US20110004352A1 - Control logic method and system for optimizing natural gas production - Google Patents

Control logic method and system for optimizing natural gas production Download PDF

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US20110004352A1
US20110004352A1 US12/878,017 US87801710A US2011004352A1 US 20110004352 A1 US20110004352 A1 US 20110004352A1 US 87801710 A US87801710 A US 87801710A US 2011004352 A1 US2011004352 A1 US 2011004352A1
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pressure
flow
well
gas
production
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Glenn Wilde
Dennis JONK
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OPTIMUM PRODUCTION TECHNOLOGIES Inc
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OPTIMUM PRODUCTION TECHNOLOGIES Inc
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Assigned to OPTIMUM PRODUCTION TECHNOLOGIES INC. reassignment OPTIMUM PRODUCTION TECHNOLOGIES INC. CORRECTIVE ASSIGNMENT TO CORRECT THE COVERSHEET DATA - CHANGE RECEIVING PARTY CITY FROM EDMONTON TO CALGARY PREVIOUSLY RECORDED ON REEL 024993 FRAME 0325. ASSIGNOR(S) HEREBY CONFIRMS THE RECEIVING PARTY'S CITY (CALGARY) IS CORRECTLY INDICATED ON THE ASSIGNMENT. Assignors: JONK, DENNIS, WILDE, GLENN
Publication of US20110004352A1 publication Critical patent/US20110004352A1/en
Priority to US13/599,294 priority patent/US9127774B2/en
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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
    • F16K—VALVES; TAPS; COCKS; ACTUATING-FLOATS; DEVICES FOR VENTING OR AERATING
    • F16K7/00—Diaphragm valves or cut-off apparatus, e.g. with a member deformed, but not moved bodily, to close the passage ; Pinch valves
    • F16K7/02—Diaphragm valves or cut-off apparatus, e.g. with a member deformed, but not moved bodily, to close the passage ; Pinch valves with tubular diaphragm
    • F16K7/04—Diaphragm valves or cut-off apparatus, e.g. with a member deformed, but not moved bodily, to close the passage ; Pinch valves with tubular diaphragm constrictable by external radial force
    • F16K7/07—Diaphragm valves or cut-off apparatus, e.g. with a member deformed, but not moved bodily, to close the passage ; Pinch valves with tubular diaphragm constrictable by external radial force by means of fluid pressure
    • F16K7/075—Diaphragm valves or cut-off apparatus, e.g. with a member deformed, but not moved bodily, to close the passage ; Pinch valves with tubular diaphragm constrictable by external radial force by means of fluid pressure a rigid body being located within the tubular diaphragm
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
    • F16K—VALVES; TAPS; COCKS; ACTUATING-FLOATS; DEVICES FOR VENTING OR AERATING
    • F16K31/00—Actuating devices; Operating means; Releasing devices
    • F16K31/12—Actuating devices; Operating means; Releasing devices actuated by fluid
    • F16K31/42—Actuating devices; Operating means; Releasing devices actuated by fluid by means of electrically-actuated members in the supply or discharge conduits of the fluid motor

Definitions

  • the present invention relates to methods and apparatus for optimizing production in natural gas wells, particularly in gas wells producing with fixed-velocity lift systems.
  • the present invention further relates to flow control valves adaptable for use in conjunction with gas well production optimization methods and systems, particularly including flow control valves that operate with no atmospheric venting.
  • Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel), coal, shale, or porous rock.
  • Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing.
  • a production chamber which may be either the tubing or the annulus between the tubing and the casing.
  • Formation liquids including water, oil, and/or hydrocarbon condensates, are generally present with natural gas in a subsurface reservoir. For reasons explained in greater detail hereinafter, these liquids must be lifted along with the gas. In order for this to happen, one of the following flow regimes must be present in the well:
  • Formation pressures in virgin reservoirs of natural gas tend to be relatively high. Therefore, upon initial completion of a well, the gas will commonly rise naturally to the surface by velocity-induced flow provided that the characteristics of the reservoir and the wellbore are suitable to produce stable flow (meaning that the gas velocity at all locations in the production chamber remains equal to or greater than the critical velocity, V CR —in other words, velocity-induced flow).
  • V CR critical velocity
  • these wells will flow with excess velocity (i.e., significantly greater than V CR ), resulting in friction between the flowing fluids and the production chamber.
  • gas wellbores are subject to two types of loading: (1) friction loading and (2) liquid loading.
  • Friction loading is caused by fluid flowing up the production tubing at high velocity, and results in restricted formation drawdown. Friction loading typically will not “kill” a well (i.e., completely halt the production of well fluids); however, it can significantly restrict production.
  • the remedy or solution for friction loading is to reduce fluid velocities—e.g., by reducing gas flow rates (thus reducing gas velocity), or by increasing production chamber size while maintaining flow rates (thus reducing gas velocity).
  • Liquid loading is caused by insufficient fluid velocity up the production tubing. Like friction loading, liquid loading results in restricted formation drawdown. Liquid loading will eventually result in the well being killed. Any time a wellbore is “killed” (i.e., its production of well fluids is stopped) due to excessive liquids, considerable costs must be incurred to correct the problem and restore production from the well.
  • liquid loading can be reduced or eliminated by increasing fluid flow velocity to produce velocity-induced flow conditions.
  • increased flow velocity also promotes increased friction loading.
  • Current wellbore design methods typically provide excess flow velocity (i.e., significantly higher than V CR ) to eliminate liquid loading and ensure that the well does not die. The resultant friction loading is accepted as the lesser of two evils.
  • the first priority is to ensure that the wellbore is substantially free from accumulation of liquids. If liquids production is substantial, any accumulation of liquids in the wellbore must be removed, either continuously or intermittently depending on the rate of accumulation. In cases where liquids are removed on an intermittent basis, the well would alternate between production and clean-out cycles, with the clean-out cycle beginning when accumulated liquids reach an undesirable level, and with gas production necessarily being stopped during the clean-out cycle.
  • U.S. Pat. No. 6,991,034 (and corresponding International Application No. PCT/CA2004/000478) teach methods and apparatus for enhancing natural gas well productivity by maintaining a velocity-induced flow regime, thus providing for continuous removal of liquids from the well and preventing or mitigating liquid loading and friction loading of the well.
  • a supplementary pressurized gas is injected into a first (or injection) chamber of a gas well as necessary to keep the total upward gas flow rate in a second (or production) chamber of the well at or above a minimum flow rate needed to lift liquids within the upward gas flow.
  • a cased well having a string of tubing may be considered as having two chambers (namely, the bore of the tubing, and the annulus between the tubing and the casing), and either of these chambers can serve as the first (or injection) chamber, with the other serving as the second (or production) chamber.
