well deliquification/New Doc… · Web viewErosion occurs if the gas and liquid production is carrying an erosive material (e.g. hydrates, sand, scale, etc.) that can impinge on

Status Document written and edited, there will be a few additions needed. Chair: Cleon Dunham, [email protected] Team: Boots Rouen, Rob Sutton, Bill Carroll, Dean Gordon, Jason Jones,

Tom Nations, Ron Schmidt, Larry Peacock Comments: Not applicable

2.4l Continuous Gas-Lift

This section discusses the practical limits of continuous gas-lift in terms of liquid production rate, gas production rate, depth, pressure, temperature, etc. It presents rough guidelines on the relative costs of continuous gas-lift. Ob-viously precise costs can not be given as they depend on many factors. It presents rough guidelines on the relative life expectancy of continuous gas-lift. Clearly, precise expectations can not be given as they depend on many factors. It concludes with a brief comparison of continuous gas-lift with con-tinuous gas circulation and intermittent gas-lift.

General Comments on Gas-Lift for Gas Wells

At first blush, it may seem strange to inject gas to produce gas. How-ever, for many wells this is a very practical process. Several artificial lift methods used to deliquify gas wells require use of energy from the well. This is true of velocity strings, all chemical processes, and plungers. The well’s “native” energy is needed to produce the well, lift the plunger, etc.

When the reservoir pressure decreases, or the inflow decreases, the well may no longer be able to supply the energy needed to produce liq-uids from the well with velocity strings, chemicals, or plungers. When this occurs, energy must be added to remove the liquids. This can be done with pumping systems, or with gas-lift.

Pumping systems require energy at the well to operate the pump. In re-mote locations, this may be a problem. If there is a source of high pres-sure gas from a central compression facility, gas-lift can be used without the needed for an energy source at the well, with the possible exception of solar power to operate a wellhead monitoring and control system,

And, if gas can be injected below the perforated interval, it can poten-tially deliquify the entire well. This can be difficult to achieve with some pumping systems, especially in deviated or horizontal wells.

Guidelines & Recommended PracticesSelection of Artificial Lift Systems

for Deliquifying Gas WellsPrepared by Artificial Lift R&D Council

mailto:[email protected]

Selection of Artificial Lift Systems for Deliquifying Gas Wells Page 2

So, there can be an important role for gas-lift in the deliquification of many gas wells.

Practical Limits and Issues

Depth Limits and Concerns. There are no practical limits to the depth for use of continuous gas-lift. The depth depends on the pressure that can be used for the injection gas, and the number of unloading gas-lift mandrels that can be installed in the tubing. Most continuous gas-lift systems are in the depth range from 5,000 to 10,000 feet vertical depth. However, there are systems that are much shallower, and there are systems installed to 15,000 feet ver-tical depth.

The goal of gas-lift for gas wells is to add enough gas so the total gas flow rate of injected gas plus produced gas is high enough achieve and maintain critical flow velocity. The amount of gas to achieve critical flow velocity depends on the cross-sectional area of the production conduit(s).

If gas is injected below the packer in the casing, so it can be in-jected below the perforated interval to achieve maximum deliquifi-cation of the well, the cross-sectional area may be larger than the cross-sectional area of the tubing, so more gas may be needed to achieve and maintain critical flow below the packer. However, there are several approaches to reduce the flow area below the packer. These can include use of a dead string below the packer, or injection down a tube below the packer and production up the annulus between the casing and the injection tube.

Size Limits and Concerns. Size is not really an issue with gas-lift. Typically for gas wells, the production tubing will be 2-inch or 2.5-inch. Typically this can support use of KB or MM mandrels that can accommodate 1-inch or 1.5-inch gas-lift valves.

There may be some wells with small casing that only support use of small tubing or coiled tubing. There are gas-lift systems that can use small gas-lift valves that can work with these small tubing sizes.

Pressure Limits and Concerns. Gas-lift systems can be de-signed for any operating pressure from a few hundred psi up to 2,000 or 3,000 psi. Typically, for gas wells, the pressure needs to be high enough to unload the well (remove liquid from the annulus). This depends on the depth of the well and the number of unloading


mandrels used. Typically, for most gas wells, an operating pres-sure will be between 800 and 1,200 psi.

Temperature Limits and Concerns. An advantage of gas-lift is that it is not limited by temperature. For most gas wells, the tem-perature at depth in the well will be essentially equal to the geother-mal temperature. In other words, the temperature of the produced gas will essentially be equal to the temperature of the earth at the depth of the reservoir.

Temperature is an issue when setting unloading gas-lift valves, since the values typically use a nitrogen-charged dome and bel-lows. The closing pressure asserted by the bellows is a function of the pressure of the nitrogen in the bellows, which is a function of temperature. Therefore, it is necessary to accurately estimate the temperature of the gas-lift valves during the unloading process. For gas wells, a reasonable assumption if that that temperature of each gas-lift valve is equal to the earth temperature at the depth of the valve. This is OK since the gas has a low heat carrying capacity and will rapidly cool to equal the temperature of its surrounds as it rises in the tubing.

