EP1250513B1

EP1250513B1 - System and method for fluid flow optimization in a gas-lift oil well

Info

Publication number: EP1250513B1
Application number: EP01909683A
Authority: EP
Inventors: Robert Rex Burnett; Frederick Gordon Carl; William Mountjoy Savage; Harold J. Vinegar
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2000-01-24
Filing date: 2001-01-22
Publication date: 2005-04-06
Anticipated expiration: 2021-01-22
Also published as: RU2002122762A; MXPA02007176A; OA12141A; AU767417B2; BR0107821B1; NO330977B1; AU3733701A; ATE292742T1; BR0107821A; EP1250513A1; DE60109894D1; WO2001055553A1; NO20023501D0; DE60109894T2; NO20023501L; RU2256067C2

Abstract

A controllable gas-lift well having controllable gas-lift valves and sensors for detecting flow regime is provided. The well uses the tubing and casing to communicate with and power the controllable valve from the surface. Ferromagnetic chokes at the surface and downhole electrically isolate the tubing from the casing. A high band-width, adaptable spread spectrum communication system is used to communicate between the controllable valve and the surface. Sensors, such as pressure, temperature, and acoustic sensors, may be provided downhole to more accurately assess downhole conditions and in particular, flow regime. Operating conditions, such as gas injection rate, back pressure on tubing and position of downhole controllable valves are varied depending on flow regime, downhole conditions, oil production, gas usage and availability, to optimize production. An Artificial Neural Network (ANN) is trained to detect Taylor flow regime using downhole acoustic sensors, plus other sensors as desired. The detection and control system and method thereof is useful in many applications involving multi-phase flow in a conduit.

Description

BACKGROUND OF THE INVENTION

The present invention relates to a system and method for optimizing fluid flow in a pipe and in particular, flow in a gas-lift well.

DESCRIPTION OF RELATED ART

Gas-lift wells have been in use since the 1800's and have proven particularly useful in increasing efficient rates of oil production where the reservoir natural lift is insufficient. See Brown, Connolizo and Robertson, West Texas Oil Lifting Short Course and H.W. Winkler, "Misunderstood or Overlooked Gas-Lift Design and Equipment Considerations," SPE, P. 351 (1994).
Typically, in a gas-lift oil well, natural gas produced in the oil field is compressed and injected in the annular space between the casing and tubing and directed from the casing into the tubing to provide a "lift" to the tubing fluid column for production of oil out of the tubing. Although the tubing can be used for the injection of the lift-gas and the annular space used to produce the oil, this is rare in practice. Initially, the gas-lift wells injected the gas at the bottom of the tubing, but of course with deep wells this requires excessively high kick off pressures and methods have been devised to inject the gas into the tubing at various depths in the wells. See e.g., U.S. Patent No. 5,267,469.
The most common type of gas-lift well uses mechanical, bellows-type gas-lift valves attached to the tubing to regulate the flow of gas from the annulus between the casing and the tubing into the tubing. See U.S. Patent Nos. 5,782,261, and 5,425,425. In a typical bellows-type gas-lift valve, the bellows is preset or pre-charged to a certain pressure to allow operation of the valve, permitting communication of gas out of the annulus into the tubing at the pre-charged pressure. The pressure charge of each valve is designed by the well engineer depending upon the position of the valve in the well, pressure head, the conditions of the well, and a host of other factors.
The typical bellows-type gas-lift valve has a pre-charge for regulating the gas flow from the annulus outside the tubing to lift the oil. Several problems are common with such typical bellows-type gas-lift valves. First, the bellows often loses its charge allowing the valve to fail in the closed position or operate at other than the design goal. Another common failure is the erosion around the valve seat and deterioration of the ball stem in the valve which often leads to partial failure of the valve or at least inefficient production. Because the gas flow through a gas-lift valve is often not continuous at a steady state, but rather exhibits a certain amount of hammer and chatter as the ball valve is in use, valve and seat degradation is common. Failure or inefficient operation of bellows-type valves leads to corresponding inefficiencies in operation of a typical gas-lift well. In fact, it is estimated that well production is at least 5-15% less than optimum because of valve failure or operational inefficiencies.
It would, therefore, be a significant advance if a system and method were devised which overcame the inefficiency of conventional bellows-type gas-lift valves. Several methods have been devised to place controllable valves downhole on the tubing string but all such known devices typically use an electrical cable along the tubing string to power and communicate with the gas-lift valves. It is, of course, highly undesirable and in practice difficult to use a cable along the tubing string either integral with the tubing string or spaced in the annulus between the tubing and the casing because of the number of failure mechanisms present in such a system. Other methods of communicating within a borehole are described in U.S. Patent Nos. 5,493,288; 5,576,703; 5,574,374; 5,467,083; 5,130,706.
U.S. Patent No. 4,839,644 describes a method and system for wireless two-way communications in a cased borehole having a tubing string. However, this system describes a downhole toroid antenna for coupling electromagnetic energy in a waveguide TEM mode using the annulus between the casing and the tubing. This toroid antenna uses an electromagnetic wave coupling which requires a substantially nonconductive fluid (such as refined, heavy oil) in the annulus between the casing and the tubing and a toroidal cavity and wellhead insulators. Therefore, the method and system described in U.S. Patent No. 4,839,644 is expensive, has problems with brine leakage into the casing, and is difficult to use as a scheme for a downhole two-way communication. Other downhole communication schemes such as mud pulse telemetry (U.S. Patent Nos. 4,648,471; 5,887,657) have shown successful communication at low data rates but are of limited usefulness as a communication scheme where high data rates are required or it is undesirable to have complex, mud pulse telemetry equipment downhole. Still other downhole communication methods have been attempted, see U.S. Patent Nos. 5,467,083; 4,739,325; 4,578,675; 5,883,516; and 4,468,665 as well as downhole permanent sensors and control systems: U.S. Patent Nos. 5,730,219; 5,662,165; 4,972,704; 5,941,307; 5,934,371; 5,278,758; 5,134,285; 5,001,675; 5,730,219; 5,662,165.
It is generally known that in a gas-lift well, an increase of compressed gas injected downhole (i.e. lift-gas) does not linearly correspond to the amount of oil produced. That is, for any particular well under a particular set of operating conditions, the amount of gas injected can be optimized to produce the maximum oil. Unfortunately, using conventional bellows type valves, the opening pressure of the gas-lift bellows type valves is preset and the primary control of the well is through the amount of gas injected at the surface. Feedback to determine optimum production of the well can take many hours and even days.
It is also generally known that in two-phase flow regimes - such as in a gas-lift well - several flow regimes exist with varying efficiencies. See, A. van der Spek and A. Thomas, "Neural Net Identification of Flow Regime using Band Spectra of Flow Generated Sound", SPE 50640, October 1998. However, while operating in a particular flow regime is known to be desirable, it has largely been considered impossible to practically implement.
It would, therefore, be a significant advance in the operation of gas-lift wells if an alternative to the conventional bellows type valve were provided, in particular, if sensors for determining flow characteristics in the well could work with controllable gas lift valves and surface controls to optimize fluid flow and in a gas-lift well.
The method and system according to the preamble of claims 1 and 15 are known from European patent EP 0721053. In the known method and system a sensor mounted below a gas-lift valve detects characteristics of a generally single phase flow of crude oil below a gas-lift injection valve, which characteristics are used to control the opening of the valve such that an optimum amount of lift gas is injected to reduce the density of the crude oil and lift gas mixture that is created at and above the lift gas injection point.
US patent 5,353,627 discloses a method for detecting a flow regime in a multiphase fluid flow by means of a passive acoustical detector. US patent 6,012,015 discloses an automated downhole flow control system for a multilateral well system comprising acoustic and other sensors for evaluating formation parameters and influx of water.
Generally, it would be a significant advance to be able to detect the flow regime in a two-phase flow conduit, and to control the operation to remain in a desirable phase.

