Report on Gas lift design, operation and troubleshooting

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ACKNOWLEDGEMENT We wish to express our thanks to Dr. V.P.Sharma HOD, Petroleum Engineering Department, ISMU, Dhanbad, Dr. T.K.Naiyya and Dr. Chandan Guria for helping to arrange such a wonderful training experience for us. We wish to sincerely thank Mr. Niladri Sinha, ED-Head, IOGPT, Panvel, Mumbai, Mr. V.V Manchalwar, GGM(P), HOD-Artificial Lift, Dr. K. R. Rao, DGM (P), In-charge Artificial Lift, Mr. Om Prakash Pal, DGM(Chem), In-charge Training and Business Development and Mr. Yogesh Verma, CE(P), In-charge Training for giving us this excellent training opportunity. We would take this opportunity to acknowledge the support of Ms. Shagun Devshali, AEE(P), Artificial Lift Group for guiding us through the interactions & suggestions that helped us to reach the successful completion of our training/project. We would like to extend heartfelt thanks to the HR department for giving us the opportunity to have a precious and rewarding experience of training in the Institute Of Oil and Gas Production Technology, Panvel, Navi Mumbai. Lastly, we would like to thank the rest of the IOGPT Staff who helped us from time to time during the training. The whole program really brought us together to appreciate the true value of teamwork.

Yatendra Singh Afzal Akhtar Kshitij Parakh Ankit Dalal Ramprakash Chaudhary

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CONTENTS: Sr. No.

Description

Page No.

1.

Introduction To Artificial Lift

4-10

2.

Inflow & Tubing Performance &Multiphase flow

11-25

3.

Gas Lift

26-41

4.

Troubleshooting

42-51

6.

Gas Lift Optimization and Case Studies

52-75

7.

Conclusion

76

8.

References

77

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1. Introduction In the process of formation of oil and gas deep under the earth crust, followed by their migration and accumulation as oil and gas reserve, a great amount of energy is stored in them. This energy is in the form of dissolved gas in oil, pressure of free gas, water and overburden pressure. When a well is drilled to tap the oil and gas to the surface, it is a general phenomenon that oil and gas comes to the surface vigorously by virtue of the energy stored in them. Over the years/months of  production, the decline of energy takes place and at one point of time, the existing energy is found insufficient to lift the adequate quantity of oil to the surface. From that time onwards, man-made effort is required and this is what is known as artificial lift. In other words artificial lift is a supplement to natural energy for lifting well fluid to the surface. Therefore, the flow of oil from the reservoir to the surface can be fundamentally dichotomized as self-flow period and artificial lift period. Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positivedisplacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal  pump like electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells use artificial lift for liquid unloading. To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field vary broadly across the industry. The methods include operator experience; what methods are available for installations in certain areas of the world; what is working in adjoining or similar fields; determining what methods will lift at the desired rates and from the required depths; evaluating lists of advantages and disadvantages; "expert" systems to both eliminate and select systems; and evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value  basis.

5

General Guidelines (Weatherford)

6

2. IPR Performance, Tubing Performance & Multi Phase Flow 2.1. Reservoir deliverability Reservoir deliverability is defined as the oil or gas production rate achievable from reservoir at a given bottom-hole pressure. It is a major factor affecting well deliverability. Reservoir deliverability determines types of completion and artificial lift methods to be used. A thorough knowledge of reservoir productivity is essential for production engineers. Reservoir deliverability depends on several factors including the following: 

Reservoir pressure



Pay zone thickness and permeability



Reservoir boundary type and distance



Wellbore radius



Reservoir fluid properties

 

 Near-wellbore condition Reservoir relative permeabilities

Reservoir deliverability can be mathematically modelled on the basis of flow regimes such as transient flow, steady state flow, and pseudo – steady state flow. An analytical relation between  bottom-hole pressure and production rate can be formulated for a given flow regime. The relation is called ‘‘inflow performance relationship’’ (IPR). In this chapter, the procedures used for establishing IPR of different types of reservoirs and well configurations will be addressed.

2.2. Inflow and Outflow Performance: 2.2.1 Productivity Index :

The productivity index of PI provides a measure of the capability of a reservoir to deliver fluids to the bottom of a wellbore for production. It defines the relationship between the surface  production rate and the pressure drop across the reservoir, known as the drawdown. It is defined as: q PI = (Pi - Pwf)

Thus, q = PI * (Pi-Pwf) Well potential, Qmax = PI * Pi

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PI and Pi are constant parameters for a well flowing under steady condition, hence q depends on Pwf, lower Pwf means higher oil production and vice versa. Where: q = stock tank bbls of liquid per day Pi = shut-in bottom hole pressure (psi) Pwf = flowing bottom hole pressure (psi) It is expressed in terms of bpd/psi pressure drawdown. Following are the important points related to PI : 

If reservoir pressure is above the bubble point, PI may be constant over a wide range of pressure drawdown.



When pressure falls below the bubble pressure, gas separates and occupying a portion of the pore causing decreasing of PI with increase in pressure drawdown.



It changes also with the life of well due changes in reservoir pressure, composition & properties of reservoir fluids and flow restriction or formation damage near the well bore.

Thus PI declines with higher well bore pressure drawdown, cumulative reservoir fluid withdrawals and degree of formation damage. 2.2.2 Inflow Performance Relationship (IPR ) : The inflow performance of a well represents the ability of that well to give fluids into the wellbore for a given drawdown. The productivity of a well depends on the type of reservoir and the drive mechanisms along with reservoir pressure, permeability, etc. The Inflow Performance curve (a Cartesian plot of bottom-hole flowing pressure versus surface flow rate) is one of the diagnostic tools used by Petroleum engineers to evaluate the performance (maximum potential) of a flowing well. The equation that describes this curve is the Inflow Performance Relationship (IPR). This equation can be determined both theoretically and empirically. In day to day variations IPR remains constant. A publication by Vogel in l968 offered an

extra

ordinary

solution

in

determining the Inflow Perform-ance Curve for a solution gas drive reservoir for flow below the bubble point or gas cap drive reservoir or any other types of reservoir having reservoir pressure below bubble point pressure Fig.2.1 : Vogel IPR behaviour

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Fig.2.2 : Variations in Inflow performance curves as predicted by various authors

While deriving the equation, Vogel assumed that flow efficiency is 1.00 which implies that there was no damage or improvement in the well. Standing extended the Vogel's equation by proposing the comparison chart where he has indicated flow efficiency either more or less than one. Fetkovich proposed and IPR Equation for Oil well having reservoir pressure below bubble point pressure which also behaves like gas well so the IPR equation being used for gas wells will also be applicable for oil wells. 2.2.3 Outflow Performance: After knowing the well potential, we have to design the outflow system in such a way so that to exploit the inflow. Outflow pressure or tubing intake pressure depends on the following parameters:

Tubing diameter



Depth



Water cut



Gas Liquid Ratio



QL(liquid flow rate)



THP(tubing head pressure)

Fig.2.3 : Outflow performance curve

Tubing intake pressure is defined as the pressure required at the bottom of the tubing to lift a particular amount of liquid through a specific tubing size, from a specific depth, with a definite water cut & GLR against a specific tubing head pressure. 2.3.

Multi-phase flow: The inflow performance characteristics are governed by the type of flow  –  single phase or multi-phase and various correlations have been introduced. Multiphase flow can occur in both regimes  – horizontal as well as vertical and take the forms as indicated in Fig. 2.4

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Fig.2.4 : Different types of Multiphase flows in an oil well

Diagrammatic representations and brief description of each of the types of multiphase flows is given below. Diagrammatic representations and brief description of each of the types of multiphase flows is given below. 

Horizontal flow :

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

Vertical flow :

Fig. 2.8 : Variation of flows with gas and liquid flow parameters and application areas for correlations

2.3.1. Multiphase Flow Concepts in Vertical and Inclined Wells It is clear that the behaviour of gas in tubing strings is markedly different. It would therefore be expected that the flow of a gas-liquid mixture would be more complex than for single phase flow. Each of the phases, both gaseous and liquid, have individual properties such as density and viscosity which will be a function of pressure and t emperature and hence position in the well. Gas-Liquid Mixtures

In the production of a reservoir containing oil and gas in solution, it is preferable to maintain the flowing bottom hole pressure above the bubble point so that single phase oil flows through the reservoir pore space.

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Consider such a case where oil flowing from the reservoir enters the production tubing. The flow of oil up the tubing and the associated pressure profile is illustrated in Figure. The oil may enter the tubing at a flowing pressure above the bubble point where no separate gas phase exists. The changing nature of the flow up the tubing can be considered in various stages from the base of the tubing: (a) single phase liquid will occur in the tubing assuming the pressure is below the bubble point  pressure. The pressure gradient is primarily influenced by the density of the liquid phase and is thus dominated by the hydrostatic head component of the pressure loss. Liquid expansion may contribute to a very slight reduction in liquid density and thence the hydrostatic gradient. (b) At the bubble point, the first gas is evolved which will: (i)

Lower the average density of the fluids in the tubing

(ii)

Increase the in-situ velocity

The gas is present in the form of discrete bubbles dispersed within the continuous oil phase. The flow regime is termed “bubble flow” and the pressure gradient will decline provided the decrease in hydrostatic head pressure loss exceeds the increase in frictional pressure loss. (c) With continued upwards flow, the pressure on the fluid declines. The decline in pressure on the fluid will cause: (i)

Expansion of the liquid phase

(ii)

Evolution of additional gas components

(iii)

Expansion of the existing gas phase.

