Gas Lift - gas lift PDF

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Australian College of Kuwait Oil and Gas Engineering Faculty

Gas Lift System

2015

Table of Contents 1. Introduction ........................................................................................................... 3 2. Artificial Lift Types ............................................................................................... 4 2.1 Hydraulic Pumping Systems (HPS) ................................................................. 4 2.2 Electric Submersible Pumps (ESP) .................................................................. 4 2.3 Rod Pumps ...................................................................................................... 4 2.4 Gas Lifts .......................................................................................................... 4 3. Gas Lift ................................................................................................................. 5 4. Types of Gas Lifts ................................................................................................. 7 4.1 Continuous Flow Gas Lift ................................................................................ 7 4.2 Intermittent Flow Gas Lift ............................................................................. 10 4.2.1 Single point injection .................................................................................. 11 4.2.2 Multi point injection ................................................................................... 11 5. Gas Lift Components ........................................................................................... 12 5.1 Surface components ....................................................................................... 12 5.2 Subsurface components ................................................................................. 13 5.2.1 Open and Closed Installations ..................................................................... 15 5.2.2 Considerations for selecting the proper installation and equipment .............. 15 6. The Elements of the Valve ................................................................................... 17 6.1 Bellows ......................................................................................................... 18 6.2 Purposes of Gas Lift Valves and Reverse Checks ........................................... 18 7. Gas Lift Valve Types and Mechanism ................................................................. 19 7.1 Pressure Operated Valve ................................................................................ 19 7.2 Fluid operated valve ...................................................................................... 24 7.3 Throttling Valve ............................................................................................ 28 7.4 Combination Valve ........................................................................................ 28 7.5 Differential Valve .......................................................................................... 29 7.6 Balanced Pressure Valves .............................................................................. 29 8. Types of Gas lift installations .............................................................................. 30 8.1 Open Installation ........................................................................................... 30 8.2 Semi-Closed Installations .............................................................................. 30 8.3 Closed Installations ........................................................................................ 30 8.4 Chamber Installations - Standard Two packer chamber .................................. 30 8.5 Small-Size Installations ................................................................................. 30 9. Gas Lift Design ................................................................................................... 31 9.1 Case Study 1...................................................................................................... 31 9.2 Case Study 2...................................................................................................... 33 1

9.2.1.1 Valve setting depth - Graphically ............................................................. 33 9.2.1.2 Valve setting depth - Mathematically ....................................................... 35 9.2.2.1 Port Size – Graphically ............................................................................ 37 9.2.2.2 Port Size – Mathematically ...................................................................... 38 9.3 Case Study 3...................................................................................................... 39 9.3.1 Valve Spacing – Graphically....................................................................... 39 9.3.2 Valve setting depth - Mathematically .......................................................... 41 9.4 Case Study 4...................................................................................................... 43 9.4.1 First Method for HP calculation .................................................................. 43 9.4.2 Second Method for HP calculation .............................................................. 43 9.5 Case Study 5...................................................................................................... 44 9.5.1 Line Diameter ............................................................................................. 44 Appendix – Charts and Design Results .................................................................... 45 References ............................................................................................................... 52

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1. Introduction As we all know, oil and natural gas are a class of chemicals called 'Hydrocarbons' which are made of hydrogen and carbon. Oil and natural gas are formed when decaying plants and micro-organisms are trapped in layers of sediment and – over the course of millions of years – become buried deep within the earth, where underground heat and pressure turn them into useful hydrocarbons. There isn't any way to be absolutely sure where new oil and natural gas reserves are located, so petroleum engineers need to collect data as to what lies deep beneath the earth's surface. This data can be gathered using airplanes and satellites to map the surface, to identify promising geological formations, and to look for oil and natural gas seeps. Ships can do the same for the ocean floor. Advanced techniques such as seismic surveys, for example, are carried out to get more useful information by looking at geological structures and rock properties below the surface. Extracting oil and natural gas from deposits deep underground isn’t as simple as just drilling and completing a well. Any number of factors in the underground environment – including the porosity of the rock and the viscosity of the deposit -- can impede the free flow of product into the well. In the past, it was common to recover as little as 10 percent of the available oil in a reservoir, leaving the rest underground because the technology did not exist to bring the rest to the surface. Today, advanced technology allows production of about 60 percent of the available resources from a formation. Whether on or off-shore, once a drilling rig has been set up, extraction starts. Oil production generally has three phases and in each phase more of the original oil in place (OOIP) is able to be extracted. Initially the oil generally gushes to the surface under its own pressure. With time, usually many years, this flow slows due to a declining driving force. The secondary phase is when the oil needs to be assisted out of the ground using artificial lift systems or injecting gases or fluids that maintain the pressure in the well. Eventually a stage is reached where pressure alone is unable to extract further oil. Then the oil properties or interaction between the oil and the rocks need to be changed – this is the tertiary phase also called enhanced oil recovery (EOR).

