 in the column of production fluid 110. As described herein, as the GLR changes in the column of production fluid 110, the pressure at various locations in the column changes.

[0029] In some embodiments, the gas-lift well 100 includes a plurality of gas-lift valves 114 at a plurality of vertical positions along the length of the production tubing 112. In some embodiments, the control valve 115 allows any liquid that enters the annular space around the production tubing 112 to be displaced by the gas pressure in the casing 106. In some embodiments, all of the gas-lift valves 114 are in a gas-filled portion of the casing 106. In some embodiments, at least one of the gas-lift valves 114 is located in a liquid-filled portion of the casing 106.

[0030] Pressurized gas 116 injected into the tubing 112 rises up the tubing 112, providing fluidic drag to the column of production fluid 110 and lowering the density of all regions above the gas-lift valve 114 injecting the pressurized gas 116. The plurality of gas-lift valves 114 may, therefore, selectively adjust the density and flow rate of the production fluid 110 by introducing pressurized gas 116 at various injection rates at different locations in the production tubing 112.

[0031] In order to precisely, accurately, and / or efficiently control the flow of pressurized gas 116 into the production tubing 112, a survey of the pressure gradient (SGS and / or FGS) within the production tubing 112 is conventionally needed. However, it is difficult to measure the pressure gradient during production. In some embodiments, systems and methods according to the present disclosure allow the determination of pressures in the production tubing for a well 100 based on injection pressures measured during production and a logarithmic ratio factor calculated from an FGS and injection rates. In some embodiments, systems and methods according to the present disclosure adjust at least one injection pressure of a gas-lift valve during production based at least partially on the logarithmic ratio factor to dynamically respond to changes in the GLR in real-time.

[0032] FIG. 2 is a system diagram of a control system for a gas-lift well, such as the gas-lift well 100 described in relation to FIG. 1. In some embodiments, the control system includes a controller 218 that is in data communication with one or more gas-lift valves 214 and a control valve 215. In some embodiments, the controller 218 is in data communication with a plurality of gas-lift valves 214. For example, the controller 218 may adjust the gas-lift valve 214 to change a pressure drop across the gas-lift valve 214. In some embodiments, the controller 218 is in data communication with the control valve 215. For example, the controller 218 may adjust the control valve 215 to change a fluid pressure in the annular space of the casing proximate to the gas-lift valve(s) 214.

[0033] In some embodiments, the control system includes at least one sensor 220-1, 220-2. In some embodiments, the control system includes at least two sensors 220-1, 220-2. The sensor(s) 220-1, 220-2 is in data communication with the controller 218 to provide measurements to the controller 218 in the process of performing at least a portion of any method described herein. In some embodiments, the sensors 220-1, 220-2 include a flowmeter to measure a gas injection rate in the gas-lift well. In some embodiments, the sensors 220-1, 220-2 include a pressure sensor to measure an injection pressure in the gas-lift well. In some embodiments, the sensors 220-1, 220-2 include a pressure sensor to measure a fluid pressure in the gas-lift well, such as in the annular space or in the production tubing.

[0034] In some embodiments, at least one sensor 220-1, 220-2 is located at a substantially equal vertical position to a gas-lift valve 214. In some embodiments, at least one sensor 220-1, 220-2 is located below the gas-lift valve 214. In some embodiments, at least one sensor 220-1, 220-2 is located above the gas-lift valve 214. In some embodiments, at least one sensor 220-1, 220-2 is located in the gas-lift valve 214. For example, a sensor 220-1, 220-2 may be integrated into the gas-lift valve 214 to measure a fluid pressure and / or fluid pressure drop in the gas-lift valve 214.

[0035] The controller 218 includes processor, communication device, and hardware storage device. In some embodiments, the processor is any microprocessor capable of computational tasks. In some embodiments, the processor is a general-use processor (such as a central processing unit). In some embodiments, the processor is an application specific integrated circuit (ASIC). In some embodiments, the processor is part of a system-on-chip (SOC).

[0036] The processor is in data communication with the hardware storage device. In some embodiments, the hardware storage device has instructions stored thereon and configured to cause the controller 218 to perform at least a portion or all of any method described herein. For example, the processor may access the instructions stored on the hardware storage device and execute at least a portion of the instructions to perform at least a portion of any method described herein.