Rate Limits and Concerns. For gas wells, the rate of gas injection should be controlled to be equal the amount of gas that is needed to be added to the produced gas to achieve and maintain critical flow. This can be a dynamic, changing amount as the native pro-duction rate of the well changes.

To determine the amount of gas to inject, it is necessary to deter-mine the critical velocity so enough gas can be injected to keep above the critical velocity. There are other sections in this docu-ment (and on this web site) that describe how to calculate the criti-cal velocity. The critical velocity needs to be determined at the depth where the flow area is greatest. If this is below the packer, then this area must be used. And the pressure and temperature of the gas at that depth must be used to determine the required critical velocity.

Once the required critical velocity is determined, the rate of gas in-jection can be controlled to assure that the actual velocity is main-tained slightly above the critical value to assure that the well is be-ing continuously deliquified.

The rate of gas that can be injected into a gas-lift well is a function of a number of factors:- The available surface injection pressure.


- The size of the injection flow path, either down the casing/tubing annulus or down an injection tube.

- The size of the gas-lift valve or orifice port size or choke size through which the gas is injected.

There are accurate computer programs that can determine the in-jection pressure profile in a well if the surface injection pressure and temperature are known, the size and length (depth) of the in-jection flow path(s) is/are known, and the characteristics of the gas-lift valve or orifice are known.

Limits and Concerns with Sand, Corrosion, Erosion, H2S, CO2, etc. Gas-lift systems can be designed and operated to handle lim-ited amounts of sand. With the use of appropriate chemicals, cor-rosion can be handled. Erosion occurs if the gas and liquid produc-tion is carrying an erosive material (e.g. hydrates, sand, scale, etc.) that can impinge on metal surfaces. This can be controlled by con-trolling the amount of erosive materials. Gas-lift wells that produce gas are typically operated with natural gas. If some H2S or CO2 is present, this must be dealt with to prevent corrosion from occurring.

- Sand. An advantage of gas-lift is that it can handle some sand. Typically, there is a clear flow path from the gas-lift injection point to the surface. Clearly, sand can more easily be produced in a gas-lift oil well. In a gas well, some sand can be trans-ported with the liquid that is being lifted (produced) from the well. If a gas well has a serious sand production problem. It will be necessary to limit the sand production by using a sand con-trol method such as a gravel pack or a screened liner. In some cases, sand production can be limited by limiting the pressure drawdown and the rate of change of pressure drawdown from the reservoir to the wellbore.

- Corrosion. If corrosion exists in a gas-lift well, the normal and most effective process is to inject enough corrosion prevention chemical with the injection gas. The necessary amount can be determined by a Chemical Engineer. The chemical injection can be controlled to inject just the needed amount of chemical. The chemical will protect the injection flow path, and the production flow path.

- Erosion. If clean, dehydrated gas is used for injection, there should not be a problem of erosion occurring due to the gas. If un-dehydrated gas used, there may be many problems includ-ing hydrate formation, damage to injection valves or orifices, etc.


If a well produces solids (sand or scale), the solids may erode pipe where there is a high velocity or a large pressure drop. It is best to prevent the production of sand or the formation of scale with appropriate chemical injection.

- H2S. If there is an H2S concentration in the produced gas, the H2S should be removed before the gas is injected into the well for gas-lift. If it is not, there may be a safety hazard and there will likely be corrosion.

- CO2. If there is a CO2 concentration in the produced gas, it may be necessary to use special materials to prevent corrosion due to formation of carbonic acid.

Power Requirements and Concerns. The power requirements for gas-lift have to do with the compression of gas to high pressure for injection. There are several approaches to provide high pres-sure gas.

- Central Compression Facility. The most common approach is to use a central compression facility to compress gas for the field operation. A typical schematic of such a system is shown here. Some of the gas may be sold, some may be used for var-ious purposes in the facility, and some may be distributed for gas-lift injec-tion. The oper-ation of central compression fa-cilities is be-yond the scope of this docu-ment. A com-pression sys-tem engineer, or engineering contractor, should be consulted to determine the design of the facility, the power requirements, etc.


One very important consideration is dehydration of the gas. There are many problems associated with using un-dehydrated (wet) gas. These include the possibility of forming hydrates that can block injection control chokes or valves, difficulties with gas injection measurement, difficulties with control, and potential downhole problems. The normal recommendation is to dehy-drate the gas to less than 7 pounds of water vapor per one mil-lion cubic of gas.

- Wellhead (or Well Site) Compression Facility. Many opera-tors of gas wells use wellhead or well site compression facilities to boost the gas pressure for flow to a central gathering station. This can permit the well to be operated at a very low wellhead pressure (perhaps even below atmospheric pressure) to aug-ment production from the well. In some cases, there wellhead or well site compressors can also be used to compress that gas to high enough pressure for gas-lift injection. A caution here is that sometimes this gas is not dehydrated and problems from using wet gas may occur.

