A Remote Monitoring and Control System and Method for Improving Hydrocarbon Production Efficiency

Abstract

The present invention relates to a remote control and monitoring system to improve the production efficiency of a hydrocarbon well, including a choke located between a wellhead production tree and the production line of hydrocarbons, an actuator operating the choke, the actuator being in communication with a remote control and monitoring unit, a power supply source supplying power to the control and monitoring unit, and a plurality of data acquisition means including transducers arranged upstream and downstream of the choke, where the data acquisition means sends information related to the wellhead pressure, the production line pressure, and optionally, the wellhead temperature to the control and monitoring unit, where the control and monitoring unit is configured to carry out well shut-in cycles and well opening cycles determined based on compliance with a plurality of well shut-in and opening criteria by which a measured or calculated value of a parameter is compared to a preset value for the parameter, where the measured or calculated parameters are selected from wellhead pressure, production line pressure, wellhead pressure to production line pressure ratio, shut-in or opening time of the well, flow rate and critical flow rate. A method for improving the production efficiency of a hydrocarbon well employing the same is also provided.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to Argentine Application No. P20230100986 filed on Apr. 24, 2023 the disclosure of which is incorporated herein by reference for all purposes.

TECHNICAL FIELD OF THE INVENTION

The invention relates to the technical field of automation of the cyclic shut-in and opening processes of hydrocarbon wells to improve production efficiency.

BACKGROUND OF THE INVENTION

Typically, gas wells reach, at some point in their life, a situation where the gas flow rate is not enough to transport the co-produced liquids to the surface.

These liquids may flow from the reservoir or condense on the gas produced in the path between the downhole and the surface.

The liquids may be condensed water, free water, oil condensate, or oil. Once this condition is reached, some fraction of the produced liquids will flow backflow with the gas and accumulate downhole. As liquids accumulate, the backpressure in the formation increases, This causes a sharp reduction in the gas production rate and, in the worst-case scenario, the well may be rendered completely non-productive and the consequent well shut-down.

A possible outcome caused by liquid-loading in the well is that the well stabilizes at a lower production rate, called “meta-stable rate”, term introduced by van Gool and Currie (2007). As a consequence of the accumulation of liquids in the well, a sharp drop in production is observed, finally stabilizing at a meta-stable rate and being able to produce at that meta-stable rate for many years.

Lea and Nickens, in the publication “Solving Gas-Well Liquid-Loading Problems”, Journal Petroleum Technology 56 (04):30-36, Apr. 1, 2004 (Issue: SPE-72092-JPT) disclose that, based on field experience, the occurrence of liquid loading in a gas well can be recognized by several symptoms which can be summarized as follows:

• • 1. A sharp reduction of flow rate.
  • 2. An onset of liquid slugs on the surface of the well.
  • 3. An increasing time difference between tubing and casing flow in pressure, measurable without packers present.
  • 4. Sudden changes in gradient in a flow-pressure survey.

To reduce the problems associated with liquid loading in a gas well and thereby maintain or increase well production, different types of techniques have been developed, where most of them are based on increasing gas rate and artificial water lifting. Lea and Nickens (2004) describe several actions that can be taken to reduce the liquid loading:

• • 1. Flowing the well at a high rate to remain in mist flow by using smaller tubing or creating a lower wellhead pressure.
  • 2. Pumping or gas lifting the liquids out of the well.
  • 3. Foaming the liquids, allowing the gas to lift the liquids from the well.
  • 4. Injecting water into an underlying disposal zone.
  • 5. Preventing liquid formation or production inside the well (e.g., by sealing off a water zone or using insulation or heat to prevent condensation).

Curtis et al., in the paper SPE 153073 titled “Cyclic Shut-in Eliminates Liquid Loading in Gas Wells” presented at the SPE/EAGE European Unconventional Resources Conference and Exhibition held in Vienna, Austria, March 2012, propose a method to eliminate production loss due to liquid-loading in tight gas wells based on cyclic well shut-in control as a simple production strategy that especially benefits low-permeability stimulated wells, including, but not limited to, shale gas wells.

This paper makes a comparison between a gas well producing (i) in an “ideal” situation in which 100% of the liquids entering from the reservoir or condensing in the tubing are continuously removed (without shut-ins), (ii) in a meta-stable liquid-loading condition with a low gas rate, typical of most wells today, and (iii) by the proposed cyclic shut-in control strategy.

Curtis et al. show that cyclic shut-in control of stimulated low-permeability vertical wells or ultra low-permeability horizontal multi-fractured wells can produce without ever experiencing liquid loading, and with little-to-no delay in ultimate recovery.

Cyclic shut-in control can be applied to all stimulated low-permeability gas wells from the onset of gas rates that result in liquid loading.

The strategy can also be applied to wells that have already experienced a period of liquid-loading, but the expected performance improvement may be less due to damage caused to the formation in the vicinity of the well by historical liquid-loading, e.g., fresh-water flowback and liquid-bank accumulation. In historically fluid-loading wells, an initial period of liquid removal and/or light stimulation may be necessary before initiating cyclic shut-in control.

Curtis et al. show that the shut-in period should be as short as operationally possible, and that cyclic shut-in control works equally well in layered, no-crossflow systems with significant differential depletion at the onset of liquid loading.

Minimizing the rate and recovery loss of liquid-loading gas wells is of international interest, so it is recommended to implement this practice for gas wells, particularly to minimize the rate of shale wells, which should lead to a significant ultimate increase in world gas reserves.

The method appears to be extremely simple and requires only a wellhead shut-in device with rate control.

Therefore, Curtis et al. propose to eliminate the problem of liquid loading accumulation by introducing a cyclic gas well shut-in control, whereby the well is never allowed to produce below the “liquid-loading” gas rate. Each time the liquid-loading rate is reached, the well is automatically shut in for a short period of time of about one hour.

During the shut-in period, gas continues to flow into the wellbore and near-wellbore region with some pressure increase. When the well is re-opened, a high transient gas rate is produced. After each shut-in period, the subsequent production period (during which the well produces at rates higher than the liquid loading rate) shortens compared to the previous production period.

The shut-in/production cycle continues ad infinitum until the well stops producing at an economic rate and becomes a dead well.

The exact shut-in time is not critical, but Curtis showed that a shorter shut-in time is always better than a longer shut-in time when compared over the life of a well in terms of ultimate gas recovery. This may not be correct if seasonal price variations are taken into account.

The optimal shut-in period may vary over time to maximize economic value.

Limitations of Cyclic Shut-In Control

Wells that have historically produced under liquid-loading conditions may have a significant amount of free liquid accumulated in the wellbore and near-wellbore region of the reservoir. In addition, shale gas wells may still be unloading treatment liquids when the liquid-loading rate is reached. Depending on the amount of free liquid in a well, cyclic shut-in may result in a gradual cleanup of the well by removing small amounts of free liquid.

However, larger amounts of free fluid may adversely affect tubing flow conditions and may not provide sufficient lift to remove significant amounts of liquid from the wellbore. A pumping method for removing excessive amounts of liquid may be necessary before initiating cyclic shut-in control.