SUMMARY OF THE INVENTION

The method and system according to the invention are characterized by the characterizing features of claims 1 and 15.
The problems outlined above are largely solved by the system and method in accordance with the present invention for determining a flow regime and controlling the flow characteristics to attain a desirable regime. In the preferred application, the controllable gas-lift well includes a cased wellbore having a tubing string positioned within and longitudinally extending within the casing. A controllable gas-lift valve is coupled to the tubing to control the gas injection between the interior and exterior of the tubing, more specifically, between the annulus between the tubing and the casing and the interior of the tubing. The controllable gas-lift valve and sensors are power are powered and controlled from the surface to regulate such tasks as the fluid communication between the annulus and the interior of the tubing and the amount of gas injected at the surface. Communication signals and power are sent from the surface using the tubing and casing as conductors. The power is preferably a low voltage AC current around 60 Hz.
In more detail, a surface computer includes a modem with a communication signal imparted to the tubing and received at a modem downhole connected to the controllable gas-lift valve. Similarly, the modem downhole can communicate sensor information to the system computer. Further, power is input into the tubing string and received downhole to control the operation of the controllable gas-lift valve and to power the sensor. Preferably, the casing is used as the ground return conductor. Alternatively, a distant ground may be used as the electrical return. The ground return path is provided from the controllable gas-lift valve via a conductive centralizer around the tubing which is insulated in its contact with the tubing, but in electrical contact with the casing.
In enhanced forms, the controllable gas-lift well includes one or more sensors downhole which are preferably in contact with the downhole modem and communicate with the surface computer. In addition to acoustic, such sensors as temperature, pressure, hydrophone, geophone, valve position, flow rates, and differential pressure gauges are advantageously used in many situations. The sensors supply measurements to the modem for transmission to the surface or directly to a programmable interface controller for determining the flow regime at a given location and operating the controllable gas-lift valve and surface gas injection for controlling the fluid flow through the gas-lift valve.
Preferably, ferromagnetic chokes are coupled to the tubing to act as a series impedance to current flow on the tubing. In a preferred form, an upper ferromagnetic choke is placed around the tubing below the tubing hanger, and the current and communication signals are imparted to the tubing below the upper ferromagnetic choke. A lower ferromagnetic choke is placed downhole around the tubing with the controllable gas-lift valve electrically coupled to the tubing above the lower ferromagnetic choke, although the controllable gas-lift valve may be mechanically coupled to the tubing below the lower ferrite choke. It is desirable to mechanically place the operating controllable gas-lift valve below the lower ferromagnetic choke so that the borehole fluid level is below the choke.
Preferably, a surface controller (computer) is coupled via a surface master modem and the tubing to the downhole slave modem of the controllable gas-lift valve. The surface computer can receive measurements from a variety of sources, such as the downhole sensors, measurements of the oil output, and measurements of the compressed gas input to the well (flow and pressure). Using such measurements, the computer can compute an optimum position of a controllable gas valve, more particularly, the optimum amount of the gas injected from the annulus inside the casing through each controllable valve into the tubing. Additional parameters may be controlled by the computer, such as controlling the amount of compressed gas input into the well at the surface, controlling back pressure on the wells, controlling a porous fret or surfactant injection system to foam the oil, and receiving production and operation measurements from a variety of other wells in the same field to optimize the production of the field.
The ability to actively monitor current conditions downhole, coupled with the ability to control surface and downhole conditions, has may advantages in a gas-lift well. Conduits such as gas-lift wells have four broad regimes of fluid flow, namely bubbly, Taylor, slug and annular flow. The most efficient production (oil produced versus gas injected) flow regime is the Taylor flow regime.
The downhole sensors of the present invention enable the detection of Taylor flow. The above referenced control mechanisms-surface computer, controllable valves, gas input, surfactant injection, etc. - provide the ability to attain and maintain Taylor flow. In enhanced forms, the downhole controllable valves may be operated independently to attain localized Taylor flow.
In the preferred embodiment, all of the gas-lift valves in the well are of the controllable type in accordance with the present invention and may be independently controlled. It is desirable to lift the oil column from a point in the borehole as close as possible to the production packer. That is, the lowest gas-lift valve is the primary valve in production. The upper gas-lift valves are used for set off of the well during production initiation. In conventional gas-lift wells, these upper valves have bellows pre-set with a 200 psi (≅ 13.8 Bar) margin of error to ensure the valves close after set off. This means lift pressure is lost downhole to accommodate this 200 psi (≅ 13.8 Bar) loss per valve. Further, such conventional valves often leak and fail to fully close. Use of the controllable valves of the present invention overcomes such shortcomings.
Construction of such a controllable gas-lift well is designed to be as similar to conventional construction methodology as possible. That is, after casing the well, a packer is typically set above the production zone. The tubing string is then fed through the casing into communication with the production zone. As the tubing string is built at the surface, a lower ferrite choke is placed around one of the conventional tubing strings for positioning above the downhole packer. In the sections of the tubing strings where it is desired, a gas-lift valve and one or more sensors are coupled to the string. In a preferred form, a side pocket mandrel for receiving a slickline insertable and retractable gas-lift valve or sensor is used. With such configuration, either a controllable gas-lift valve in accordance with the present invention can be inserted in the side pocket mandrel or one or more sensor packages can be used. Alternatively, the controllable gas-lift valve or sensors may be tubing conveyed. The tubing string is built to the surface where a ferromagnetic choke is again placed around the tubing string below the tubing hanger. Communication and power leads are then connected through the wellhead feed through to the tubing string below the upper ferromagnetic choke.
In an alternative form, a sensor and communication pod is inserted without the necessity of including a controllable gas-lift valve. That is, an electronics module having pressure, temperature or acoustic sensors or other sensors, power supply, and a modem is inserted into a side pocket mandrel for communication to the surface computer to determine flow regime using the tubing and casing conductors. Alternatively, such electronics modules may be mounted directly on the tubing (tubing conveyed) and not be configured to be wireline replaceable. If directly mounted to the tubing an electronic module or a controllable gas-lift valve may only be replaced by pulling the entire tubing string. With only sensors placed downhole, measurements are communicated to the surface and surface parameters (e.g. compressed gas input) are regulated to obtain a desirable downhole flow regime.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of the controllable gas-lift well in accordance with a preferred embodiment of the present invention;
FIG. 2 is a schematic detail of a tubing string in a cased borehole illustrating the disposition of a side pocket mandrel on the tubing string;
FIG. 3 is a series of fragmentary, vertical sectional views illustrating flow patterns in two-phase vertical (upward) flow wherein FIG. 3A illustrates bubbly flow, FIG. 3B illustrates slug flow FIG. 3C illustrates churn flow, and FIG. 3D illustrates annular flow;
FIGS. 4A-4D illustrate flow patterns in horizontal two-phase flow wherein FIG. 4A illustrates annular dispersed flow, FIG. 4B illustrates stratified wavy flow, FIG. 4C illustrates slug or intermittent flow, and FIG. 4D illustrates dispersed bubble flow;
FIG. 5 is a graph plotting quantity of compressed gas vs. tubing pressure and depicts the four flow regimes typically encountered in a gas-lift well, namely bubbly, Taylor, slug flow, and annular flow;
FIG. 6 is an enlarged schematic illustrating a controllable gas-lift valve received in a wireline retrievable, side pocket mandrel;
FIGS. 7A-7C are vertical sectional views of a preferred form of the controllable valve in a cage configuration;
FIG. 8 is an enlarged vertical section schematic, depicting an electronics module containing sensors coupled to the tubing string separate from the controllable valve;
FIG. 9 is a depiction of the equivalent circuit diagram of the controllable gas-lift well of FIG. 1;
FIG. 10A is an enlarged schematic illustrating a controllable valve permanently coupled to the tubing string;
FIG. 10B is an enlarged vertical sectional view of a controllable gas-lift valve, illustrating an alternative embodiment of the controllable valve;
FIG. 11 is a schematic diagram depicting the surface computer in communication with the electronics of the controllable gas-lift valve;
FIG. 12 is a system block diagram of an electronics power and control system; and
FIG. 13 is a block diagram of a feed forward, bank propagation neural network for interpretation of acoustic date.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