- High Pressure Gas. In some fields there is high pressure gas from gas wells available for gas-lift injection. In this case, it may be necessary to control (reduce) the pressure to that needed for gas-lift. And it may be necessary to dehydrate the gas to re-move water vapor.

Installation Requirements and Concerns. There are several im-portant installation requirements associated with gas-lift for gas wells.

- Unloading. Even if the reservoir pressure may be low, it is still necessary to install unloading gas-lift mandrels and valves to unload comple-tion or workover fluid from the annulus. For this process, a conventional unloading design as is used for gas-lift of oil wells should be used.

- Gas-Lift Mandrels. Gas-lift mandrels must be used to install the gas-lift valves used for un-loading. The schematic here shows a typical deign with gas-lift mandrels for unloading. For most gas wells, KB style mandrels that can ac-commodate 1-inch gas-lift valves are adequate. If the casing size is too small for use of “normal” KB style mandrels, it may be necessary to use smaller tubing or even coiled tubing. There are


gas-lift mandrels designed to work with small tubing and coiled tubing.

- Gas-Lift Valves. For unloading gas wells, 1-inch injection pressure operated (IPO) gas-lift valves should be used. If smaller tubing or coiled tubing is used, smaller gas-lift valves may be necessary. At the operating depth (normally the bottom gas-lift mandrel), an orifice may be used rather than a gas-lift valve. A schematic of a gas-lift valve in a man-drel is shown here.

- Packer. When gas is injected down the casing/tub-ing annulus, a packer should be used to prevent the injection pressure from being exerted on the forma-tion. If gas is being injected below the packer, a mechanism is needed to allow the gas to pass be-low the packer. There are several designs available from different companies to allow this to occur.

Operating Requirements and Concerns. There are several im-portant operational requirements associated with gas-lift for gas wells.

- Measurement. The rate of gas injection must be measured so it can be controlled, and so surveillance of the gas-lift operation can be conducted in a routine basis. There are many methods for measurement. The most effective is to use a real-time pro-duction automation system (some people refer to this as a SCADA system) to measure gas injection rate (and volume) on a continuous basis. Some operators measure gas injection manually, but this is never as efficient or effective as using an automation system.

Various devices can be used for gas measurement. These in-clude orifice meters, turbine meters, vortex meters, etc. Each can be effective if they are properly installed, operated, and cali-brated.

- Calculation of Gas Velocity. Based on the measured gas in-jection rate, the velocity can be calculated in the production paths. The velocity may vary if gas is being injected down the annulus and then down a tube below the packer to reach an in-jection point below the perforated interval. The velocity must be the actual velocity of the gas, which depends on the pressure and temperature profile in the well. Therefore, the calculation


system, which will either be in the production automation system or in a computer system that is supporting the operation, must have a means to calculate or estimate the pressure and temper-ature of the gas at depth in the well.

In addition to the actual gas velocity, the critical gas velocity must be calculated so the two can be compared. The goal is to inject enough gas to keep the actual gas velocity above the criti-cal velocity so the well can be continuously deliquified.

- Control of Gas Injection Rate. The gas injection rate must be controlled to be sufficient to achieve and maintain critical flow. The required rate will depend on where the gas is being injected into the tubing. This may be above the packer, below the packer but in a vertical portion of the well, or potentially below the packer and in a horizontal portion of the wellbore.

- Surveillance. The goal is to inject the gas on a continuous ba-sis as deep in the well as possible, so the entire production path can be deliquified. Problems can occur in a gas-lift well includ-ing: o Injection High in the Well. Injecting through an upper gas-

lift valve, thus not deliquifying the well from the desired depth. This can occur if an upper valve re-opens for some reason due to mis-design of the valve’s closing pressure, un-accounted for changes in temperature, valve leakage, etc.

o Multipointing. Injecting through multiple valves, thus wast-ing gas. This can occur if an upper valve is open all or part of the time and gas injection occurs through more than one valve all or part of the time.

o Hole in the Tubing. Injecting through a hole in the tubing, thus wasting gas and not deliquifying from the desired depth. This can occur if a hole has developed in the tubing due to erosion, corrosion, poor make-up, etc.

o Heading. Unstable or heading – pressure fluctuations – thus having inefficient gas-lift operation.

o Other Problems. Many other types of problems can exist at the surface or in the well. There are entire courses that deal with the causes of these problems, how to detect them, and how to correct them.

