Study of Gas Lift Methods [PDF]

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STUDY OF GAS LIFT METHODS



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TABLE OF CONTENTS Chapter 2 Artificial Lift Selection……………………………………………………….17 2.1. Introduction ………………………………………………………………………17 2.2.



Criteria



considered



for



selecting



Artificial



Lift



Technique……………………………………………………………………………….18 Chapter 3 Types of Artificial Lift………………………………………………………...24 3.1Pump Types…………………………………………………………………………24 3.2Gas Method………………………………………………………………………….24 3.1.1Beam Pumping/Sucker Rod Pumps (Rod Lift)……………………………...24 3.1.2Progressing Cavity Pumps (PCP Pumps)……………………………………25 3.1.3Subsurface Hydraulic Pumps…………………………………………………27 3.1.4Electric Submersible Pumps (ESPs)…………………………………………..28 3.2.1Gas Lift………………………………………………………………………….30 Chapter 4 Gas Lift Methods………………………………………………………................31 4.1. Definitions of Gas Lift Methods……………………………………………………31 4.2. History of Gas Lift Methods…………………………………………………………31 4.3. Principle………………………………………………………………………………..32 4.4. Gas Lift Systems……………………………………………………………………….33 4.5 Types of Gas Lift Installations………………………………………………………..36 4.6. Operation………………………………………………………………………………38 4.7. Unloading sequence……………………………………………………………………41 4.8. Gas Lift Valves and their Mechanism ……………………………………………….43 4.9. Types of Gas Lift Valves ……………………………………………………………..47 4.9.1. Pressure Valve …………………………………………………………………48 4.9.2. Fluid-Operated Valve …………………………………………………………48 2



4.9.3. Combination Valves …………………………………………………………...48 4.10.Advantages ……………………………………………………………………………49 4.11. Limitations ……………………………………………………………………………50 References……………………………………………………………………………………….52



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LIST OF TABLES Table2.1 Suitable prime mover types for different artificial lift techniques………………20 Table 2.2 presents range of operating parameters for different artificial lift techniques…23



LIST OF FIGURES



Figure A Location Map CB/OS-2 with Area Breakdown……………………………………12 Figure B Onshore Suvali Terminal……………………………………………………………13 Figure C Plant Process Flow-Diagram……………………………………………………….14 Figure 2.1.Suitable production rates for different artificial lift techniques……………….18 Figure 2.2. Energy efficiencies of different artificial lift techniques……………………….21 Figure 3.3 Sucker Rod Pump…………………………………………………………………25 Figure 3.4. Progressing Cavity Pumps…………………………………………………….....26 Figure 3.5 Hydraulic Pumps……………………………………………………………….....28 Figure 3.6 Electric Submersible Pumps…………………………………………………….29 Figure 3.7 Gas Lift System…………………………………………………………………...30 Figure 4.8 Gas Lift well configuration……………………………………………………....33 Figure 4.9 Gas Lift System schematic for Onshore Plant ………………………………….35 Figure 4.10 Types of gas lift installations……………………………………………………38 Figure 4.11 Continuous Gas Lift…………………………………………………………….39 Figure 4.12 Intermittent Gas Lift…………………………………………………………..40 Figure 4.13 Unloading sequence…………………………………………………………….42 Figure 4.14 Elements of pressure regulator and a gas lift valve…………………………..43



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CHAPTER 2 ARTIFICIAL LIFT SELECTION



2.1. INTRODUCTION The most important problem is how to select optimum artificial lift techniques taking into consideration reservoir, well, environmental conditions. Also economic implications are important (such as investment, work over costs).



The main objective is select an artificial lift method to increase the chances of maximizing profit under safe operational conditions (for humans and for the environment).



The artificial lift techniques need also to be flexible enough to cope with the expected changes of production conditions and reservoir performance. Sometimes more than one method is selected to be used in a well or in a field at different phases of development.



The proper selection of artificial lift system depends on several other disciplines such as drilling, completion, reservoir management, production layout, flow assurance and automation.



The selection should be strictly technical and economical. The objective is to maximize the expected profit through an intelligent management of operational and investment costs. A well designed system will balance costs, production and reliability under the various physical, economical, safety, environmental, human and technical constraints.