This section of the tubing would demonstrate a continuously declining pressure gradient  provided the decrease in the hydrostatic component exceeds the increase in frictional gradient. The above mechanisms will continue to occur continuously as flow occurs up the tubing. (d) As flow continues higher up the tubing, the number and size of gas bubbles will increase until such a point that the fraction of the tubing volume occupied by gas is so large that it leads to  bubble coalescence. The coalescence of bubbles will yield a “slug flow” regime characterised by the upward rise, due to buoyancy, of slugs of gas segregated by continuous liquid columns. The upwards movement of the slugs will act as a major mechanism to lift oil to surface. (e) Often, as velocity continues to increase in the slug flow regime, it may be possible that a froth type transitional flow occurs where both the oil and gas phases are mutually dispersed, ie, neither is continuous.

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(f) With continued upward movement, further gas expansion and liberation will occur, resulting in slug expansion and coalescence, leading to slug enlargement and eventually “annular flow”. In annular flow, the gas flows up the centre of the tubing with  oil flow occurring as a continuous film on the inside wall of the tubing. (g) At extremely high velocities of the central gas column, shear at the gas-oil interface can lead to oil dispersion in the gas in the form of a “mist”. This “mist flow” pattern will occur at very high flow velocities in the tubing and for systems with a high gas-oil ratio GOR. It is possible that, as flow nears the surface, the increase in frictional pressure gradient exceeds the reduction in hydrostatic pressure gradient and, in such cases, the total pressure gradient in the tubing may start to increase. These flow patterns have been observed by a number of investigators who have conducted experiments with air-water mixtures in visual flow columns. The conventional manner of depicting the experimental data from these observations is to correlate the liquid and gas velocity parameters against the physical description of the flow pattern observed. Such  presentations of data are referred to as flow pattern maps.

Fig. 2.6 Flow pattern in V sw vs V g - Log scale

Fig.2.7. Type of Gas-Liq. Mixture Flow

2.3.2. Fluid Parameters in Multiphase Flow

In calculating the pressure loss for single phase flow, fluid properties can be evaluated at any  prescribed pressure and temperature. However, when evaluating the pressure gradient in multiphase flow, values for the various parameters must first be derived which are representative of the multiphase mixture. The properties of a multiphase mixture can normally be evaluated by combining the individual properties of the phases.

13

Important parameters which will influence the properties of a multiphase flow system are slippage and holdup. 1. Slippage

If a gas-liquid mixture flows up a tubing string, the effects of buoyancy on each of the phases will not be equal. The lighter of the phases, primarily gas, will rise upwards at an incrementally higher rate compared to the oil due to the effects of buoyancy. The slip velocity, Vs, is defined as the difference in velocities of the two phases, ie, for a gas-oil system.

2. Holdup

Holdup is a term used to define the volumetric ratio between two phases which occupy a specified volume or length of pipe. The liquid holdup for a gas-liquid mixture flowing in a pipe is referred to as H L:

HL therefore has a value between zero and one. Similarly, the gas holdup Hg is defined as

Obviously

3. Fluid Velocity

A difficulty arises as to how to define the velocity of a specific phase. There are two options: (a) The first option is to define velocity based upon the total cross-sectional area of the pipe despite the fact that each phase will occupy a fraction of the area. The velocity in this case is termed the superficial velocity For gas:

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Where,

A = cross-sectional area of the pipe

and for liquid:

(b) A more accurate value for the velocity of each phase is to correct for the holdup of each  phase. The actual gas velocity:

2.3.3 Correlations for Multi-phase flow : The vertical performance characteristics have been studied by various authors and correlations are listed below :

     

Horizontal flow Lockhart and Martinelli. Baker. Andrews et al. Dukler et al. Eaton et al. Beggs & Brill.

       

Vertical/ Inclined flow Duns and Ros. Orkiszewski. Hagedorn and Brown. Winkler and Smith. Beggs and Brill. Govier and Aziz Flanigan Beggs and Brill

A typical graphical representation is shown in Fig. 1,.6.

Fig.2.5 : Typical graphical representation of IPR correlations applicable in Multiphase flows

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Many investigators have conducted research into multiphase flow in tubing. Most of the investigative approaches have made basic assumptions which can be used to classify the correlations derived as follows: (1) Methods which do not consider: (a) slippage between phases, (b) the use of flow regime or pattern. (2) Methods which consider slippage between the phases but not flow regimes. (3) Methods which consider both flow regime and slippage. 2.4. Gradient Curves

Gilbert was the first to introduce the concept of a pressure gradient curve. The gradient curve provides a plot of pressure variations with depth in a tubing string for a range of specified flow conditions and as such provides a simplified but less accurate approach to predicting tubing  performance using a multiphase flow correlation. Gilbert obtained data in the form of  pressure traverses upon a range of oil  production wells and the data was plotted with respect to the following parameters: Fig.2.8. Depth-Press. gradient curve for 2.875” tubing •GOR or GLR •Tubing diameter  •Liquid or oil production rate His data was restricted to 1.66", 1.9", 23/8", 27/8" and 31/2"; for flow-rates of 50, 100, 200, 400 and 600 BPD. Therefore, for constant values of the above parameters, a range of curves were obtained by plotting the data, each curve reflecting different tubing head pressure, as shown in Figure below. The implication of this was that a specific gradient curve would be required for each tubing head pressure to be considered

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However, by shifting the curves downwards, he found that, for a constant GLR, flow-rate and tubing size, the curves overlapped, as depicted in Figure below. Then, single curve could be utilised to represent flow in the tubing under assumed conditions. This curve could be constructed to pass through the point of zero pressure at surface. The impact of moving the individual curves down until they overlapped was in effect to extend the depth of the well by a length which, if added to the top of the tubing, would dissipate the tubing head pressure and result in zero pressure at the top. Gilbert was then able to collect all the curves for a constant tubing size and flow-rate together on the one graph, resulting in a series of gradient curves which would accommodate a variety of GLRs. He was then able to prepare a series of gradient curves which apply for a constant liquid production rate and tubing size. 2.5.

Effect of Gas liquid Ratio on IPR and VLP curves : Presence of Gas in liquid increases the Gas liquid ratios (GLR). GLR affects both inflow and outflow performance.

Fig.2.6 : Effect of GLR on IPR correlations in Horizontal & Vertical flow

The general shape of the tubing performance

curves

reflect

the

increasing intake pressure as the liquid rate increases for a constant GLR due to the increased pressure drop as Fig.2.7: Effect of GLR on Tubing Intake curve

2.6.

mixture velocity increases.

Operation of Oil & Gas wells  –  IPR/VLP interactions: At a given time in the life of a flowing well, the gas to liquid ratio (GLR) is dependent on the flow conditions in the reservoir rock as expressed by relative permeability and gas saturation.

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To control the flow rate from the well, the only practical parameter at our disposal (once the tubing has been installed) is the tubing head pressure. For given tubing size, tubing depth and gas liquid ratio, the tubing intake pressure is a function of liquid rate and tubing head pressure, as illustrated by VLP (Vertical Lift Performance) curves. The pressure required at the intake of the tubing (bottom of tubing) to be able to flow the fluid mixture to the surface is defined as the Tubing Intake Pressure (Pin).

Fig.2.8 : IPR-TIC interactions in Self-flowing wells and Wells requiring Artificial Lift

As the tubing head pressure (P t) is reduced to zero, the tubing intake pressure for a given liquid rate decreases causing an increase of the drawdown pressure between the wellbore and the reservoir and a corresponding increase of the flow rate from the reservoir. The point of intersection of the VLP curve, corresponding to a given tubing head pressure and the IPR curve for the formation, represents an equilibrium condition and the well will flow. An increase in tubing head pressure will cause an increase in the VLP pressure and a corresponding decrease in flow rate. Further decrease in tubing head pressure, say to zero, will result in achieving the maximum production rate from the well.

Once the tubing

pressure is reduced to zero and maximum self-flow rate is achieved, it is not possible to produce fluid from the well at a higher rate without modifying the installation or introducing some form of artificial lift.

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3. GAS LIFT 3.1 Introduction Gas lift technology increases oil production rate by injection of compressed gas into the lower section of tubing through the casing – tubing annulus and an orifice installed in the tubing string. Upon entering the tubing, the compressed gas affects liquid flow in two ways: (a) the energy of expansion propels (pushes) the oil to the surface and (b) the gas aerates the oil so that the effective density of the fluid is less and, thus, easier to get to the surface. There are four categories of wells in which a gas lift can be considered: 1. High productivity index (PI), high bottom-hole pressure wells 2. High PI, low bottom-hole pressure wells 3. Low PI, high bottom-hole pressure wells 4. Low PI, low bottom-hole pressure wells

Fig 3.1

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Wells having a PI of 0.50 or less are classified as low productivity wells. Wells having a PI greater than 0.50 are classified as high productivity wells. High bottom-hole pressures will support a fluid column equal to 70% of the well depth. Low bottom-hole pressures will support a fluid column less than 40% of the well depth. Gas lift technology has been widely used in the oil fields that produce sandy and gassy oils. Crooked/deviated holes present no problem. Well depth is not a limitation. It is also applicable to offshore operations. Lifting costs for a large number of wells are generally very low. However, it requires lift gas within or near the oil fields. It is usually not efficient in lifting small fields with a small number of wells if gas compression equipment is required. Gas lift advancements in pressure control and automation systems have enabled the optimization of individual wells and gas lift systems. Early application of gas lift adopted the simple “U”-tube or pin-hole principle in producing oil from shallow wells. Then with the advent of gas lift valves, the gas lift application could be extended to deeper wells. Gas lift system is now broadly classified into 2 categories depending upon the duration of lift gas  being injected into the tubing: 1. Continuous gas lift 2. Intermittent gas lift.

SURFACE GAS NETWORK It will have become apparent from the above and the following sections that the performance of the gas lift system will depend on the pressure and flow capacity of the lift gas available at the well head. The surface piping network should thus be designed to: (i) have minimal (< 100psi) pressure loss between the compressor and the most distant wellhead, (ii) prevent one well from interfering with a second well by having sufficient pipe volume to dampen pressure surges and (iii) provide individual gas measurement and flow control for each well Large diameter piping encourages all the above - typically 4 in OD piping is used for the main backbone of the system with individual 2 in OD flow lines installed to each well. A ring main system is an option for large systems employing more than one compressor - the gas lift manifold for a group of wells and the compressors being attached to the gas supply ring main as appropriate.