  • the invention of U.S. Pat. No. 6,991,034 provides for a gas injection pipeline, for injecting the supplemental gas into the injection chamber, and further provides a throttling valve (also referred to as a “choke”) for controlling the rate of gas injection, and, more specifically, for maintaining a gas injection rate sufficient to keep the gas flowing up the production chamber at or above a set point established with reference to a critical flow rate.
  • a throttling valve also referred to as a “choke”
  • the critical flow rate is a well-specific gas velocity above which liquids will not drop out of an upward-flowing gas stream (as previously explained).
  • the critical flow rate for a given wellbore may also be expressed in terms of volumetric flow based on the critical gas velocity and the cross-sectional area of the production chamber.
  • the critical flow rate for a particular well may be determined using methods or formulae well known to those skilled in the art.
  • a “set point” i.e., minimum rate of total gas flow in the production chamber
  • the set point may correspond to the critical flow rate, but more typically will correspond to a value higher than the critical flow rate, in order to provide a margin of safety.
  • Gas productions systems as taught in U.S. Pat. No. 6,991,034 may be referred to as fixed-velocity production systems.
  • U.S. Pat. No. 7,275,599 (and corresponding International Application No. PCT/CA2004/001567) teach methods and apparatus whereby the intake pipeline running between the production chamber of a natural gas well and the suction inlet of an associated wellhead compressor is completely enclosed within a vapour-tight jacket of natural gas under positive pressure (i.e., greater than atmospheric pressure). Being enclosed inside this “positive-pressure jacket”, the intake pipeline is “blanketed” with positive-pressure gas and therefore is not exposed to the atmosphere at any point. This allows gas to be drawn into the compressor through the intake pipeline under a negative pressure (i.e., lower than atmospheric pressure), without risk of air entering the intake pipeline should a leak occur in the pipeline.
  • a negative pressure i.e., lower than atmospheric pressure
  • the ideal solution for optimizing a wellbore producing with a fixed-velocity lift system is to determine whether it requires continuous liquids removal, or whether it would be more optimally produced at velocities below critical with reduced friction loading, accompanied by intermittent removal of liquids.
  • a well that liquid-loads over a period of (for example) ten days would benefit from intermittent clean-outs, while a well that loads over a period of one hour would require continuous liquids removal.
  • Control valves of various types are commonly used to control the flow of both liquid and gaseous fluids.
  • Flow control may be achieved using a control valve in combination with a controller (i.e., a device incorporating a processor and a memory, such as but not limited to a pneumatic controller or a programmable logic controller (PLC)) that compare one or more flow variables (such as but not limited to flow rate, pressure, and temperature) against pre-established values (or “set points”).
  • a controller i.e., a device incorporating a processor and a memory, such as but not limited to a pneumatic controller or a programmable logic controller (PLC)
  • PLC programmable logic controller
  • the control valve either opens (partially or fully) or closes as necessary to maintain the flow variable(s) in question at the appropriate set point(s).
  • control valve may be understood as referring to either a discrete control valve or to a control valve assembly that incorporates a control valve, according to the context.
  • a typical conventional control valve assembly (such as, for example, the Fisher® D (globe-style) or DA (angle-style) valve) includes a valve body, internal valve trim (“valve trim” being a term readily understood by persons skilled in the art), and a valve actuator.
  • a conventional control valve assembly will commonly be provided in conjunction with additional accessories such as (but not limited to) positioners and proportional controllers. These accessories provide a means to enter a control set point for the control valve.
  • Each configuration for a conventional control valve typically provides a relatively narrow capacity range for a given set of process conditions. Due to this narrow capacity range and the inherent complexity of the control valve, maintenance and design must be done by professional instrumentation personnel. As a result, conventional control valves are relatively expensive to purchase and maintain.
  • Electric actuators can be used to eliminate the venting of gas.
  • electric actuators are comparatively expensive and have significant electrical power requirements, with correspondingly high operating costs.
  • control valve that can control fluid flow effectively under a broad range of process conditions with minimal power consumption and absolutely no external venting of gas.
  • Such a control valve would ideally be serviceable by any ordinarily-skilled field personnel using comparatively inexpensive non-precision parts.
  • a typical bladder-type valve of the Sur-FloTM type has a valve core comprising a pair of frustoconical sections configured much like common pails, each having a solid base at its small-diameter end and with its large-diameter end being open, but with its conical sidewall having a plurality of perforations.
  • the two frustoconical sections are coaxially arranged inside a generally cylindrical valve housing, with their bases in close juxtaposition.
  • a generally cylindrical elastomer sleeve (or “bladder”) is disposed within the valve housing, completely encircling the frustoconical sections, and a pressure port is provided through the cylindrical sidewall of the valve housing.
  • valve assembly When this valve assembly is installed in a fluid flow line, and when there is no external pressure acting on the bladder through the pressure port, fluid can flow freely into the first frustoconical section and out through that section's sidewall perforations into the space between the frustoconical sections and the bladder, and then into the second frustoconical section through its sidewall perforations.
  • sufficient external fluid pressure is applied against the bladder via the pressure port (such as from a “volume bottle” or “expansion bottle” of well-known type, or from another pressure source)
  • the bladder will contract against the frustoconical sections, sealing off their sidewall perforations, and thus preventing fluid flow through the valve assembly.
  • the bladder At lower external fluid pressures, the bladder will restrict but not completely prevent fluid flow through the valve. Accordingly, flow through the valve can be incrementally controlled across the range between the fully-closed and fully-open position by varying the fluid pressure applied against the bladder via the pressure port, with the degree of flow restriction being roughly proportional to the external pressure acting
  • the bladder-type control valve is a comparatively simple non-venting valve that provides a wide range of flow control options under any process conditions. This valve is considerably less expensive than more complex control valves commonly in use, and it is readily serviceable by ordinarily skilled field personnel. This type of valve has proven durability and is very commonly used as a fixed-set-point back-pressure valve.
  • the present invention teaches methods, systems and apparatus for optimizing natural gas production in response to variations in one or more selected wellbore-specific parameters.
  • Wellsite intelligence technology is used to monitor the liquid and gas production from the wellbore under friction-loaded conditions.
  • Wellsite technology suitable for purposes of methods and systems in accordance with the present invention may take the form of one or more programmable logic controllers (PLCs) or other suitable programmable data-processing devices.
  • PLCs programmable logic controllers
  • the term PLC will be used in this patent document as a general reference to wellsite intelligence technology, with it being understood that the scope of such references is not restricted to programmable logic controllers per se.
  • the PLC determines and initiates the appropriate operating mode for the wellbore to optimize a selected production criterion (such as maximum gas production rate or maximum cash flow), to suit measured wellbore-specific parameters.
  • the operating mode thus determined will be either a continuous clean-out mode, in which gas is continuously injected into the wellbore to prevent or minimize liquid loading, or an intermittent clean-out mode, in which liquid loading can be regulated by intermittent gas injection only.