A good surveillance system can detect these problems so they can be corrected before significant losses occur. Some typical detection methods include:


o Automation Systems. More is said about automation sys-tems in a section below. Suffice it to say here that a real-time automation system can detect surface problems and of-ten can infer downhole problems as well. It can detect prob-lems with the supply of gas to the well, the injection of gas into the well, and production from the well. It can also detect or at least infer downhole problems by calculating (estimat-ing) pressure profiles in the well to determine (estimate) the injection and production pressures at the depth of each gas-lift valve and at the bottom of the well. The good aspect of a real-time automation system is that it can perform these functions 24 hours per day, seven days per week.

o CO2 Tracer Surveys. CO2 tracer surveys are run by inject-ing a small slug of CO2 with the gas-lift gas. The CO2 con-centrate is measured on the production stream and from the time of arrival of the CO2 at the surface, the depth or depths of gas injection into the tubing can be determined. This does not require that the well’s production be stopped and no equipment is placed in the well. This can detect the depth of gas injection into the tubing, if multi-point injection is occur-ring, or if injection is occurring through a tubing leak.

o Pressure and Temperature Surveys. Pressure and tem-perature surveys can be run by inserting a pressure/temper-ature measurement instrument in the well. A flowing pres-sure survey is run with the well on production. Then, pro-duction is stopped for measuring the static bottom-hole pres-sure. The flowing pressure/temperature survey can deter-mine the depth(s) of gas injection. In a gas well, the pressure gradient below the depth of injection should be heavier due to the existence of liquid. The static pressure survey can de-termine the reservoir pressure, or at least the pressure rea-sonably near the wellbore. The static and flowing bottom-hole pressures are used in determining the inflow perfor-mance relationship for the well.

Maintenance Requirements and Concerns. The gas-lift system must be well maintained to be effective. The most important re-quirement are:

- Compression System. o Continuously monitor the compressor suction, inter-stage,

and discharge pressure to assure proper operation.o The compressor(s) must be kept in balance. Check for vi-

bration and correct the foundation of the compressor if vibra-tion is excessive.


o The gas entering the compressor(s) should be “cleaned” of any hydrocarbon liquids. Use a scrubber to remove any liq-uids from the suction gas.

o The system must be cooled to prevent overheating. This is usually required between compression stages. The amount of cooling may be very different in summer than in winter.

o If there is a chance of the suction to the compressor(s) being starved with too little gas, gas can be recalculated from the compressor discharge to the suction.

- Dehydration System. o Monitor the vapor content of the gas discharge to assure it is

dry.o The dehydration system must be maintained to produce

“dry” gas for gas-lift injection.o The typical target is to reduce the amount of water vapor to

less than 7 pounds of water per one million cubic feet of gas.o Check the materials being used in the dehydration system

frequently to be certain they are in adequate supply.

- Distribution System. o Keep the distribution piping clean of any solids or water ac-

cumulation.o Where possible deliver injection gas to a gas-lift manifold

and then from the manifold to the individual wells. o Do this rather than delivering the gas directly from well to

well.

- Measurement System. o Measure the gas-lift distribution system pressure at the dis-

charge of the compressor. o If more than one compressor plant is used for a large distri-

bution system, measure it at each compressor station.o For accurate gas measurement, measure the gas pressure,

temperature, and differential pressure, or turbine pulses.o If a manifold system is being used, measure the gas pres-

sure and temperature upstream of the manifold and then measure the rate of gas to each well downstream of the con-trol valve for each well.

o If gas is being distributed directly to each well, measure the pressure, temperatures, and gas rate at each well.

o In any case, measure the gas-lift injection pressure at the wellhead, downstream of any control device or pressure re-duction device. The goal is to know the actual wellhead in-jection pressure.


o Measure the production pressure at the wellhead, upstream of any control device, wellhead choke, or choke body. The goal is to know the actual wellhead production pressure.

o If wellhead temperature is measured, measure it at a loca-tion where the sun can not affect the measured temperature. The goal is to measure the temperature of the produced fluid, not the atmosphere.

o If the wellhead production rate is measured, measure this as close to the wellhead as possible. This measurement may be made by measuring the differential pressure across a wellhead choke body.

o Measure the pressure at the production manifold. The goal is to compare the pressure at the manifold with the wellhead production pressure to detect any flowline plugging.

- Control System. o Various methods are used to control the gas injection rate.

These range from manually-operated chokes and control valves, to manually-set controllers, to fully automated control systems.

o The objective is to control the rate of injection so the overall injected plus produced gas production rate is slightly above the critical rate.

o Since well conditions can change with time, the control sys-tem should be able to adjust the injection rate with time.

o When gas flow rate is controlled, there will be a pressure drop across the control device. If the gas is not adequately dehydrated, hydrates (ice crystals) may form and may inhibit or block the flow of gas into the well. The recommended ap-proach is to dehydrate the gas so this doesn’t occur. If the gas is not dehydrated, the may be necessary to prevent hy-drate formation by heating the control device, or to remove the hydrates if they form.

o Control devices can leak, or they can become plugged. If the surveillance system is functioning properly, it should be able to detect these problems so they can be corrected.

