TABLE OF CONTENTS
1.1 Introduction 03
1.2 Definition of Gas Lift 03
1.3 Principle of gas lifting 04
1.4 Different method of gas lifting 07
1.5 Gas Lift Manifold Header 09
1.6 Gas lift flow measurement and set point control 09
1.7 Gas Lift flow Distribution and Optimization 10
1.8 Purpose of Gas Lift valves 11
1.9 Location of Gas Lift valves 11
1.10 Types of Gas Lift valves 12
1.11 Gas Lifted Well Operation Procedure 15
1.12 Gas Lifted Well Monitoring and Trouble Shooting 16
The first period in the production life of a reservoir is called primary production or primary recovery. During this stage, reservoir pressure is used to use to push the oil from wells to the surface. This pressure is provided by the expansion of liquid or gas contained in the reservoir. This driving force or pressure, which displaces oil from a reservoir, comes from the natural energy of the compressed fluids in the reservoir. A reduction in pressure between the reservoir and the well bore is required for a well to produce. If this pressure difference is great enough, the well will flow naturally to the surface using only the natural energy supplied by the reservoir. However, if the pressure equalizes between the well bore and the reservoir, no flow from the reservoir will take place and there will be no production from the well. When the natural energy cannot overcome the hydrostatic head of the fluid in the tubing, some form of artificial lift must supplement the natural energy.
In addition, a secondary recovery method is also used which is know as ‘Improved or Enhanced oil Recovery’ method. This method is done to maintain the reservoir pressure by injecting gas or water into the reservoir. Injecting steam or nitrogen can also be done for improved recovery. Injecting water or gas into reservoir is helping in maintaining the reservoir pressure. Steam injection helps in reducing the viscosity of the oil and improving the production.
Some of the Forms of artificial lifts are:
- Gas lift
- Rod Pumping
- Electrical Submersible Pumps (ESP)
- Screw Pump(PCP)
In North Oman continuous gas lift is the most common artificial lift method. This will also give a positive contribution to the production optimization efforts. With this understanding the field production staff will recognize quit or less productive wells at an earlier stage and realize the significance of proper well test data and monitoring.
1.2 Definition of Gas Lift:
Gas lift is the method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas to reduce the liquid column density in the well and therefore reduce the well-bore pressure(Pwb) or the pressure at the perforation area. To produce the oil from the reservoir in the direction of the perforations(well bore), a pressure difference must be created between the reservoir and the well bore. This means that the well-bore pressure(Pwb) must be lower than the Static Reservoir Pressure(Pres) for fluid to flow from the formation to the well bore. The primary consideration in the selection of a gas lift system for lifting of wells in the entire field is the availability of gas and the cost of compression.
If, Pwb < Pres; well will flow
If, Pwb = Pres; well will not flow
An often used term for the pressure difference (Pres – Pwb) is DRAWDOWN. The draw down is a measure of the energy required to flow a certain amount of fluid from the formation into the well bore. It is of a great importance because in general the production of a well is proportional to the draw down applied to the formation.
Outflow Performance of a well:
The well-bore pressure(Pwb) is influenced by the separator back pressure, the pressure drop in the flow-line, the pressure drop in the tubing and the static head in the well. This can be expressed mathematically as follows:
Pwb = separator pressure + pressure drop in flow-line + pressure drop in tubing + static head.
Where separator pressure, pressure drop in tubing and flow-lines are based on several factors like, separator operating set-point pressure, tubing and flow-line size etc. But static head depends upon the quality of crude oil produced and waters in the tubing, which has a certain weight. This weight causes a back pressure on the well. This back pressure is called the static head. Its magnitude depends on two things; the depth of the well and the density of the liquid in the tubing.
Static head = Density(kg/m3) X Gravity(9.81 m/sec2) X True Vertical Depth of the well(m).
From the above equation, the deeper the well the higher the static head. Also the higher the density of the crude oil the higher the static head. Water has higher density than oil; therefore crude with a high water cut will increase the static head. On the other hand gas has a much lower density than that of oil, therefore crude with a high Gas to Liquid Ratio(GLR) will cause decrease the static head. This is why gas is injected into the well. The light gas injected deep in the tubing will reduce the density of the crude oil produced and reduce the static head and lead to a lower well-bore pressure(Pwb).