1. Description of Flow Regimes

Without a flow regime classification, it is hard to quantify fluid flow rates of two-phase flow in a conduit. The conventional way of flow regime classification is by visual observation of flow in a conduit by a human observer. Although downhole video surveys are commercially available, visual observation of downhole flow is not standard practice in (horizontal well, production logging, as it requires a special wireline (optical fiber cable). Moreover, downhole video surveys can only be successful in transparent fluids; either gas wells or wells killed with clear kill fluid. In oil wells, an alternative to visual observation for classifying the flow regime is needed.
All flow regimes produce their own characteristic sounds. A trained human observer can classify flow regime in a pipe by aural rather than visual observations. Contrary to video surveys, sound logging services are available from various cased hole wireline service providers. The traditional use of such sound logs is to pinpoint leaks in either casing or tubing strings. In addition to the sound logs recorded, the surface control panel is equipped with amplifiers and speakers that allow audible observation of downhole produced sounds. The sound log typically is a plot vs. along hole depth of (uncalibrated) sound pressure level after passing the sound signal through 5 different high pass filters (noise cuts: 200 Hz, 600 Hz, 1000 Hz, 2000 Hz and 4000 Hz). In principle, the logging engineer, based on aural observation of the downhole sounds, could carry out flow regime classification. This procedure, however, is impractical: it is prone to errors, it cannot be reproduced from recorded logs (the sound is not normally recorded on audio tape) and it relies on the experience of the specific engineer.
Successful application of neural net classification of flow regime from sound logs in the field brings several benefits to the business. First of all it will allow the application of the correct, flow regime specific, hydraulic model to the task of evaluating horizontal well, two-phase flow production logs. Secondly, it allows a more constrained consistency check on recorded production logging data. Last it alleviates the need to predict flow regime using hydraulic stability criteria from first principles thereby reducing computational loads by at least a factor of 10 resulting in faster turn around times.