SUB-SURFACE GAS NETWORK

3.2 Gas Lift System A complete gas lift system consists of a gas compression station, a gas injection manifold with injection chokes and time cycle surface controllers, a tubing string with installations of unloading valves and operating valve, and a down-hole chamber.

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Figure 1 depicts a configuration of a gas-lifted well with installations of unloading valves and operating valve on the tubing string. There are four principal advantages to be gained by the use of multiple valves in a well: 1. Deeper gas injection depths can be achieved by using valves for wells with fixed surface injection pressures. 2. Variation in the well’s productivity can be obtained by selectively injecting gas valves set at depths ‘‘higher’’ or ‘‘lower’’ in the tubing string. 3. Gas volumes injected into the well can be ‘‘metered’’ into the well by the valves. 4. Intermittent gas injection at progressively deeper set valves can be carried out to ‘‘kick off’’ a well to either continuous or intermittent flow. 3.2.1 Continuous Gas Lift

A continuous gas lift operation is a steady-state flow of the aerated fluid from the bottom (or near bottom) of the well to the surface. Intermittent gas lift operation is characterized  by a start-and-stop flow from the bottom (or near bottom) of the well to the surface. This is unsteady state flow. In continuous gas lift, a small volume of high-pressure gas is introduced into the tubing to aerate or lighten the fluid column. This allows the flowing bottom-hole pressure with the aid of the expanding injection gas to deliver liquid to the surface. To accomplish this efficiently, it is desirable to design a system that will permit injection through a single valve at the greatest depth possible with the available injection pressure. Continuous gas lift method is used in wells with a high PI (0.5 stb/day/psi) and a reasonably high reservoir pressure relative to well depth. Intermittent gas lift method is suitable to wells with (1) high PI and low reservoir Fig 3.2  pressure or (2) low PI and low reservoir pressure. The type of gas lift operation used, continuous or intermittent, is also governed by the volume of fluids to be produced, the available lift gas as to both volume and pressure, and the well reservoir’s conditions such as the case when the h igh instantaneous BHP drawdown Encountered with intermittent flow would cause excessive sand production, or coning, and/or gas into the wellbore. 3.2.2 Intermittent Gas Lift In intermittent gas lift sufficient volume of gas at the available injection pressure is injected as quickly as possible into the tubing under a liquid column and then the gas injection is stopped. The gas expands and in this process it displaces the oil on to the surface. So, the assistance of flowing

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 bottom hole pressure is not required when the gas displaces the oil. Static bottom hole pressure, flowing bottom hole pressure, and productivity index of the well govern the fluid accumulation in the tubing. In this system, a pause or idle period is provided, when no gas injection takes place. In this period the well is allowed to buildup the level of liquid which depends upon he reservoir pressure and PI of the well. Then again next gas injection cycle is initiated to lift oil. In this manner, as the name suggests, intermittent gas lift works on the principle of intermittent injection of gas in a regular cycle. It is to be noted that in the cycle the injection time should be as short as possible. A large volume of gas should be injected quickly underneath the oil slug as a result the oil slug above the  point of gas injection will acquire the terminal velocity( maximum velocity) within shortest possible time, which would minimize the liquid fallback in the tubing string. Less fluid fallback will not only increase production but also help reduce the paraffin accumulation problem in the tubing, if oil is  paraffinic in nature. For injecting large amount of gas, bigger port size gas lift valves are required. That is why gas lift valves having port sizes 1/2”, 7/16”, 3/8”, or 5/16” are preferred. In intermittent gas lift application, two different injection flow rates are considered. One is the normal gas injection rate( called day rate) required for a well on per day basis and other is the instantaneous gas injection rate, commonly called per minute demand rate of gas injection. It helps to minimize the injection gas breakthrough the oil slug and arrests liquid fall back to a desired extent. Similar to continuous gas lift, a number of gas lift valves are also installed in the intermittent gas lift well. The last valve is located as deep as possible (conventionally last valve is just above the top of  perforations). At every cycle, the injection of gas takes place through this valve first and as such, it is also termed as operating valve. The upper valves may or may not operate, when the liquid slug crosses the valve during its upward travel. If the upper valve opens as the slug crosses the valve, the additional gas further arrests the liquid fall back and thus results in more oil production. In the light of above discussion it can be comprehended that continuous gas lift system should be employed when well moderate to high reservoir pressure and PI. Continuous gas lift characteristically provides high volume of oil production. Intermittent gas lift system should be deployed when the well has a poor pi and low reservoir pressure.

22

Figure below illustrates a simplified flow diagram of a closed rotary gas lift system for a single well in an intermittent gas lift operation. The time cycle surface controller regulates the startand-stop injection of lift gas to the well. For proper selection, installation, and operations of gas lift systems, the operator must know the equipment and the fundamentals of gas lift technology.

Fig 3.3: Intermittent gas lift

Fig 3.4: Gas lift Loop

3.3 Gas Lift Advantages and Limitations a) Advantages

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b) Limitations

3.4 Type of installation- Open, Semi-closed, Closed 1. Open Installation 

When there is neither any packer in the tubing-casing annulus nor any standing valve in the tubing shoe. Limitation of open installation:





 

U tubing through the tubing will occur, especially when reservoir pressure is very low and the deepest gas lift valve is very near to the perforation. Fluid level will rise in the annulus in case of compressor upsets and during idle period of intermittent gas lift. In the absence of a packer, the same liquid is to be U-tubed again through the gas lift valve before the normal gas injection is resumed. Production casing will come in contact with the well fluid. In case of offshore wells, it is mandatory to have packer in the annulus. This is primarily due to safety aspect for offshore wells to prevent accidental leakage of oil and gas in the sea through leaked casing.

2. Semi-closed Installation 

When there is only packer in the tubing annulus and no standing valve.



It is standard practice for intermittent gas lift wells and continuous gas lift wells.

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3. Closed Installation a. When there is a packer in the tubing-casing annulus, below the deepest gas lift valve. b. When there is a standing or non-return valve in the tubing at the tubing shoe.

The installation of standing valve is recommended when reservoir pressure is low and PI is in the range of moderately high to high. Generally the lowering of standing valve is decided afterwards during the production from the well. For this reason, in most of the places, the general practice is to lower A-nipple or D-nipple or equivalent along with the tubing in the initial installation period. If required, the standing valve is either dropped or lowered with the wire line on the A-nipple or D-nipple. It is also likely that with the production through the well, the sand slowly gets settled on the standing valve making the standing valve non operative. So, to avoid this problem the deepest gas lift valve should always be placed just above or near to the standing valve. The turbulence created due to gas injection at that place inhibits the build-up of sand on the standing valve. It is standard practice for continuous gas lift wells.

3.5 Gas Lift Valve A gas lift valve is analogous to a down hole pressure regulator. The surface areas of the gas lift valve exposed to tubing and casing pressures. So, in response to casing or tubing pressure the gas lift valves open, which allows injection gas to enter the production string to lift fluid to the surface. In the course of improvement of gas lift system several types of gas lift valves were developed. Probably the differential type of valve was a very early development. Now a days bellow operated nitrogen pressure loaded gas lift valves is most common type of gas lift valves being used by oil industries. 3.5.1 Component of Gas Lift Valve

1) 2) 3) 4) 5)

Body Loading element Responsive element Transmission element Metering element

1) Body:

The body is the outer cover of the gas lift valve and is generally of  1 ½” O.D. or 1” O.D. Some pencil type of gas lift valve is also there, which has an O.D. of 5/8” .The body of the gas lift valve is generally of S.S.-304 or 316.The conventional type of gas lift valve is

25

threaded and is screwed with the mandrel. In case of wire line type, the “O” ring or “V” seal rings are provided on the body for isolating the required portion of the gas lift valve from the adjacent areas and are housed into the side pocket using wire line operated kick off tool. The length of gas lift valve i.e. its body varies usually from merely a foot to around three feet. 2) Loading Element:

The loading element can be spring, nitrogen gas or a combination of both. The spring of gas charge provides a required balancing force so that the valve can be operated at a desired  pressure. it means that above this pressure the valves opens and below that it gets closed automatically. Spring provides the required compression force, so when spring loaded valve is required to open, the external pressure should be sufficient to overcome the compression force of the spring. In case of gas charged valve i.e. nitrogen-loaded valve, thee external pressure is required to overcome force due to nitrogen pressure to make the valve open for gas injection. 3) Responsive Element:

Responsive element can be metal bellows or piston. Bellows type of gas lift valve is most  prevalent. The bellow is made of very thin metal tube preferably of 3-ply monel metal. Its th thickness is approximately 150   of an inch. This is hydraulically formed into a series of convolutions. This form makes the tube very flexible in the axial direction and can be compared with a similar rubber bellows. The bellow is regarded as the heart of the gas lift valve. If bellows are properly strengthened, the gas lift valves become very strong. If bellows is of high quality, it is reflected in the quality of gas lift valve. 4) Transmission Element:

The transmission element is generally a metal rod, whose one end is fitted with the lowermost  portion of the bellow and the other end is rigidly attached with the stem tip. 5) Metering Element:

It refers to the opening or port of the gas lift valve, through which injection gas passes into the well fluid in the production tubing.