1.3 Principle of gas lifting:
Gas lift gas is introduced into the wells usually through the casing and product flow out through tubing, in some cases, lift gas in introduced through tubing and product flow out through casing, depending upon the status of how the well flow is required. As the gas mixes with the oil the total weight of the fluid column is reduced to a point where formation pressure is greater than the bottom hole pressure. The higher formation pressure forces the fluid out of the wellbore.
Schematic function of the Gas-lift IPO valve in a well:
Unloading process of a gas lifted well is described in the following steps:
The unloading process of a gas lifted well is described using a casing pressure-operated or Injected Pressure Operated(IPO) valve. The casing and tubing of a new well or worked over well is usually filled with kill brine(fluid). To bring this well into production the kill fluid(brine) in the casing and tubing should be produced to the surface. The process of producing these fluids out of the well is called unloading. This is a simple, but very important process as it can have a significant impact on the well production.
During the process of unloading, kill brine is transferred from the annulus or casing to the tubing through the gas lift valves. The liquid transferred passes through small openings in the gas lift valves. If lift gas is admitted to the casing at a very high rate, then the liquid will pass through these openings at very high speeds. This will cause damage to the internals of the valves and sometimes even destroy them completely. Therefore it is always a good practice to start with a low gas lift rate and increase it in steps to the designed rate.
With the help of the figure given above, we will discuss the systematic function of the gas lift valve in an oil well.
Figure section (A): For this, we will consider an oil well, which needs to be opened-up initially after drilling completion. It is a single completion well with one packer and four gas lift valves. Initially, well will be filled with heavy liquid (brine water) in the tubing and casing, which causes a static pressure against the reservoir pressure.
Note: If there is sufficient pressure difference between the reservoir and the well bore to lift the static liquid in the tubing, the well might flow on it’s own (self-flow) without gas lift. The casing-liquid in-between the top-most packer and the sliding-sleeve-door(SSD) will not be unloaded during these well unloading operation.
For high static fluid-level wells, the casing pressure gradually increases until it is equal to or above the set opening pressure of the first top-unloading valve, lift gas is introduced into the tubing through the annulus fluids (brine). This is followed by a reduction in casing pressure.
For low reservoir pressure/fluid level wells, the lift gas pushes the brine through the bottom orifice and the unloading valves are not functioning due to low pressure in the casing(empty casing).
To avoid unloading valve damage and as a “rule of thumb” for introduction of gas lift to a well, the gas lift rate should be 50% of the maximum design rate for the first eight hours. This will allow for a gradual build-up of pressure in the casing to the required set-point value of the top-most gas lift valve to operate(open) . Similarly the second, third and follow-on valve’s will function.
For a typical well, this will have the effect of increasing the casing pressure by 100 kPa every 20 minutes. After that the gas lift rate can be increased to 100% of the maximum rate.
Figure section (B):
In this, due to the reduction of the fluid level in the casing and tubing,(lower casing pressure) opens the second unloading valve and lift gas enters with lighter head in the tubing. The first gas lift unloading valve is closed. The fluid in the tubing is being aerated to surface by injected gas and the well starts flowing. Fluid in the tubing and casing starts dropping. Gas in the annulus continues to displace the brine.
Figure section ©:
The reduction of further fluid level in casing and tubing (lower casing pressure through the lower open and close set pressure of unloading valves continues as more gas lift enters the tubing) until such a time that the bottom orifice is reached. At this point the full well tubing contents are aerated, and well fluid has moved down wards, each valve has closed as gas entered the next lowest valve and the well producing at maximum production. The gas lift injection rate is increased to 100% of the maximum rate to prevent the casing pressure from reducing any further causing the well to surge and lose production.
Note: All unloading gas lift valves should now be closed with the correct stated injected rate used for the sized orifice down hole at the estimated casing pressure. If one of these above stated steps is not correct, the well has a problem.
1.4 Different methods of gas lifting into the vertical flow tubing:
There are two methods of gas lifting into the vertical flow tubing well; i.e. continuous gas lifting method and intermittent gas lifting.
Continuous gas lift
This is basically a high rate producing method. High-pressure gas is injected into the production conduit continuously. From there it enters at some point into the tubing which causes an increase in the gas liquid ratio above that point. The injection gas mixes with the produced well fluids and decreases the flowing pressure gradient of the mixture from the point of gas injection to the surface. The lower flowing pressure gradient reduces the flowing bottom hole pressure (BHFP) to establish the draw down required for attaining a design production rate from the well. If sufficient draw down in the bottom hole pressure (BHP) is not possible by continuous flow; intermittent gas lift operation may be used.