The liquid-loading rate for wells with free liquids in the wellbore and near-wellbore region may be higher than the estimate from Turner-like minimum lift rate correlations. For the purpose of cyclic shut-in, we define the liquid-loading rate as the rate where the pressure drop in the tubing significantly exceeds the pressure drop for “single-phase” gas flow.

Liquid removal by plunger lifting is a form of cyclic shut-in control, with many variations on when and for how long the well is shut in.

Longer shut-in periods may be necessary to build up sufficient pressure to lift the plunger and liquids to the surface.

The “inefficiency” of the plunger lift, relative to the proposed cyclic shut-in control method, is primarily related to the shut-in period.

If the plunger-lift shut-in is short (on the order of hours), the efficiency of the plunger lift is comparable to that of the proposed cyclic shut-in control method.

Curtis recommends controlling the plunger lift cycle using the liquid-loading rate as the shut-in control, as it will ensure that only free liquids from the reservoir are being lifted and not “new” liquids that accumulate in the tubing during production at rates lower than the liquid-loading rate.

Finally, Curtis concludes that liquid-loading problems, and associated gas rate deterioration, can be completely avoided by never allowing the well to produce at rates below the minimum liquid lifting rate (liquid-loading rate).

1. A method is proposed to eliminate the adverse effect of liquid-loading on stimulated gas wells. The method is simple and cost effective, requiring only a wellhead device that automatically shuts in the well when a specified “liquid-loading” rate is reached and re-opens the well after a brief shut-in period.

2. Cyclic well shut-in control has been shown to be effective in recovering the same amount of gas as would be recovered in a hypothetical “ideal” well that is continuously unloaded without shut-ins. It is also shown that the cyclic shut-in periods should be as short as possible, typically in the order of one hour.

3. The time required to produce ultimate (economic) gas recovery using cyclic shut-in control is little-to-no longer than that of an ideal well that is continuously unloaded without shut-ins.

4. Cyclic shut-in is best suited to low-permeability stimulated vertical wells and horizontal multi-fractured ultra-low permeability (shale) wells.

5. Cyclic shut-in is equally valid for layered no-crossflow gas wells that develop differential depletion before reaching the liquid-loading gas rate.

6. Cyclic shut-in periods can vary throughout the year to maximize total annual revenues, given seasonal price variations.

The longest shut-in periods would logically occur during low-price summer months, but optimization is needed to automate control of shut-in periods throughout the year.

This methodology of cyclic shut-in and openings of hydrocarbon wells although simple in many well installations is carried out with in situ measurements and by manual opening and shut-in of the well by a specialized operator, which carries the risk of being a human-dependent operation.

In addition, in non-automated gas well facilities, this task is not a scheduled task, therefore, this operation is not always performed at the right time (when the well needs it), generating production loss.

Therefore, there is a need in the state-of-the-art to provide automated systems and methods for controlling and monitoring a hydrocarbon well using the cyclic shut-in and re-opening methodology described above in order to improve the production efficiency of the hydrocarbon well and avoid the problems associated with liquid accumulation, and that are easy to implement in existing facilities and low cost.

BRIEF DESCRIPTION OF THE INVENTION

Therefore, to solve the problem posed, the present invention provides a remote control and monitoring system for improving the production efficiency of hydrocarbon wells, comprising a choke located between a production tree of a hydrocarbon well and the hydrocarbon production line, having an actuator in communication with a remote control and monitoring unit for actuating said choke, a power supply source for supplying power to said control and monitoring unit, and a plurality of data acquisition means including transducers arranged upstream and downstream of said choke, wherein said data acquisition means send information relating to a plurality of measured parameters selected from wellhead pressure (WHP), production line pressure (LP), to the control and monitoring unit (3), and wherein the control and monitoring unit (3) is configured to perform hydrocarbon well shut-in and opening cycles by executing an algorithm employing said plurality of measured parameters to determine compliance with a plurality of hydrocarbon well opening and shut-in criteria based on a plurality of preset values for said parameters.

The invention also provides methods employing said remote control and monitoring system to improve the hydrocarbon well production.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows a block diagram of the control algorithm in the two cycles of operation thereof: opening cycle and shut-in cycle.

FIG. 2 shows a block diagram of the shut-in cycle.

FIG. 3 shows a block diagram of the opening cycle.

FIG. 4 shows a schematic view of a liquid droplet in a gas stream and the forces to which it is subjected with f_d being the drag force, f_g the force of gravity and d, the droplet diameter.

FIG. 5 shows a graphical representation of a first mode of operation corresponding to “shut-in based on pressure/opening based on pressure”.

FIG. 6 shows a graphical representation of a second mode of operation corresponding to “shut-in based on time/opening based on time”.

FIG. 7 shows a graphical representation of a third mode of operation corresponding to “shut-in based on time/opening based on pressure”.

FIG. 8 shows a graphical representation of a fourth mode of operation corresponding to “shut-in based on flow rate/opening based on pressure”.

FIG. 9 shows a graphical representation of a fifth mode of operation corresponding to “shut-in based on WHP/LP/opening based on WHP/LP”.

FIG. 10 shows a graphical representation of a sixth mode of operation corresponding to “shut-in based on pressure/opening based on time”.

FIG. 11-a shows a cross-sectional view of a positive choke (choke on-off) and FIG. 11-b shows an exploded view of a choke of the present invention.

FIG. 12 shows an orifice calibrated with an insert of the present invention.

FIG. 13 shows the arrangement of system components according to a first preferred embodiment.

FIG. 14 shows an arrangement of system components according to a second preferred embodiment.

FIG. 15 shows a block diagram of the algorithm executing the control and monitoring unit for the cyclic shut-in of a gas well.

DETAILED DESCRIPTION OF THE INVENTION

To optimize the production of a hydrocarbon well, particularly, of a natural gas well, the present invention provides an automated remote control and monitoring system and methods employing the cyclic shut-in and opening methodology of the hydrocarbon well, by means of the actuation of a choke arranged between the production tree and the production line comprising logics installed in an automatic control and monitoring unit and a plurality of data acquisition means arranged in the production tree and in the production line for the acquisition of data which are sent to said remote control and monitoring unit by means of the execution of a determined algorithm which actuates said choke opening or shutting in the well at the required time with the purpose of improving the production efficiency thereof and extending the productive life thereof. Thus, the control and monitoring system of the present invention automates the shut-in and opening cycles of the well, becoming independent of the human factor, improving the efficiency of the well control operations and reducing the time and costs associated with such operations taking into account the extensive distances that must be traveled by authorized personnel to the facilities for manual operation of the well, the fuel required, the production valve maintenance and the carbon footprint associated with these tasks.

Hydrocarbon wells, particularly natural gas wells, that can be intervened by cyclic shut-in and opening to improve the production efficiency thereof, may be low permeability stimulated vertical wells, ultra-low permeability multi-fractured horizontal wells (shale) or layered no-crossflow gas wells that develop differential depletion before reaching the liquid-loading gas rate.