[0037] In some embodiments, the communication device is in data communication with the processor and configured to allow the processor to transmit and / or receive information from other components of the gas-lift well, such as valves, sensors, and other components. In some embodiments, the communication device is in data communication with the processor and configured to allow the processor to transmit and / or receive information from other computing devices, such as via a network. In some embodiments, the communication device is a wired communication device. In some embodiments, the communication device is a wireless communication device.

[0038] The control system and gas-lift system can allow for a more accurate and responsive control of production rates by calculating a logarithmic ratio factor (i.e., “n factor”) that allows a flowing pressure across the gas-lift orifice valve to be extrapolated dynamically during production. A dynamically calculated flowing pressure across the gas-lift orifice valve may allow for more accurate adjustments to the gas injection pressure of the gas-lift system as the GLR changes during production.

[0039] FIG. 3 is a flowchart illustrating a method 322 of controlling a production in a gas-lift well, according to a least some embodiments of the present disclosure. In some embodiments, the method 322 includes obtaining FGS data for the well including at least a first location in the well at 324. The FGS data includes pressure measurements through the vertical column of production fluid when flowing through the production fluid. In some embodiments, the FGS data includes at least a bottomhole pressure measurement. In some embodiments, the FGS data includes a pressure measurement at a first orifice of the production tubing corresponding to a first gas-lift valve location.

[0040] In some embodiments, the method 322 further includes obtaining a measured gas-injection rate from a first orifice in the production tubing in the well at 326. For example, a sensor, such as one of the sensors described in relation to FIG. 2, may measure the gas-injection rate from the first orifice into the production tubing in the well. In some embodiments, the measured gas-injection rate is collected by a sensor located proximate to the gas-lift valve. In some embodiments, the measured gas-injection rate is collected by a sensor integrated into the gas-lift valve.

[0041] The method 322 further includes, in some embodiments, calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure of the gas-lift valve at the gas-lift orifice valve at 328. In some examples, calculating the logarithmic ratio factor (n factor) is based at least partially on a calculated gas-lift tuning (GLT) value. For example, the GLT may be calculated based on the FGS including a measured production fluid pressure in the production tubing. In at least one embodiment, the GLT is calculated by the Thornhill-Craver equation below using the FGS data and the measured gas-injection (Qg) rate:G⁢L⁢T=Qg155⁢CD⁢Ap⁢Pi⁢2⁢g⁢kk-1[(PpPi)2 / k-(PpPi)k+1k]Z⁢δ⁢T

[0042] Where Pp is the measured production fluid pressure from the FGS data, CD is the discharge coefficient, K is a ratio of specific heats, Pi is the downhole gas injection pressure in psi, Z is a gas compressibility, g is the gas specific gravity, T is the temperature at the control valve in deg R, and Ap is the area of the port through which the pressurized gas flows. The GLT informs the system and / or operator of adjustments to the injection rate with respect to injection pressure and the effect on the gas-lift system.

[0043] In some embodiments, the calculated GLT further enables calculations of a maximum gas injection rate possible for a given port size area Ap orifice valve at a given Pi (Downhole gas-injection pressure at orifice valve) at Pp=Ppc (production fluid critical pressure in tubing at gas-lift orifice valve) where Ppc=Pi*Rcp (the critical pressure ratio) by reordering the equation and solving for the Qg:Qg⁢Ma⁢x=155⁢CD⁢Ap(GLT)⁢Pi⁢2⁢g⁢kk-1[(Rcp)2 / k-(Rcp)k+1k]Z⁢δ⁢T

[0044] In some embodiments, the maximum gas injection rate (QgMax) is used to calculate the logarithmic ratio factor (n):n=log(1-QgQgMax)log(Pp-Ppc Pi-Ppc)

[0045] In at least some embodiments, according to the present disclosure, and as will be described below, the logarithmic ratio factor allows dynamic calculation of downhole pressures and therefore adjustments to the injection pressure for a well with a variable GLR, and the logarithmic ratio factor remains relatively constant across flow regimes as the GLR changes.