- Equipment in the Well. The equipment in the well includes the casing, tubing, gas-lift mandrels, gas-lift valves, packer, packer by-pass (if this is used), injection valve or orifice, etc.o Casing. Casing leaks can occur due to corrosion, poor

make-up, or external forces. A casing leak can be detected in a number of ways. If one exists, it should be evaluated and corrected if necessary.


o Tubing. Tubing leaks can occur due to corrosion, erosion, or poor make-up. If a tubing leak exists, it can sometimes be repaired by installing a pack-off across the leak. If the leak is severe, it may be necessary to pull the tubing and replace the bad joint(s). The tubing must not be too large or the gas flow rate to achieve and maintain critical flow velocity will be too large. Conversely, it must not be too small as this will cause a too large pressure drop due to flowing friction.

o Mandrels. Gas-lift mandrels can leak due to corrosion, ero-sion, or problems with seals. If a mandrel leak exists, it may be possible to place a dummy valve in the mandrel or place a pack-off across the mandrel. If the leak can’t be corrected, it may be necessary to pull the tubing and replace the bad mandrel(s).

o Valves. Gas-lift valves can leak, be incorrectly set (wrong set pressure), or be mis-sized. If a gas-lift valve is not func-tioning properly, it can normally be pulled with wireline and replaced.

o Packer. Packers can leak. This can allow injection pres-sure to be exerted on the production formation. It may be possible to reset the packer. If not, it may need to be pulled, redressed or replaced, and reinstalled.

o Packer By-Pass. If gas-lift injec-tion is to occur beneath the packer, there must be a system to allow the gas to flow past the packer and (usually) down an injection string below the packer. See the schematic to the right. If this is not functioning correctly, it must be re-paired.

o Injection Valve or Orifice. The in-jection valve or orifice is the point where gas is injected into the pro-duction path. This may be at the bottom of the casing (above the packer) where gas is injected into the tubing, or it may be at the bottom of an injection string where gas is in-jected from the injection string into the annulus below the packer. If an orifice is used, the most common problem is sizing. Often the orifice is too large which can lead to unsta-ble operation. If the well is heading, and if the cause is a mis-sized orifice, it should be pulled with wireline and re-designed.

- Wellhead System. The purposes of the wellhead are to hold the casing and tubing, connect the flow from the tubing to the


flowline, hold the production pressure measurement device, and hold a choke or control valve in the rare case that this is needed to restrict flow from the well.

The wellhead should be configured to impose a minimum back-pressure on the production from the well. Normally, no choke or control valve should be used, and in some cases the choke body should also be removed. However, it may be kept in place in case a choke is ever needed, or a system is used to estimate the production rate of the well by measuring the pressure drop across the choke body.

- Gathering System. The purpose of the gathering system is to transfer gas and liquid production from the well to the production handling system. The gathering system must be kept clean of water, paraffin, sand, and any other material that may inhibit flow from the well to the handling system. The pressure drop through the system should be monitored or checked periodically to determine if there is any blockage. If the blocking is due to water or paraffin, it may be possible to remove this by pigging the line. If it is due to sand, it may be necessary to replace the line.

- Production Handling System. The production handling sys-tem typically consists of many parts.o Manifold. The manifold is used to route production from in-

dividual wells in to the test separator or the bulk separator. Manifolds can leak and they can cause pressure drops. They should be checked to determine if problems exist so they can be corrected if they do.

o Test Separator. The test separator is used to measure the production rate of gas, oil or condensate, and water from each well, one well at a time. There are many types of sepa-rators. The best is a three-phase separator that can measure the rates of gas, oil or condensate, and water separately. The separator pressure must be set so that the back-pres-sure exerted by the test separator is equivalent to the back pressure exerted by the bulk separator. And separators can sometimes become plugged with sand, paraffin, etc. If this occurs, the separator must be cleaned.

o Bulk Separator. The bulk separator is used to separate the gas and liquid or in some cases, the gas, oil or condensate, and water. The separator pressure must be high enough so gas can flow to the suction of the compressor, but low enough so as to not exert a high back-pressure on the wells.


Bulk separators can also become plugged and need to be cleaned.

o Scrubber. Typically a scrubber is used to remove liquids from the gas before it flows into the suction of the compres-sor. It must be maintained to perform this function correctly.

o Other Equipment. There will often be other equipment in the production facility such as free water knockout systems, tanks, transfer pumps, generators, etc. There will be mainte-nance procedures for each of these components as well.

Cost Guidelines

Capital Expense (CAPEX). The overall capital cost of a gas-lift system can be very expensive. However, there are several factors to consider. The actual cost of this equipment must be determined on a case by case basis, usually by obtaining quotations from the equipment suppliers.

- Compression Plant. Depending on the number of compres-sors, the size of the ancillary equipment (scrubbers, coolers, de-hydrators, etc.), a compression plant may cost in the millions of dollars. However the plant can serve multiple purposes includ-ing compressing gas for sales, for use in the facility, and to serve many gas-lift wells. Once a compression plant exists, the incremental cost to add another gas-lift well may be negligible.

A wellhead or well site compressor may also serve multiple pur-poses. It may compress gas to boost its pressure so it can flow to a remote production facility, it may compress the gas to lower the wellhead pressure to atmospheric pressure or below to aug-ment production from the well, and it may compress gas for gas-lift. If a compressor is used to assist in production, the incre-mental cost to boost the pressure enough for gas-lift injection may not be excessive.