Therefore, the present invention provides an automated remote control and monitoring system for improving the production efficiency of a hydrocarbon well, preferably, a natural gas well, including a conventional production tree, wherein the control and monitoring system comprises a choke comprising an orifice disposed between the wellhead tree and the production line, an actuator for said choke, remote control and monitoring unit being connected to a power supply source, and a plurality of data acquisition means disposed downstream and upstream of said choke, which send information relating to the various measured production and environmental parameters (transducers) to said remote control and monitoring unit to which they are wired or wirelessly connected, so that said remote control and monitoring unit uses this data sent by the plurality of data acquisition means to execute a specific algorithm, by means of which the moment in which the choke is actuated is determined in order to carry out in a completely automated manner the shut-in and opening cycles of the hydrocarbon well, thus improving the production efficiency of the gas well, avoiding problems associated with the accumulation of liquids and consequently, premature dead wells.

The plurality of data acquisition means comprises at least one line pressure transducer, at least one wellhead pressure (WHP) transducer, and optionally, at least one wellhead temperature transducer.

Additionally, the control and monitoring system includes a timekeeper for timing.

Another object of the invention is to provide a choke to be installed between the production tree, preferably, in a lateral branch, and the production line, comprising an actuator, preferably, a pneumatic actuator. Said choke has been specifically developed by the present inventors for the implementation of the remote control and monitoring system of the present invention and will be described in detail below. The data acquired by the plurality of data acquisition means are sent to the control and monitoring unit for the execution of a specific algorithm determining the start and completion of the shut-in and opening cycles of the hydrocarbon well by actuating in an automated manner a choke through an actuator according to two modes of operation, a well shut-in cycle mode and a well opening cycle mode. Said modes of operation require the accurate measurement of at least the wellhead pressure (WHP), and the production line pressure (LP), whereby it is possible, by means of a specific algorithm, to calculate the relationship between both pressures, the wellhead pressure (WHP) and the production line pressure (PL), as well as the gas flow rate and the critical gas flow rate as described below.

The algorithm uses a mathematical model for each gas flow condition to predict an estimated gas flow rate value and a critical gas flow rate value. For this purpose, the algorithm further requires other parameters such as the inner diameter of the orifice, the specific gravity of the gas, the ratio of heat capacity at constant pressure and heat capacity at constant volume: K=Cp/Cv.

Modes of Operation

FIG. 1 schematically shows the modes of operation of the remote control and monitoring system of the present invention.

The remote control and monitoring system of the present invention has two modes of operation: 1—shut-in cycle mode and 2—opening cycle mode (see FIGS. 1 to 3).

1—For the mode of operation corresponding to the shut-in cycle, the algorithm considers the following parameters: well shut-in time, wellhead pressure and production line pressure.

For the mode of operation corresponding to the opening cycle, the algorithm considers the following parameters: well opening time, wellhead pressure (WHP), production line pressure (LP), and calculates the ratio of wellhead pressure to production line pressure (WHP/LP), gas flow rate (using various mathematical models for each gas flow condition), and critical flow rate using Turner's mathematical model. In both modes of operation, the remote control and monitoring system of the present invention executes an algorithm that considers, in addition to the measured parameters indicated above, other parameters such as the diameter of the orifice of the choke, the specific gravity of the gas, and the ratio between the heat capacity at constant pressure and the heat capacity at constant volume: K=Cp/Cv. These parameters will make it possible to calculate the gas flow rate and the critical gas flow rate.

Then, based on the various measured and calculated parameters, the remote control and monitoring unit performs iterative comparisons between said set of measured and calculated parameters and the respective preset values for each of said measured and calculated parameters according to production requirements, so that, once a certain condition is met, it actuates the choke to carry out the opening and shut-in cycles of the gas well in a controlled manner.

The following describes various iterative comparison criteria performed by the control and monitoring unit according to each mode of operation.

The mode corresponding to a shut-in cycle can be performed using the following criteria:

According to a first criterion, it is iteratively compared whether the elapsed time for well shut-in is greater than or equal to a preset time for well opening; if this condition is met, the control and monitoring unit actuates the choke via its actuator for well opening.

According to a second criterion, it is iteratively compared whether the measured wellhead pressure (WHP) is equal or greater than a preset wellhead pressure for well opening; if this condition is met, the control and monitoring unit actuates the choke via its actuator for well opening.

According to a third criterion, the remote control and monitoring unit iteratively compares whether the ratio between wellhead pressure and production line pressure (WHP/LP) is greater than or equal to a predetermined WHP/LP ratio for the well opening; if this condition is met, the control and monitoring unit actuates the choke via its actuator for well opening.

In the mode corresponding to a well opening cycle, in the same way as in the well shut-in cycle mode, iterative comparisons are executed between a measured or calculated value of a given parameter and a preset value for that same parameter to determine the well shut-in. These iterative comparisons are made between the parameters of opening time, wellhead pressure (WHP), wellhead pressure/line pressure ratio (WHP/LP), gas flow rate calculated according to various flow conditions and critical gas flow rate calculated according to Turner's model.

Thus, the opening cycle is carried out pursuant to the following criteria: According to a first criterion, it is iteratively compared whether the elapsed time for well opening is greater than or equal to a value of the preset time for well shut-in; if this condition is met, the control and monitoring unit actuates the choke via the actuator to cause the well shut-in.

According to a second criterion, it is iteratively compared whether the measured wellhead pressure (WHP) is equal to or greater than the preset wellhead pressure value for well shut-in; if this condition is met, the control and monitoring unit actuates the choke via its actuator to cause the well shut-in.

According to a third criterion, it is iteratively compared whether the ratio between the measured wellhead pressure and the measured production line pressure (measured WHP/measured LP) is greater than or equal to a preset value of said ratio (WHP/LP) for well shut-in; if this condition is met, the control and monitoring unit actuates the choke via its actuator to cause the well shut-in.

According to a fourth criterion, it is iteratively compared whether the calculated gas flow rate is greater than or equal to a value of the preset gas flow rate for well shut-in; if this condition is met, the control and monitoring unit actuates the choke via its actuator to cause the well shut-in.

Finally, according to a fifth criterion, during the well opening cycle, it is iteratively compared whether the calculated gas flow rate is greater than or equal to a value of the preset critical gas flow rate for well shut-in; if this condition is met, the control and monitoring unit actuates the choke via its actuator to cause the well shut-in.

With respect to the critical flow rate parameter, the algorithm developed by the present invention uses Turner's model for the estimation thereof:

Turner et al. proposed two physical models for the removal of liquids:

• • 1. Liquids form a continuous film on the tubing inner wall, moving upwards due to interfacial forces.
  • 2. Liquid droplets appear in the tubing as free particles moving upwards due to a high gas rate. After developing these two methods, Turner et al. independently compared actual field data with the models to find which is closer and which mechanism controls liquid removal.

In this regard, Turner's studies dictate that the existence of liquid droplets in the gas stream presents a different problem, which is based on determining the flow rate required to lift the liquid droplets and transport them to the surface. According to the study, a free-falling particle reaches a final rate which is the maximum rate it can achieve vs. gravity (FIG. 4). Therefore, that final rate, also known as critical gas rate, is determined by the flow conditions necessary to remove liquids on a continuous basis, and is based on the drag and gravitational forces acting on the droplet.