Flow Regimes

"Two-phase flow is the interacting flow of two phases, liquid, solid or gas, where the interface between the phases is influenced by their motion" (Butterworth and Hewitt, 1979). Many different flow patterns can result from the changing form of the interface between the two phases. These patterns depend on a variety of factors; for instance the phase flow rates, the pressure, and the diameter and inclination of the pipe containing the flow in question, etc. Flow regimes in vertical upward flow is illustrated in FIG. 3 includes:

Bubble flow: A dispersion of bubbles in a continuum of liquid.
Intermittent or Slug flow: The bubble diameter approaches that of the tube. The bubbles are bullet shaped. Small bubbles are suspended in the intermediate liquid cylinders.
Churn or froth flow: A highly unstable flow of an oscillatory nature, whereby the liquid near the pipe wall continuously pulses up and down.
Annular flow: A film of liquid flows on the wall of the pipe and the gas phase flows in the center.

Above flow patterns are obtained with increasing gas rate. For gas wells annular flow is expected over a major part of the tubing whereas for oil wells intermittent flow prevails in the upper part of the tubing. At tubing intake conditions bubble flow is predominantly present, hence in the tubing, because of the release of associated gas from oil when the pressure falls a transition from bubble flow to intermittent flow occurs. Flow regimes in horizontal flow are illustrated in FIG. 4 and are described below:

Bubble flow: The bubbles tend to float at the tope in the liquid.
Stratified flow: The liquid flows along the bottom of the pipe and the gas flows on top.
Intermittent or Slug flow: Large frothy slugs of liquid alternate with large gas pockets.
Annular flow: A liquid ring is attached to the pipe wall with gas blowing through. usually, the layer at the bottom is very much thicker than the one at the top.

Another flow regime has been identified - Taylor flow

which occurs between Bubbly and Slug flow of FIGS. 3A and 3B and has characteristics of each. More in particularly, as illustrated in FIG. 5, Taylor flow is a most desirable flow regime for maximizing oil output for a quantity of gas injected. Although the preferred embodiment is primarily concerned with achieving Taylor flow in a vertical oil well, the principles are applicable to horizontal wells (FIG. 4) and most two-phase flows in a conduit. Superficial velocity is the ratio of volumetric flow rate at line conditions, Q, to the cross-section of the pipe, A, such that: vs=QA

Superficial velocity is the velocity that a phase would have had if it were the only phase in the pipe. Gas volume fraction (GVF) is the superficial gas velocity divided by the sum of the superficial gas and superficial liquid velocities. GVF=Vse VseVst
The gas volume fraction is pressure dependent. Note that in the flow loop experiments gas flow rate is expressed at normal conditions (Nm³/h).
A convenient and illustrative way to depict flow regimes vs. flow rates is to map flow regime on a two dimensional plane with superficial gas velocity on the horizontal axis and superficial liquid velocity on the vertical axis for a given pipe inclination, see FIG. 3. In theory, 8 variables are needed to define a flow regime in a pipe. In an angle dependent flow map representation, only 3 variables are used. In this case, the approach is justified because the 3 flow map variables, i.e. pipe inclination angle, superficial gas velocity and superficial liquid velocity are the only variables that were changed in the course of the studies. All other variables, i.e. gas and liquid density and viscosity, surface tension, pipe diameter and pipe roughness are fixed (Wu, Pots, Hollenberg, Meerhoff, "Flow pattern transitions in two-phase gas/condensate flow at high pressures in an 8 inch horizontal pipe," Proc. of the Third International Conf. on Multiphase-Phase Flow, The Hague, The Netherlands, 18-20 May, pp. 13-21, 1987; Oliemans, Pots, Trompe, "Modeling of annular dispersed two-phase flow in vertical pipes," J. Multiphase Flow, 12:711-732, 1986).
An exemplary flow map covers 3 orders of magnitude for both the gas and the liquid flow rate. At 10 m/s liquid superficial velocity, a 4-inch pipe will sustain a flow rate of approximately 10000 barrels of liquid per day if the liquid were the only fluid flowing in the pipe. Thus such a flow map covers all situations that are of practical use in oilfield application. Since gas volume fraction is the ratio of superficial gas velocity to the sum of superficial gas and superficial liquid velocity, lines of constant gas volume fraction appear on the flow map as straight parallel lines of 45-degree slope. the 50% GVF line is the line passing through the points (10,10) and (0.01,0.01). To the right of this line higher gas volume fractions occur, whereas to the left the gas volume fraction decreases.

Sound Measurements

Sound is rarely made up of only one frequency. Hence, in order to analyze it, a whole range of frequencies should be investigated. The chosen frequency spectrum can be divided into contiguous bands (Pierce, 1981) such that: f u(n)=f L(n+1) and subsequently f u(n+1)=f L(n+2) where the n^th band is limited by a lower frequency f_L(n) and an upper frequency f_u(n). The bands are said to be proportional if the ratio f_u(n)/f_L(n) is the same for each band. An octave is a band for which f u = 2f L i.e. the top frequency is twice the lower limit frequency of the band. In the same way, a one third octave band is one where f u=32f t any proportional band is defined by its center frequency. This is given by f o = f u f t
The standard 1/3 octave-partitioning scheme (ANSI S.1.6-1967 (R 1976)) uses the fact that ten 1/3 octave bands are nearly a decade. Standard 1/3 octave bands are such that: f on+10=10f o(n) i.e. 1, 10, 100, 1000 and so on are some of the standard 1/3 octave center frequencies. A graphical display of 1/3 octave band numbers vs. frequency can be made. On a logarithmic scale 1/3 octave bands are equidistant and are of the same width.
Two analysis ranges used by recording equipment are the 100 kHz and 1 kHz ranges. The 100 kHz range covers the bands 20 through 49. The 1 kHz range covers the bands 1 to 28. Apart from 1/3 octave spectra and octave spectra, an alternative partitioning scheme using decades is also possible. The center frequencies of two adjacent decade bands have ratio of 10.
The signal magnitude in any given band is expressed as sound pressure level. The sound pressure level (SPL) has a logarithmic scale and is measured in decibels (dB) (Kinsler et al., 1982). If p is the sound pressure then:
P_ref is a reference pressure, often taken to be 1 µPa in underwater acoustics. Putting the concept of decibels into a more familiar context, in air (reference pressure of 20 µ Pa), 0 dB is the threshold of acute hearing of a human being whilst 130 dB would be the level of a sound inducing acute pain. Assuming the sources of sound are all incoherent, sound pressure levels can be combined using the following formula:
where (SPL)_NEW is the combined sound pressure level of the n original (SPL)_n levels. For example, given that (SPL)₁=100 dB and (SPL)₂=120 dB the, their sum will be (SPL)_SUM=120.043 dB ≈ 117 dB.