  • the system can be adapted to monitor wellbore performance on either a continuous or periodic basis, and to adjust the operational characteristics of the operating mode in effect at a given time, and/or to switch the operating mode, as may be dictated by variations in measured wellbore parameters.
  • the present invention teaches a method for optimizing production from a natural gas well that is associated with a gas compressor, and which is adapted for injection of gas into a wellbore injection chamber to regulate wellbore velocity.
  • the method comprises the steps of:
  • test input parameters may comprise (but are not limited to) the compressor suction pressure and the wellbore flow rate (i.e., gas flow rate up the wellbore).
  • well productivity information may comprise (but is not limited to) a rate of gas production from the well, or a rate of cash flow realized from the well.
  • the method of the present invention may comprise the further steps of:
  • one or more control valve assemblies may be are used to regulate wellbore velocity in accordance with the operative input parameters.
  • the one or more control valve assemblies may be of any functionally suitable design or type, including control valve assemblies in accordance with embodiments of control valve assemblies described and illustrated in the patent document.
  • the PLC may be adapted to control the operation of one or more of the control valves.
  • the present invention teaches a system for regulating multiple separate fluid flows originating from a single fluid flow source.
  • the system comprises:
  • the set point ranges for all of the control valves are wide enough to prevent valve chatter (i.e., rapid and repetitive opening and closing of a valve, typically due to the upper and lower set points being too close to each other).
  • the set point range of at least one control valve is a fixed set point range.
  • the set point range of at least one of the control valves is a variable set point range.
  • at least one control valve may have a fixed set point range, while at least one control valve has a variable set point range.
  • the system may further comprise a programmable logic controller (PLC) having a memory storing the set point range of the control valves.
  • PLC programmable logic controller
  • the PLC is adapted to regulate fluid flow through the control valves by carrying out the following steps:
  • control valves used for the system of the invention may be of any functionally suitable design or type, including control valve assemblies in accordance with embodiments of control valve assemblies described and illustrated in the patent document.
  • the system optionally may comprise a PLC having a memory that stores a selected suction pressure set point range, with the PLC being adapted to control the compressor speed and thereby to regulate suction pressure by performing the following steps:
  • the present invention teaches a method for optimizing production from a natural gas well associated with a gas compressor, where the well includes a string of tubing disposed within the wellbore and defining an annulus surrounding the tubing, with the method including the following steps:
  • the method includes the following steps:
  • control logic methods and systems of the present invention incorporate the use of a control valve assembly that enables the use of variable set points, in accordance with the present teachings.
  • control valve assembly comprises:
  • solenoid valves are well known in the art, and are commonly referred to simply as solenoids.
  • solenoids will be used throughout this patent document to denote a solenoid valve.
  • the upstream and downstream solenoids When the valve assembly is not in use, the upstream and downstream solenoids will be closed. As a result, the bladder pressure P B will be constant, resulting in a fixed set point for the control valve. If the upstream pressure P U increases above this set point, the valve will automatically open, allowing flow through the valve. If the upstream solenoid is held open, the upstream pressure P U and the bladder pressure P B will be in equilibrium, such that the bladder will contract against the valve core and close off fluid flow through the valve. To commence flow through the valve, the downstream solenoid is opened, and the upstream solenoid is closed, thus reducing the bladder pressure P B .
  • fluid flow will be controlled by pulsing the downstream solenoid to increase the flow rate Q and pulsing the upstream solenoid to decrease the flow rate.
  • a controller such as a programmable logic controller (PLC) is provided to control the operation of the upstream and downstream solenoids, in response to control signals from a control sensor.
  • PLC programmable logic controller
  • the control sensor could measure fluid pressure, fluid flow rate, fluid temperature, or other flow variables.
  • the control sensor is a motor RPM sensor, measuring the speed of a motor associated with a gas compressor.
  • the location of a control sensor within the control valve assembly may vary depending on the particular flow variable being controlled, and depending on whether the variable is being sensed directly or indirectly.
  • a selected set point for the flow variable (for example, gas flow rate or gas pressure)—or, perhaps more typically, an allowable range between selected upper and lower values for the flow variable)—is stored in the PLC's memory. If the corresponding control sensor determines that the controlled flow variable is outside the allowable range, the PLC will pulse the appropriate solenoid to bring the variable back within the allowable range.
  • control valve assemblies in accordance with the present invention are not limited or restricted to the use of those particular types of valves.
  • the present invention teaches a non-venting control valve assembly, for installation in a flow line carrying a fluid (gas or liquid) under pressure, and comprising: a valve having a fluid inlet; a fluid outlet; a pressure port in fluid communication with a pressure source; and a flow restriction element exposed to the pressure source via the pressure port.
  • the flow restriction element is adapted to fluid decrease flow through the valve in response to increases in the pressure source pressure, and to increase flow through the valve in response to decreases in the pressure source pressure.
  • control valve assembly also comprises an upstream bypass line connecting the fluid inlet and the pressure source; an upstream solenoid operable to regulate fluid flow through the upstream bypass line; a downstream bypass line connecting the fluid outlet and the pressure source; and a downstream solenoid operable to regulate fluid flow through the downstream bypass line.
  • the control valve assembly may further comprise a programmable logic controller (PLC) adapted to control the operation of the upstream and downstream solenoids.
  • PLC programmable logic controller
  • the PLC may be adapted to control the operation of the upstream and downstream solenoids in response to data inputs from a pressure sensor associated with the fluid inlet.
  • the PLC may be adapted to control the operation of the upstream and downstream solenoids in response to data inputs from a pressure sensor associated with the fluid outlet.
  • the PLC may be adapted to control the operation of the upstream and downstream solenoids in response to data inputs from a flow rate sensor associated with a fluid source upstream of the fluid inlet.
  • the valve may comprise a pair of frustoconical valve core sections, each having a perforated frustoconical sidewall, a solid end wall, and an opposing open end, with the solid end walls of said sections juxtaposed.
  • the flow restriction element comprises a generally cylindrical and deformable bladder surrounding the valve core, such that:
  • one or both of the upstream and downstream solenoids optionally may be adapted for pulsed operation, thereby facilitating incremental adjustments to the pressure source pressure.
  • FIG. 1 is a schematic diagram of the wellhead of a natural gas well producing gas under velocity-induced flow conditions in accordance with prior art methods taught in U.S. Pat. No. 6,991,034.
  • FIG. 2 is a schematic diagram of the wellhead of a natural gas well producing gas under velocity-induced flow conditions and enclosed within a positive pressure gas jacket in accordance with prior art methods taught in U.S. Pat. No. 7,275,599.
  • FIG. 3 is a graph of wellbore velocity versus time, schematically illustrating the variable critical fluid flow velocity above which a gas well will be friction loaded and below which a gas well will be liquid loaded.