[0046] The method 322 further includes determining a calculated flowing pressure based on the logarithmic ratio factor at 330 according to:fn(Pp)=0=[(PpPi)2 / k-(PpPi)k+1k][(Rcp)2 / k-(Rcp)k+1k]-[1+(Pp-PpcPi-Ppc)n]

[0047] In some embodiments, the method 322 includes adjusting the downhole gas injection pressure based on the calculated flowing pressure at 332. In some embodiments, adjusting the downhole gas injection pressure includes adjusting a position of the control valve of the pressurized gas in the casing. In some embodiments, adjusting the downhole gas injection pressure includes adjusting a position of the gas-lift valve of the pressurized gas between the casing and the production tubing. In some embodiments, adjusting the downhole gas injection pressure includes the controller adjusting a position of the control valve of the pressurized gas in the casing. In some embodiments, adjusting the downhole gas injection pressure includes the controller adjusting a position of the gas-lift valve of the pressurized gas between the casing and the production tubing.

[0048] The logarithmic ratio factor remains substantially constant (as will be described in more detail herein) across GLR conditions and production conditions of the well. In some embodiments, the logarithmic ratio factor is used to determine a second calculated flowing pressure based on the logarithmic ratio factor. In such examples, the method includes adjusting the valve based on the second calculated flowing pressure.

[0049] The logarithmic ratio factor, in some embodiments, allows the calculation of flowing pressure in other wells of the same completion type and the same control valve type. In some embodiments, the logarithmic ratio factor allows the calculation of flowing pressure in other wells of the same completion type, the same control valve type, and the same gas-lift valve type. For example, the GLT and / or logarithmic ratio factor are based at least partially on the area of the port and the gas used in the baseline well from which the initial values are measured. However, other wells using a similar or the same port and pressurized gas may use the same logarithmic ratio factor to allow dynamic adjustments to the gas-lift system of additional wells without interrupting production.

[0050] Referring now to FIG. 4, another method 434 of controlling production in a well is described. In some embodiments, the logarithmic ratio factor allows extrapolation of well properties to other, similar wells. In some embodiments, the method 434 includes obtaining FGS data for the well including at least a first location in a baseline well at 424. The FGS data includes pressure measurements through the vertical column of production fluid when flowing through the production fluid. In some embodiments, the FGS data includes at least a bottomhole pressure measurement. In some embodiments, the FGS data includes a pressure measurement at a first orifice of the production tubing corresponding to a first gas-lift valve location.

[0051] In some embodiments, the method 434 further includes obtaining a measured gas-injection rate from a first orifice in the production tubing in the baseline well at 426. For example, a sensor, such as one of the sensors described in relation to FIG. 2, may measure the gas-injection rate from the first orifice into the production tubing in the baseline well. In some embodiments, the measured gas-injection rate is collected by a sensor located proximate to the gas-lift valve. In some embodiments, the measured gas-injection rate is collected by a sensor integrated into the gas-lift valve.

[0052] The method 434 further includes, in some embodiments, calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure of the gas-lift valve at the gas-lift orifice valve of the baseline well at 428. In some examples, calculating the logarithmic ratio factor (n factor) is based at least partially on a calculated gas-lift tuning (GLT) value for the baseline well. For example, the GLT may be calculated based on the FGS including a measured production fluid pressure in the production tubing of the baseline well. In at least one embodiment, the GLT is calculated by the Thornhill-Craver equation below using the FGS data and the measured gas-injection (Qg) rate:G⁢L⁢T=Qg1⁢5⁢5⁢CD⁢Ap⁢Pi⁢2⁢g⁢kk-1[(PpPi)2 / k-(PpPi)k+1k]Z⁢δ⁢T

[0053] Where Pp is the measured production fluid pressure from the FGS data, CD is the discharge coefficient, K is a ratio of specific heats, Pi is the downhole gas injection pressure in psi, Z is a gas compressibility, g is the gas specific gravity, T is the temperature at the control valve in deg R, and Ap is the area of the port through which the pressurized gas flows. The GLT informs the system and / or operator of adjustments to the injection rate and the effect on the gas-lift system.