For maximum benefit the gas injected as deep as possible. Valves are generally needed to establish the point of gas injection. This is the only method that fully utilizes the energy of the formation-gas produced by the well.
A typical gas lift system consists of the following components.
- Source of high pressure gas, compressor, gas well
- Distribution lines to pass the gas to the well head.
- Surface controls.
- Subsurface controls (gas lift valves)
- Flow measuring instruments for individual wells.
A gas lift system requires a source of gas at sufficient pressure so as to inject it at the proper place and rate into the flow system. The method of operation and type of installation depends largely on the type of valves used.
Closed Cycle Gas lift System:
Most gas lift systems are designed to circulate the lift gas. The low-pressure gas from the production separators is piped to the suction of the compressor. The high-pressure gas from the discharge of compressor is injected into the well to lift the fluids from the well. Excess produced gas; normally the amount of associated gas produced from the reservoir, can be exported, re-injected or flared to the atmosphere. For operational purpose it is important to find the balance between lift gas, export and flaring rate for a given compressor capacity. The gas lift system should have adequate compression capacity to develop sufficient header pressure and the required flow. Discharge pressure from the gas compressor should be sufficient enough to lift the fluid of the well with suitable depth and reservoir pressure over the field. The main components of a gas lift system are; the Gas lift Compressor, Gas lift flow measurement, Test/bulk separators and Backup gas/flaring system/export facilities.
1.5 Gas Lift Manifold Header:
In order to have the better control and plan of these gas lift line’s to individual wells, the high-pressure gas is distributed from the main header, known as gas lift header. Each of the line taking-off from this header is laid-out to supply high-pressure gas to dedicated well with it’s own control instrument equipment and wiring. It includes the orifice metering facility as well to measure quantity of gas utilized by each well.
1.6 Gas Lift flow Measurement and Set-point Control:
The production from the gas lifted well depends on the volume of gas injected at the deepest possible valve. It is therefore very important to make sure that each well is admitted with the required gas volume.
The gas lift flow is measured by the differential pressure across an orifice meter which converted in the flow transmitter to a pneumatic (low air pressure) output signal. This pneumatic signal is subsequently converted to a current (4-20mA) in the electronic controller. The reason for this is that the DCS system cannot read pneumatic signals. The DCS system will check and control the output signal against a given gas lift set point, and will give a signal to the gas lift control valve, (first current and subsequently a pneumatic signal, through the converter).
This control loop will constantly monitor the flow rate, and will adjust the output signal to the value so that the preset gas lift rate will be maintained as stable as possible. This stability is essential for gas lift operations. If applicable SCADA will feed the DCS system with flow rates, which are generated by Win-GLUE. These flow rates can be down loaded automatically.
The following checks are recommended for smooth and efficient Gas Lift operation:
- Ensure that the ranges are identical in SCADA, DCS and the Meter factor.
- Ideally the normal flow rate should be between the 5 and 7 units on a 1 – 10 square root scale (50 % on linear scale). This may not always be possible, but when the normal flow approaches 80 % of the linear scale, initiate re-ranging the flow control loop, and visa versa for down wards adjustment.
- Visually (by looking) check the G/L system from time to time. Even very small leaks on the impulse lines and instrument air leaks can cause major differences in measurement.
- Maintenance on the gas lift system should be carried out regularly.
1.7 Gas Lift flow Distribution and Optimization:
The gas lift supply to the wells in an oil field is not always stable. There are changes in supply due to compressor trips, export trips, temperature etc. The number of wells opened-up can also be changing; this will change the lift gas requirement (DEMAND). One or both changes give an imbalance in the lift gas distribution hence; redistribution is therefore required.
Normal oil-field practice is to open or close wells to balance the supply and demand. A swing list is used to determine in which order to open or close wells. Another method of balancing supply and demand is; increasing or decreasing lift gas flow to wells. The amount of lift gas available will be used more efficiently.
1.8 Purpose of Gas lift valves:
The primary purpose of string of gas lift valves is to unload a well with the available injection gas pressure to a maximum depth of lift. Gas lift valves provide the flexibility to allow for a changing depth in the point of gas injection to compensate for a varying BHFP, water cut, daily production rate allowable and well deliveribility. The gas lift valve provides the means to control the injection gas volume per cycle. Another important function of gas lift valves is the availability to maintain an excessive BHFP draw down in a temporarily damaged well until the well cleans up.