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2.2. CRITERIA CONSIDERED FOR SELECTING ARTIFICIAL LIFT TECHNIQUE IPR: A well’s inflow performance relationship defines its production potential Liquid production rate: The anticipated production rate is a controlling factor in selecting a lift method; positive displacement pumps are generally limited to rates of 4000-6000 B/D. Figure 2.1 shows suitable production rates for different artificial lift techniques.



Figure 2.3Suitable production rates for different artificial lift techniques



Water cut: High water cuts require a lift method that can move large volumes of fluid Gas-liquid ratio: A high GLR generally lowers the efficiency of pump-assisted lift Viscosity: Viscosities less than 10 cp are generally not a factor in selecting a lift method; high viscosity fluids can cause difficulty, particularly in sucker rod pumping 7



Formation volume factor: Ratio of reservoir volume to surface volume determines how much total fluid must be lifted to achieve the desired surface production rate. Reservoir drive mechanism: Depletion drive reservoirs: Late-stage production may require pumping to produce low fluid volumes or injected water. Water drive reservoirs: High water cuts may cause problems for lifting systems Gas cap drive reservoirs: Increasing gas-liquid ratios may affect lift efficiency. Well depth: The well depth dictates how much surface energy is needed to move fluids to surface, and may place limits on sucker rods and other equipment. Completion type: Completion and perforation skin factors affect inflow performance. Casing and tubing sizes: Small-diameter casing limits the production tubing size and constrains multiple options. Small-diameter tubing will limit production rates, but larger tubing may allow excessive fluid fallback. Wellbore deviation: Highly deviated wells may limit applications of beam pumping or PCP systems because of drag, compressive forces and potential for rod and tubing wear. Flow rates: Flow rates are governed by wellhead pressures and backpressures in surface production equipment (i.e., separators, chokes and flow lines). Fluid contaminants: Paraffin or salt can increase the backpressure on a well. Power sources: The availability of electricity or natural gas governs the type of artificial lift selected. Diesel, propane or other sources may also be considered.



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Table 2.1 Suitable prime mover types for different artificial lift techniques



Energy Efficiency: Energy efficiency also affects the selection of artificial lift. Figure 2.2 depicts a comparison of the energy efficiencies of different artificial lift techniques.



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Figure 2.4 Energy efficiencies of different artificial lift techniques



Field location: In offshore fields, the availability of platform space and placement of directional wells are primary considerations. In onshore fields, such factors as noise limits, safety, environmental, pollution concerns, surface access and well spacing must be considered. Long-range recovery plans: Field conditions may change over time. Pressure maintenance operations: Water or gas injection may change the artificial lift requirements for a field.



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Enhanced oil recovery projects: EOR processes may change fluid properties and require changes in the artificial lift system. Field automation: If the surface control equipment will be electrically powered, an electrically powered artificial lift system should be considered. Availability of operating and service personnel and support services: Some artificial lift systems are relatively low-maintenance; others require regular monitoring and adjustment. Servicing requirements (e.g., workover rig versus wire line unit) should be considered. Familiarity of field personnel with equipment should also be taken into account. Economic Analysis: After designing the appropriate candidates, a final realistic economic analysis will indicate the “best” choices. The economic analysis requires investment costs and salvage values, operational costs, artificial lift system horsepower consumption, production forecast, estimate of failure rate for the expected operating conditions, estimated cost and duration time of repairs. The best possible artificial lift system is selected after taking into account, the above mentioned parameters. Selection of poor technique could result with decrease in efficiency and low profitability. As a result, it will lead to high operating expenses. Several techniques have been developed for selection of optimum artificial lift techniques. For example, OPUS (optimal pumping unit search) firstly was introduced by Valentine et al. (1988) for selection of optimum artificial lift techniques. The advantage of such computer based programs like OPUS is that these programs take into consideration technical and financial issues of each artificial lift technique.



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Table 2.2 presents range of operating parameters for different artificial lift techniques.



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CHAPTER 3 TYPES OF ARTIFICIAL LIFT



TYPES OF ARTIFICIAL LIFT



Artificial-lift methods fall into two groups, those that use pumps and those that use gas.