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3.5.2 Different Types of Gas Lift Valve 1.Casing Pressure Operated Gas Lift Valve:

As the name implies the Casing pressure operated gas lift valves operate predominantly with the pressure of casing. So, its larger surface of opening and closing mechanism i.e., the bellows area is directly exposed to casing and not the tubing pressure. That is, the casing  pressure acts on the bellows and tubing pressure on the downstream side of the seat. If it is required to reduce the influence of the tubing Fig 3.5: Casing Pressure Operated Valve  pressure, it is required to reduce the port size to as minimum as possible. 2) Fluid Operated Gas Lift Valves (or Tubing Pressure Operated Gas Lift Valve) As the name implies the fluid operated gas lift valves operate predominantly with the pressure of tubing. So, its larger surface of opening and closing mechanism i.e., the bellows area is directly exposed to tubing  and not the casing pressure. That is, the tubing pressure acts on the bellows and casing  pressure on the downstream side of the seat. Due to this, the force balance equations as described for casing pressure operated valves are reversed. If it is required to reduce the influence of the casing  pressure, it is required to reduce the port size to as minimum as possible.

Fig 3.6: Tubing Pressure Operated Valve

3. Pilot Operated Gas Lift Valve This is a casing pressure operated gas lift valve, but with some fundamental differences in the construction of the valve as well as in its operating mechanism. The  principle behind the construction of this type of valve is to separate the gas flow capacity from the pressure control system. The pilot valve has two distinct sections. One is pilot section  and the other is power

Fig 3.7: Pilot Valve

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section . The pilot section is very similar to an unbalanced type of valve, with the exception that injection gas does not pass through the pilot port into the tubing.The power section consists of- a  piston, stem, spring and the valve port through which injection gas enters into the tubing.

As the casing pressure reaches the opening pressure of the valve, at first, the pilot section port opens. The gas through the pilot port, then, exerts pressure over the piston in the main valve section. The piston is, then pushed downward against the compressive force of spring. This causes the downward movement of the stem and the valve gets opened. Casing gas then, passes through the main section port to find entry in the tubing. When the casing pressure decreases  below the closing pressure of the pilot section valve, the pilot section, like in the normal casing  pressure operated valves, gets closed. Then, the trapped gas between the pilot port and piston is  bled in the tubing through a specially constructed bleeder line in the main valve section. The same force balance equation is applied to the pilot section only for the opening and closing of the valve, since it is the main functional area. 3.6. GAS LIFT VALVE MECHANICS

The mode of action of the upper gas lift valves, in which the top valves are designed to open and close to allow the fluid in the casing/tubing annulus to be unloaded so that deep gas injection can be achieved, was described in the previous section. The operating valve is different, being designed to allow for a continuous flow of gas. The upper gas lift valves have ports sized to pass only the required volume of gas, limiting the rate at which the unloading takes place. A larger port is often installed in the operating valve so that gas injection can be increased, if dictated by future well or reservoir conditions. Dummy valves are installed in the “Bracketing Envelope” where “live” valves are currently not required.

Fig 3.8: Gas Lift Valve Schematics

3.6.1. Casing or Inflow Pressure Operated (IPO) Valves

A casing pressure operated valve includes: (i) dome or top section of the valve is charged, via the plug, with nitrogen to the required  pressure (Pdome). (ii) nitrogen charge acts on the bellows ; exerting a force pushing the ball against the choke or  port and halting the flow of lift gas into the tubing. (iii) spring  prevents damage to the bellows due to excessive collapse when exposed to forces much greater than those generated by the nitrogen charge. Such excessive collapse would result

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in the bellows losing their elastic response to pressure changes. If this occurs the gas lift valve needs to be changed. (iv) choke or port prevents excessive (gas) flow rates. (v) check valve prevents formation fluids flowing from the tubing into the annulus. Simple, mechanical considerations allow us to derive the following equations: The Closing Force, Fc, tending to seat the ball is given by: FC = Pdome * Abellows Where Ax refers to the Area of component x and Py refers to the Pressure at point y. The Opening Force (FO) is made up of two components: FO1, and FO2, where FO1 = Ptubing * Aport FO2 = Pcasing * (Abellows - Aport) and FO = FO1 + FO2 The Opening and Closing forces

are

equal

just

before

the

valve

3.6.2 Dome Pressure Calibration The dome is charged with nitrogen and the gas lift valve installed in a Test Rack placed in a temperature controlled enclosure set at 60ºF The simulated Ptubing is at atmospheric pressure (or O psig). A gradually increasing gas pressure is app lied to simulate Pcasing. The valve opening pressure (Popening) is recorded as the pressure when gas begins to flow.

Fig 3.9: Dome Pressure Calibration

Application of the above force balance equation gives: Popening = Pdome/(1 - Aport/Abellows)

opens.

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This can be used to confirm that the manufacturing of the gas lift valve is on specification and that the dome nitrogen pressure, Pdome, has been set correctly. The valve closing pressure (Pclosing) may be measured by pressurising both the injection and tubing sides so that the valve is fully open. The pressure on the tubing side is reduced and valve closure recognised as the  pressure at which Pcasing no longer decreases in line with Ptubing. The design of the valve dictates that Pclosing will be lower than Popening, since starting from the open valve situation means that the injection pressure acts on the complete bellows area. The valve spread is defined as the difference between the valve test rack opening and closing  pressures i.e. (Popening - Pclosing). It is a measure of the difference between the effective area of the bellows and the port.

Fig: 3.10

3.7

GAS LIFT DESIGN

3.7.1. OBJECTIVES

The gas lift system designed for installation in a specific well should meet the following objectives: (i) M axim ise the (net) value of oil produced  . This normally implies that the: (a) operating valve, through which the gas will be continuously injected, should be situated as deep as possible and (b) gas injection rate should equal the economic limit at which the marginal value of the extra oil  produced equals the marginal cost of providing this extra gas. Further optimisation is required when more than one well is being produced and there is insufficient lift gas available to meet this economic criteria in all wells (ii) M aximi se design fl exibi li ty. The gas lift design should be capable of coping with the expected changes in the well producing conditions during its lifetime, as well as the “unplanned” uncertainties in reservoir properties and performance. These changes normally involve deterioration, from a well productivity point of view, due to decreases in the Reservoir Pressure and Well productivity Index and increases in the Water Cut

30

(iii) M in imi se well in terventi on  . This is particularly important in subsea or other wells where wireline access is difficult or impossible. Well completions with a “dry” tree and deviations less than 60o allow the option to replace the gas lift valve by a relatively quick, wireline operation. The operating parameters (or valve performance) o f the gas lift valves installed in the side pocket mandrels can thus be adjusted at any time in the well’s life i.e. the tubing production conditions can be adapted to take into account changes in the reservoir conditions and the well performance. These operating parameters include the: (a) tubing or casing pressures (depending on the type of side pocket mandrel installed) at which gas flow through the gas lift valve starts and stops a nd (b) port (or choke) size, which controls the maximum volume of gas that can be injected as well as the associated pressure drop due to the gas flow through the valve. This ability to modify the valve performance when required leads to great flexibility in the choice of gas lift operating parameters, despite the fact that the installation depth of the gas lift valves is fixed. {The (side pocket) gas lift mandrels within which the valve is placed are permanent fixtures in the completion string, having been installed during the well completion process}. The flexibility of a particular gas lift design is further increased by installing one or two extra gas lift valves as possible both above and below the chosen depth of the operating valve. They should be placed as close together as possible, but sufficiently far apart that they do not interfere with each other’s operation (typically 150 m vertical depth apart). This is known as the “bracketing envelope”. The inclusion of the bracketing envelope mandrels will allow the operating valve to be moved to a slightly higher or lower depth, as dictated by the well & reservoir performance changes during the well life. This  procedure maximizes the (liquid) production by, for a given gas injection rate, allowing the well to be lifted from as deep as possible commensurate with the current producing conditions. (i v) Stable Well Operati on. Well “heading”, in which the Tubing Head or Casing Head Pressure Shows

regular changes should be avoided. Stable operation - with a constant value for the casing and tubing head  pressures - should be aimed for. This is because stable well operation will always produce more oil and, often, require less lift gas than unstable gas lifted well operation. Casing Head pressure excursions of as little as 5 psi can indicate valve multiporting {the gas injection point changing from one valve to another or a second valve cycling (opening and closing) in addition to the operating valve}.

3.7.2 Gas lift design parameters The gas lift design process has to answer the following questions to meet the above ob jectives: (i) How many unloading valves are required and at what depths should they be placed? (ii) What are the required settings for the Unloading Valves? (iii) What is the depth of the operating valve where the gas is continuously injected? (iv) What is the gas injection (or casing head) pressure? (v) How much lift gas should be injected? (vi) What is the tubing head pressure for the target flow rate? This is translated into practice  by ensuring that the gas lift valve spacing and pressure setting are such that: (i) the operating valve should have adequate flow capacity and be placed as deep as possible, (ii) the available lift gas pressure must be able to displace the fluid in the casing to the operating valve depth.

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3.7.3. Gas-lift Designing Designing a gas lift depends on the following important parameters: 1)

Productivity index, PI or Inflow Performance Relationship, IPR. SBHP FBHP & corresponding flow rate PVT properties Bubble point pressure Formation volume factor Reservoir temperature  

2)

  

3) 4) 5) 6) 7) 8) 9) 10)

Depth of perforation interval. Tubing and casing size. Available injection pressure Water cut Tubing Head Pressure Type of reservoir drive mechanism. Inclination profile of the well. Specific gravity of kill fluid.

Depth is plotted against pressure and the pressure traverse of the fluids starts from the flowing BHP at the bottom of the well and moves all the way to the surface. Assuming an average flowing gradient beneath the point of gas injection and an average flowing gradient above the point of gas injection, we start with the tubing pressure and calculate the flowing BHP as follows: Pwh + Gta * L + Gfb * (D-L) = Pwf Where: Pwh = wellhead pressure Gta = average flowing gradient above the point of gas injection L = depth to point of gas injection Gfb = average flowing gradient below the point of gas injection D = total depth of well Pwh = flowing BHP This is the basis for gas lift design. Continuous flow creates the necessary flowing BHP to allow the well to produce at a particular flow rate. Gas is injected at such a point that this pressure may  be obtained. Factors such as available pressure, available gas volume, flow configuration sizes and flowing tubing pressure at the surface will influence produ ction.