- Location of Gas lift valves:
There are two ways in which gas lift valves can be set in the tubing:
- Outside the tubing
- Inside the tubing
- Outside the tubing:
In this type gas lift valves are positioned on the casing side of the tubing. The biggest disadvantages of this type is that in case the valves should be changed, the tubing has to be pulled-out. This is costly and time consuming
- Inside the tubing:
In this type gas lift valves are placed in the so-called Side Pocket Mandrel(SPM), picture of an SPM is shown below.
This is a piece of tubing larger than the size of the rest of the tubing string. The larger tubing is required to provide a space for the gas lift valve without obstructing the flow. The advantage of this method is that gas lift valves can be pulled and set in a relatively short period of time using wire-line.
1.10 Types of Gas lift valves:
There are several types of gas lift valves available in the market; the most commonly used is the one where the closing force of the valve is generated by nitrogen pressure enclosed in a chamber within the valve. The two basic types of these valves are:
- Casing pressure-operated valve or Injection Pressure Operated(IPO).
- Fluid operated valve or Production Pressure Operated(PPO).
Gas lift valves are distinguished by their sensitivity to the casing pressures and /or tubing pressures needed to open and close them. This sensitivity is determined by the mechanical design of the gas lift valve because it is the pressure exposed to the largest area in that valve that controls the valve operation.
- Casing pressure-operated valve or Injection Pressure Operated(IPO):
The main opening force is provided by the gas injection pressure in the casing. An Injection Pressure Operated(IPO) valve is easier to control than the Production Pressure Operated valve(PPO) because IPO valve can be controlled by gas lift rate set point changes and PPO valve is influenced by reservoir pressure, which is difficult to control. IPO valves are used in wells completed as singles and have their own gas lift flow controllers(i.e. not sharing gas lift lines). During initial start-up of the well, the pressure in the annulus will increase due to the fact that all the gas lift valves in the well are closed.
Nitrogen is normally injected into the dome and charged to a specified pressure(Pd). The bellows serves as a flexible or responsive element. The movement of the bellows causes the stem to rise and fall and the ball to open and close over the port. When the port is open, the annulus and tubing are in contact. It is the casing pressure(Pi) which controls the operation of the valve. It requires building up in casing pressure to open and a reduction in casing pressure to close. The valve often has a spring, which is located below the bellows.
Figure of different type of Injection Pressure Operated or Casing Pressure Operated valve(Closed position):
Note: In this type, gas injection pressure(Pi) in the casing is acting on the ball-seating attached to the valve stem. When gas injection pressure in the casing(Pi) is equal or higher than the set pressure of the bellow(Pd), the valve will open. Then lift gas enters through the port and into the tubing.
- Fluid operated valve or Production Pressure Operated(PPO) valve:
Figure of different type of Tubing Operated or PPO valve(closed position):
The main opening force is provided by the Production pressure in the tubing. PPO valves are used in dual wells or in single wells that share the same gas lift line. This is done to minimize the influence of one string on the other string performance.
During well start-up when the well is full of liquid all the gas lift valves are open due to the hydrostatic head of the liquid column(Pf) acting against the preset bellows pressure(Pd). In this situation there is communication between the casing and the tubing, however the check valve prevents flow from tubing to casing. In this case because of the large bellows area, it is the tubing pressure rather than the casing pressure which controls the operation of the valve.
In this type, the tubing fluid column pressure(Pf) is acting on the ball-seating attached to the valve stem. As soon as the tubing pressure is equal or higher than the set pressure of the bellow, the valve will open. When the tubing pressure becomes less than the pre-set bellow pressure the valve will close.
Note: In IPO as well as PPO valves, the non-return(Check Valve) valves functions according to the flow path of the valve. It works on it’s own principle with the valve seating, piston and travelling-path. In both the types of the valves, it is the Piston effect(Ap), which functions according to the difference in pressure within the casing and tubing.
In a well with more than one gas lift valve, the predicted lowest injection point is normally completed with an orifice valve rather than a normal gas lift valve. This type of valve is without bellows, but has a check valve to prevent back flow into the casing.
The advantage of using an orifice rather than a normal gas lift valve at the deepest lifting point are as follows:
- Mechanically simpler therefore less possibility of mechanical failures, which can cause blockage.