  • FIG. 4 is a graph of wellbore velocity versus time, schematically illustrating optimization of wellbore velocity, with the well operating in a continuous clean-out mode in accordance with an embodiment of a gas production optimization method of the present invention.
  • FIGS. 5A and 5B are schematic diagrams illustrating parameters for determination of a wellbore's maximum liquid storage volume.
  • FIG. 6A is a schematic diagram of a wellbore at the beginning of the production cycle of the intermittent clean-out mode of an embodiment of a gas production optimization method of the present invention.
  • FIG. 6B is a schematic diagram of a wellbore as in FIG. 6A , shown at the end of the production cycle.
  • FIG. 7A is a schematic diagram of a wellbore at the beginning of the clean-out cycle of the intermittent clean-out mode of an embodiment of a gas production optimization method of the present invention.
  • FIG. 7B is a schematic diagram of a wellbore as in FIG. 7A , shown at the end of the clean-out cycle.
  • FIG. 8 is a schematic diagram of a first embodiment of a bladder-type control valve assembly in accordance with the present invention.
  • FIG. 9 is a schematic diagram of a second embodiment of a bladder-type control valve assembly in accordance with the present invention.
  • FIG. 10 schematically illustrates the use of bladder-type control valves in accordance with the present invention, to regulate the flow of sales gas and injection gas in conjunction with embodiments of the method of the present invention.
  • FIG. 11 illustrates an example of a production test grid for use in conjunction with gas production optimization methods in accordance with the present invention.
  • FIG. 12 is a schematic diagram of a gas lift system for a producing oil well in accordance with an embodiment of the present invention.
  • FIG. 13 is a schematic diagram of the wellbore of the system illustrated in FIG. 12 .
  • FIG. 1 schematically illustrates a natural gas well W penetrating a subsurface formation F containing natural gas, with well W producing gas under velocity-induced flow conditions in accordance with one embodiment of the methods taught in U.S. Pat. No. 6,991,034.
  • Well W is lined with a casing 20 which has a number of perforations conceptually illustrated by short lines 22 within a production zone (generally corresponding to the portion of the well penetrating the formation F).
  • formation fluids including gas, oil, and water flow into the well through perforations 22 .
  • a string of tubing 30 extends inside casing 20 , terminating at a point within the production zone.
  • tubing 30 The bottom end of tubing 30 is open, such that fluids entering the wellbore can freely enter tubing 30 .
  • An annulus 32 is formed between tubing 30 and casing 20 .
  • the upper end of tubing 30 runs into a surface termination apparatus or “wellhead” (not illustrated in detail), of which various types are known in the field of gas wells.
  • Tubing 30 and annulus 32 may be considered as separate chambers of well W.
  • a selected one of these chambers serves as the “production chamber” through which gas is lifted from the bottom of well W to the surface, while the other chamber serves as the “injection chamber”, the purpose and function of which are explained in greater detail hereinafter.
  • tubing 30 serves as the production chamber
  • annulus 32 serves as the injection chamber.
  • tubing 30 serves as the injection chamber
  • annulus 32 serves as the production chamber.
  • tubing 30 serves as the production chamber to carry gas from well W to a production pipeline 40 , the downstream end of which is connected to the suction manifold 42 S of a gas compressor 42 .
  • the upstream end of a discharge pipeline 41 connects at one end to the discharge manifold 42 D of compressor 42 and continues therefrom to a gas processing facility (not shown).
  • a gas injection pipeline 16 for diverting production gas from production pipeline 40 for injection into the injection chamber, is connected at one end to the discharge pipeline 41 at a point X, and at its other end to the top of the injection chamber (i.e., annulus 32 , in FIG. 1 ).
  • a throttling valve (or “choke”) 12 which is operable to regulate the flow of gas from production pipeline 40 into the injection chamber via injection pipeline 16 .
  • Choke 12 may be of any suitable type.
  • choke 12 may be of a manually-actuated type, which may be manually adjusted to achieve desired rates of gas injection, using trial-and-error methods as necessary or appropriate.
  • choke 12 may be an automatic choke; e.g., a Kimray® Model 2200 flow control valve.
  • a flow controller 50 is provided for operating choke 12 .
  • a flow meter 14 adapted to measure the rate of total gas flow up the production chamber, and to communicate that information to flow controller 50 .
  • Flow controller 50 may be a pneumatic controller of any suitable type, such as a FisherTM Model 4194 differential pressure controller.
  • Wellhead assemblies as schematically depicted in FIG. 1 will typically incorporate a gas-liquid separator (not shown) in production pipeline 40 upstream of compressor 42 for removing liquids present in the produced well fluids so that only gas flows to compressor 42 .
  • a gas-liquid separator (not shown) in production pipeline 40 upstream of compressor 42 for removing liquids present in the produced well fluids so that only gas flows to compressor 42 .
  • a critical gas flow rate is determined.
  • the critical flow rate which may be expressed in terms of either gas velocity or volumetric flow, is a parameter corresponding to the minimum velocity V CR that must be maintained by a gas stream flowing up the production chamber (i.e., tubing 30 , in FIG. 1 ) in order to carry formation liquids upward within the gas stream (i.e., by velocity-induced flow).
  • This parameter is determined in accordance with well-established methods and formulae taking into account a variety of quantifiable factors relating to the well construction and the characteristics of formation from which the well is producing.
  • a minimum total flow rate (or “set point”) is then selected, based on the calculated critical flow rate, and flow controller 50 is set accordingly.
  • the selected set point will preferably be somewhat higher than the calculated critical rate, in order to provide a reasonable margin of safety, but also preferably not significantly higher than the critical rate, in order to minimize friction loading in the production chamber.
  • flow controller 50 will adjust choke 12 to increase the gas injection rate if and as necessary to increase the total flow rate to a level at or above the set point. If the total flow rate is at or above the set point, there may be no need to adjust choke 12 .
  • Flow controller 50 may be adapted such that if the total gas flow is considerably higher than the set point, flow controller 50 will adjust choke 12 to reduce the gas injection rate, thus minimizing the amount of gas being recirculated to the well through injection, and maximizing the amount of gas available for processing and sale.
  • flow controller 50 has a computer with a microprocessor 60 and a memory 62 .
  • Flow controller 50 also has a meter communication link 52 for receiving gas flow measurement data from flow meter 14 .
  • Meter communication link 52 may comprise a wired or wireless electronic link, and may comprise a transducer.
  • Flow controller 50 also has a choke control link 54 , for communicating a control signal from computer 60 to a choke control means (not shown) which actuates choke 12 in accordance with the control signal from computer 60 .
  • Choke control link 54 may comprise a mechanical linkage, and may comprise either a wired or wireless electronic link.
  • the set point is stored in memory 62 .