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2. Artificial Lift Types As previously mentioned, artificial lifts are used as a form of secondary recovery in order to extract more hydrocarbons from underground. This is achieved by attaining a lower bottom-hole flowing pressure (BHFP) which enables the formation to give the desired fluids. The inflow performance relationships (IPR) of the formation reflect the ability of the well to give fluids which depends on the reservoir types and the driving mechanisms. There are different types of artificial lifts, which are:

2.1 Hydraulic Pumping Systems (HPS) HPS transmit energy to the bottom of the well by means of pressurized power fluid that flows down in the wellbore tubular to a subsurface pump. There are at least three types of hydraulic subsurface pump: 1. Reciprocating piston pumps 2. Jet pumps 3. Hydraulically driven downhole turbines.

2.2 Electric Submersible Pumps (ESP) The ESP consists of a downhole pump, an electrical motor, a separator, and a power cable. The motor works to transform electrical energy into kinetic energy which turns the pump

2.3 Rod Pumps Those are long cylinders with both fixed and movable elements inside. The pump is inserted inside the tubing of a well in order to gather fluids from beneath it and lift them to the surface. Its most important components are: the barrel, valves, and the piston.

2.4 Gas Lifts Gas lift is another widely used artificial method. Gas is injected in the tubing to reduce weight of the hydrostatic column, thus reducing back pressure (which is created by the tubing acting down against the reservoir pressure flow) and allowing reservoir pressure to push the produced fluids up to the surface. So, it is basically using high pressure gas through a mechanical process to lift the fluids.

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3. Gas Lift An emerging method of artificial lift, gas lift injects compressed gas into the well to reestablish pressure, making it produce. Even when a well is flowing without artificial lift, it many times is using a natural form of gas lift.

Gas LiftSource: Tech Flo Consulting LLC The gas lift process involves injecting gas into the well in order to re-establish pressure. The gas is allowed to enter the flowstream within the production tubing at some specific depth through a single or more usually a series of gas lift valves. The injection of gas into the production tubing provides a stepwise increase in the gas liquid ratio of the fluids flowing in the tubing at that depth and throughout the tubing above the injection point. This results in a reduction of the bottomhole pressure. By injecting gas, the gasliquid ratio (GLR) of the flowing fluid is increased, its effective flowing density is reduced, and thus, an increase in flow rate. In addition, the compressibility of the gas will assist in the lift process since as the gas rises up the tubing with the liquid it will expand, causing an increase in the tubing flow velocity. However, frictional pressure losses are an issue which will hinder the flow rate past a certain point. With very few surface units, gas lift is the optimal choice for offshore applications. Occurring downhole, the compressed gas is injected down the casing tubing annulus, entering the well at numerous entry points called gas-lift valves. As the gas enters the tubing at these different stages, it forms bubbles, lightens the fluids and lowers the pressure.

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The flexibility of gas lift, in terms of production rates and depth of lift, can seldom be matched by other methods of artificial lift if adequate injection-gas pressure and volume are available. Gas lift is one of the most forgiving forms of artificial lift because a poorly designed installation will normally gas lift some fluid. The mandrel depths for many gas lift installations with retrievable-valve mandrels are calculated with minimal well information. Highly deviated wells that produce sand and have high formation-gas/liquid ratios are excellent candidates for gas lift when artificial lift is needed. Many gas lift installations are designed to increase the daily production from flowing wells. No other method is as ideally suited for through-flowline ocean-floor completions as a gas lift system. Wireline-retrievable gas lift valves can be replaced without killing a well or pulling the tubing. The gas lift valve is a simple device with few moving parts, and sand-laden well fluids do not have to pass through the valve to be lifted. The individual-well downhole equipment is relatively inexpensive. The surface equipment for injection-gas control is simple and requires little maintenance and practically no space for installation. Typically, the reported high overall reliability and lower operating costs for a gas lift system are superior to other methods of lift. The primary limitation for gas lift operations is the lack of formation gas or an injectiongas source. Wide well spacing and lack of space for compressors on offshore platforms may also limit the application of gas lift. Poor compressor maintenance can increase compressor downtime and add to the cost of gas lift gas, especially with small field units. Compressors are expensive and must be properly maintained. Generally, gas lift is not as suitable as some other systems for single-well installations and widely spaced wells. The use of wet gas without dehydration reduces the reliability of gas lift operations The figure below shows a graphical explanation of the optimum injection rate.