In this model, the droplet weight is a downward force (gravity), and the gas rate is an upward force (drag). When the drag is equal to the weight, the particle is suspended in the gas stream (critical rate); therefore, a gas rate greater than the critical rate is required to transport the liquids to the surface.

Consequently, the Critical Rate is the minimum rate that a liquid droplet must have in order to be lifted by the gas. For the calculation thereof, the following Turner's Equation is used.

$v_c=\frac{1.3{{\sigma }_l^{1/4}\left({\rho }_l-{\rho }_z\right)}^{1/4}}{C_d^{1/4}{\rho }_z^{1/2}}$

• • V_c=critical rate (ft/s)
  • δl=gas-liquid interfacial tension (dynes/cm)
  • ρ=gas-liquid density under well conditions (lb/ft³)
  • C_d=drag coefficient (with a recommended value of 0.44).

From the critical rate, it is possible to calculate the critical flow rate (Q_critical) with the following formula:

$Q_{\mathrm{critical}}\left(\mathrm{MMsef}/D\right)=\frac{.0676{\mathrm{Pd}}_{\mathrm{ti}}^2}{\left(T+460\right)Z}\frac{{\left(45-\text{.0031}P\right)}^{1/4}}{{\left(\text{.0031}P\right)}^{1/2}}$

• • Wherein
  • MMscf/D=million standard cubic feet per day
  • P=wellhead pressure flow (psi)
  • T=temperature (° F.)
  • d_ti=tubing inside diameter (inches)
  • Z=compressibility factor

Therefore, it is sufficient to use the tubing diameter “d_ti” to calculate the critical flow rate using the above equation.

According to the present invention, the following fixed values are adopted for the following parameters assuming a condition as conservative as possible, that is, that the type of liquid is water (worst condition), which involves:

• • Surface tension=60 dyne/cm
  • Density=67 lbm/(ft³)
  • Z=0.9
  • T=84.2° degrees Fahrenheit (° F.).

Thus, the critical flow rate will only depend on the wellhead pressure (P) and the tubing internal diameter (d_ti).

To estimate the gas flow rate, various gas flow conditions must be considered as shown in the block diagram in FIG. 15.

Single-Phase Gas Flow

For a first ideal situation, where the gas flow is single phase with no critical or subcritical conditions, the following Equation 1 is used according to the modified ISO-5167 Standard, since the present invention uses an orifice to cause a differential gas pressure instead of an orifice plate as determined according to said Standard. This leads to Equation 1 making it possible to calculate the gas flow rate with an error of less than 10% which constitutes an acceptable error in the gas extraction industry.

$\begin{array}{cc}\mathrm{Qg}\left(m3/d\right)=0.68*\frac{1}{\sqrt{V\left(\mathrm{Grav}.\mathrm{of}\mathrm{gas}\mathrm{as}\mathrm{regards}\mathrm{air}\right)}}*\sqrt{\frac{520}{460+\text{?}+\frac{9}{5}T\left(°C.\right)}}*F_{\text{?}}*\sqrt{h_W\left(\mathrm{inches}\mathrm{of}\mathrm{water}\right)*\left(\mathrm{Pf}\left(\mathrm{psi}\right)+14.7\right)}& \mathrm{Equation}1\end{array}$ $\text{?}\text{indicates text missing or illegible when filed}$

• • Wherein
  • Qg: is the gas flow rate in m³/day
  • γ: is the specific gravity of the gas with respect to air.

Typically, the gas has high concentrations of methane, ethane, and propane, estimated between 0.6 and 0.62 to simplify the calculation.

• • T: is the wellhead gas temperature in ° C., upstream of the choke.
  • h_w: is the differential pressure in ° C. at the orifice (in inches of water).
  • Pf: is the line pressure, downstream of the choke.
  • F_b: is the correction factor.

The F_b factor depends on the dimensions of the casing and the diameter of the orifice (choke).

For practical purposes, it is assumed that the gas temperature at the wellhead is 25° C. (77° F.), since temperature variations have a negligible impact on the gas flow calculation.

Given that the orifice diameter varies over time as gas well production declines, the F_b factor can be determined by well-known correlations for those with average knowledge in the field, which consider the internal diameter of the casing pipe and the orifice diameter used at the time the gas flow rate is calculated.

Typically, in the first 12 months of the well productive life, the orifice diameter may be the smallest orifice diameter used in the industry, i.e., it may range from 4 mm to 2.54 cm (1 in). After this period, as production declines, the orifice may increase up to 2 inches, particularly within the first 24 months.

Once said F_b factor is determined, it is possible to calculate the gas flow rate according to Equation 1 above. This equation allows estimating the gas flow rate with an error of less than 10%.

However, it may be necessary to adjust the equation to further reduce the error, preferably to 0. Therefore, it will be necessary to perform a well control to know an actual accurate value of gas flow rate in the well, corresponding to a given differential pressure in the orifice (h_w) and a line pressure (Pf), all of them measured at the same timepoint. With these instant data, Equation 1 can be rewritten as follows:

$\frac{\mathrm{Qg}\left(m3/d\right)}{\sqrt{h\text{?}\left(\mathrm{inches}\mathrm{of}\mathrm{water}\right)*\left(\mathrm{Pf}\left(\mathrm{psi}\right)+14.7\right)}}=0.68*\frac{1}{\sqrt{V\left(\mathrm{Grav}.\mathrm{of}\mathrm{gas}\mathrm{as}\mathrm{regards}\mathrm{air}\right)}}*\sqrt{\frac{520}{460+\text{?}+\frac{\text{?}}{5}T\left(°C.\right)}}*\mathrm{Fb}=\mathrm{Fk}$ $\text{?}\text{indicates text missing or illegible when filed}$

• • Wherein
  • h_w, γ, Pf and T have the meanings stated above.

Finally, Equation 1, adjusted to reduce the gas flow calculation error, is defined according to Equation 2 below:

$\begin{array}{cc}\mathrm{Qg}\left(m3/d\right)=\mathrm{Fk}*\sqrt{h_W\left(\mathrm{inches}\mathrm{of}\mathrm{water}\right)*\left(\mathrm{Pf}\left(\mathrm{psi}\right)+14.7\right)}& \mathrm{Equation}2\end{array}$

This equation reduces the estimation error by using the actual well production conditions determined by instant well control (which is called “history matching” in the technical field of the invention).

Single-Phase Gas Flow at Critical and Subcritical Conditions

The following gas flow condition considered by the algorithm of the present invention for gas flow rate estimation corresponds to a single-phase gas flow under flow conditions which may be critical and subcritical. In this condition, the pressure drop in the choke (orifice) is considered, so that when the wellhead pressure (pressure upstream of the choke) is more than twice the line pressure (pressure downstream of the choke), the gas rate in the choke is the speed of sound, and the condition that occurs is the critical flow condition. Under this critical or sonic flow condition, pressure changes downstream of the choke caused by various dynamics (e.g., a compressor shutdown) would not affect the pressure upstream of the choke (i.e., the wellhead pressure). In other words, the flow rate is independent of line pressure under critical conditions.