3.1. Pump Types  Beam Pumping / Sucker Rod Pumps (Rod Lift)  Progressive Cavity Pumps  Subsurface Hydraulic Pumps  Electric Submersible Pumps 3.2. Gas Method  Gas Lift Each of these methods will be discussed below: 3.1.1. Beam Pumping/Sucker Rod Pumps (Rod Lift) This type of artificial lift utilizes a positive displacement pump that is inserted or set in the tubing near the bottom of the well. The pump plunger is connected to surface by a long rod string, called sucker rods, and operated bya beam unit at surface. Each upstroke of the beam unit lifts the oil above the pump’s plunger.



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Figure 3.3 Sucker Rod Pump



3.1.2. Progressing Cavity Pumps (PCP Pumps)



Progressing Cavity Pumps (PCP) are also widely applied in the oil industry. The PCP consists of a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The rotation created sequential cavities and the produced fluids are pushed to surface. The PCP is a flexible system with a wide range of applications in terms of rate (up to 5,000 bbl/d (790 m3/d) and 6,000 ft (1,800 m)). They offer outstanding resistance to abrasives and solids but they are



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restricted to setting depths and temperatures. Some components of the produced fluids like aromatics can also deteriorate the stator’s elastomer.



Figure 3.4. Progressing Cavity Pumps



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3.1.3. Subsurface Hydraulic Pumps



Hydraulic Lift Systems consist of a surface power fluid system, a prime mover surface pump, and a downhole jet or reciprocating/piston pump. In the operation of a hydraulic lift system, crude oil or water (power fluid) is taken from a storage tank and fed to the surface pump. The power fluid, now under pressure built up by the surface pump, is controlled by valves at a control station and distributed to one or more wellheads. The power fluid passes through the wellhead valve and is directed to the downhole pump. In a piston pump installation, power fluid actuates the engine, which in turn drives the pump, and power fluid returns to the surface with the produced oil, is separated, and is piped to the storage tank. A jet pump has no moving parts and employs the Venturi principle to use fluid under pressure to bring oil to the surface.



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Figure 3.5 Hydraulic Pumps



3.1.4. Electric Submersible Pumps (ESPs)



Electric Submersible Pumping (ESP) Systems incorporate an electric motor and centrifugal pump unit run on a production string and connected back to the surface control mechanism and transformer via an electric power cable. The downhole components are suspended from the production tubing above the wells' perforations. In most cases the motor is located on the bottom of the work string. Above the motor is the seal section, the intake or gas separator, and the pump. The power cable is banded to the tubing and plugs into the top of the motor. As the fluid comes



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into the well it must pass by the motor and into the pump. This fluid flow past the motor aids in the cooling of the motor. The fluid then enters the intake and is taken into the pump. Each stage (impeller/diffuser combination) adds pressure or head to the fluid at a given rate. The fluid will build up enough pressure as it reaches the top of the pump to lift it to the surface and into the separator or flowline. Electric submersible pumps are normally used in high volume (over 1,000 BPD) applications.



Figure 3.6 Electric Submersible Pumps



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3.2.1. Gas Lift



In a typical gas lift system, compressed gas is injected through gas lift mandrels and valves into the production string. The injected gas lowers the hydrostatic pressure in the production string to reestablish the required pressure differential between the reservoir and wellbore, thus causing the formation fluids to flow to the surface. Essentially, the liquids are lightened by the gas which allows the reservoir pressure to force the fluids to surface. A source of gas, and compression equipment is required for gas lift. Proper installation and compatibility of gas lift equipment, both on the surface and in the wellbore, are essential to any gas lift system.



Figure 3.7 Gas Lift System



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CHAPTER 4 GAS LIFT METHODS



4.1.Definitions of Gas Lift Methods



A continuous lift gas lift installation is one where compressed high pressure gas is injected continuously at the surface into the gas injection conduit and then continuously downhole into the production fluid conduit.