[0054] In some embodiments, the calculated GLT further enables calculations of a maximum gas injection rate possible at a given Pi at Pp=Ppc (production fluid critical pressure) where Ppc=Pi*Rcp (the critical pressure ratio) by reordering the equation and solving for the Qg:Qg⁢Ma⁢x=155⁢CD⁢Ap(GLT)⁢Pi⁢2⁢g⁢kk-1[(Rcp)2 / k-(Rcp)k+1k]Z⁢δ⁢T

[0055] In some embodiments, the maximum gas injection rate (QgMax) is used to calculate the logarithmic ratio factor (n):n=log(1-QgQgMax)log(Pp-Ppc Pi-Ppc)

[0056] In at least some embodiments, the logarithmic ratio factor allows dynamic calculation of downhole pressures and therefore adjustments to the injection pressure for a second well with a variable GLR, and the logarithmic ratio factor remains relatively constant across flow regimes as the GLR changes.

[0057] The method 434 further includes determining a second calculated flowing pressure in a second well based on the logarithmic ratio factor, wherein the second well and the baseline well have the same completion type and the same valve type at 436 according to:fn(Pp)=0=[(PpPi)2 / k-(PpPi)k+1k][(Rcp)2 / k-(Rcp)k+1k]-[1+(Pp-PpcPi-Ppc)n]

[0058] In some embodiments, the method 434 includes adjusting a second downhole gas injection pressure of the second well based on the second calculated flowing pressure at 438. In some embodiments, adjusting the downhole gas injection pressure includes adjusting a position of the control valve of the pressurized gas in the casing. In some embodiments, adjusting the downhole gas injection pressure includes adjusting a position of the gas-lift valve of the pressurized gas between the casing and the production tubing. In some embodiments, adjusting the downhole gas injection pressure includes the controller adjusting a position of the control valve of the pressurized gas in the casing. In some embodiments, adjusting the downhole gas injection pressure includes the controller adjusting a position of the gas-lift valve of the pressurized gas between the casing and the production tubing.

[0059] FIG. 5 is a graph 540 illustrating a variation in simulated pressure surveys for a single well. Conventional simulations produce a large variation in bottomhole pressure calculations. For example, the three-hundred twenty-four simulations illustrated in FIG. 5 present a range of bottomhole pressure calculations from approximately 550 psig to over 1200 psig for the same well. In some embodiments, the logarithmic ratio factor provides a more consistent and more accurate estimation of a gas injection rate across a variety of GLR and / or wells, as the logarithmic ratio factor is based on the well response to pressure changes.

[0060] FIG. 6 is a graph 642 illustrating a comparison of measured gas injection rates to calculated gas injection rates by the logarithmic ratio factor across four wells. In each of the four wells tested, the calculated gas injection rates based on the logarithmic ratio factor provided no more than a 7% error from the measured gas injection rates. The gas injection rates, however, ranged by over 100% variation Case 4 to Case 3, illustrating an efficacy over a large range of injection rates and production fluid pressures.

[0061] FIG. 7 is a graph 744 illustrating a comparison of the error rate of the calculated gas injection rates according to the logarithmic ratio factor and at least some embodiments of methods described herein and the error rate of the conventionally calculated gas injection rate. In each instance, the calculated gas injection rates according to the logarithmic ratio factor described herein is more accurate to the measured gas injection rate. In the illustrated examples, the calculated gas injection rates according to the logarithmic ratio factor described herein is within 7% for all four cases, while the error rate of the conventionally calculated gas injection rate exceeded 18% in all cases with Case 3 exhibiting a 49% error.

[0062] While each of the four cases illustrated in FIG. 6 and FIG. 7 show consistent accuracy in different wells, FIG. 8 is a set of graphs 846 illustrating the consistent calculations within a single well with varying GLR conditions as measured in a series of FGS data sets. For example, the graph illustrates a trend line of the production fluid pressure in the production tubing and a trend line of the gas injection pressure. The pressures change over time, reflecting changing conditions for each of the measured FGS data. The logarithmic ratio factor, however, remains relative consistent, as the relationship between the production fluid pressure in the production tubing and the gas injection pressure remain relatively consistent. In such examples, a logarithmic ratio factor calculated for any one of the well conditions (as measured by the three FGS data sets) may be approximately accurate to the other well conditions.

[0063] FIG. 9 is a yet another representation of a benefit provided by systems and methods according to the present disclosure. While other benefits described herein and realized by the present disclosure are possible, in at least some embodiments, a more accurate downhole flowing pressure is made possible by the logarithmic ratio factor and methods associated therewith. By comparison, a commercially available estimation 950 of a downhole flowing pressure is illustrated for a test well. The commercially available estimation 950 produces a bottomhole pressure estimate that is far from the actual measured bottomhole pressure 952. In some embodiments, a logarithmic ratio factor-based estimation 954 is based at least partially on the measured bottomhole pressure 952, ensuring the logarithmic ratio factor-based estimation 954 is anchored to the measured data and provides a more accurate estimation along the entire length of the test well.