If the line pressure continues to increase due to other dynamics occurring downstream of the choke, (for example the shutdown of another compressor), the ratio between wellhead pressure and line pressure may be less than 2, which determines that the gas rate is less than the speed of sound (subsonic rate) and in such a case, subcritical or subsonic flow conditions occur.

Both conditions are limitations (critical flow and subcritical flow) that the algorithm of the present invention considers for the correct calculation of the gas flow rate.

Therefore, under subcritical or subsonic flow conditions, Equation 3 is used for the calculation of the gas flow rate in the choke:

$\begin{array}{cc}{q}_{sc}=1.248C_D{A}_2{P}_{up}*\sqrt{\frac{k}{\left(k-1\right){\gamma }_g{T}_{up}}\left[{\left(\frac{P_{dn}}{P_{up}}\right)}^{\frac{2}{k}}-{\left(\frac{P_{dn}}{P_{up}}\right)}^{\frac{k+1}{k}}\right]}& \mathrm{Equation}3\end{array}$

• • Wherein
  • k is the specific heat ratio of the gas at constant pressure and constant volume Cp/Cv
  • T_up is the temperature upstream of the choke
  • P_dn is the pressure downstream of the choke
  • P_up is the pressure upstream of the choke
  • while under critical or sonic flow conditions, the gas flow rate is expressed by the modified Equation 3:

$Q_{sc}=879C_{D}A{P}_{up}*\sqrt{\frac{k}{{\gamma }_g{T}_{up}}{\left(\frac{2}{k+1}\right)}^{\frac{k+1}{k-1}}}$

• • Wherein
  • Q_sc: is the gas flow (Mscl/day)
  • P_up: is the pressure upstream of choke (psia)
  • P_dn: is the pressure downstream of the choke (psia)
  • A₂: is the choke cross section in in²
  • T_up: is the temperature upstream of the choke (° R)
  • g: is the acceleration of gravity (32.2 ft/sec²)
  • γ_g: is the specific gravity of the gas relative to air
  • k: is the heat capacity ratio Cp/Cv
  • C_D: is the flow coefficient in the choke
  • while C_D is calculated as follows:

$C_D=\frac{d_2}{d_1}+\frac{0.3167}{{\left(\frac{d_2}{d_1}\right)}^{0.6}}+0.025\left[\log \left(N_{Re}\right)-4\right]$

• • Wherein
  • N_Re: is the Reynolds number
  • d₁: is the pipe diameter upstream of the choke (in)
  • d₂: is the diameter of the choke (in).

As can be seen, C_D depends on the Reynolds number which in turn depends on the gas flow rate and the viscosity and specific gravity of the gas. This implies that the gas flow rate must be calculated by cycles of iterations using Equation 3.

Multiphase Flow

When the upstream pressure is lower than the oil bubble point pressure, there is free gas in the fluid stream flowing through the downhole control valve.

The behavior of the fluid at the downhole control valve will depend on the gas content and whether the flow regime is sonic or subsonic.

The mathematical modeling of multiphase flow through the choke has been subject of controversy for decades. As such, the Sachdeva and Perkins models are currently of particular interest in the industry and have been coded in commercial network modeling software to characterize flow behavior for both surface and downhole chokes. The first step in the application of these models is to predict the downstream/upstream pressure relationship at the critical flow transition. Both Sachdeva and Perkins developed equations to estimate this relationship. Sachdeva's work assumed that the derivative of the mass flow rate of the mixture with respect to the pressure downstream of the choke orifice is zero at the critical flow transition, meaning that the mass flow reaches a maximum with respect to the downstream pressure. Assuming that the gas phase at the choke inlet contracts isentropically, but expands polytrophically, equations were developed to predict the critical pressure ratio and mass flow rate at critical and subcritical conditions.

Perkins' work derives from the general energy equation assuming polytrophic processes, and an important feature is that Perkins assumed the gas compressibility factors at both the upstream and downstream choke orifice were the same. This assumption may be reasonable at low differential pressures, but is not applicable at high differential pressures. Assuming that the derivative of the mixture mass flow rate with respect to the downstream/upstream pressure ratio is zero, which is similar to Sachdeva's work (1986), an equation was developed to predict the critical pressure ratio.

Both models used a constant discharge coefficient (Cd) to correct for errors resulting from various assumptions. However, downhole control valves typically operate at high temperatures and pressures, and the shape of the control-valve choke varies with different choke positions. Therefore, these models must be modified by incorporating downhole pressure and temperature conditions, correlated choke discharge coefficients, and upstream/downstream completion geometries. With this in mind, the algorithm of the present invention uses the Sachdeva and Perkins model in order to calculate gas flow at critical and subcritical conditions according to the following equations.

Firstly, it is necessary to determine the multiphase flow conditions, i.e., whether the multiphase flow is at critical or subcritical conditions based on the following Equation 4:

$\begin{array}{cc}{y}_{\text{?}}={\left(\frac{\frac{k}{k-1}+\frac{\left(1-x_{\text{?}}\right)V_{\text{?}}\left(1-y_{\text{?}}\right)}{x_1{V}_{G1}}}{\frac{k}{k-1}+\frac{n}{2}+\frac{n\left(1-x_{\text{?}}\right)V_{\text{?}}}{x_1{V}_{G2}}+\frac{n}{2}{\left(\frac{\left(1-x_{\text{?}}\right)V_{\text{?}}}{x_1{V}_{G2}}\right)}^2}\right)}^{\frac{k}{k-1}}& \mathrm{Equation}4\end{array}$ $\text{?}\text{indicates text missing or illegible when filed}$

• • Wherein
  • y_c: is the ratio of critical pressures
  • k: is the ratio of specific heat points (Cp/Cv)
  • n: is the polytropic index for gas
  • x_l: the mass fraction of upstream free gas can be estimated or calculated by a well control
  • V_L: is the specific upstream liquid volume (ft³/lbm)
  • V_G1: is the specific upstream gas volume (ft³/lbm)
  • V_G2: is the specific downstream gas volume (ft³/lbm)

In addition, the Sachteva model contemplates the following ratio:

• • Wherein

$y_{\text{?}}=\frac{p_2}{p_1}$ $\text{?}\text{indicates text missing or illegible when filed}$

• • y_a: is the actual downstream pressure to upstream pressure ratio
  • p₁: is the upstream pressure (psi)
  • p₂: is the downstream pressure (psi)

Then, if y_a<y_c, there are critical flow conditions, therefore, y_c should be used to calculate the mass flow (y=y_c) using Equation 5.

Otherwise, subcritical flow conditions exist and consequently, y=y_a=p₁/p₂ should be considered.