Figure 1 showing hypothetical recommended gas injection rate Gas lift optimization curves for each well are derived through measurement of gas-oil production across a range of injection pressures. With continuous instrumentation at each well, these curves can be dynamically computed and used in optimization strategies. 6

4. Types of Gas Lifts 4.1 Continuous Flow Gas Lift The vast majority of gas lift wells are produced by continuous flow, which is very similar to natural flow. Fig. 2 shows a schematic of a gas-lift system.

Fig. 2—Schematic of a gas lift system. (Courtesy of Schlumberger.) In continuous-flow gas lift, the formation gas is supplemented with additional highpressure gas from an outside source. Gas is injected continuously into the production conduit at a maximum depth that depends upon the injection-gas pressure and well depth. The injection gas mixes with the produced well fluid and decreases the density and, subsequently, the flowing pressure gradient of the mixture from the point of gas injection to the surface. The decreased flowing pressure gradient reduces the flowing bottomhole pressure below the static bottomhole pressure thereby creating a pressure differential that allows the fluid to flow into the wellbore. The gas is injected through annulus (tubing flow) at a fixed rate and pressure. The main operating valve is put at a suitable depth which depends on the surface operating pressure. A regulator is used at the surface to control the injected gas. 7

A reliable, adequate supply of good quality high-pressure lift gas is mandatory. This supply is necessary throughout the producing life of the well if gas lift is to be maintained effectively. In many fields, the produced gas declines as water cut increases, requiring some outside source of gas. The gas-lift pressure typically is fixed during the initial phase of the facility design. Ideally, the system should be designed to lift from just above the producing zone. Wells may produce erratically or not at all when the lift supply stops or pressure fluctuates radically. Poor gas quality will impair or even stop production if it contains corrosives or excessive liquids that can cut valves or fill low spots in delivery lines. The basic requirement for gas must be met, or gas lift is not a viable lift method. Uses:  Wells which have high productivity index (J)  Wells with high bottom hole pressure relative to depth. Gas lift has the following advantages. 

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Gas lift is the best artificial lift method for handling sand or solid materials. Many wells produce some sand even if sand control is installed. The produced sand causes few mechanical problem in the gas-lift system; whereas, only a little sand plays havoc with other pumping methods, except the progressive cavity pump (PCP). Deviated or crooked holes can be lifted easily with gas lift. This is especially important for offshore platform wells that are usually drilled directionally. Gas lift permits the concurrent use of wireline equipment, and such downhole equipment is easily and economically serviced. This feature allows for routine repairs through the tubing. 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. High-formation GORs are very helpful for gas-lift systems but hinder other artificial lift systems. Produced gas means less injection gas is required; whereas, in all other pumping methods, pumped gas reduces volumetric pumping efficiency drastically. Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow also can be easily accomplished to handle exceedingly high volumes. A central gas-lift system easily can be used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing. A gas-lift system is not obtrusive; it has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering. The low profile is usually an advantage in urban environments. Well subsurface equipment is relatively inexpensive. Repair and maintenance expenses of subsurface equipment normally are low. The equipment is easily pulled and repaired or replaced. Also, major well workovers 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. 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.

Gas lift has the following disadvantages. 

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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. Thus, a 10,000-ft well with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be difficult to lift with the standard continuousflow gas-lift system. However, there are special schemes available for such wells. Gas lift is relatively inefficient, often resulting in large capital investments and high energy-operating costs. Compressors are relatively expensive and often require long delivery times. The compressor takes up space and weight when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas use also may increase the size of necessary flowline and separators. Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas becomes too expensive, it may be necessary to switch to another artificial lift method. In addition, there must be enough gas for easy startups. Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%). There is increased difficulty when lifting low gravity (less than 15°API) crude because of greater friction, gas fingering, and liquid fallback. The cooling effect of gas expansion may fu...