  • Computer 60 receives a signal from flow meter 14 (via meter communication link 52 ) corresponding to the measured total gas flow rate in the production chamber, and, using software programmed into Computer 60 , compares this value against the set point. Computer 60 then calculates a minimum injection rate at which supplementary gas must be injected into the injection chamber, or to which the injection rate must be increased in order to keep the total flow rate at or above the set point. This calculation takes into account the current gas injection rate (which would be zero if no gas is being injected at the time).
  • computer 60 will convey a control signal, via choke control link 54 , to the choke control means, which in turn will adjust choke 12 to deliver injection gas, at the calculated minimum injection rate, into injection pipeline 16 , and thence into the injection chamber of the well (i.e., annulus 32 , in FIG. 1 ). If the measured total gas flow equals or exceeds the set point, no adjustment of choke 12 will be necessary, strictly speaking.
  • FIG. 2 conceptually illustrates a gas-blanketed natural gas wellhead in accordance with one embodiment of prior art apparatus taught by U.S. Pat. No. 7,275,599, and adapted to provide for gas injection into an injection chamber generally as in the apparatus of FIG. 1 .
  • the apparatus shown in FIG. 2 has numerous components that correspond to components of the apparatus of FIG. 1 (with like numerical references). Although not shown, the apparatus of FIG. 2 may incorporate a flow controller 50 , choke 12 , and associated components as in the apparatus of FIG. 1 .
  • production pipeline 40 is divided into an upstream section 40 U that conveys produced well fluids under negative pressure from well W's production chamber (i.e., tubing 30 in FIG. 2 ) to a gas-liquid separator 70 , and a downstream section 40 D extending between separator 70 and suction manifold 42 S of compressor 42 .
  • a discharge pipeline 41 connects to discharge manifold 42 D of compressor 42 and continues therefrom to a gas processing facility (not shown).
  • liquids entering separator 70 separate into a gas fraction that exits separator 70 through downstream section 40 D of production pipeline 40 to compressor 42 , and a liquids fraction 72 which, being heavier than the gas fraction of the well fluids, accumulates in a lower section of separator 70 .
  • Liquids 72 flow under negative pressure through a pump inlet line 78 to a pump 74 , which pumps liquids 72 (now under positive pressure) through a liquid return line 76 which connects into discharge pipeline 41 at a point Z downstream of compressor 42 .
  • liquids 72 may be pumped to an on-site storage tank 80 .
  • upstream section 40 U and downstream section 40 D of production pipeline 40 , separator 70 , and pump inlet line 78 are fully enclosed by a vapour-tight positive pressure jacket 150 that defines a continuous internal chamber 152 .
  • a gas recirculation pipeline 260 extends between, and is in fluid communication with, discharge pipeline 41 at point X located between compressor 42 and point Z, and a selected pressure connection point Y on positive pressure jacket 150 , such as between compressor 42 and separator 70 as shown in FIG. 2 .
  • a portion of the gas discharged from discharge manifold 42 D of compressor 42 may be diverted into positive pressure jacket 150 , such that upstream section 40 U and downstream section 40 D of production pipeline 40 , separator 70 , and pump inlet line 78 are entirely enclosed by a “blanket” of gas under positive pressure.
  • Positive pressure jacket 150 thus enshrouds all components that contain containing combustible fluids under negative pressure with a blanket of gas under positive pressure, thereby preventing the entry of air in the event of a leak developing in any component containing combustible fluids under negative pressure.
  • Blanketing gas may be diverted from internal chamber 152 for injection into a selected injection chamber of well W via a suitable injection pipeline represented by reference numeral 116 in FIG. 2 , for producing well W under velocity-induced flow conditions as previously described in connection with FIG. 1 .
  • injection gas can be introduced into the injection chamber via a separate injection pipeline (not shown) connected into gas recirculation pipeline 260 .
  • FIG. 3 conceptually illustrates the previously-discussed principle that production optimization for a gas well requiring continuous removal of liquids can be achieved by keeping the upward fluid velocity in the production chamber as close as practically possible to the well's critical velocity, in order to prevent accumulation of liquids while minimizing friction loading.
  • V CR which may be referred to as the critical velocity curve
  • the critical upward velocity for well fluids flowing up the production chamber of a gas well at or above which liquid droplets will be lifted along with the gaseous portion of the well fluids; in other words, the velocity at or above which the well will be producing gas under velocity-induced flow conditions.
  • the value of critical velocity V CR for a given wellbore is dependent upon a number of factors that are subject to change over the production life of the wellbore (such as flow line pressure, reservoir pressure, liquid production rate, liquid composition, gas composition, and wellbore design).
  • the wellbore velocity V WB the actual upward flow velocity in the production chamber
  • the current value of V CR i.e., above the critical velocity curve in FIG. 3
  • the well will be producing under velocity-induced flow conditions.
  • the higher the wellbore velocity is relative to V CR the greater the extent to which the wellbore will be subject to friction loading.
  • the wellbore velocity is lower than the current value of V CR (i.e., below the critical velocity curve)
  • the well will be prone to liquid loading.
  • FIG. 4 schematically illustrates how wellbore velocity V WB may be optimized using methods and systems in accordance with the present invention; i.e., to induce a wellbore that maintains velocity-induced flow to minimize or prevent liquid loading, while also minimizing friction loading.
  • the system automatically makes upward or downward adjustments to the wellbore velocity V WB to keep it just sufficient to prevent liquid loading—in other words, effectively matching the flow rate to the critical velocity.
  • This optimized production state is graphically illustrated in FIG. 4 , in which the solid curve represents the critical velocity V CR , and the stepped line indicates the actual wellbore velocity V WB as periodically adjusted in accordance with methods of the present invention.
  • production from the well in accordance with methods of the present invention may be commenced in a friction-loaded state—i.e., at an initial wellbore velocity V WB having a value above the critical velocity curve in FIG. 3 .
  • the initial value for wellbore velocity V WB may be determined on a trial-and-error basis, or on the basis of a theoretical prediction of critical velocity V CR , but in either case erring on the high side to protect against starting production with the well in a liquid-loaded state.
  • the system's PLC gathers selected production data for the wellbore, such as liquid flow rates, gas flow rates, tubing pressure, and casing pressure, by means of suitable sensing or metering devices (which will be familiar to persons skilled in the art).
  • the PLC is programmed to process this collected data to determine whether the wellbore velocity V WB needs to be increased or decreased to keep it close to the critical velocity V CR and thus prevent accumulation of liquids. This is accomplished without needing to quantify the critical velocity V CR , as the system determines the need to adjust wellbore velocity based on actual, real-time wellbore operational conditions. Any necessary adjustments to wellbore velocity will be automatically initiated by the PLC, which regulates the operation of gas flow control valves as described in detail later in this specification.
  • the PLC can also be programmed to run additional production tests at specified intervals to determine whether the wellbore can be optimally produced with intermittent clean-out of liquids rather than on a continuous clean-out basis.