4.2. History of Gas Lift Methods



Gas lifting of water with a small amount of oil used in the United States as early as 1846. Compressed air is known to have been used earlier to lift water. In fact, it has been reported that compressed air was used to lift water from wells in Germany as early as the eighteenth century. These early systems operated in a very simple manner by the introduction of air down the tubing and up the casing. Aeration of the fluid in the casing tubing annulus decreased the weight of the fluid column so that fluid would rise to the surface and flow out of the well. The process was sometimes reversed by injecting down the casing and producing through the tubing. Air lift continued in use for lifting oil from wells by many operators, but it was not until the mid-1920's that gas for lifting fluid became more widely available. Gas, being lighter than air, gave better performance than air, lessened the hazards created by air when exposed to combustible materials and decreased equipment deterioration caused by oxidation. During the 1930's, several types of gas lift valves became available to the oil producing industry for gas lifting oil wells. Gas lift was



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soon accepted as a competitive method of production, especially when gas at adequate pressures was available for lift purposes. 4.3. Principle 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 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.



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4.4. Gas Lift Systems 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.



Figure 4.8depicts a configuration of a gas-lifted well with installations of unloading valves and operating valve on the tubing string.



Figure 4.8Gas Lift well configuration



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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.



Figure 4.9illustrates schematic of a gas lift system. For proper selection, installation, and operations of gas lift systems, the operator must know the equipment and the fundamentals of gas lift technology. The basic equipment for gas lift technology includes the following: a. Main operating valves b. Wire-line adaptations c. Check valves d. Mandrels e. Surface control equipment f. Compressors



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Figure 4.9 Gas Lift System schematic for Onshore Plant



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4.5 Types of Gas Lift Installations: Different types of gas lift installations are used in the industry depending on well conditions. They fall into four categories: A. Open installation, B. Semi-closed installation, C. Closed installation, and D. Chamber installation. As shown in Fig. 4.10(a), no packer is set in open installations. This type of installation is suitable for continuous flow gas lift in wells with good fluid seal. Although this type of installation is simple, it exposes all gas lift valves beneath the point of gas injection to severe fluid erosion due to the dynamic changing of liquid level in the annulus. Open installation is not recommended unless setting packer is not an option.



Figure 4.10(b) demonstrates a semi-closed installation. It is identical to the open installation except that a packer is set between the tubing and casing. This type of installation can be used for both continuous- and intermittent-flow gas lift operations. It avoids all the problems associated with the open installations. However, it still does not prevent flow of well fluids back to formation during unloading processes, which is especially important for intermittent operating.



Illustrated in Fig. 4.10(c) is a closed installation where a standing valve is placed in the tubing string or below the bottom gas lift valve. The standing valve effectively prevents the gas pressure



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from acting on the formation, which increases the daily production rate from a well of the intermittent type.



Chamber installations are used for accumulating liquid volume at bottom hole of intermittentflow gas lift wells. A chamber is an ideal installation for a low BHP and high PI well. The chambers can be configured in various ways including using two packers, insert chamber, and reverse flow chamber.



A standard two-packer chamber is installed to ensure a large storage volume of liquids with a minimum amount of backpressure on the formation so that the liquid production rate is not hindered.



An insert chamber is normally used in a long open hole or perforated interval where squeezing of fluids back to formation by gas pressure is a concern. It takes the advantage of existing bottomhole pressure. The disadvantage of the installation is that the chamber size is limited by casing diameter. A reverse flow chamber ensures venting of all formation gas into the tubing string to empty the chamber for liquid accumulation. For wells with high formation GLR, this option appears to be an excellent choice.



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Figure 4.10 Types of gas lift installations



4.6. Operation:



Gas Lift Systems are broadly of two types: Continuous and Intermittent. 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 i.e. gas is injected in batches which follows a time-cycle. This is unsteady state flow.



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Figure 4.11 Continuous Gas Lift



In continuous gas lift (shown in figure 4.11), 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 ( 0.5stb/day/psi) and a reasonably high reservoir pressure relative to well depth. Intermittent gas lift method (shown in figure 4.12) is suitable to wells with (1) high PI and low reservoir pressure or (2) low PI and low reservoir pressure. The time cycle surface controller regulates the start-and-stop injection of lift gas to the well. Here, initially the liquid slug that has 28



accumulated. When gas lift valve opens, high-pressure injection gas enters the tubing and rapidly expands. This action forces the liquid slug (shaded in figure 4.12) from the tubing.