- No throttling action and therefore a continuous rather than intermittent gas lift flow can be achieved.
These valves are made of a solid metal, resembling a normal gas lift valve. They will provide total isolation between the casing and the tubing. A dummy valve is used to seal an SPM when no gas lift is required to be injected at that SPM.
1.11 Gas Lift Well Opening-up and Closing-in Procedure:
An oil well has got it’s own opening-up and closing-in procedure. Especially, when it is a gas-lifted well, the procedures differ from a normal well operation.
Note: Well (new) Initially Opening-up should be done as the ‘Opening-up Program’ from the Programmer.
Gas Lifted well normal opening-up Procedure:
- Open-up the gas-lifted well is as and how, a normal well is opened, i.e. line-up oil manifold valves, wellhead location valve and open-up the tubing wing valve.
Note: Ensure prior to opening the well, wellhead master is open and all sampling points are closed.
- As it is a gas lifted well, open-up casing wing valve which is connected with the gas-lift line.
- Ensure that required set-point value of the gas lift is available in the system, if not, re-feed the value.
- Open-up slowly, gas lift manifold isolation valve of the dedicated well, which is to be opened-up. Initially gas lift flow will be maximum due to signal of the existing set-point value. Instrument controller and logic will adjust the required flow rate according to the set-point value.
Gas Lifted well closing-in Procedure:
While closing a normal flowing well, tubing wing valve to be closed from the well head and then valve’s from the oil manifold. When closing a Gas Lifted well:
- Close the gas lift manifold isolation valve.
- Then close the casing wing valve and the tubing wing valve.
Note: The well is now isolated and it should be available to open-up any time.
- Well Monitoring and Trouble Shooting:
Well monitoring will provide a lot of information about the well performance. This information is used to identify a well that is performing sub-optimally. Sub optimal performance can take many forms and can have varying degree of impact on well integrity and production. Examples of sub optimal performance are heading, high CHP, low CHP, well circulating gas and quit wells. The flow chart attached below is a guideline for general gas lifted well trouble shooting.
Observing the following parameters can monitor a well performance:
- CHP and THP trends, obtained from RTU’s and SCADA or, if not available, by using two-pen pressure chart recorders.
- Measurement of the gas flow rate.
- Well tests; for oil, water and associated gas production.
- Subsurface flowing surveys.
- Subsurface static pressure surveys.
- Visual observation of surface facilities and samples.
- Recording Surface Pressure Of The Tubing and Casing:
the permanent installations of Wellhead RTU’s (where available) offers much better trending and analysis. RTU’s allow for remote monitoring and trending from a central control room. It is also possible to set pressure limits that, if exceeded, will raise an alarm, this make it easy to spot problem wells.
- Measurement of Gas Volume:
Gas lift flow rates are measured and it is very important to ensure that the right amount of gas lift is injected. Gas meters on separators determine total gas produced and by subtracting lift gas the associated gas flow rate can be calculated.
- Testing the well:
Well tests to measure oil and water production provide important parameters for determining the efficiency of a gas lift operation.
- Flowing Survey:
Flowing surveys will locate the point of injection, leaks in the tubing, valve failures of multiple injection. They will also determine the flowing gradient above and below the point of injection and the flowing bottom hole pressure(Pwb). It is important that an accurate well test is carried out at the same time as the flowing survey, so that the productivity index (PI) of the well can be calculated.
- Static Pressure Survey:
This will determine the static bottom hole pressure (or reservoir pressure), the static fluid level and the static gradient of the well fluids. For use in reservoir pressure maps & simulations.
- Visual Observation of Surface Installation:
Visual observation of a gas lift installation may sometimes uncover conditions that are bad for the overall efficiency of the installation. Examples are excessive pressure drop in the gas lift lines, restrictions at the well head, obstruction/blocked manifold choke, leaks in gas lift line or flow line, gas freezing at points of restriction and improper surface control of gas lift.
It is always a good practice to examine the system at regular intervals and before a well test or flowing survey.
Well monitoring as discussed in the previous section will provide a lot of information about the well performance. This information is used to identify a well that is performing sub-optimally. Sub optimal performance can take many forms and can have varying degree of impact on well integrity and production. Examples of sub optimal performance are heading, like CHP, low CHP, well circulating gas and quit wells. The flow chart in attachment below is a guideline for general gas lifted well trouble shooting.