Neural Networks

An artificial neural network is an information processing system, designed to simulate the activity in the human brain (Caudill and Butler, 1992). It comprises a number of highly interconnected neural processors and can be trained to recognize patterns within data presented to it such that it can subsequently identify these patterns in previously unseen data. The data presented to a neural network is assigned to one of three sets (Learn set, Training set and Validation set) and labeled accordingly. The training set is used to train the network, where as the test set is there to monitor the network's performance. The validation set is where the network can put its acquired skills to use on unseen data.
Preferably a feed forward, back propagation neural network such as FIG. 13 is used for interpretation and classification of acoustic sensor. The neural network architecture for classification problems on 1/3 octave spectra is given in FIG. 13. The neural network consists of three layers, an input layer comprising 52 input units, a hidden layer comprising 16 units and 4 units in the output layer each of which corresponds to one of the target flow regime classes. The output units generate a scaled output, a number between 0 and 1 that can be interpreted as the likelihood of occurrence of that particular flow regime govern a certain pattern of inputs. The probabilities of the four output units value of each of the calculated likelihood after training the network. Output is considered to be low if its value is 0.5 or below, and high if it is above 0.5. Each sample in a data set can be classified as:
Correct: the output unit corresponding to the target class has a high output, all other output units have a low output.
Wrong; the wrong output unit has high output, all other output units (including the one corresponding to the target class) have a low output.
Unknown; two or more output units have a high output, or all output units have a low output.
Forced correct: the output unit corresponding to the target class has the highest output, irrespective of its absolute value. This number will include all correct samples and some of the unknown samples.
A confusion matrix indicates how the network classified all given regimes. A sensitivity analysis is performed on each input feature. This is expressed as a percentage change in the error, were a particular input to be omitted from the training process. A surface computer processing the sensor data may compare the target regimes to the outputs from the network with the largest and second largest probabilities, denoted best and second best respectively.