Figure 4.12 Intermittent Gas Lift



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 high instantaneous BHP drawdown encountered with intermittent flow would cause excessive sand production, or coning, and/or gas into the wellbore.



4.7. Unloading sequence: 29



Figure 4.13shows a well unloading process. Usually all valves are open at the initial condition, as depicted in Fig. 4.13a, due to high tubing pressures. The fluid in tubing has a pressure gradient Gs of static liquid column. When the gas enters the first (top) valve as shown in Fig. 4.13b, it creates a slug of liquid–gas mixture of less density in the tubing above the valve depth. Expansion of the slug pushes the liquid column above it to flow to the surface. It can also cause the liquid in the bottom hole to flow back to reservoir if no check valve is installed at the end of the tubing string. However, as the length of the light slug grows due to gas injection, the bottomhole pressure will eventually decrease to below reservoir pressure, which causes inflow of reservoir fluid.



When the tubing pressure at the depth of the first valve is low enough, the first valve should begin to close and the gas should be forced to the second valve as shown in Fig. 4.13c. Gas injection to the second valve will gasify the liquid in the tubing between the first and the second valve. This will further reduce bottom-hole pressure and cause more inflow. By the time the slug reaches the depth of the first valve, the first valve should be closed, allowing more gas to be injected to the second valve. The same process should occur until the gas enters the main valve (Fig. 4.13d). The main valve (sometimes called the master valve or operating valve) is usually the lower most valve in the tubing string. It is an orifice type of valve that never closes. In continuous gas lift operations, once the well is fully unloaded and a steady-state flow is established, the main valve is the only valve open and in operation (Fig. 5.29e).



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Figure 4.13 Unloading sequence



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4.8. Gas Lift Valves and their Mechanism The heart of any gas lift system is the gas lift valve. Gas lift valves are basically downhole pressure regulator. The functional elements of a pressure regulator and a gas lift valve are similar. A spring (Fig-4.14A), as in the gas lift valve (Fig-4.15B), forces the stem tip against the seat.



Figure 4.14 Elements of pressure regulator and a gas lift valve



The diaphragm of the pressure regulator and the bellows of the gas lift valve provide an area of influence for the upstream pressure greater than the port area. The force that results from this combination of upstream pressure and diaphragm or bellows area acts in a direction to overcome



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the force of the spring. When this force of pressure times area exceeds the force of the spring, the stem tip moves away from the seat, opening the valve. Both the pressure regulator and the gas lift valve illustrated are controlling the upstream pressure. The regulator upstream pressure is a function of spring force and effective diaphragm or bellows area. Practically all gas lift valves use the effect of pressure acting on the area of a valve element (bellows, stem tips, etc) to cause the desired valve action. Knowledge of pressure, force, and area is required to understand the operation of most gas lift valves.



Because the opening and closing characteristics of the various valves in our gas lift system are so important to their operation, we should understand how and when a valve will open, when it will close, and what the difference in these two pressures, referred to as spread, really means.



We would like to calculate the opening and closing pressures. To do this, we must write a forcebalance equation for the valve. Closing Force: Most gas lift valves have gas pressure (Pb) trapped in the dome. This pressure acts on the area of the bellows and create a force ( Fc ) that is applied to the stem. The stem tip is forced into contact with the upper edge (seat) of the port. The stem tip and seat portion of the port are finely matched (often lapped) to form a seal. When the dome pressure (Pb) and bellows area (Ab) are known, the force holding the stem tip against the seat is: Fc = Pb*Ab …………………………..……………………………………………………..(5.1) Fc = Closing Force. Pc = Pressure inside the dome space sealed by the bellows and valve housing 33