- Distribution System. If a central system is used, the distribu-tion system will typically serve multiple wells. The cost of the system will depend on its design. If gas is distributed to mani-folds and from there to individual wells, the piping cost may be more than if the system brings gas from well to well. However, there are advantages of the manifold design. The primary ad-vantage is the injection pressure for a well is essentially inde-pendent of the injection pressure in other wells; there is no inter-ference between wells. If a manifold type distribution system is already in place, the cost to add another well to the system is


the cost to add an injection line from the manifold to the new well.

If wellhead or well site compression is used, the cost of the dis-tribution system is only the cost to bring the gas from the com-pressor discharge to the wellhead, which may only be a few feet.

Gas-lift on an offshore platform may be similar. Here a compres-sor is installed on a platform. The cost to bring gas to the gas-lift wells on the platform is small. If wells on another platform or platforms in the field are served by the same compressor(s), there must be a line (normally a subsea line) to bring gas to the other platform(s). Here, the gas will be brought to a manifold on the remote platform(s) and distributed from the manifold to the individual wells.

- Wellhead Equipment. If a manifold system is used, typically the lift gas for each well served by the manifold will be mea-sured and controlled at the manifold. There will be one up-stream pressure measurement, one upstream temperature measurement, and a control valve to control the rate of gas in-jection into each well.

If there is no manifold the gas pressure and temperature must be measured at each well and the control must occur at each well.

In either case, the injection pressure should be measured at each well directly on the casing, downstream of any pressure drop devices. And the production pressure should be measured at each well directly on the wellhead, upstream of any pressure drop devices. Further, if a production rate estimate is being made, this should be made at each well.

- Downhole Equipment. The primary gas-lift costs in the well are for gas-lift mandrels and valves. Enough mandrels and valves need to be installed to permit the well to be unloaded to the bottom. The “bottom” will depend on whether gas is being injected from the casing into the tubing above the packer, or is being injected beneath the packer and below the perforations.

Since many gas well artificial lift systems don’t use a packer, the cost of the packer should be included with the downhole equip-ment needed for gas-lift.


- Surveillance (Production Automation) Equipment. Surveil-lance, monitoring, and control of gas-lift may be performed man-ually, with a semi-automatic system, or with a comprehensive production automation system. If an automation system is used, it will entail the following cost components:o Automation Host System. An automation “host” system

will normally consist of a personal computer with associated hardware peripherals, software, database, etc. Typically, a field will have a system to monitor and control production fa-cility equipment, well test systems, etc. The incremental cost to add gas-lift to this system will be for the specific software and database(s) required.

o Facility Remote Terminal Unit. Typically a remote terminal unit (RTU) will be used to monitor and control the gas com-pression plant and its associated equipment. The incremen-tal cost for gas-lift is to measure the gas-lift system pressure.

o Injection Manifold RTU. The injection manifold will be used to support measurement and control of the gas for each well. This is a cost of gas-lift.

o Wellhead RTU. The wellhead RTU will be used to support measurement of the wellhead injection and production pa-rameters – pressure, temperature, etc. This is a cost of gas-lift.

o Ancillary Costs. There will be additional costs for commu-nicating information between the automation host system and the RTUs, and to supply power to the RTUs, which may be solar power if electrical power isn’t available.

- Other Equipment. Most of the rest of the equipment including the wellhead, flowline, production manifold, well test separator, bulk production separator, etc. must exist anyway so it not part of the capital cost of the gas-lift system.

Operating Expense (OPEX). There are operating expenses to be considered. These include:

- Fuel. The cost of fuel to run the compression plant will be shared by the various uses of the plant, but some will be allo-cated to the cost of the gas-lift operation. If wellhead or well site compression is used, produced gas may be used to operate the compressor. Here the cost is equal to the value of the gas had it been sold.

- Consumables. There will be consumables associated with op-erating the dehydration facility, injecting chemicals, etc.


- Labor. The labor costs will depend on how the system is oper-ated and controlled. If it is done manually, there will be labor costs associated with data collection, surveillance, adjusting controllers, etc. If the system is automated, there will be costs associated with using the automatically-collected information to optimize the surveillance and control.

Repair and Maintenance Expense (R&M). On a day-to-day ba-sis, the R&M costs will be modest. However, at times there may be major R&M costs to repair and maintain the compression facility, the dehydrators, the monitoring and control equipment, and of course, the downhole equipment. This last category should not be minimized. If there is a leak or a malfunction downhole, this can se-riously affect the performance of the gas-lift system. When a down-hole problem (leak, mis-sized equipment, etc.) is detected, it must be evaluated and corrected if feasible.

Life Expectancy Guidelines

Infant Mortality (Early Time Failures). Typically there are two types of infant mortality or early time failures that can occur with gas-lift.