2. Description of a Gas-Lift Well

Turning to the drawings, a gas-lift well in accordance with a preferred embodiment of the present invention as illustrated. Broadly speaking, FIG. 1 illustrates a gas-lift oil well 10 extending from the surface 12 through a bore hole and extending into a production zone 14 down hole.
The production platform 20 is schematically illustrated above the surface 12 in FIG. 1. A standard wellhead having a hanger 22 has tubing 26 suspended and supported therefrom. The casing 24 is conventional, i.e. it is typically cemented in the bore hole during well completion. Similarly, the tubing string 26 is generally conventional comprising a plurality of elongated tubular production pipe sections joined by threaded couplings at each end of the tubing section. A gas input throttle 30 is employed to permit the input of compressed gas into the annular space between the casing 24 and tubing 26. Conversely, output valve 32 permits the expulsion of oil and gas bubbles from the interior of the tubing 26 during oil production.
Schematically illustrated is a computer and power source 34 at the surface with power and communication feeds 36 passing through pressure feed 38 in the hanger 32. Top and bottom ferromagnetic chokes 40, 42 are installed on the production tubing to act as a series impedance to current flow. The size and material of the chokes 40, 42 can be altered to vary the series impedance value. Power and communications from source 34 are injected into the tubing 26 through feeds 36 at a point below the top choke 40. That is, the area of the tubing between the top and bottom chokes 40, 42 may be viewed as a power and communications path (see also FIG. 6). The chokes 40, 42 are manufactured of high permeability magnetic material and mounted concentric and external to the tubing and typically hardened with injected epoxy and encased elastomer to withstand rough handling.
As can be seen in FIG. 1, a packer 44 is placed downhole in the casing 24 above the production zone 14 and used to isolate the production zone, but electrically connects the metal production tubing 26 with the outer metal casing 24. Similarly, above the surface 12 the metal hanger 22 (along with the surface valves, platform, and other production equipment) electrically connects the inner metal production tubing 26 and the outer metal casing 24. Typically, such configuration would not allow electrical signal to be transmitted or received up and down the well using the tubing as one conductor and the casing as the other conductor. However, the disposition of the ferromagnetic chokes 40, 42 alter the electrical characteristics of the well metal structure providing a system and method to provide communication and power signals up and down the bore hole of the gas-lift well 10.
FIG. 1 illustrates the preferred use of a controllable gas-lift valve 52 operatively connected to the tubing 26. In FIG. 1 every gas-lift valve attached to the tubing 26 is a controllable gas-lift valve 52 in accordance with the present invention. Additionally, acoustic sensors 51 are placed along the tubing 26 and communicate with surface computer 34.
Turning to FIG. 2, the downhole configuration of the controllable valve 52, as well as the electrical connections with the casing and tubing 24, 26 is depicted. The tubing sections 26 are conventional and where it is desired to incorporate a gas-lift valve in the tubing section, a side pocket mandrel such as made by Weatherford or Camco is employed. As can be seen in FIG. 2, such side pocket mandrels are a concentric enlargement of the tubing section 26 and permits the wireline retrieval and insertion of the contents of the side pocket mandrel.
In gas-lift well 10, standard bow spring centralizers are employed to center the tubing 26 within the casing 24. However, the insulating bow spring centralizers 60 (FIG. 2 and FIG. 3) between the chokes 40, 42 employ PVC insulators 62 to electrically isolate the casing 24 from the tubing 26. Other types of nonconductive centralizers may be used, such as the ball type or tubing string coated with epoxy. For example, a high temperature rubber plug configuration may be used as a centralizer. Power and signal jumper 64 connects the electronics within the controllable valve 52 to the tubing section 26 as shown in FIG. 2. A grounded centralizer 61 adjacent the controllable valve 52 is grounded to the casing 24 by a gripper (FIG. 6). A ground wire 66 provides the return path from the electronics of the controllable valve 52, and as can be seen in FIG. 6 grounds through the centralizer 61 and gripper 63 to the casing 24.
Use of controllable valves 52 is believed preferable for several reasons. For example, conventional bellows valves 50 often leak when they should be closed during production, resulting in inefficient well operation. Additionally, conventional bellows valves 50 are usually designed for a tolerance of about 200 psi per valve, resulting in further inefficiency.
Turning to FIG. 6 and FIG. 7, the configuration of the controllable gas-lift valve 52 in disposition within a side pocket mandrel 70 is illustrated in more detail. The side pocket mandrel 70 includes in its external housing a gas inlet port 72 in fluid communication with the annular space in the bore hole between the tubing 26 and casing 24. The controllable valve 52 meters the amount of gas flowing from the annulus into the tubing 26 through the gas outlet port 74.
FIGS. 7A-7C illustrate the preferred embodiment of the controllable valve 52 of the present invention. As shown in FIG. 7C, the controllable valve 52 is slidably received in the side pocket mandrel 70. A gas inlet port 72 is in fluid communication with the annular space in the bore hole between the tubing 26 and the casing 24. The controllable valve 52 meters the amount of gas flowing from the annulus into the tubing 26 through the gas outlet port 74.
In more detail, as shown in FIG. 7A, an electronics module 82 is disposed in housing 80. A check valve 94 prevents backflow from the tubing through outlet port 74. A stepper motor 84 rotates a pinion 202, which through worm gear 204, raises and lowers cage 206. Cage 206 engages seat 208, which regulates flow into orifice 210. As shown in more detail in FIG. 7B, a shoulder 212 is configured to complementarily engage a mating collar on cage 206 when the valve is closed. This "cage" valve configuration is believed to be a preferable design from a fluid mechanics view to the alternative embodiment needle valve configuration of FIG. 10B. That is, fluid flow from inlet port 72, past the cage/seat juncture (206/208) permits precise fluid regulation without undue fluid wear on the mechanical interfaces.
Turning to FIG. 8, an altered version of the controllable valve 52 of the present invention is shown and should be contrasted with the side pocket mandrel configuration of FIG. 6. In FIG. 8, tubing 26 includes an annularly enlarged pocket 100 housing electronics and the controllable gas-lift valve 52 of the present invention. That is, the gas-lift valve 52 is tubing mounted and is not insertable and retrievable by slickline through the side pocket mandrel 70 of FIG. 6 (i.e. "tubing conveyed) . The controllable valve 52 in FIG. 8 includes a ground wire 102 (similar to the ground wire 66 of FIG. 6) which is an isolated feed-through to connect to the centralizer bow 61 grounded to the casing 24. The electronics module 106 is connected for communications and power to the tubing 26 via the power and signal jumper 104. A motorized cage valve 108 is schematically illustrated, but operates in a similar fashion to FIG. 7 to control the operative communication of the annular space between the tubing 26 and casing 24 into the interior of the tubing 26. In similar fashion to FIG. 7, a reverse flow valve 110 is provided.
FIG. 8 also illustrates the provision of a variety of sensors which can be used to control the operation of the gas-lift well 10. That is, an acoustic sensor 113 is mounted to the tubing 26 to sense the internal acoustic signature of the fluid flow, while in similar fashion, a temperature sensor 114 determines the temperature of the fluid within the tubing 26. As can be seen from FIG. 8, the acoustic and temperature sensors 113, 114 are coupled to the electronics module 106 and electrically connected for receiving power and communications.
In similar fashion, a salinity sensor 116, pressure sensor 112, and differential pressure sensor 118 are electrically connected to the electronics module 106. As can be seen, the salinity sensor 116 is operatively disposed through the pocket 100 to sense the salinity of the fluid in the annulus between the casing 24 and tubing 26. The differential pressure sensor 118 provides a measurement of the pressure on each side of the needle valve 108. It can be understood that the alternative configurations illustrated by FIG. 6 and FIG. 8 can include or exclude any number of the sensors 112, 114, 116 or 118. Alternative sensors can be employed such as gauge, absolute or a differential pressure, lift gas flow rate, tubing acoustic waves, gas-lift valve position, or any analog signal. Similarly, the electronics module 106 and sensors 112, 114, 116 can be packaged and deployed independently of the controllable valve 52. In the preferred embodiment at least an acoustic sensor is used.