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The following procedure serves as a guide for designing a gas lift installation. All information’s are plotted on a sheet of rectangular co-ordinate paper:1. Depth is plotted on the ordinate with zero depth at top and maximum depth at bottom. 2. Pressure is plotted on the abscissa with pressure increasing from zero at origin to a maximum. 3. the static BHP is plotted at the correct depth(bottom of the well) 4. The necessary draw down in pressure is determined to produce the desired flow rate. 5. The draw down is subtracted from the static BHP to obtain the flowing BHP. This  pressure is noted at depth. 6. From the point of static BHP the static gradient line is extended up the hole until it intersects the depth. this will the static liquid level at the well for Pwh=0 and in the event the well is not loaded can be used as a point of location for the first GLV. 7. From the point of flowing BHO the flowing pressure traverse below the point of injection is plotted. 8. High flow rates of water and low gas liquid ratios this line may be equal. 9. the surface operating pressure (i.e. pressure that can be maintained at the well site to operate the gas lift well)is selected 10. the point where the operating casing pressure intersects the flowing gradient line as the  point of balance is marked 11. 100 psi from the pressure in the casing at this point is subtracted and the point of injection is obtained 12. The flowing well head pressure (Pwh) is approximated and the value at the zero depth is marked. 13. The flowing well head pressure (Pwh) is connected to the point of gas injection by means of computer calculations. This curve will in turn gives the total GLR required to produce the well. 14. Solution gas is subtracted from the total gas volume, the required injection GLR is obtained, from which the required gas flow rate ca n be determined. The determination of this point of gas injection is correct for a particular well at a particular time in its life. Depending upon the type of drive mechanism by which the well produces, its characteristics may change considerably in one or two years.

3.7.4 Gaslift Valve Spacing Criteria The chosen installation depths of valves will b e based on the following criteria: (i) Specify a minimum number of gas lift valves. This will not only reduce the cost but also the number of potential leak paths. (ii) Gas lift valves to be installed sufficiently far apart that they do not interfere with each other’s operation (150m suggested minimum spacing). (iii) (continuous) Gas injection through the operating valve occurs as deep as possible based on current producing conditions.

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4.0 Gas-Lift Troubleshooting

Fig. 4.1 - Gas Lift System

4.1 PROBLEMS ASSOCIATED WITH GAS LIFT Gas-lift problems are usually associated with three areas: inlet, outlet, and downhole. 





Inlet problems may be the input choke sized too large or too small, fluctuating line  pressure, plugged choke, etc. Outlet problems could be high backpressure because of a flowline choke, a closed or  partially closed wing or master valve, or a plugged flowline. Downhole problems could include a cutout valve, restrictions in the tubing string, or sand-covered perforations

34

A) INLET PROBLEMS Choke size is too large :  Check for casing pressure at or above design operating pressure. This can cause reopening of upper-pressure valves and/or excessive gas usage. Approximate gas usages for various flow rates are included in Fig. 2.

Fig 4.2 - Continuous Flow Gas Lift Operation Choke sized too small:   Check for reduced fluid production as a result of insufficient gas injection. This condition can sometimes prevent the well from unloading fully. The design gas:liquid ratio can often give an indication of the choke size to use as a starting point. Low casing pressure: This condition can occur because the choke is sized too small, it is  plugged, or it is frozen up. Choke freezing can often be eliminated by continuous injection of methanol in the lift gas. A check of injected-gas volume will separate this case from low casing pressure based on a hole in the tubing or cutout valve. Verify the gauge readings to be sure the problem is real. High casing pressure: This condition can occur because the choke is too large. Check for excessive gas usage from the reopening of upper pressure valves. If high casing pressure is accompanied by low injectiongas volumes, the operating valve may be partially plugged or high tubing pressure may be reducing the differential between the tubing and casing. If this is the case, remove the flowline choke or restriction. High casing pressure accompanying low injection-gas volumes may also be caused by higher-than-anticipated temperatures raising the set pressures of pressure operated valves.

35

Inaccurate gauges : Inaccurate gauges can cause false indications of high or low casing  pressures. Always verify the wellhead casing and tubing pressures with a calibrated gauge. Low gas volume: Check to ensure that the gas-lift line valve is fully open and that the casing choke is not too small, frozen, or plugged. Check to see if the available operating pressure is in the range required to open the valves. Be sure that the gas volume is being delivered to the well. Nearby wells, especially intermittent wells, may be robbing the system. Sometimes a higher-than-anticipated producing rate and the resulting higher temperature will cause the valve set pressure to increase, thereby restricting the gas input. Excessive gas volume:  This condition can be caused by the casing choke sized too large or excessive casing pressure. Check to see if the casing pressure is above the design pressure, causing upper pressure valves to be opened. A tubing leak or cutout valve can also cause this symptom, but they will generally also cause a low casing pressure. Intermitter problems : Intermitter cycle time should be set to obtain the maximum fluid volume with a minimum number of cycles. Injection duration should then be adjusted to minimize tail gas. Avoid choking an intermitter unless absolutely necessary. For small gaslift systems in which opening the intermitter drastically reduces the system pressure, it may  be possible to reduce pressure fluctuation by placing a small choke in parallel dead wells as volume chambers. Check to make sure that the intermitter has not stopped, whether it is a manual-wind or battery-operated model. Wells intermitting more than 200 BFPD should be evaluated for constant flow application. Less than one barrel per cycle is probably an indication that the well is being cycled too rapidly.

B) OUTLET PROBLEMS Valve restrictions : Check to ensure that all valves at the tree and header are fully open or that an undersized valve is not in the line (1-in. valve in a 2-in. flowline). Other restrictions may result from a smashed or crimped flowline. Check locations where the line crosses a road, which is where this situation is likely to occur. High backpressure:  Wellhead pressure is transmitted to the bottom of the hole, reducing the differential into the wellbore and reducing production. Check to ensure that no choke is in the flowline. Even with no choke bean in a choke body, it is usually restricted to less than full ID. Remove the choke body if possible. Excessive 90° turns can cause high backpressure and should be removed when feasible.

High backpressure can also result from paraffin or scale buildup in the flowline. Hot-oiling the line will usually remove paraffin; however, removal of scale may or may not be possible,

36

depending on the type. Where high backpressure is caused by long flowlines, it may be  possible to reduce the pressure by looping the flowline with an inactive line. The same would apply to cases in which the flowline ID is smaller than the tubing ID. Sometimes a partially opened check valve in the flowline can cause excessive backpressure. Common flowlines can cause excessive backpressure and should be avoided if possible. Check all possibilities, and remove as many restrictions from the system as possible. Separator operating pressure:   The separator pressure should be maintained as low as  possible for gas-lift wells. Often a well may be flowing to a high or intermediate pressure system when it dies and is placed on gas lift. Make sure the well is switched to the lowest pressure system available. Sometimes an undersized orifice plate in the meter, at the separator, will cause high backpressure. C) DOWNHOLE PROBLEMS Hole in the tubing. Indicators of a hole in the tubing include abnormally low casing pressure and excess gas usage. A hole in the tubing can be confirmed as follows: 1. Equalize the tubing pressure and casing pressure by closing the wing valve with the lift gas on.

2. After the pressures are equalized, shut off the gas input valve and rapidly bleed-off the casing pressure. 3. If the tubing pressure bleeds as the casing pressure drops, then a hole is evident. 4. The tubing pressure will hold; if not, then a hole is present since both the check valves and gas-lift valves will be in the closed position as the casing pressure bleeds to zero. 5. A packer leak may also cause symptoms similar to a hole in the tubing. Operating pressure valve by surface closing-pressure method : A pressure-operated valve will pass gas until the casing pressure drops to the closing pressure of the valve. As a result, the operating valve can often be estimated by shutting off the input gas and observing the  pressure at which the casing will hold. This pressure is the surface closing pressure of the operating valve, or the closing-pressure analysis. The opening-pressure analysis assumes the tubing pressure to be the same as the design value and at single-point injection. These assumptions limit the accuracy of this method because the tubing pressure at each valve is always varying, and multipoint injection may be occurring. This method can be useful when used in combination with other data to bracket the operating valve.

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Well blowing dry gas : For pressure valves, check to ensure that the casing pressure is not in excess of the design operating pressure, which causes operation from the upper valves. Using the procedure mentioned above, make sure that there are no holes in the tubing. If the upper valves are not being held open by excess casing pressure and no hole exists, then operation is  probably from the bottom valve.

4.2 TROUBLESHOOTING Additional verification can be obtained by checking the surface closing pressure as indicated above. When the well is equipped with fluid valves and a pressure valve on the bottom,  blowing dry gas is a positive indication of operation from the bottom valve after the  possibility of a hole in the tubing has been eliminated. Operation from the bottom valve usually indicates a lack of feed-in. Often it is advisable to tag bottom with wireline tools to determine whether the perforations have been covered by sand. When the well is equipped with a standing valve, check to ensure the standing valve is not stuck in the closed position. 4.2.1 Well will not take any input gas: Eliminate the possibility of a frozen input choke or a closed input gas valve by measuring the pressures upstream and downstream of the choke. Also, check for closed valves on the outlet side. If fluid valves were run without a pressure valve on bottom, this condition is probably an indication that all the fluid has been lifted from the tubing and not enough remains to open the valves. Check for feed-in problems. If  pressure valves were run, check to see if the well started producing above the design fluid rate because the higher rate may have caused the temperature to increase sufficiently to lock out the valves. If the temperature is the problem, the well will probably produce periodically and then stop. If this is not the problem, check to make sure that the valve set pressures are not too high for the available casing pressure. 4.2.2 Well flowing in heads:   Several causes can be responsible for this condition. With  pressure valves, one cause is port sizes that are too large. This would be the case if a well initially designed for intermittent lift were placed on constant flow because of higher-thananticipated fluid volumes. In this case, large tubing effects are involved and the well will lift until the fluid gradient is reduced below a value that will keep the valve open. This case can also occur because of temperature interference. For example, if the well started producing at a higher-than-anticipated fluid rate, the temperature could increase, causing the valve set  pressures to increase and locking them out. When the temperature cools sufficiently, the valves will open again, thus creating a condition in which the well would flow by heads. With tubing pressure having a high tubing effect on fluid-operated valves, heading can occur as a result of limited feed-in. The valves will not open until the proper fluid load has been obtained, thus creating a condition in which the well will intermit itself whenever adequate