Then, the gas mass flow rate is calculated using Equation 5

$\begin{array}{cc}{G}_2={c_d\left(288g_{\text{?}}{p}_{\text{?}}{{\rho }_{\text{?}}}^2\left(\frac{\left(1-x_{\text{?}}\right)\left(1-y\right)}{{\rho }_L}+\frac{x_{1}k}{k-1}\left(V_{\text{?}}-{\mathrm{yV}}_{\text{?}}\right)\right)\right)}^{\text{?}}& \mathrm{Equation}5\end{array}$ $\text{?}\text{indicates text missing or illegible when filed}$

• • G₂=downstream mass flow rate (lbm/ft²/sec)
  • C_d: is the choke discharge index
  • y: is the downstream pressure/upstream pressure ratio
  • k: is the ratio of specific heat points (Cp/Cv)
  • x_l: the mass fraction of upstream free gas can be estimated or calculated by a well control
  • ρ_m2: is the downstream multiphase mixture density (lbm/ft³)
  • ρ_L: is the liquid density (lbm/ft³)
  • V_G1: is the specific upstream gas volume (ft³/lbm)
  • V_G2: is the specific downstream gas volume (ft³/lbm)

Then, knowing the area of the choke orifice, it is possible to calculate the mass flow of the multiphase mixture and, with the density of the mixture, the volume flow can be calculated, as follows:

M2:G2.A

• • M₂: is the mass flow rate of the downstream mixture (lbm/sec)
  • G₂=downstream mass flow rate (lbm/ft²/sec)
  • A=area of choke orifice (ft²)

Then, knowing M2, it is possible to know the gas flow rate under multiphase flow conditions, either at critical or subcritical conditions. Then, with the calculation of gas flow rate using Equations 1 to 4 described above according to each of the four detailed flow conditions (FIG. 15), it is possible to determine whether the well is entering choked conditions by comparing the calculated gas flow rate with Turner's critical flow rate.

As can be seen, the automated control and monitoring system of the present invention dispenses with the use of flowmeters when calculating the gas flow rate by means of the algorithm developed by the present inventors, which contemplates the various gas flow conditions in the well, representing a clear operational and economic advantage over other well control systems that do require the use of flowmeters.

On the other hand, the preset values for the time parameters (set point), wellhead pressure, line pressure (LP), ratio (WHP/PL) and flow rate are established based on a periodic analysis of the well actual behavior to which the remote control and monitoring system of the present invention is applied.

The remote control and monitoring system of the present invention is further configured to automatically collect well production data, generate well profiles based on the data, and self-adjust to maintain a well production rate at a desirable level.

Choke On-Off

The gas well production control and monitoring system according to the present invention is based on the implementation of gas well shut-in and opening cycles by means of the actuation of choke 1 (see FIGS. 11, 13 and 14) by means of an actuator which is in communication with the control and monitoring unit 3. Said choke 1 has been specially designed for the implementation thereof in the automated control and monitoring system of the present invention (FIG. 11) and possesses a dual function, since it not only acts as a choke but also as a shut-in means (valve). This choke 1 according to the present invention has the advantage that it can be used in existing installations without the need for modifications, for example, it can be used in the existing orifice choke in the installation.

The choke 1 according to the present invention (FIG. 11) comprises a main body 1.1 featuring integrated connecting means 1.2, 1.2′, such as a flange, adapted to connect to the production tree 6 or other flow control component, such as a safety valve, on the one hand, and to the tubing 7 (LP) on the other, so that the choke 1 is conveniently located between the wellhead production tree 6 and the tubing 7 (see FIGS. 13 and 14). Preferably, the choke 1 is connected to a lateral branch of the wellhead production tree 6.

The choke body 1.1 is hollow and defines a through conduit 1.3 within which a calibrated orifice 1.4 is housed. Said calibrated orifice 1.4 is configured to house a hollow insert 1.5 (FIG. 12) which has a through conduit extending longitudinally and which is preferably made of a ceramic or tungsten carbide material or other material that withstands the operating conditions of high pressures, flow rates and corrosive fluids.

The calibrated orifice 1.4 has an elongated hollow body 1.4a with a through inner conduit 1.4b extending along the entire length thereof, and at one of its ends, it widens defining a bearing surface 1.4c. Conveniently, the external surface of the calibrated orifice 1.4 presents a perimeter flange 1.4d extending radially and on which sits a gasket 1.4e that allows sealing the calibrated orifice within the through conduit 1.3 of choke 1. In a preferred embodiment, the calibrated orifice 1.4 is inserted into a seat 1.13 of stem 1.10 of a conventional choke 1 (FIG. 13).

The choke body 1.1 comprises an upper end sealed with a plug 1.6 and a quick-connect nut 1.7 configured to receive an actuator 1.8, preferably a pneumatic actuator.

Said actuator 1.8 comprises a hollow actuator body 1.9 configured to house a compression spring 1.11 and to allow displacement in the direction of the axial axis of an actuating stem 1.10, which, in response to a pneumatic signal of choke 1 closing, moves against the spring 1.11 compressing it, while, in response to a pneumatic signal of choke 1 opening, it moves in the opposite direction decompressing said spring 1.11. Said actuating stem 1.10 has two ends: an actuating end and an opposite sealing end connected to a seal 1.12, so that when the actuating stem 1.8 moves in the direction of the axial axis towards the calibrated orifice, it partially or completely seals the calibrated orifice, acting as a choke or closing means (valve). The main objective of the configuration of choke 1 is to allow the conversion of a conventional positive choke into a choke on-off (see FIG. 11) without losing the “positive choke” functionality, which is very useful when automating the production by cyclic shut-in and opening of mature natural gas wells, since it does not require modifications of existing installations. In other words, the control and monitoring system of the present invention adapts to existing installations by using the same orifice choke existing in a conventional installation to insert the calibrated orifice 1.4 with the insert 1.5 in accordance with the present invention.

Description of the Control and Monitoring System

As above indicated, the invention provides a remote control and monitoring system for improving the production efficiency of a hydrocarbon well, comprising a choke 1 (orifice), an actuator 1.8, an automatic control and monitoring unit 3, a power supply source 4, preferably a solar panel or a battery, and a plurality of data acquisition components including transducers 16, 17, 18 arranged on the production tree 6 or on tubing 7 which send coded information relating to various measured parameters to the control and monitoring unit 3 which by means of a given algorithm actuates the choke to execute fully automated shut-in and shut-out cycles of the gas well improving the production efficiency of the well and avoiding the problems associated with fluid accumulation and eventually, dead wells.

The plurality of data acquisition components 16, 17, 18 comprises at least one line pressure transducer, at least one wellhead pressure (WHP) transducer, and optionally, at least one wellhead temperature transducer located on the wellhead tree (not shown).

FIGS. 13 and 14 show two preferred arrangements of the system for controlling and monitoring the production of a hydrocarbon well, particularly a gas well according to the present invention.

As shown in FIG. 13, the remote control and monitoring system of the present invention is linked to a typical wellhead tree 6 typically comprising a main body with upper and lower master gate valves 8, 8′, an upper end with an upper plunger valve 9 adapted to be connected to a pressure gauge, at least one left lateral branch including a well choke valve 10 and at least one right lateral branch including a production valve 11. Typically, the wellhead tree 6 is connected through its production side branch to the production line 7 via a surface choke (orifice) 1.