Turning to FIG. 9, the equivalent circuit diagram of FIG. 9 should be compared with FIG. 1. As can be seen, the computer and power source 34 includes an AC power source 120 and a communication master modem 122 electrically connected between the casing 24 and tubing 26. FIG. 9 illustrates two separate downhole communications and electronics modules which are identical as illustrated. It should be understood that any such electronics module, for example mounted in a side pocket mandrel 70, may contain or omit different components and combinations such as the sensors 112-118 or controllable valve 52. In FIG. 9 such an electronics module (such as electronics module 82 of FIG. 7) is electrically connected between the tubing 26 and casing 24. Such an electronics module 82 includes a power transformer 124 as shown. Similarly, a data transformer 128 is coupled with a slave modem 130 as depicted.
FIG. 10 shows a mandrel mounted, controllable gas-lift valve 132 that is not slickline replaceable. In fact, many of the oil gas-lift wells in use today use mechanical bellows-type gas-lift valves that are not slickline replaceable. These mechanical valves are replaced by pulling the tubing string. FIG. 10 shows the electronics of the controllable valve 132 mounted in the valve housing, it being understood that power and control may be separately configured and mounted in the tubing conveyed mandrel 134. FIG. 10 shows the needle valve configuration of the alternative embodiment, if being understood the cage valve of FIG. 7 and other valve configurations may alternatively be used. As shown in FIG. 10, a ground wire 136 couples an electronics module 138 integral to the housing of the valve 132 and grounds to the bow spring centralizer 61. A power and signal jumper is integral to the mandrel 134 and couples the electronics module 138 to the tubing 26. Stepper motor 142, needle valve 144, and check valve 146 are similar in operation and configuration to the controllable valve 52 depicted in FIG. 7. In similar fashion to FIG. 8, inlet opening 148 and outlet opening 150 are provided to provide a fluid communication path between the annulus and the interior of the tubing 26.
FIG. 11 illustrates a block diagram of the communication system 152 in accordance with a preferred embodiment of the present invention. FIG. 11 should be compared and contrasted with FIG. 1 and FIG. 6, and broadly includes a master modem 122 and an AC power source 120. A computer 154 is shown coupled to the master modem 122, preferably via an RS232 bus, with the computer 154 running an operating system such as Windows NT and a variety of user applications. The AC power source 120 includes a 120 volt AC input 156, ground 158, and neutral 160 as illustrated. A fuse 162 (e.g. 7.5 amp) with transformer output 164 at approximately 6 volts AC and 60 Hz is shown. The power source 120 and master modem 122 are connected to the casing and tubing 24, 26 as schematically depicted in FIG. 11.
The electronics module 82 includes a power supply 166 and an analog-to-digital conversion module 168. A programmable interface controller 170 is shown coupled to the slave modem 130 (see FIG. 9). I/O decouplings 172 are provided.
FIG. 12 expands on the depiction in FIG. 11 and shows in detail a preferred embodiment of the electronics module 82. Amplifiers and signal conditioners 180 are provided for receiving inputs from a variety of sensors 112-118 (see FIG. 8 such as acoustic signature, tubing temperature, annulus temperature, tubing pressure, annulus pressure, lift gas flow rate, valve position, salinity, differential pressure, etc. Preferably, low noise operational amplifiers are configured with noninverting single ended inputs (e.g. Linear Technology LT1369). The amplifiers of 180 are all programmed with gain elements designed to convert the operating range of the individual sensor input to a meaningful analog output. The programmable interface controller 110, using standard analog to digital conversion techniques generates an 8 bit digital signal equal to an amplifier's 180 output.
In more detail pressure sensors 112 (such as produced by Measurement Specialties, Inc.) are used to measure the pressure in the tubing, internal pod housing and differentially across the gas-lift valve shown in FIG. 8 at 112 and 118. In commercial operation, the internal pod pressure is considered unnecessary, but is available as an option. Such pressure transducers 112, 118 are podded to withstand the severe vibration associated with gas-lift tubing strings. The temperature sensor 114 (such as Analog Devices, Inc. LM-34) are used to measure the temperature in the tubing and operationally in a diagnostic mode in the housing pod, power transformer, or power supply. The temperature transducers are rated for -50 to 300 °F and are conditioned by input circuitry 180 to +5 to 255 °F.
Address switches 182 are provided to address a particular device from the master modem 122. As shown in FIG. 12, 4 address bits are switch selectable to form the upper 4 bits of a full 8 bit address. The lower 4 bits are implied and are used to address the individual elements within each electronics module 82. Thus, using this illustrated configuration, 1024 modules are assigned to a single master modem 122 (FIG. 9) on a single communications line. As configured, up to 4 master modems 122 can be accommodated on a single communications line.
The programmable interface controller 170 of FIG. 12 (PIC 16C77 as manufactured by Microchip) has a basic clock speed of 20 MHz and is configured with 8 analog-to-digital inputs as shown at 184 and 4 address inputs as shown at 186. The PIC 170 includes a TTL level serial comminations UART 188, as well as a stepper motor controller interface 190.
The power supply 166 of FIG. 12 converts a nominal 6 volts AC line power to plus 5 volts DC at 192, minus 5 volts DC at 194, and plus 6 volts DC at 196 which are used by various elements within the electronics module 82 (ground is depicted at 198). The PIC 170 uses the plus 5 volts DC, while the slave modem 130 uses the plus 5 and minus 5 volts DC (as shown at 192, 194). The stepper motor 84 uses the plus 6 volts DC as shown at 196. The power supply 166 comprises a step-up transformer for converting the nominal 6 volts AC to 7.5 volts AC. The 7.5 volts AC is then rectified in a full wave bridge to produce 9.7 volts unregulated DC. Three-terminal regulators provide the regulated outputs 192-196 which are heavily filtered and protected by reverse EMF circuitry. As can be appreciated, the modem 130 is the major power consumer, typically using 350+ milliamps at plus/minus 5 volts DC when transmitting.
In more detail, the digital spread spectrum modem 130 consists of an IC/SS power line carrier chip set (brand EG ICS1001, ICS1002 and ICS1003 from National Semiconductor) and is capable of 300-3200 baud data rates at carrier frequencies ranging from 14 kHz to 76 kHz (U.S. Patent No. 5,488,593 describes the chips set in more detail and is incorporated herein by reference).
The PIC 170 controls the operation of the stepper motor 84 through a stepper motor controller 200 (e.g. Motorola SA1042 stepper motor driver circuit). The controller 200 needs only directional information and simple clock pulses from PIC 170 to drive the stepper motor 84. A single "set" of the controller 200 at initialization conditions all elements for initial operation in known states. The stepper motor 84 (preferably a MicroMo gear head) positions a cage valve stem toward or away from its seat (see FIG. 7) as the principal operative component of the controllable gas-lift valve 52. Stepper motor 84 provides .4 inch-ounce (≅ 0.0028 Nm) of torque and rotates up to 1000 pulses per second (for emergency close time). A complete revolution of the stepper motor 84 consists of 24 individual steps. The output of the stepper motor 84 is directly coupled to a 989:1 gear head which produces the necessary torque to open and close the cage valve. The continuous rotational torque required to open and close the cage valve is 3 inch-pounds with 15 inch-pounds required to seat and unseat the cage valve.
The PIC 170 communicates through the digital spread spectrum modem 130 to the outside world via the modem coupling network 202 to the casing and tubing 24, 26 as shown in FIG. 9. The PIC 170 uses the MODBUS 584/985 PLC protocol. The protocol is ASCII encoded for transmission.