- Unloading. Unloading gas-lift valves serve two general pur-poses in a gas-lift well. o Initial Unloading. They are used when gas-lift must be

started initially or after a workover when the casing annulus is full of completion or workover fluid. They must be open during the unloading process and then closed thereafter so gas can be injected below them and into the operating gas-lift valve or orifice. If the unloading process is too rapid and the completion or workover fluid is pushed through the valves too quickly, the valves can erode. If this occurs, it may not be possible to close the valves and inject gas be-neath them. This problem can be largely prevented by fol-lowing the unloading recommendations of the American Pe-troleum Institute. These recommendations are to unload the well slowly, with a slow build-up of injection pressure and flow of liquid through the unloading valves.

o Kick-Off. They may be needed again if a well must be restarted after a period of downtime. Here, there is normally no liquid in the annulus since it has previously been un-loaded. Therefore, there is much less risk of damaging the unloading valves.


- Mandrel and Valve Design. A second type of infant mortality or lack of desired performance can occur if the mandrel spac-ings and valve set pressures are not properly designed. These problems can be alleviated by following conservative design methods for mandrel spacing and using accurate temperature estimates for the depths of the gas-lift valves. o Mandrels. If the mandrels are too far apart, it may not be

possible to unload to the deeper valves. Conservative man-drel spacing will result in use of more mandrels but if a man-drel is not needed initially, a dummy can be installed.

o Valves. If the valve set pressures are not correct, it may not be possible to close the upper valves during the unloading process or to re-open them when they are needed for subse-quent kick-off. Accurate temperature estimates can be made using projections of both static (earth) temperature gradients and flowing temperature gradients measured on other wells in the field.

Normal Operating Life. There are many things that can go wrong in a gas-lift well, and thus the need for close surveillance of the op-eration. However, the gas-lift equipment should, for the most part, have a long operating life of many years. This will almost certainly be true if the equipment is properly maintained. The component most likely to fail or need replacement is the operating gas-lift valve or orifice. There are two reasons for this.

- Operating Depth. As the well ages and production proceeds, the reservoir pressure may change and/or the well’s inflow per-formance may change. When either of these occur, it may be-come necessary to operate from a different (usually deeper) valve. This may require that the valves in the well be pulled and redesigned to allow the well to lift from a different depth.

- Operating Valve or Orifice. If the necessary gas-lift injection rate changes, it may be necessary to change the design of the operating gas-lift valve or orifice. This can usually be accom-plished by pulling the valve or orifice with wireline and replacing it.

Recommended Practices for Automation, Surveillance, and Opti-mization of Continuous Gas-Lift Systems

A detailed discussion of automation, surveillance, and optimization is in Section 4.2 of this Recommended Practice, and the documents it refer-ences. The purpose here is to provide a brief outline of the subject.


Automation. Automation involves using computers and electronic systems and instrumentation to automate certain gas-lift functions:

- Data Acquisition. Data is acquired from the wells and facilities by remote terminal units (RTUs), programmable logic controllers (PLCs), or distributed control systems (DCSs) that are installed at the well, manifold, or facility. Typically, these systems gather data at least once per second, and sometimes much more frequently. They gather the data, convert is to a digital format, store it for for-warding to the host Automation System, and may perform calcula-tions such as detecting alarms, calculating flow rates, etc.

- Communication. Typically the host Automation System scans the RTUs, PLCs, or DCSs and requests transmission of the data from them. Typically, this is done on a frequency of once every several minutes. The host system may also communicate param-eters and commands to the remote units. These commands may be generated automatically by the host Automation system, or they may be entered by the system operator. The communica-tions are secure; they are protected to assure against receiving or sending errors, and against being intercepted by unauthorized 3rd parties.

- Calculations. The Automation system can make many types of calculations. Examples include calculating the:o Current gas flow velocity at any pertinent depth in the well.o Critical gas flow velocity needed to achieve liquid unloading.o Amount of gas that needs to be injected into the well to

achieve and maintain critical flow.o Allocation of gas to each well in the case of an overall short-

age of gas in the field.

- Remote Control. The Automation system can perform remote control of the wells. It can do this automatically based on adjust-ing the gas injection rate to achieve and maintain critical flow. It can also do this automatically if required to balance overall out-flow from the gas-lift distribution system into the wells with inflow into the system from the compression plant(s), high pressure gas wells, etc. It can also do this manually when the field operator re-quests a change in injection rate or requests the injection to a well to be turned off, etc.