In a preferred embodiment, a safety valve 12 is arranged between the production side valve 11 and the choke 1, as shown in FIG. 13. This safety valve 12 is used to shut the tubing in order to prevent the well gas flow through the tubing and/or to relieve the wellhead pressure in case of an overpressure or in case of fire hazard, for example.

In a preferred embodiment, the pressure gauge 13 usually located in the upper bore of the wellhead production tree 6, is replaced by a pressure regulating valve 14 which is operated by a gas instrument 15, which has been connected to the control and monitoring unit 3. The gas instrument 15 is connected to the well to feed gas in the actuation circuit. This gas pressurizes the actuator keeping it open. Should the control and monitoring unit 3 determine to close the well, a solenoid valve (not shown) will relieve the circuit pressure, shutting in the well. Additionally, block and bleed valves 16 are provided where pressure transducers are located upstream and downstream of the choke 1 (choke on-off) as shown in FIG. 13. Said pressure transducers are configured to measure the pressure upstream and downstream of the choke 1 and are part of the data acquisition means connected to the control and monitoring unit 3.

In the embodiment shown in FIG. 14, the wellhead production tree 6 includes a wellhead pressure transducer 17 located on the side branch downstream of the well choke valve 10 that measures wellhead pressure (WHP), while the other pressure transducer 18 is located on the production line (LP) upstream of choke 1.

All pressure transducers 16, 17, and 18 are in wired or wireless communication with the control and monitoring unit 3.

In another preferred embodiment, between the production side valve 11 and choke 1, a surface safety valve 19 is provided which is of hydraulic type and has the same function as safety valve 12 (see FIG. 14).

EMBODIMENT EXAMPLES

EXAMPLES

Specific examples of application of the control and monitoring system of the present invention are described below, where different criteria are applied in combination to establish the timing of shut-in and opening of a mature gas well.

Example 1: Shut-In Cycle Based on Wellhead Pressure (WHP)/Opening Cycle Based on Wellhead Pressure (WHP)

The time interval during which the opening and shut-in cycle is performed is generally the same as the time interval during which the user performed manual controls. In Illustrative Example 1, the monitoring and control system for cyclic shut-in and opening of a gas well was run for a period of approximately 31 hours. In this example, preset WHP values were set at 17.2 kg/cm² (minimum acceptable for shut-in) and 54.5 km/cm² (maximum acceptable for opening) according to production requirements (FIG. 5). As liquid accumulation took place, the wellhead pressure progressively decreased, and when it reached the lower limit of 17.2 kg/cm², the control and monitoring unit actuated choke 1 to shut in the gas well until the wellhead pressure reached the 54.5 kg/cm² preset as an acceptable pressure for well opening.

Example 2: Shut-In Cycle Based on Time/Opening Cycle Based on Time

In Illustrative Example 2, the monitoring and control system for cyclic shut-in and opening of a gas well was run for a period of approximately 31 hours. In this example, the elapsed time to shut in the well was 14 hours and the elapsed time to open the well was 10 hours according to production requirements and well trend analysis (see FIG. 6). This analysis determines how long to shut in the well before the pressure recovery becomes asymptotic and how long to open the well before the well begins to choke.

As fluid accumulation takes place, the wellhead pressure progressively decreased, when it reached the lower limit of wellhead pressure, which occurred after approximately 14 hours of well opening, the control and monitoring unit actuated choke 1 to shut in the gas well until the wellhead pressure increased and reached an acceptable upper limit (approximately 78 kg/cm²), which corresponded to a shut-in period of 10 hours, starting a fresh well opening cycle.

Example 3: Shut-In Cycle Based on Time/Opening Cycle Based on Wellhead Pressure (WHP)

In Illustrative Example 3, the monitoring and control system for cyclic shut-in and opening of a gas well was run for a period of approximately 31 hours. In this example, the elapsed time for well shut-in was 15 hours and the preset pressure for well opening was 74.1 kg/cm² according to production requirements (see FIG. 7). As liquid accumulation took place, the wellhead pressure progressively decreased, when it reached the lower limit of wellhead pressure which occurred approximately 15 hours after well opening, the control and monitoring unit actuated choke 1 to shut in the gas well until the wellhead pressure increased and reached an upper limit of 74.1 kg/cm² at which time a fresh well opening cycle started.

Example 4: Shut-In Cycle Based on Flow Rate/Opening Cycle Based on Wellhead Pressure (WHP)

In Illustrative Example 4, the monitoring and control system for the cyclic shut-in and opening of a gas well was run over a period of approximately 31 hours on a mature well. In this example, the flow rate preset for well shut-in was 10 km³/day and the wellhead pressure preset for well opening was 67 kg/cm² according to production requirements (see FIG. 8). As liquid accumulation took place in the well, the gas flow rate progressively decreased, and was calculated at 12 km³/day, i.e. slightly above the preset value for well shut-in of 11 km³/day, the control and monitoring unit actuates choke 1 to shut in the gas well until the wellhead pressure reached an acceptable upper limit for well opening of 67 kg/cm², starting a fresh well opening cycle.

Example 5: Shut-In Cycle Based on Wellhead Pressure to Line Pressure Ratio/Opening Cycle Based on Wellhead Pressure to Line Pressure Ratio

In Illustrative Example 5, the monitoring and control system for the cyclic shut-in and opening of a gas well was run over a period of approximately 31 hours on a mature well. As liquid accumulation takes place, the gas wellhead pressure progressively decreased, while the line pressure was maintained with small fluctuations (between 12 and 16 kg/cm²) as shown in FIG. 9. Thus, when the wellhead pressure was equal to the line pressure, i.e. WHP/PL=1, the lower admissible limit for this ratio was reached, and the control and monitoring unit activated choke 1 to close the gas well consequently increasing the pressure until the ratio of wellhead pressure (WHP)/line pressure LP, (WHP/Lp) was 5.13, i.e., the wellhead pressure reached a preset acceptable upper limit (approximately 82 kg/cm²) for a well opening cycle.

Example 6: Shut-In Cycle Based on Wellhead Pressure (WHP)/Opening Cycle Based on Time

In Illustrative Example 6, the monitoring and control system for cyclic shut-in and opening of a gas well was run for a period of approximately 31 hours. In this example, the preset pressure for well shut-in was 17.5 kg/cm² and the elapsed time for well opening was 11 hours according to production requirements (see FIG. 10). As liquid accumulation takes place in the well, the wellhead pressure progressively decreased, when it reached the lower wellhead pressure limit of 17.5 kg/m³, the control and monitoring unit actuated choke 1 to shut in the gas well until the wellhead pressure increased and reached an acceptable upper limit (73 kg/cm²) which corresponded to a shut-in time of 11 hours after which a fresh opening cycle started.