OPERATION

A large percentage of the artificially lifted oil production today uses gas lift to help bring the reservoir oil to the surface. In such gas-lift wells, compressed gas is injected downhole outside the tubing, usually in the annulus between the casing and the tubing and mechanical gas-lift valves permit communication of the gas into the tubing section and the rise of the fluid column within the tubing to the surface. Such mechanical gas-lift valves are typically mechanical bellows-type devices that open and close when the fluid pressure exceeds the pre-charge in the bellows section. Unfortunately, a leak in the bellows is common and renders the bellows-type valve largely inoperative once the bellows pressure departs from its pre-charge setting unless the bellows fails completely, i.e. rupture. Further, a common source of failure in such bellows-type valve is the erosion and deterioration of the ball valve against the seat as the ball/seat contact frequently during normal operation in the often briny, high temperature, and pressure conditions around the ball valve. Such leaks and failures are not readily detectable at the surface and probably reduce a well's production efficiency on the order of 15 percent through lower production rates and higher demands on the field lift gas compression systems.
The controllable gas-lift well 10 of the present invention has a number of data monitoring pods and controllable gas-lift valves 52 on the tubing string 26, the number and type of each pod and controllable valves 52 depends on the requirements of the individual well 10. Preferably, at least an acoustic sensor is used to determine the flow regime using the trained Artificial Neural Network of FIG. 13. Each of the individual data monitoring pods and controllable valves 52 are individually addressable via the wireless spread spectrum communication through the tubing and casing. That is, a master spread spectrum modem at the surface and an associated controller communicates to a number of slave modems. The data monitoring pods report such measurements as downhole tubing pressures, downhole casing pressures, downhole tubing and casing temperatures, lift gas flow rates, gas valve position, and acoustic data (see Fig. 8, sensors 112, 113, 114, 116, 118). Such data is similarly communicated to the surface through a slave spread spectrum modem communicating through the tubing and casing.
The surface computer 34 (either local or centrally located) continuously combines and analyzes the downhole data as well as surface data, to compute a real-time tubing pressure profile. An optimal gas-lift flow rate for each controllable gas-lift valve 52 is computed from this data. Preferably, pressure measurements are taken at locations uninfluenced by gas-lift injection turbulence. Acoustic sensors 113 (sounds less than approximately 20 kilohertz) listen for tubing bubble patterns. Data is sent via the slave modem directly to the surface controller. Alternatively, data can be sent to a mid-hole data monitoring pod and relayed to the surface computer. The tubing bubble patterns are analyzed by the Artificial Neural Network of FIG. 13 to determine the flow condition. If not Taylor flow, production control is modified.
That is, in addition to controlling the flow rate of the well, production may be controlled to operate in or near Taylor fluid flow state. Unwanted conditions like "heading" and "slug flow" can be avoided. By changing well operating conditions, it is possible to attain and maintain Taylor flow, which is the most desirable flow regime. By being able to determine such unwanted bubble flow conditions quickly downhole, production can be controlled to avoid such unwanted conditions. That is, a fast detection of such conditions and a fast response by the surface computer can adjust such factors as the position of a controllable gas-lift valve, the gas injection rate, back pressure on tubing at the wellhead, and even injection of surfactant.

Claims

A method of controlling the fluid flow in a conduit where the fluid is multiphase, comprising the steps of:

determining the signature of the fluid flow along a portion of the conduit;

conveying the signature to a controller via the conduit; and

determining the flow regime of said fluid in said portion based on said signature;

characterized in that said signature is the acoustic signature of the multiphase fluid flow and that the amount of at least one of said fluids in said conduit is adjusted on the basis of the determined flow regime to attain a desirable flow regime.
The method of claim 1, the conduit comprising an oil well and said multiphase fluid including lift gas injected into the well and oil.
The method of claim 1, the controller comprising a computer having an Artificial Neural Network trained for determining a flow regime based on said acoustic signature.
The method of claim 1, the desirable flow regime comprising Taylor flow.
The method of claim 2, the desirable flow regime comprising minimizing the amount of lift gas and maximizing the amount of oil produced.
The method of claim 2, further comprising the steps of:

mounting one or more sensors proximate a production pipe (26) in the oil well;

sensing the signature of flow in the production pipe (26);

communicating said signature to a surface controller (34) using the production pipe (26);

characterized in that the sensors are acoustic sensors (51,113) for sensing the acoustic signature of two-phase flow;
that the flow regime of the two-phase flow is determined using said surface controller (34); and
that the operating parameters of the oil well (10) are controlled based on said determination of said flow regime by said surface controller (34).
The method of claim 6, said controlling step including regulating the amount of compressed lift gas injected into the oil well (10).
The method of claim 6, said controlling step including regulating the amount of compressed lift gas input through a downhole controllable valve (52) into the production pipe (26).
The method of claim 6, said determining step including inputting said acoustic signature into an Artificial Neural Network.
The method of claim 6, said controlling step including adjusting said operating parameters to attain a Taylor flow regime.
The method of claim 6, including sensing additional fluid physical characteristics.
The method of claim 11, including sensing pressure and temperature of the fluid in the production pipe (26).
The method of claim 6, said production pipe comprising a pipe laterally extending from a generally vertical oil well.
The method of claim 6, including the step of powering an acoustic sensor using the production pipe (26).
A gas-lift oil well comprising:

a production tubing (26) for conveying two-phase fluid, comprising oil and lift gas, to the surface;

one or more sensors (51,113) downhole proximate the production tubing (26) operable for sensing a physical fluid parameter;

a modem operatively coupled to the production tubing (26) for receiving data from said sensor and conveying the data on the production tubing (26) to the surface;

a surface controller for receiving said data and determining a fluid flow regime in the production tubing (26); and

a throttle (30) and/or a downhole controllable valve (51,113) for controlling the amount of lift gas injected into the production tubing (26);

characterized in that the throttle (30) and/or downhole valve (52) is controlled by said surface controller (34) based on the determined flow regime of the two-phase fluid.
The well of claim 15, said sensor comprising an acoustic sensor (51,113).
The well of claim 16, said computer including an Artificial Neural Network for determining a flow regime based on measurements from said acoustic sensor (51,113).
The well of claim 15, including a power source (34) coupled to the production tubing (26) for providing power to said sensor (51,113).