  • Wells accumulating (or “making”) large quantities of water can load up within minutes of wellbore velocities falling below the critical velocity V CR .
  • liquid loading can be alleviated or prevented by maintaining a wellbore velocity V WB at or above a critical velocity, as conceptually illustrated in FIG. 4 .
  • This production mode may be referred to as the continuous clean-out mode, in which all liquids are removed from the wellbore on a continuous basis.
  • FIGS. 5A and 5B schematically illustrate the parameters for determining the maximum volume of liquids that can accumulate in a wellbore without killing the wellbore.
  • This maximum liquid storage volume, or LSV MAX for a given wellbore may be defined as the maximum volume of liquid that can be stored in the wellbore and removed up the production chamber (typically tubing 30 ) by means of gas injection into the injection chamber (typically annulus 32 ).
  • LSV MAX When LSV MAX is stored in tubing 30 and annulus 32 as illustrated in FIG. 5A , with no differential pressure between tubing 30 and annulus 32 , LSV MAX will come to a static height H 1 above the bottom of the wellbore.
  • static height H 1 must not rise above perforations 22 in casing 20 , in order to prevent the well from being killed. Accordingly, the static height H 1 of LSV MAX will be one variable in the determination of LSV MAX .
  • LSV MAX The value of LSV MAX will also be dependent upon the capacity of the particular compressor 42 associated with the wellbore. Stated another way, the hydrostatic pressure that would be produced when LSV MAX is completely contained within tubing 30 must be less than the pressure that compressor 42 is capable of inducing by means of gas injection into annulus 32 . This maximum hydrostatic pressure will be equal to the vertical liquid height H 2 of LSV MAX if wholly contained within tubing 30 (as illustrated in FIG. 5B ) multiplied by the specific gravity of the liquid.
  • LSV MAX An additional limiting factor with respect to the maximum liquid storage volume LSV MAX will be the reservoir pressure. If the hydrostatic pressure of LSV MAX is greater than the reservoir pressure, it will be impossible to clean out the accumulated liquids because the injection gas will simply flow into the subsurface formation rather than lifting the liquids. Therefore, the hydrostatic pressure of LSV MAX must not be greater than the lesser of the reservoir pressure and the compressor capacity.
  • LSV MAX the value of LSV MAX will vary from well to well, depending upon wellbore dimensions, perforation height, compressor capacity, and reservoir pressure.
  • the compressor will be capable of raising a column of liquid in tubing 30 under a hydrostatic head of about 700 kiloPascals.
  • the value of LSV MAX for a particular well will typically be determined by calculation.
  • the intermittent clean-out mode is characterized by the alternating production and clean-out cycles, as follows:
  • the methods and systems of the present invention provide for testing a well to assess whether optimal productivity will be realized operating in intermittent clean-out mode rather than continuous clean-out mode. This may be referred to as the “mode test” phase.
  • the PLC After calculating the production cycle time (as described in detail later herein), the PLC will cause the well to produce in intermittent clean-out mode for a predetermined time (for example, one week). Once this time has elapsed, the PLC will automatically change modes and produce in the continuous clean-out mode for the same predetermined time period.
  • the PLC Upon completion of the “mode test” phase, the PLC will default into the mode that produced more gas during the test period (or that produced the greater cash flow, depending on the selected optimization criteria).
  • a downhole packer 26 with an integral three-way valve 28 (of any suitable type) may be used.
  • the operation of such a three-way valve is schematically illustrated in FIGS. 6A , 6 B, 7 A, and 7 B.
  • gas is produced up annulus 32 as well as up tubing 30 , with three-way valve 28 being set in a first position that allows gas to flow out of annulus 32 and into tubing 30 at an upper region thereof.
  • three-way valve 28 is set in a second position that allows supplementary or “recycle” gas to be injected into annulus 32 to remove accumulated liquids.
  • production from a gas well is commenced in a friction-loaded state—i.e., at a production fluid velocity above the critical velocity curve in FIG. 3 .
  • This state may be initiated on a trial-and-error basis, or based on a theoretical prediction of the critical velocity but erring on the high side to protect against a liquid-loaded state.
  • the PLC (or other suitable wellsite intelligence technologies) is used to gather production data for the wellbore, including liquid flow rates, gas flow rates, tubing pressure, and casing pressure; this production data is collected at regular intervals.
  • the system's PLC calculates the duration of the next production cycle (i.e., how long it will take for LSV MAX to accumulate in the wellbore). This value is determined in accordance with the following formula:
  • Q AV is the average volumetric gas flow rate
  • the wellbore velocity V WB is gradually reduced in order to effectively eliminate friction loading.
  • the PLC does this by initiating incremental changes to V WB at predetermined time intervals, while continually comparing real-time wellbore data against the baseline data in order to detect the onset of liquid loading as V WB is reduced.
  • Imminent liquid loading will typically be indicated by an upward trend in casing pressure and a downward trend in liquid production rates.
  • Other “flags” may also be used to identify the beginning or approach of a liquid-loaded state.
  • the optimization system of the present invention automatically increases the rate of gas injection to raise the wellbore velocity V WB by an increment sufficient to return the wellbore to a marginally friction-loaded state.
  • the system automatically makes upward or downward adjustments to the wellbore velocity V WB to keep it just sufficient to prevent liquid loading—in other words, effectively matching the flow rate to the changing critical velocity, based on real-time wellbore data.
  • This optimized production state is graphically illustrated in FIG. 4 , in which the solid curve represents the critical velocity, and the stepped line indicates the actual gas flow rate as periodically adjusted in accordance with the present invention.
  • the critical velocity for a producing gas well is automatically determined, and the set point (i.e., upward fluid velocity in the production tubing) is automatically adjusted as may be necessary from time to time in response to changes in the critical velocity, thereby maintaining a set point substantially equal to the critical velocity, thus preventing liquid loading and minimizing friction loading in the wellbore.
  • the set point i.e., upward fluid velocity in the production tubing
  • the PLC can calculate an estimated time until the next blowcase dump cycle, in accordance with the following formula:
  • Time until next dump Time of last dump ⁇ [Volume per cycle/(WGR ⁇ Q AV )]
  • a secondary flag for liquid loading will be an upward trend in the pressure in annulus 32 . This is a proven method of identifying wellbore loading commonly used in most wellsite optimization systems currently available.
  • FIG. 8 schematically illustrates a basic embodiment of a control valve assembly 100 in accordance with the present invention, and in the specific context of a natural gas flow line.
  • the control valve assembly 100 includes a bladder-type control valve 120 a valve core 122 disposed within a valve housing 125 , with valve housing 125 having an intake port 127 , an outlet port 128 , and a pressure port 126 .
  • Valve core 122 comprises an upstream frustoconical section 122 U and a downstream frustoconical section 122 D, each having a solid base at its small-diameter end and with its large-diameter end being open, but with its conical sidewall having a plurality of perforations 123 .