Claims

1. A remote control and monitoring system to improve the production efficiency of a hydrocarbon well, the system characterized in that it comprises: a choke (1) located between a wellhead production tree (6) and the production line (7) of hydrocarbons, an actuator (1.8) operating said choke (1), said actuator (1.8) being in communication with a remote control and monitoring unit (3), a power supply source (4) supplying power to said control and monitoring unit (3), and a plurality of data acquisition means including transducers (16, 17, 18) arranged upstream and downstream of said choke (1), where said data acquisition means sends information related to the wellhead pressure (WHP), production line pressure (LP), and optionally, wellhead temperature (T) to the control and monitoring unit (3), where said control and monitoring unit (3) is configured to carry out well shut-in cycles and well opening cycles determined based on compliance with a plurality of well opening and shut-in criteria by which a measured or calculated value of a parameter is compared to a preset value for said parameter, where said measured or calculated parameters are selected from wellhead pressure (WHP), production line pressure (LP), wellhead pressure to production line pressure ratio (WHP)/LP), shut-in or opening time of the well, flow rate and critical flow rate.

2. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that said hydrocarbon well is a natural gas well.

3. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that said choke (1) is connected, on the one hand, to the production side valve (11) of a wellhead tree (6) and on the other hand, to the production line (7).

4. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that a safety valve (12, 19) is arranged between the production side valve (11) of a wellhead tree (6) and choke (1).

5. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that at the upper end of the wellhead production tree (6), a pressure regulating valve (14) operated by a gas instrument (15) is arranged to feed gas to the pneumatic circuit of the actuator (1.8).

6. A remote control and monitoring system for improving production efficiency of a hydrocarbon well according to claim 1, characterized in that said plurality of data acquisition means includes transducers (16, 17, 18) configured to measure pressure upstream and downstream of choke (1).

7. A remote control and monitoring system for improving production efficiency of a hydrocarbon well according to claim 6, characterized in that said plurality of data acquisition means includes transducers (16, 17, 18), wherein the transducers (16) are configured to measure pressure upstream and downstream of choke (1) and are disposed on respective block and bleed valves, or the transducers (17) are disposed on a lateral branch of the wellhead production tree (6) and the transducers (18) are disposed on the production line (7).

8. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that said actuator (1.8) comprises a hollow actuator body (1.9) configured to house a compression spring (1.11) and allow the displacement in axial direction of an actuating stem (1.10) having an actuating end and an opposite end connected to a seal (1.12), where, in response to a closing signal of choke (1), said actuating stem (1.10) moves against the spring (1.11) compressing it, while in response to an opening signal of choke (1), said actuating stem (1.10) moves in the opposite direction decompressing said spring (1.11).

9. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that said choke (1) comprises a main hollow body (1.1) having integrated connection means (1.2, 1.2′), said main hollow body defining a through conduit (1.3) housing a calibrated orifice (1.4) configured to house a hollow insert (1.5).

10. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 9, characterized in that said calibrated orifice (1.4) has an elongated hollow body (1.4a) defining a through inner conduit (1.4b) inside which said hollow insert (1.5) is housed, said through inner conduit (1.4b) extends along the entire length of the calibrated orifice (1.4), and at one of its ends, it widens defining a support surface (1.4c).

11. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 9, characterized in that the calibrated orifice (1.4) has a perimeter flange (1.4d) extending radially and on which a gasket (1.4e) is seated to seal the calibrated orifice (1.4) within the through conduit (1.3) of choke (1).

12. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 9, characterized in that said insert (1.5) has a through conduit extending longitudinally.

13. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 9, characterized in that said insert (1.5) is made of a ceramic or tungsten carbide material or other material that withstands the operating conditions of high pressures, flow rates and corrosive fluids.

14. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 9, characterized in that the calibrated orifice (1.4) is inserted into the seat (1.13) of the stem (1.10) of said choke (1).

15. A remote control and monitoring system for improving the production efficiency of a hydrocarbon well according to claim 1, characterized in that said actuator (1.8) is a pneumatic actuator.

16. A method for improving the production efficiency of a hydrocarbon well employing the remote monitoring and control system according to claim 1, characterized in that said method comprises the steps of: i) acquiring data corresponding to wellhead pressure and production line pressure using data acquisition means comprising pressure transducers (16, 17, 18);ii) sending the acquired data to the control and monitoring unit (3)iii) determining from the acquired data, the operating mode of the hydrocarbon well, where the operating mode may correspond to an opening cycle or a shut-in cycle of the well,iv) if the well is in a shut-in cycle, the control and monitoring unit (3) shall actuate the choke open the well when: a) the elapsed time of well shut-in is longer than or equal to a preset time for well opening, orb) the measured wellhead pressure is equal to or greater than a preset wellhead pressure for well opening, orc) the ratio of wellhead pressure to production line pressure (WHP/LP) is greater than or equal to a predetermined ratio (WHP/LP) for the well opening,v) if the well is in an opening cycle, the control and monitoring unit (3) shall actuate the choke (1) to shut in the well when: d) the elapsed well opening time is greater than or equal to a value of the preset time for well shut-in; ore) the measured wellhead pressure (WHP) is equal to or greater than the value of the preset wellhead pressure for well shut-in; orf) the ratio of the measured wellhead pressure to the measured production line pressure (measured WHP/measured LP) is greater than or equal to a preset value of that ratio (WHP/LP) for the well shut-in; orj) the calculated gas flow rate is greater than or equal a preset value of the preset gas flow rate for well shut-in; ork) the calculated gas flow rate is greater than or equal to a value of the preset critical gas flow rate for well shut-in.

17. A method for improving the production efficiency of a hydrocarbon well according to claim 16, characterized in that the critical flow rate is determined by the Turner's Equation:

18. A method for improving the production efficiency of a hydrocarbon well according to claim 16, characterized in that the gas flow rate is calculated considering the following gas flow conditions: i—single-phase gas flow, wherein no critical or subcritical conditions exist,ii—single-phase gas flow wherein critical or subcritical conditions existiii—multiphase gas flow wherein critical or subcritical conditions exist.

19. A method for improving the production efficiency of a hydrocarbon well according to claim 18, characterized in that when the gas flow is single phase where no critical or subcritical conditions exist, the gas flow rate is calculated according to the following Equation 1:

20. A method for improving the production efficiency of a hydrocarbon well according to claim 18, characterized in that the gas flow rate in the choke is calculated with Equation 3 when the gas flow is single phase under subcritical conditions:

21. A method for improving the production efficiency of a hydrocarbon well according to claim 18, characterized in that the gas flow rate in the choke, when the gas flow is multiphase, is determined by the mixture mass flow equation and the mixture density, wherein the downstream mixture mass flow M2 (lbm/sec) is calculated according to the following formula: M2:G2.AG2=downstream mass flow rate (lbm/ft2/sec)A=area of choke orifice (ft2)WhereinG2 is the downstream mass flow rate (lbm/ft2/sec)

22. A method for improving the production efficiency of a hydrocarbon well according to claim 18, characterized in that the preset values for the parameters of time, wellhead pressure (WHP), line pressure (LP), wellhead pressure to production line pressure ratio (WHP/PL) and gas flow rate are established based on a periodic analysis of the actual behavior of the well to which the remote monitoring and control system is applied.

23. A method for improving the production efficiency of a hydrocarbon well according to claim 18, characterized in that the remote control and monitoring system is configured to automatically collect well production data, generate well profiles based on the data, and self-adjust to maintain a well production rate at a desirable level.