Ab = Area of the bellows. Opening Forces: A valve starts to open when the stem tip moves out of contact with the valve seat. This occurs when the opening force is slightly greater than the closing force, therefore, just before opening (Fo=Fc). Two forces usually work together to overcome the closing force (Fc). Pressure (P1) applied through the side opening and pressure (P2) applied through the valve port are the pressure sources to produce the two opening forces. When the stem tip is seated on the port, P1 does not act on the entire bellows area (Ab). The area of stem tip (Ap) in contact with the seat forms part of the bellows area (Ab). Ap is isolated from P1 by the stem tip and seat. The area acted on by pressure (P1) is the bellows area minus the area of the stem tip isolated by the seat (Ab – Ap). The opening force resulting from pressure P1 applied through the side opening is: F1=P1*(Ab–Ap) …………………………………………………………………………….(5.2) The area of the stem tip in contact with the seat (Ap) is acted upon by pressure (P2) applied through the port. The opening force contributed by this combination is: F2 = P2*Ap …………………………………………………………………….......................(5.3) The total opening force is the sum of these two forces: Fo = F1 + F2 Or Fo= P1*(Ab – Ap) + P2*Ap …………………………………………………………………(5.4) Just before the valve port opens, the opening force and the closing force are equal Fo = Fc or 34



P1*(Ab – Ap) + P2*Ap = Pb*Ab ……………………………………………………………(5.5) Solving for P1(injection pressure required to balance opening and closing forces prior to opening an injection pressure operated valve under operative conditions): P1 = [Pb – P2*(Ap/Ab)] / 1 – (Ap/Ab)…………………………...…………..……………..(5.6) Or P1 = [Pb – P2*R] / 1 – R…………………………...…………..……………..........................(5.7) Where, R= Ap/Ab = Ratio of port area to bellows area. P1 is the pressure in contact with the valve bellows. P2 is the pressure in contact with the portion of the stem tip sealed by the seat (port). Ap is the area of the portion of the stem tip sealed by the seat. Abis the area of the bellows. F1 = Opening force resulting from P1 acting on the bellows area less than the port area F2 = Opening force resulting from P2 acting on the stem tip area in contact with the Seat (port) Fo = Total opening force. The pressure (P1) determined by this equation is the balance pressure. Actually the valve stem tip is still on seat and only slight leakage by the stem tip and seat may be observed. An increase in P1 or P2 will move the stem tip proportionally further from the seat and allow more gas passage. A decrease in P1 or P2 will load the stem tip harder against the seat and cause a tighter stem tip to seal. This is the case as the valve closes. The difference between the opening pressure and the closing pressure is the valve spread. Spread = opening pressure - closing pressure 35



We see that for given bellows and tubing pressures we may reduce the spread by reducing the area of the port opening. The spread is particularly important in intermittent gas lift installations, because it controls the volume of gas used in each cycle. As the pressure reduction, or spread, required to close the operating valve increases, the amount of gas injected during the cycle also increases. A small port size, though, increases horsepower requirements and, therefore, a balance must be struck between gas conservation and horsepower requirements.



4.9. Types of Gas Lift Valves There are different types of unloading valves, namely casing pressure-operated valve (usually called a pressure valve), throttling pressure valve (also called a proportional valve or continuous flow valve), fluid-operated valve (also called a fluid valve), and combination valve (also called a fluid open-pressure closed valve). Different gas lift design methods have been developed and used in the oil industry for applications of these valves.



4.9.1. Pressure Valve Pressure valves are further classified as unbalanced bellow valves, balanced pressure valves, and pilot valves. Tubing pressure affects the opening action of the unbalanced valves, but it does not affect the opening or closing of balanced valves. Pilot valves were developed for intermittent gas lift with large ports.



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4.9.2. Fluid-Operated Valve



The basic elements of a fluid-operated valve are identical to those in a pressure-operated valve except that tubing pressure now acts on the larger area of the bellows and casing pressure acts on the area of the port. This configuration makes the valve mostly sensitive to the tubing fluid pressure.



4.9.3. Combination Valves



A combination valve consists of two portions. The upper portion is essentially the same as that found in pressure-operated valves, and the lower portion is a fluid pilot, or a differential pressure device incorporating a stem and a spring. Holes in the pilot housing allow the casing pressure to act on the area of the stem at the upper end. The spring acts to hold the stem in the upward position. This is the open position for the pilot. The casing pressure acts to move the stem to the closed position. The fluid pilot will only open when tubing pressure acting on the pilot area is sufficient to overcome the casing pressure force and move the stem up to the open position. At the instant of opening, the pilot opens completely, providing instantaneous operation for intermittent lift.