  • the two frustoconical sections 122 U and 122 D are coaxially arranged inside a generally cylindrical valve housing, with their bases in close juxtaposition.
  • a generally cylindrical bladder 124 made from of a resilient, deformable material, is disposed around surrounding valve core sections 122 U and 122 D. In FIG.
  • bladder 124 is shown contracted against the conical sidewalls of frustoconical sections 122 U and 122 D, in response to differential pressure acting on bladder 124 , thereby blocking flow through perforations 123 , such that gas entering upstream valve core section 122 U cannot flow into downstream valve core section 122 D.
  • Control valve assembly 100 of FIG. 8 further comprises a fluid inlet line 130 in fluid communication with intake port 127 ; a fluid outlet line 140 in fluid communication with outlet port 128 ; and a pressure port 126 .
  • a pressure source 150 (such as a volume bottle, in a preferred embodiment) is connected to pressure port 126 .
  • An upstream bypass line 132 connects fluid inlet line 130 to pressure source 150 , with an associated upstream solenoid 134 operable to regulate fluid flow through upstream bypass line 132 .
  • a downstream bypass line 142 connects fluid outlet line 140 to pressure source 150 , with an associated downstream solenoid 144 operable to regulate fluid flow through downstream bypass line 142 .
  • P U denotes gas pressure upstream of control valve 120
  • P B denotes gas pressure acting on bladder 124 of control valve 120
  • P D denotes gas pressure downstream of the control valve.
  • Pulsing downstream solenoid 144 open causes P U to exceed P B , thus initiating a flow of gas through control valve 120 .
  • FIG. 9 illustrates an embodiment of the flow control valve assembly using a PLC 160 in conjunction with a pressure sensor 170 installed upstream of control valve 120 , with PLC 160 being in electronic communication with pressure sensor 170 via a pressure sensor link 172 .
  • PLC 160 is in electronic communication with upstream solenoid 134 and downstream solenoid 144 , via upstream and downstream solenoid links 162 and 164 respectively, for controlling the operation of solenoids 134 and 144 .
  • control valve 120 may be operated by the following steps, as controlled by PLC 160 :
  • the system illustrated in FIG. 9 may be operated by the following steps:
  • Control valve arrangements in accordance with the present invention offer a number of significant advantages over known technologies, including the following:
  • FIG. 10 schematically illustrates how bladder-type control valves as taught herein may be used to regulate two or more separate gas flows originating from a single fluid flow source. This is illustrated in FIG. 10 , by way of non-limiting example, in the specific context of a first flow of gas from a well to a processing and sales facility, and a second flow of gas intended for injection into a selected injection chamber of the well for purposes of producing or maintaining velocity-induced flow conditions as previously described herein.
  • process block 200 conceptually represents wellhead apparatus comprising a compressor and other components (typically including a separator) as may be required for a given gas well.
  • a gas supply flowline 210 (analogous to production pipeline 40 in FIG. 1 or upstream production pipeline 40 U in FIG. 2 ) conveys produced fluids from the well to wellhead apparatus 200 .
  • a volumetric flow meter 220 is provided in association with supply flowline 210 .
  • Wellhead apparatus 200 processes the well fluids to produce a first flow of gas into a sales gas pipeline 230 downstream of the compressor and a second flow of gas into an injection pipeline 240 (analogous to injection pipeline 16 in FIG. 1 or injection pipeline 260 in FIG. 2 ).
  • a first control valve CV- 1 provided in association with sales gas pipeline 230 , is generally in accordance with the embodiment shown in FIG. 8 , with an upstream solenoid 134 - 1 , a downstream solenoid 144 - 1 , and a volume bottle (or other pressure source) 150 - 1 .
  • First control valve CV- 1 is in electronic communication with a PLC 160 for regulating the operation of upstream and downstream solenoids 134 - 1 and 144 - 1 as previously described in connection with FIG. 9 .
  • PLC 160 is also in electronic communication with flow meter 220 . Accordingly, first control valve CV- 1 is configured to control the volumetric flow rate in supply flowline 210 by regulating the flow of gas in sales pipeline 230 .
  • a similar second control valve CV- 2 is provided in association with injection pipeline 240 , and has an upstream solenoid 134 - 2 , a downstream solenoid 144 - 2 , and a volume bottle 150 - 2 , plus a pressure sensor 170 as in the embodiment of FIG. 9 .
  • Second control valve CV- 2 is in also electronic communication with PLC 160 (or, in alternative embodiments, with a separate PLC) for regulating the operation of upstream and downstream solenoids 134 - 2 and 144 - 2 .
  • PLC 160 is also in electronic communication with pressure sensor 170 . Accordingly, second control valve CV- 2 is configured to control pressure.
  • first control valve CV- 1 controls the flow rate in supply flowline 210 .
  • First control valve CV- 1 slowly begins to close if the tubing rate is below a selected lower tubing rate set point (or LTRSP) stored in PLC 160 's memory. As first control valve CV- 1 closes, more gas is recycled to the well's selected injection chamber via injection pipeline 240 , thereby causing the tubing flow rate to increase.
  • First control valve CV- 1 slowly begins to open if the tubing rate is above a selected upper tubing rate set point (or UTRSP) stored in PLC 160 's memory. As first control valve CV- 1 opens, less gas is recycled to the injection chamber, thus causing the tubing rate to decrease.
  • First control valve CV- 1 will have no action if the tubing rate is in the operational envelope between the UTRSP and the LTRSP.
  • second control valve CV- 2 controls upstream gas pressure.
  • second control valve CV- 2 is illustrated as having an upstream solenoid 134 - 2 and a downstream solenoid 144 - 2
  • second control valve CV- 2 can have a fixed set point with no solenoids. In that scenario, the set point will need to be set above the peak flow line pressure typically seen during normal operation. This will allow first control valve CV- 1 to direct gas either to sales or recycle. If first control valve CV- 2 has a fixed set point below the flowline pressure it will be impossible to send gas to sales.
  • second control valve CV- 2 can incorporate solenoids as shown in FIG. 10 , to provide a variable pressure set point.
  • the set point will be automatically be maintained at a fixed amount above the flowline pressure. As the flowline pressure changes, so will second control valve CV- 2 's set point.
  • FIG. 3 illustrates how the critical rate is the point at which both friction loading and liquid loading are minimized.
  • the second part of the optimization process is to determine the speed (measured in RPM) at which the compressor should run.
  • the design of any compressor will dictate that at any given throughput and discharge pressure there will be a corresponding suction pressure.
  • the tubing rate set point (or TRSP) defines the throughput and the flowline pressure defines the discharge pressure, so compressor speed will be directly related to suction pressure.
  • TRSP tubing rate set point
  • the production optimization system of the present invention will gradually speed up the compressor until this suction pressure set point is met (provided that the compressor motor is not overloaded).