38

feed-in is achieved. Because an injection gas rate that is too high or too low can often cause a well to head, try tuning in the well. 4.2.3 Gas-lift operation stalls and will not unload:   This typically occurs when the fluid column is heavier than the available lift pressure. Applying injection-gas pressure to the top of the fluid column, usually with a jumper line, will often drive some of the fluid column  back into the formation. This reduces the height of the fluid column being lifted and allows unloading with the available lift pressure. This procedure is called “rocking the well.” The check valves prevent this fluid from being displaced back into the casing. For fluid-operated valves, rocking the well in this fashion will often open an upper valve and permit the unloading operation to continue. Sometimes a well can be swabbed to allow unloading to a deeper valve. Ensure that the wellhead backpressure is not excessive or that the fluid used to kill the well for workover was not excessively heavy for the design. 4.2.4 Valve hung open : This case can be identified when the casing pressure will bleed  below the surface closing pressure of any valve in the hole yet tests to determine the existence of a hole show that one is not present. Try shutting the wing valve and allow the casing pressure to build up as high as possible, and then rapidly open the wing valve. This action will create high differential pressure across the valve seat, removing any trash that may be holding it open. Repeat the process several times if required. In some cases valves can be held open by salt deposition. Pumping several barrels of fresh water into the casing will solve the problem. If the above actions do not help, a flat valve cutout may be the cause. 4.2.5 Valve spacing too wide : Try rocking the well when it will not unload. This will sometimes allow working down to lower valves. If a high-pressure gas well is nearby, using the pressure from it may allow unloading. If the problem is severe, the only solution may be to replace the current valve spacing, install a packoff gas-lift valve, or shoot an orifice into the tubing to achieve a new point of operation. 4.3 TUNING IN THE WELL 4.3.1 Continuous-Flow Wells

Unloading a well typically requires more gas volume than producing a well. As a result the input gas volume can be reduced once the point of operation has been reached. Excess gas usage can be expensive in terms of compression costs; therefore, it is advantageous, in continuous-flow installations, to achieve maximum fluid production with a minimum amount of input gas. This can be accomplished by starting the well on a relatively small input choke size, at 1/64 increments, until the maximum fluid rate is achieved. Allow the well to stabilize for 24 hours after each change before making another adjustment. If for some reason a flowline choke is being used, increase the size of that choke until maximum fluid is produced

39

 before increasing the gas-input choke. If the total gas:liquid ratio (TGLR) exceeds the values shown in Fig. 2, it is possible that too much gas is being used. 5.3.2 Intermittent-Flow Wells

In intermittent lift, the cycle frequency is typically controlled by an intermitter. The intermitter opens periodically to lift an accumulated fluid slug to the surface by displacing the tubing with gas. The same amount of gas is required to displace a small slug of fluid to the surface as is required to displace a large slug of fluid (Fig 3.). As a result, optimal  performance is obtained when the well produces the greatest amount of fluid with the least number of cycles. The cyclic operation of the injection gas causes the surface casing pressure to fluctuate  between an opening casing pressure (high) and a closing casing pressure (low). The difference in the surface opening and closing pressures during a single cycle is referred to as “spread.” Injection-gas volume per cycle increases as spread value increases.

Fig 4.3. - Intermittent Gas Lift: Saw tooth Shape to Surface Casing Pressure

To accomplish this, the initial injection-gas volume and the number of injection cycles must  be more than required. A good rule of thumb is to set the cycle based on 2 minutes per 1,000 ft of lift, with the duration of gas injection based on 1/2 minute per 1,000 ft of lift. Reduce the number of cycles per day until the most fluid is obtained with the least number of cycles, and then decrease the injection time until the optimal amount of fluid production is maintained with the least injection time. If one barrel or less is produced per cycle, the cycle time should probably be increased. Be sure the intermitter stays open long enough to fully open the gas-lift valve. This will be indicated by a sharp drop in casing pressure. When a two-pen recorder is used, it will give a saw-tooth shape to the casing pressure line (Fig. 4.3).

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5.4 SOME COMMON MALFUNCTIONS OF GAS LIFT SYSTEM - POSSIBLE CAUSES & CURES 1. Communication between Casing & Tubing Causes

Cures

A. Valve Stuck Open

A. Rock the well, flush the valve

B. Packer leaking

B. Reset packer

C. Tubing Leak

C. Tubing patch / re-run new tubing

2. Injection Pressure Increases Causes

Cures

A. Upper valve is operating valve

A. Adjust injection gas Pressure

B. Valve plugged

B. Valve needs to be replaced

C. Temperature rise affecting valves

C. Lower TRO pressure of valve

3. High Back Pressure at Wellhead Causes

Cures

A. Plugged flow line

A. Needs treatment accordingly

B. Flow line size too small

B. Loop flow line or larger line

C. Well using too much gas

C. Adjust injection choke

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4.5 Troubleshooting: Diagnostic Tools 4.5.1 Calculations:   One method of checking gas-lift performance is by calculating the “tubing load required” (TLR) pressures for each valve. This can be accomplished by calculating surface closing pressures or by comparing the valve opening pressures with the opening forces that exist at each valve downhole based on the operating tubing, and casing  pressures, temperatures, etc. Although this method may not be as accurate as a flowing  pressure survey because of inaccuracies in the data used, it can still be a valuable tool in highgrading the well selection for more expensive diagnostic methods. Weatherford’s VALCAL gas-lift design software is available for this type of diagnostics. 4.5.2 Well-Sounding Devices:   The fluid level in the annulus of a gas-lift well will sometimes give an indication of the depth of lift. This method involves imploding or exploding a gas charge at the surface and uses the principle of sound waves to determine the depth of the fluid level in the annulus. Acoustic devices are fairly economical compared to flowing-pressure surveys. It should be noted that for wells with packers, it is possible for the well to have lifted down to a deeper valve while unloading, then return to operation at a valve up the hole. The resulting fluid level in the annulus will be below the actual point of operation. 4.5.3 Tagging Fluid Level: Tagging the fluid level in a well with wireline tools can sometimes give an estimation of the operating valve subject to several limitations. Fluid feedin will often raise the fluid level before the wireline tools can be deployed down the hole. In addition, fluid fallback will always occur after the lift gas has been shut off. Both of these factors will cause the observed fluid level to be above the operating valve. Care should be taken to ensure that the input gas valve was closed before closing the wing valve, or the gas  pressure will drive the fluid back down the ole and below the point of operation. This is certainly a questionable method. 4.5.4 Two Pen Recorder:

Fig. 4.4 - Two Pen Recorder Installed on Well Head

4.5.5. Flowing Pressure Survey In this type of survey, an electronic pressure gauge or bomb is run in the well under flowing conditions. These recording instruments can also measure temperature, and both ambient and “quick -response” models are available.Under flowing conditions, a no-blow tool is run with the tools, which prevents the tools from being blown up the hole. The no-blow tool is equipped with dogs, or slips, that are activated by sudden movements up the hole. The bomb is stopped at each gas-lift valve for a period of time,

42

recording the pressures at each valve. From this information, the exact point of operation can  be determined, as well as the actual flowing bottomhole pressure (BHP). This type of survey is the most accurate way to determine the performance of a gas-lift well, provided that an accurate well test is run in conjunction with the survey. The following procedure explains the  process in detail. Procedure for Running a Flowing BHP Test When the Well Is Equipped with Gas-Lift Valves a. Continuous-Flow Wells

1. Install a crown valve on the well, if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate normal  production facilities as nearly as possible. 2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. A gas and fluid test, two-pen recorder chart, and separator chart should be sent in with the pressure traverse. 3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a smalldiameter bomb. 4. Install a lubricator and pressure-recording bomb. Make the first stop in the lubricator to record wellhead pressure. Run the bomb, making stops 15 ft below each gas-lift valve for 3 minutes. Do not shut in the well while rigging up or recording flowing pressures in tubing. 5. Leave the bomb on bottom for at least 30 minutes, preferably at the same depth that the last static BHP was taken. 6. The casing pressure should be taken with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder. b. Intermittent-Flow Wells

1. Install a crown valve on the well if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate, as nearly as  possible, normal production facilities. 2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Test information, two-pen recorder charts, and separator chart should be sent in with the pressure traverse.

43

3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a smalldiameter bomb. 4. Install a lubricator and pressure recording bomb. Let the well cycle one time with the bomb,  just below the lubricator, to record the wellhead pressure and to ensure that the no-blow tools are working. Rub the bomb, making stops 15 ft below each gas-lift valve. Be sure to record a maximum and minimum pressure at each gas-lift valve. Do not shut in the well while rigging up or recording flowing pressures in the tubing. 5. Leave the bomb on bottom for at least two complete intermitting cycles. 6. High and low tubing and casing pressures should be checked with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder. Where to Install a Two-Pen Recorder Connect Casing Pen Line • At the well, not at compressor or gas distribution header. • Downstream of input choke so that the true surface casing pressure is recorded. Connect Tubing Pen Line • At the well, not the battery, separator, or production header. • Upstream of choke body or other restrictions. Even with no choke bean,a less-than-full opening found in most of the chokes.

44

5. GAS LIFT OPTIMIZATION: Under-Performing / Sub-Optimal Wells: A well is said to be under performing when

Operating at shallower depths than at desired deeper depths



Wells with insufficient Injection gas



Wells with more Injection gas



Leaking gas lift valves



Tubing leaks



Multi porting

5.1. Production Optimization by Gas lift (Case Studies) Scope: The following is the scope of the work 

Analysis of self and continuous Gas lift wells



Sensitivity analysis at reduced tubing head pressure(THP)



Sensitivity analysis at increased injection gas rate



Quantify liquid gain

Basis of Study: 

Flowing Bottom hole Studies data and corresponding production rates.