[0064] In at least some embodiments, systems and methods according to the present disclosure allow a controller or an operator of a gas-lift well to calculate a logarithmic ratio factor that is applicable to a variety of GLR conditions in the well and to similar wells with the same completion type and the same valve type. Such versatility of the logarithmic ratio factor allows more accurate and more dynamic adjustments to the gas injection pressure and gas injection rate of the gas-lift well to improve production therefrom.

[0065] Embodiments of systems and methods related to controlling downhole tools are described herein according to the clauses below:

[0066] Clause 1. A method of controlling production in a well, the method comprising: obtaining flow gradient survey (FGS) data for the well at a first location in the well; obtaining a measured gas-injection rate from a gas-lift orifice valve in the well; calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the gas-lift orifice valve; determining a calculated flowing pressure based on the logarithmic ratio factor; and adjusting the downhole gas injection pressure based on the calculated flowing pressure.

[0067] Clause 2. The method of clause 1, wherein obtaining the gas-injection rate includes receiving a gas-injection rate value from a flowmeter of the well in real-time.

[0068] Clause 3. The method of clause 1 or 2, wherein calculating the logarithmic ratio factor includes determining a gas-lifting tuning (GLT) factor.

[0069] Clause 4. The method of clause 3, wherein calculating the GLT factor includes calculating the GLT factor by a Thornhill-Craver equation.

[0070] Clause 5. The method of clause 4, wherein calculating the logarithmic ratio factor includes determining a maximum gas-lift injection rate based on the GLT factor.

[0071] Clause 6. The method of any preceding clause, wherein the logarithmic ratio factor is a ratio of a first logarithmic value based partially on the measured gas-injection rate and a second logarithmic value based partially on the downhole gas injection pressure of the well.

[0072] Clause 7. The method of clause 6, wherein the logarithmic ratio factor (n) is calculated by:n=Log (1−Qg / Qgmax) / Log ((Pp−Ppc) / (Pi−Ppc)).

[0073] Clause 8. The method of any preceding clause, further comprising: obtaining a second measured gas-injection rate; determining a second calculated flowing pressure based on the logarithmic ratio factor; and adjusting the downhole gas injection pressure based on the second calculated flowing pressure.

[0074] Clause 9. The method of any preceding clause, wherein the logarithmic ratio factor is substantially constant across the FGS data for the well completion life.

[0075] Clause 10. A method of controlling production in a well, the method comprising: obtaining flow gradient survey (FGS) data for a baseline well at a first location in the baseline well; obtaining a measured gas-injection rate from a first orifice in the baseline well; calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the gas-lift orifice valve; determining a calculated flowing pressure in a second well based on the logarithmic ratio factor; and adjusting a second downhole gas injection pressure of the second well based on the second calculated flowing pressure and the logarithmic ratio factor.

[0076] Clause 11. The method of clause 10, wherein the logarithmic ratio factor is based at least partially on a gas-lifting tuning (GLT) factor.

[0077] Clause 12. The method of clause 11, wherein the GLT factor is based at least partially on the FGS data and the downhole gas injection pressure.

[0078] Clause 13. The method of any of clause 10-12, wherein the baseline well and the second well have a same completion type.

[0079] Clause 14. The method of any of clause 10-13, wherein the baseline well and the second well have a same valve type.

[0080] Clause 15. A system for controlling production in a well, the system comprising: a valve; a sensor; and a controller in data communication with the valve and the sensor, the controller having instructions stored thereon configured to cause the controller, when executed by the controller, to: obtain a logarithmic ratio factor, determine a calculated flowing pressure based on the logarithmic ratio factor and at least one measurement from the sensor, and adjust the valve to change a downhole gas injection pressure based on the calculated flowing pressure.

[0081] Clause 16. The system of clause 15, wherein the sensor is a pressure sensor.

[0082] Clause 17. The system of clause 15, wherein the sensor is an injection rate sensor.