Surveillance. A major job of the Automation System is to continu-ously monitor the gas-lift system and wells to detect any problems. It does this in a number of ways:


- Alarms. The Automation system monitors for and detects at least three classes of alarms.o Class I Alarms. These are simple, straight-forward alarms

such as pressure too high or too low, flow rate too high or too low, etc. The Automation system should contain a significant amount of logic to filter out “nuisance” alarms and only report alarms that people need to observe and on which they can take action.

o Class II Alarms. These are alarms that are based on a com-bination of information (e. g combination of pressure, tempera-ture, and flow data) that provide unique information of the gas-lift operation. Examples include detection of hydrate formation and freezing problems, detection of shallow injection through a tubing leak or leaking upper gas-lift valve or mandrel, detec-tion of multi-point injection through more than one valve all or part of the time, detection of an imbalance between the use of gas for injection into the wells served by the system and the source of gas into the system, and detection of injection below the required rate to achieve and maintain critical flow.

o Class III Alarms. These are alarms or situations that are found by running models of the well’s operation. An example is estimation of the injection depth in the well by calculating which valve(s) is/are open with the current injection and pro-duction pressures and temperatures in the well.

- Reports. The Automation system can produce several types of reports. These reports may be produced on a fixed schedule (e.g. daily, at shift change, etc.), on request, or on the occurrence of some event such as a major alarm or facility upset. The reports may contain current data, historical data, statistical data, etc.

- Plots. The system can produce several types of plots. As with reports, they may be displayed on a fixed schedule, on de-mand, or on the occurrence of a major event. The plots may show current data or historical data. They may show variables (e.g. pressure, temperature, flow rate, etc.) vs. time or they be “x, y” plots showing pressures vs. depth.

- Graphics. The system can display graphical images, such as an image of a gas-lift well with key variables and parameters shown on the image. Graphics can be of one well, a group of wells at a well site, or of an entire distribution system.


Optimization. The word optimization means different things to differ-ent people:

- Problem Solving. Some people say that they have “optimized” their gas-lift system if they have detected and corrected problems in the system. Most of the problem detection is done with a good surveillance system. Problem correction requires that actions be taken to address the problems so the system and wells operate at peak efficiency.

- Well Optimization. Gas-lift wells are optimized if the optimum amount of gas is being injected, at the optimum depth, to achieve the optimum rate of production. For gas wells, the optimum injec-tion rate is that needed to achieve and maintain critical flow. The optimum depth is as deep as possible, and hopefully beneath the perforations so that the entire well is deliquified. The optimum production rate is removal of all of the liquid so there may be free flow of the gas. This level of optimization requires determination of the amount of gas that is needed for deliquification, design of the well to permit injection as deep as possible, monitoring of the liquid production rate, and the pressure profile in the well, to as-sure that all of the liquid is being produced.

- Full Field Optimization. Optimization of gas injection into indi-vidual wells may not result in optimum operation of the entire field. There may not be enough high pressure gas to “optimize” each well. And, there may be restrictions in distribution lines or gather-ing lines that inhibit optimum production. Full field optimization re-quires that the full field system be monitored and evaluated. It may mean some wells must be operated at less than optimum so the overall performance of the system can be as good as it can be under the less than ideal conditions.

Information on Continuous Gas Circulation

The rest of this document addresses continuous gas-lift. There is a version of continuous operating referred to as con-tinuous gas circulation (CGC). A schematic of this is shown to the right. It differs from normal continuous gas-lift in several important ways.

No Packer. For continuous gas circulation, there is no packer installed in the well. Gas is injected down the cas-ing/tubing annulus, around the end of the tubing, and into the tubing to produce the well.


No Gas-Lift Valves. There are no gas-lift valves. The well is un-loaded by pushing any liquid back into the formation and then circu-lating the gas down the annulus and up the tubing to produce the liq-uid from the well.

Continuous Operation. Whereas continuous gas-lift may be stopped and restarted if necessary, and wells can be initially un-loaded and then kicked off, CGC must operate continuously. If a CGC well needs to be stopped, any liquid in the well must be pushed back into the formation to start the well again.

Gas Supply. Normally gas for CGC is supplied by using a wellhead compressor.

CGC Advantages. The advantages of CGC are that it is lower cost since there is no packer and no gas-lift valves. Many gas wells are completed without a packer. So, CGC can be started in a well with-out the need for a workover to install a packer and gas-lift valves. And, since the source of high pressure gas is normally from a well-head compressor, there are no distribution lines and no issues with system wide optimization or control.

CGC Disadvantages. The disadvantages are that fluid must be pushed into the formation to start the process, and it can be difficult to restart a well if it goes off production for some reason

Information on Intermittent Gas-Lift

Intermittent gas-lift is often used for oil wells that no longer produce enough to sustain continuous flow gas-lift. Normally this isn’t pertinent for gas wells since the idea is to continuously remove liquids so the gas can flow freely. However, if a well only produces a small amount of liq-uid, it may not be necessary to inject gas all of the time. This would not be true intermittent gas-lift, but might be referred to as timer-controlled gas-lift.

Copyright

Rights to this information are owned by the Artificial Lift Research and Develop-ment Council (ALRDC). This material may be used by any member of ALRDC in any way they see fit as long as they refer to the ALRDC Artificial Lift Selection document where it is presented.

Disclaimer


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well deliquification/New Doc… · Web viewErosion occurs if the gas and liquid production is carrying an erosive material (e.g. hydrates, sand, scale, etc.) that can impinge on