Reservoir pressure, PVT and well completion data as given.



Input data as given and considered for well modelling and analysis is placed in Table given below

Methodology: Well modelling and analysis has been done using ‘Prosper Software’ 

Actual pressure gradients and corresponding liquid rate, water cut, THP, and GOR have  been used to determine the matching flow correlations.

45





Flowing bottom hole pressure (FBHP) calculated with matching flow correlation is used to plot IPR and outflow curves for the wells. Sensitivity analysis of the wells is carried out for the wells for different ga s injection rates and THPs to arrive at envisaged oil/liquid gains.

CASE-1: Wells with insufficient Injection gas Implications 

Loss of production due to not producing the well to its potential

Indicators 

Higher rates vis –  a –  vis higher gas injection rates

Detection 

By Sensitivity Analysis ( Gas in – Liquid out curve )

A. Case Study: Well : ABCD#5 Input Data : (i) PVT Properties: Sand

Bassein

Reservoir Temperature

104.44 Deg C

Bubble point ( Pb )

123.372 Kg/cm

Solution GOR (R s)

45.4 v/v

Oil API

39

(ii) Production Data: Test Date

Liq. Rate

Water cut

Gas inj rate

07.06.2013

1091.547 STB/day

80%

27,801 M /d

GLV depths (m) t

Port sizes: (1/64 inch):

665.27, 1357.01, 1814.02, 2060.67 (C.V) 12,12,16,20

46

(iii) Reservoir Data 2,337.00-2529 M

Perforation: Reservoir pressure

1083.83 psig at 1512.48 m TVD. (September’13)

FBHP

60.79 Kg/cm a at 2077.74 m MD. (07.06.13)

Reservoir Temp.

102.03 Deg C at 2077.74 m MD. (07.06.13)

* Current Res. pressure of 1083.83 psiga 1821.65 m MD has been considered for the model.

Analysis: 

th

From FG data of 08  June 2013 and other production parameters, the AOFP of the well is estimated at 3476.0 STB/day with PI of 4.62 STB/day/psi.



Gas injection observed to be through CV at 2060.67 m.



The following correlations were used for VLP-IPR matching Tubing Correlation: Petroleum Experts 2 Pipe Correlation:

Beggs & Brill

Fig: 5.1. IPR plot

47

Fig: 5.2. IPR plot: VLP-IPR matching for the well ABCD#1 

It has been observed from simulation that production increases with increase in gas injection rate as shown in the Table & Fig below: Inj gas rate in 3 M /day

Qliq STB/day

Qoil STB/day

10,000

827.0

165.4

20,000

1037.3

207.5

27,801

1089.8

218.0

30,000

1100

220.1

35,000

1120.9

224.2

40,000

1136.0

227.2

45,000

1147.0

229.4

60,000

1163.2

232.6

48

Fig: 5.3. Sensitivity Plot

Recommendation: 3



3

It is suggested to increase gas injection rate from 27,801 M /day to 40,000 M /day to enhance liquid production from 1089.8 STB/day to 1136.0 STB/day.

Envisaged liquid gain : 46.2 STB/day. Envisaged oil gain

: 9.2 STB/day.

CASE-2: Wells with injection gas more than required Implications 

Wastage of high pressure gas

Loss of production not only from the individual well, but also from Inter-connected / other wells flowing to the same platform. 

Indicators 

 No distinctive indicators for minor quantities.

However, characterized by 

Drop in production



Higher THPs

49

Detection: 

By Sensitivity Analysis ( Gas in – Liquid out curve )

A. Case Study: Well : LMNO#1 Input Data : (i) PVT Properties: Sand

Muktabasin

Reservoir Temperature

104.444 Deg C

Bubble point ( Pb )

124.427 Kg/cm

Solution GOR (R s)

111 v/v

Oil API

36.1

(ii) Production Data: Test Date

Liq. Rate

Water cut

Gas inj rate

17/12/2013

485.245 STB/day

64%

51,365 M /d

842.0732, 1419.20, 1639.329, 1820.732 (C.V)

GLV depths (m) t

12,12,16,24

Port sizes: (1/64 inch):

(iii)Reservoir Data: Reservoir pressure

60.0984 Kg/cm a at 1422.67m TVD (August’13)

FBHP

32.479 Kg/cm a at 1835.37 m MD. (15.08.13).

Reservoir Temp.

97.88 Deg C at 1835.37 m MD. (15.08.13). 2

* Current Res. pressure of 60.0984 Kg/cm a 1835.37 m MD has been considered for the model.

Analysis: th

From FG data of 17 December’13 and other production parameters, the AOFP of the well is estimated at 731.2 STB/day with PI of 1.38 STB/day/psi

50

Fig: 5.4. IPR Plot





Gas injection observed to be through CV at 1820.732 m. It has been observed from simulation that production of the well has not been optimized. We are injecting more gas than required. This pro duction is yielded even with a lesser injection of gas as shown in the VLP-IPR matching graph, the well is producing far from its optimum production point.



The following correlations were used for VLP-IPR matching Tubing Correlation: Beggs & Brill Pipe Correlation:

Beggs & Brill

Fig: 5.5 VLP-IPR curve as per on 17/12/13

51



Production data with various gas injection rates for total GOR 344.378 and Water Cut of 64%

Inj gas rate in M3/day

Qliq STB/day

Qoil STB/day

10,000

458.7

166.51

20,000

503.5

181.2

25,000

511.3

184.1

30,000

513.6

184.9

35,000

511.5

184.2

40,000

506.1

182.2

50,000

486.2

175.0

51,365

482.7

173.8

60,000

456.7

164.9

Fig: 5.6: Sensitivity Plot

Recommendation: 

3

3

It is suggested to decrease gas injection rate from 51,365 M /day to 25,000 M /day to enhance liquid production from 511.3 STB/day to 482.7 STB/day.

52



The lesser gas injections produces more liquid and also the excessive gas can be used in other wells and reduces our pumping requirements.

Envisaged liquid gain : 28.6 STB/day. Envisaged oil gain

: 10.3 STB/day.

CASE-3: Leaking gas lift valves Implications: Leaking upper valve/s 

Deprive operating valve of desired injection gas resulting in loss of production.



Pose problems in valve shifting to lower valves making completion ineffective



May necessitate re-completion by WOR ( onshore )

Indicators: 

Low Surface Operating Pressure ( Pso / GIP )



Increase in Injection Gas & Total Gas quantities / Increased GLR



Loss in production



Drop in system pressure

Detection: 

By P&T survey

A. Case Study: Well:-C#1 Input Data : (i) PVT Properties: Sand

Bassein

Reservoir Temperature

104.44 Deg C

Bubble point ( Pb )

123.372 Kg/cm2

Solution GOR (R s)

58.27 v/v

Oil API

39

53

(ii) Production Data: Test Date

Liq. Rate

Water cut

Gas inj rate

28.10.2013

1647.833 STB/day

90%

21,744 M /d

GLV depths (m)

t

Port sizes: (1/64 inch):

623.47,1069.512,1402.744,1644.817,1799.39 (C.V) 12,12,16,20,24

(iii) Reservoir Data Perforation:

1951 - 2314 M ; 1981 - 2216 M

Reservoir pressure

97.8987 Kg/cm a at 1475.95 m TVD.(August’13)

FBHP

79.72 Kg/cm a at 1821.65 m MD. (15.08.13).

Reservoir Temp.

102.03 Deg C at 1821.65 m MD. (15.08.13).

2

* Current Res. pressure of 97.8987 Kg/cm a 1821.65 m MD has been considered for the model.

Analysis: 

From FG data of 28th October’13 and other production parameters, the AOFP of the well is estimated at 6581.2 STB/day with PI of 5.76 STB/day/psi

Fig: 5.7 IPR Plot

54



Gas injection observed to be through 3

rd

GLV at 1402.744 m whereas with the available

gas injection pressure and other production parameters, it should have been through CV at 1644.817 m. 

Quicklook analysis as shown in Fig. below co nfirms the possibility of gas injection through CV at 1644.817 m.

Fig: 5.8 Quicklook  rd



It seems that 3  GLV at 1402.744 m is malfunctioning and stuck open.



The following correlations were used for VLP-IPR matching Tubing Correlation: Beggs & Brill Pipe Correlation:

Beggs & Brill

Fig: 5.9 VLP/IPR curve for the latest production data

55



rd

Liquid production can be enhanced considerably by shifting gas injection point from 3

GLV at 1402.744 M to CV at 1644.817 M as shown in the plot and in the Table.1 given  below:

Depth of Injection 3

Inj gas Rate in M /day

1402.744 M

1644.817 M

Qliq

Qoil STB/day

Qliq

STB/day

STB/day

Qoil STB/day

15,000

1573.6

125.9

1807.1

144.6

21744

1693.4

135.5

1999.8

160.0

30,000

1761.6

140.9

2105.5

168.4

40,000

1817.3

145.4

2163.6

173.1

45,000

1838.0

147.0

2184.1

174.7

60,000

1880.8

150.5

2225.6

178.1

Fig: 5.10. Sensitivity Plot

56

Recommendation: 

It is suggested to attempt to arrest leakage/passing (GLV) by rocking the well, otherwise the damaged GLV to be replaced at the earliest.



Liquid production can be enhanced from 1693.4 STB/day to 1999.8 STB/day with change 3

of gas injection point to CV with injection gas of 21,744 M /day. Envisaged liquid gain : 304 STB/da Envisaged oil gain

: 24.5 STB/day

CASE-4: Wells producing optimally Implications wells are producing at the optimum rates they can





 No loss of either production or gas due to less or excessive injection of gas.