[0083] Clause 18. The system of any of clause 15-17, wherein the valve is a control valve.

[0084] Clause 19. The system of any of clause 15-18, wherein the instructions are further configured to cause the controller to: obtain flow gradient survey (FGS) data for the well at a first location in the well; obtain a measured gas-injection rate from a gas-lift orifice valve in the well; and calculate the logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the first orifice.

[0085] Clause 20. The system of clause 19, wherein the measured gas-injection rate is received from the sensor.

[0086] The terms “comprising,”“including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0087] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0088] It should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “front” and “back” or “top” and “bottom” or “left” and “right” are merely descriptive of the relative position or movement of the related elements.

[0089] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

1. A method of controlling production in a well, the method comprising:obtaining flow gradient survey (FGS) data for the well at a first location in the well;obtaining a measured gas-injection rate from a gas-lift orifice valve in the well;calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the gas-lift orifice valve;determining a calculated flowing pressure based on the logarithmic ratio factor; andadjusting the downhole gas injection pressure based on the calculated flowing pressure.

2. The method of claim 1, wherein obtaining the gas-injection rate includes receiving a gas-injection rate value from a flowmeter of the well in real-time.

3. The method of claim 1, wherein calculating the logarithmic ratio factor includes determining a gas-lifting tuning (GLT) factor.

4. The method of claim 3, wherein calculating the GLT factor includes calculating the GLT factor by a Thornhill-Craver equation.

5. The method of claim 4, wherein calculating the logarithmic ratio factor includes determining a maximum gas-lift injection rate based on the GLT factor.

6. The method of claim 1, wherein the logarithmic ratio factor is a ratio of a first logarithmic value based partially on the measured gas-injection rate and a second logarithmic value based partially on the downhole gas injection pressure of the well.

7. The method of claim 6, wherein the logarithmic ratio factor is calculated by a ratio of a first log based at least partially on a first ratio of gas-injection rate relative to maximum gas-injection rate and a second log based at least partially on a second ratio of first difference between a production fluid pressure and a production fluid critical pressure and a second difference between a downhole gas injection pressure and the production fluid critical pressure.

8. The method of claim 1, further comprising:obtaining a second measured gas-injection rate;determining a second calculated flowing pressure based on the logarithmic ratio factor; andadjusting the downhole gas injection pressure based on the second calculated flowing pressure.

9. The method of claim 1, wherein the logarithmic ratio factor is substantially constant across the FGS data for a well completion life.

10. A method of controlling production in a well, the method comprising:obtaining flow gradient survey (FGS) data for a baseline well at a first location in the baseline well;obtaining a measured gas-injection rate from a gas-lift orifice valve in the baseline well;calculating a logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the gas-lift orifice valve;determining a calculated flowing pressure in a second well based on the logarithmic ratio factor; andadjusting a second downhole gas injection pressure of the second well based on the second calculated flowing pressure.

11. The method of claim 10, wherein the logarithmic ratio factor is based at least partially on a gas-lifting tuning (GLT) factor.

12. The method of claim 11, wherein the GLT factor is based at least partially on the FGS data and the downhole gas injection pressure.

13. The method of claim 10, wherein the baseline well and the second well have a same completion type.

14. The method of claim 10, wherein the baseline well and the second well have a same valve type.

15. A system for controlling production in a well, the system comprising:a valve;a sensor; anda controller in data communication with the valve and the sensor, the controller having instructions stored thereon configured to cause the controller, when executed by the controller, to:obtain a logarithmic ratio factor,determine a calculated flowing pressure based on the logarithmic ratio factor and at least one measurement from the sensor, andadjust the valve to change a downhole gas injection pressure based on the calculated flowing pressure.

16. The system of claim 15, wherein the sensor is a pressure sensor.

17. The system of claim 15, wherein the sensor is an injection rate sensor.

18. The system of claim 15, wherein the valve is a control valve.

19. The system of claim 15, wherein the instructions are further configured to cause the controller to:obtain flow gradient survey (FGS) data for the well at a first location in the well;obtain a measured gas-injection rate from a first gas-lift orifice valve in the well; andcalculate the logarithmic ratio factor based on the FGS data and a downhole gas injection pressure at the first gas-lift orifice valve.

20. The system of claim 19, wherein the measured gas-injection rate is received from the sensor.

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