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4.10. Advantages Advantages: 



Can produce high rates from high productivity wells



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Flexible, easy to change rate



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Can handle solids



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Easy to obtain downhole pressures and gradients



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Lifting gassy wells is no problem



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Crooked/deviated holes pose no problem



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Permits the concurrent use of wire line equipment, and such downhole equipment is easily and economically serviced.



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The normal gas-lift design leaves the tubing fully open. This permits the use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc.



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A central gas-lift system can be easily used to service many wells or operate an entire field which lowers total capital cost and permits easier well control and testing.



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Has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering.



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Well subsurface equipment is relatively inexpensive and their repair and maintenance expenses normally are low. Also, major well Workover occur infrequently.



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Installation of gas lift is compatible with subsurface safety valves and other surface equipment. The use of a surface-controlled subsurface safety valve with a 1/4-in. control line allows easy shut in of the well.



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Gas lift can still perform fairly well even when only poor data are available when the design is made. This is fortunate because the spacing design usually must be made before the well is completed and tested.



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4.11. Limitations



High initial investment 



Availability of lift gas



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Not feasible for marginal fields



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Gas hydrate problem



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Safety issues with high pressure gas



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Relatively high backpressure may seriously restrict production in continuous gas lift. This problem becomes more significant with increasing depths and declining static BHPs.



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Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%).



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Difficulty when lifting low gravity (less than 15°API) crude because of greater friction, gas fingering, and liquid fallback. Also, the cooling effect will compound any paraffin problem.



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Good data are required to make a good design. If not available, operations may have to continue with an inefficient design that does not produce the well to capacity. Potential gas-lift operational problems that must be resolved include:



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Freezing and hydrate problems in injection gas lines



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Corrosive injection gas



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Severe paraffin problems



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Fluctuating suction and discharge pressures



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Wireline problems Other problems that must be resolved are:



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Changing well conditions



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Especially declines in Bottom Hole Pressure (BHP) and productivity index (PI)



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Deep high-volume lift



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Valve interference (multipointing) Additionally, dual gas lift is difficult to operate and frequently results in poor lift efficiency. Emulsions forming in the tubing, which may be accelerated when gas enters opposing the tubing flow, also must be resolved.



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REFERENCES Paper in a Journal







Lea, J. F., & Nickens, H. V. (1999, January 1). Selection of Artificial Lift. Society of Petroleum Engineers. doi:10.2118/52157-MS







Neely, B., Gipson, F., Clegg, J., Capps, B., & Wilson, P. (1981, January 1). Selection of Artificial Lift Method. Society of Petroleum Engineers. doi:10.2118/10337-MS







Brown, K. E. (1982, October 1). Overview of Artificial Lift Systems. Society of Petroleum Engineers. doi:10.2118/9979-PA







Al-Lawati, M. (2014, October 6). Gas-Lift Nodal Analysis Model - Economical Optimization Approach. Society of Petroleum Engineers. doi:10.2118/171345-MS



Referred Book







Takacs, G.: “Modern Sucker-Rod Pumping” PennWell Books. Tulsa, Oklahoma, 1993.







Gault, R. H.: “Designing a Sucker-Rod Pumping System for Maximum Efficiency”







SPE Production Engineering. Nov. 1987, 284-90







Brown, K E: “The Technology of Artificial Lift Methods”, Volumes 1-4, Pen Well Books, 1980



41



Unpublished Report and Ph. D. Thesis 



Schlumberger: “Gas Lift Design and Technology”,1999







Elshanaliyev: “Development of expert system for artificial lift selection” MS Thesis,







Middle East technical university, 2013







Takacs, G.: “Program Optimizes Sucker-Rod Pumping Mode.” Oil and Gas Journal.



Oct. 1990, 84-9



Material from Web Site







Sucker Rod Pump - Production Technology: http://aoghs.org/technology/all-pumped-upoil-production-technology/



42







http://www.zulcon.com/page7/files/ALPresentationNotes.pdf







http://web.mit.edu/2.972/www/reports/sucker_rod_pump/sucker_rod_pump.html







http://www.pftsys.com/products.php







http://vigiku.blogspot.in/2012/10/introduction-to-oil-and-gas-production.html