  • the system can identify when the gas processing plant goes down and the system is in full recycle (i.e., with no gas going to sales). As well, the compressor speed can be reduced to minimize wasted power. It is also a good idea to protect the system by establishing a maximum compressor speed. This would be an RPM set point slightly above the typical operating RPM.
  • a fixed-velocity system will have the ability to maintain the tubing gas rate within pre-set upper and lower tubing rate set points (UTRSP and LTRSP).
  • UTRSP upper and lower tubing rate set points
  • LTRSP tubing rate set points
  • a further aspect of the production optimization methods of the present invention is the ability to automatically determine the tubing flow rate and the corresponding suction pressure that will result in optimal production from a given wellbore.
  • This optimal combination of tubing rate and suction pressure may be referred to as the optimum set point (or OSP).
  • a wellbore's OSP can be defined in different ways, depending on selected criteria.
  • the OSP would most commonly be defined to maximize gas production—which in most conditions will correspond to maximum cash flow from the wellbore. In some situations, however, maximum production might not equate to maximum cash flow. For example, power consumption and water production might not be directly proportional to the gas production rate, such that the incremental power cost to increase well production could be more than the incremental value of gas produced.
  • WGR water-to-gas ratio
  • OSP Order to Price
  • criteria for establishing the OSP might vary over the life of the wellbore. It is also possible that the OSP for some wellbores would be based on criteria other than production or cash flow.
  • the production test grid may be defined using selected input values for the following operational parameters, which are programmed into the PLC:
  • the PLC totalizes the gas production during each test period. Back pressure is kept constant for all tests to ensure that a true measurement of wellbore productivity is provided. After a desired number of these production tests have been completed, with the test results being used to populate Table 1 as appropriate, the combination of TRSP and suction pressure that resulted in the highest gas production during the tests will represent the optimum set point (OSP) for the wellbore.
  • OSP set point
  • FIG. 11 provides a pictorial representation of data used for purposes of a production test grid as described above, with tubing rate being plotted against compressor suction pressure, with further reference to compressor speed (RPM).
  • RPM compressor speed
  • the PLC totalizes gas and water production as well as power consumption during each test period. Back pressure is kept constant for all tests to ensure that a true indication of wellbore productivity is provided.
  • the PLC uses the measured gas and water production data and the corresponding cost and price information to determine a cash flow indicator. After a desired number of these production tests have been completed, with the test results being used to populate Table 1 as appropriate, the combination of TRSP and suction pressure that resulted in the highest cash flow during the tests will represent the optimum set point (OSP) for the wellbore. These values will be saved as the default operating parameters for the wellbore, and the system will revert to operating at these optimum conditions once the production testing is complete.
  • OSP set point
  • the optimization test grid will preferably be run on a periodic basis throughout the life of the well. In most cases, a very broad range of suction pressures and tubing gas rate values will be used the first time the test grid is run. Subsequent optimization runs will concentrate the test grid around the default optimum conditions determined from earlier tests. Based on the average time between liquid dumps, the system will determine whether the well should be tested for intermittent liquids removal. For example, if the time between dumps is 24 hours, there is a good chance that production improvements can be realized through intermittent liquid removal. In contrast, if the time between liquid dumps is, say, only 8 minutes, intermittent removal of liquids would not be an option, because this would almost certainly have the effect of killing the well.
  • Sub-critical flow is a flow rate in the wellbore that does not provide sufficient velocity to lift liquids. Accordingly, the sub-critical flow time in Table 2 is the time during which the wellbore operates under sub-critical flow conditions. During this time liquids are slowly accumulated in the wellbore; however, friction loading is eliminated. Sub-critical flow can occur up the wellbore annulus alone or up the tubing and the annulus together.
  • the production test grid may be defined using selected input values for the following operational parameters:
  • Production testing will be terminated prematurely by the PLC (i.e., before the end of the specified test duration has been reached) if any of the above-mentioned conditions should develop. Otherwise, testing will continue until the end of the specified test period unless the well is producing less gas, in which case testing will be aborted and the well will revert to the previous operational parameters.
  • definition of the production test grid may entail the use of inputs values for additional parameters, such as:
  • Production testing will be terminated prematurely by the PLC (i.e., before the end of specified test duration has been reached) if any of the above-mentioned conditions should develop. Otherwise testing will continue until the end of the specified test period unless the well is producing a reduced cash flow, in which case testing will be aborted and the well will revert to the previous operational parameters.
  • FIGS. 12 and 13 illustrate how principles and concepts taught herein may also be applied to enable a simple compressor to provide onsite gas lift for a producing oil well.
  • Produced gas is separated at the surface, and a portion of the produced gas re-injected into the wellbore through a coiled tubing string.
  • This gas lift gas lightens the fluid column in the wellbore and facilitates production of liquids up the wellbore by pressure-induced flow (as opposed to velocity-induced flow).
  • the well casing in this scenario will typically be closed, resulting in an accumulation of high-pressure gas within the casing. Anytime additional gas lift gas is required for the system, this high-pressure gas stored in the casing may be utilized for that purpose.
  • process block 300 conceptually represents a flow-splitting apparatus.
  • a first input flow Q 1 is a flow of oil emulsion from a wellbore.
  • a second input flow Q 2 is gas flow from the wellbore casing.
  • a first output flow Q 3 is a flow of oil emulsion down a flow line.
  • a second output flow Q 4 is a flow of lift gas flow down the coiled tubing. It will be noted that all of the gas lift gas passes through the compressor.
  • a first control valve CV- 1 (which may be in accordance with a control valve embodiment disclosed elsewhere in this patent document) is controlled by a first liquid level sensor LLS- 1 (alternatively referred to as a fluid level indicator). If first liquid level sensor LLS- 1 is down, first control valve CV- 1 will be closed. If first liquid level sensor LLS- 1 is up, first control valve CV- 1 will open. First control valve CV- 1 attempts to maintain the liquid level below first liquid level sensor LLS- 1 .
  • a second control valve CV- 2 is controlled based on second liquid level sensor LLS- 2 . If second liquid level sensor LLS- 2 is down, second control valve CV- 2 will be closed. If second liquid level sensor LLS- 2 is up, second control valve CV- 2 will open. Second control valve CV- 2 attempts to maintain a liquid level above second liquid level sensor LLS- 2 .
  • VFD variable-frequency drive
  • any form of the word “comprise” is to be understood in its non-limiting sense to mean that any item following such word is included, but items not specifically mentioned are not excluded.
  • a reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.
  • Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the subject elements, and may also include indirect interaction between the elements such as through secondary or intermediary structure.

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US20090151928A1 (en) * 2007-12-17 2009-06-18 Peter Francis Lawson Electrical submersible pump and gas compressor
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AU2010220792B2 (en) 2014-10-09
US9127774B2 (en) 2015-09-08

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