Indicators 

 No distinctive indicators for minor quantities.

Detection: 

By Sensitivity Analysis ( Gas in – Liquid out curve )

Case Study:

Well: ABCD#1

Input Data : (i) PVT Properties: Sand

Bassein

Reservoir Temperature

104.44 Deg C

Bubble point ( Pb )

123.376 Kg/cm

Solution GOR (R s)

84.8 v/v

Oil API

39

(ii) Production Data:

57

Test Date

Liq. Rate

Water cut

30.10.2013

611 STB/day 73%

Gas inj rate

37493 M /d

741,1248,1559,1732 (C.V)

GLV depths (m) t

Port sizes: (1/64 inch):

12, 16, 20, 24

(iii)Reservoir Data: Perforation:

2231.5-2482 M

Reservoir pressure

102.282 Kg/cm a at 1503.4 m TVD.(Jan’13)

FBHP

58.822 Kg/cm a at 2195.12 m MD. (11.09.2012).

Reservoir Temp.

102.79 Deg C at 2195.12 m MD. (08.01.13). 2

* Current Res. pressure of 102.282 Kg/cm a at 2195.12 m MD has been considered for the model. Analysis: 

th

From FG data of 8 January’13 and other production parameters, the AOFP of the well is estimated at 1009.1 STB/day with PI of 1.06 STB/day/psi.

Fig: 5.11. IPR 

Gas injection observed to be through CV at 2164.94 m.

58



The following correlations were used for VLP-IPR matching Tubing Correlation: Beggs & Brill Pipe Correlation:

Beggs & Brill

\ Fig:5.12 VLP/IPR curve for the latest production data 

It is observed that production increases with increase in gas injection rate bu t not 3

significantly high. Maximum gas can be injected upto 60,000 M /day as shown in the in Table 1 and Fig. 1.1, beyond which production reduces because of additional frictional component. M3/day

Qliq STB/day

Qoil STB/day

15,000

463.6

125.2

20,000

523.5

141.3

30,000

588.6

158.9

35,000

605.3

163.4

37,493

611.2

165.0

40,000

615.8

166.3

50,000

627.1

169.3

60,000

626.3

169.1

Inj gas rate in

59

Fig: 5.13 Sensitivity Plot

Recommendation: 

It is suggested to continue with the present parameters.

Well: ABCD#5 Input Data : (i) PVT Properties: Sand

Bassein

Reservoir Temperature

104.44 Deg C

Bubble point ( P b )

123.372 Kg/cm2

Solution GOR (R s)

45.4 v/v

Oil API

39

(ii) Production Data: Test Date

07.06.2013

Liq. Rate

1091.547 STB/day

Water cut

80%

Gas inj rate

27,801 M3/d

GLV depths (m)

665.27, 1357.01, 1814.02, 2060.67 ( C.V)

Port sizes: (1/64th inch):

12,12,16,20

60

(iii)Reservoir Data Perforation:

2,337.00-2529 M

Reservoir pressure

1083.83 psig at 1512.48 m TVD. (September’13)

FBHP

60.79 Kg/cm Kg/cm a at 2077.74 m MD. MD. (07.06.13) (07.06.13)

Reservoir Temp.

102.03 Deg C at 2077.74 m MD. (07.06.13)

* Current Res. pressure of 1083.83 psig a 1821.65 m MD has been considered for the model.

Analysis: 

From FG data of 08 th  June 2013 and other production parameters, the AOFP of the well is estimated at 3476.0 STB/day with PI of 4.62 STB/day/psi.



Fig: 5.14 IPR Plot 





Gas injection observed to be through CV at 2060.67 m. The VLP/IPR graph shows that the well is producing at optimum rates and hence do not need any further change in the gas injection rates, which would increase our production cost without any significant add up in liquid production. The following correlations were used for VLP-IPR matching Tubing Correlation: Petroleum Experts 2 Pipe Correlation: Beggs & Brill

61

Fig: 5.15 IPR Plot 

It has been observed from simulation that production increases with increase in gas injection rate as shown in the Table & Figure below. Inj gas 3 M /day

rate

in

Qliq STB/day

Qoil STB/day

10,000

827.0

165.4

20,000

1037.3

207.5

27,801

1089.8

218.0

30,000

1100

220.1

35,000

1120.9

224.2

40,000

1136.0

227.2

45,000

1147.0

229.4

60,000

1163.2

232.6

Fig: 5.16 Sensitivity plot

62

Recommendation: 

It is suggested to continue with the present parameters.

CASE-5: Multi porting Implications: 

Deprive operating valve of desired injection gas resulting in loss of Production



Pose problems in valve shifting to lower valves making completion ineffective



May necessitate re-completion by WOR ( onshore )

Indicators: 

Low Surface Operating Pressure ( Pso / GIP )



Increase in Injection Gas & Total Gas quantities / Increased GLR



Loss in production



Drop in system pressure

Detection: 

By P&T survey

Case Study: Well E#1 WELL

KB

12.12

All depth from Kb.m.

7"L/H

7"L/S

General Information TYPE OF STUDY:

Flowing Gr.

Tubing

TVD

9 5/8"C/S

Date study

3-Feb-04

2,7/8

1530

2002

of

5"L/H

63

TEST DATA Date

02-Mar-04

15-Sep-02

FTHP(psi)

213

228

Psep(psig)

199

213

Tsep(oF)

118

129

Qliq.(blpd)

672

839

Qoil(bopd)

513

572

W/C(%)

23.6

31.8

Qgi(m3/d)

20868

24111

Qgt(m3/d)

29199

41488

GLR(m3/m3)

273

311

GOR(m3/m3)

102

191

GIP(psig)

996

868

Date of study  – Feb’04 Rate at time of study  –   672 blpd with Injection gas of 20,800 M3/d & Tot gas of 29,200 M3/d

Entry mainly through 2nd GLV ( 1130 mts ) though multipoint entry thro all valves is suspected , THP- 242 psig , water cut –  25 % Observation  –  By shifting to CV , production rate of 1000 blpd is expected with present injection gas of 21,000 M3/d for an oil gain of 200 bopd .

Fig: 5.17

64

Fig: 5.18 and Fig 5.19

CASE-6: Operating at shallower depths than at desired deeper depths Implications 

Loss of production

Indicators 

Higher Surface operating pressure ( Pso / GIP )



Drop in production

Detection 

By P&T study

65

Case Study: Well F#1 Date of study  –   May,2003 Rate at time of study  –  2228 blpd with Injection gas of 25,000 M3/d & Tot gas of 31,000 M3/d

Entry through GLV1 ( 601 mts ) , THP- 213 psi , W/cut- 89 % Observation   - Second GLV at 1161 Mts and CV at 1841 Mts. In present condition , it is difficult to shift to lower valves due to high tubing pressure due to high rate and water cut and tubing size of 2 7/8” . It may be possible to shift to second GLV by using a 7/16 inch port and  production may increase to around 2700 blpd , but may not result in much oil gain as water cut is already quite high. WELL

F#1

General Information

KB

16.64

All depth from Kb.m.

7"L/H

7"L/S

TYPE OF Flowing STUDY: Gr.

Tubing

TVD

9 5/8"C/S

Date study

1493

1530

2005

of

28-May03

TEST DATA Date

08-Jun-03

20-Sep-02

FTHP(psi)

213

242

Psep(psig)

199

228

Tsep(oF)

139

145

Qliq.(blpd)

2228

1633

Qoil(bopd)

254

150

W/C(%)

88.6

90.8

Qgi(m3/d)

25229

14692

Qgt(m3/d)

30877

31507

GLR(m3/m3)

87

121

GOR(m3/m3)

140

705

GIP(psig)

964

981

5"L/H

66

PART NO

DEPTH

PORT

PSO

PSC

TEMP

Qginj.

Qliq.

(Supplier)

mts.tvd.

(1/64")

psig.

psig.

0F

(m3/d)

(blpd)

GLV1

537

12

925

906

183

18805

656

GLV2

929

16

906

888

196

31776

1124

GLV3

1183

20

888

871

204

40753

1376

GLV4

1337

28

871

852

210

52591

1510

CV

1416

28

852

212

45001

1560

Fig: 5.20 Quick Analysis for the feasibility of injection through lower valves

Fig: 5.21 VLP/IPR Matching curve for the well ABCD#10

67

Figure:5.22 Sensitivity Analysis of production rates at different Injection depth with varying Gas-lift Injection Rates

68

7. Conclusion: Gas lift is a process of lifting fluids from a well by the continuous injection of high pressure gas to supplement the reservoir energy (continuous flow), or by injecting gas beneath an accumulated liquid slug for a short time to move the slug to surface(intermittent lift). The injected gas moves the fluid to surface by one or a combination of the following: reducing the fluid load pressure on the formation because of decreased fluid density, expansion of injected gas, and displacing the fluid. In addition to serving as a primary method of artificial lift, gas lift can also be used efficiently and effectively to accomplish the following objectives: 1. To enable wells that will not flow naturally to produce. 2. To increase production rates in flowing wells. 3. To unload a well that will later flow naturally. 4. To remove or unload fluids from gas wells and to keep the gas well unloaded(usually intermittent, but can be continuous). 5. To backflow saltwater disposal wells to remove sands and other solids that can plug the  perforations in the well. 6. In water source (aquifer) wells to produce the large volumes of water necessary for water flood applications. Although other types of artificial lift offer certain advantages, gas lift is suitable for almost every type of well to be placed on artificial lift. An added advantage to gas lift is its versatility .Once an installation is made, changes in design can be accomplished to reflect changes in well conditions. This is particularly true when wire line retrievable valves are u sed. From the simple domain of point injections to the designs of specialized gas lift systems, variation in design of gas lift valves, gas lift operations today are unique technological systems that govern various regimes stretching from shallow to deep wells, striper and water loaded gas wells to prolific producers, single completion to dual and combination lift applications.