selection of artificial lift method

8/12/2019 Selection of Artificial Lift Method

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Selection of Artificial Lift Method

Abstract

This Paper summarizes the opening remarks of the panel members on a panel discussion of

"Selection of Artificial Lift Method". This is not a co-authored paper in the normal sense. It is paper

with five sections, each section independently authored by a panel member.

Reservoir and well considerations

In artificial design the engineer is faced whit matching artificial lift capabilities and the well

productivity so that an efficient lift installation results. With the increasing cost of energy, it is

becoming more important that the best efficiency possible be obtained. In the typical artificial lift

problem, the type of lift has already been determined and the engineer has the problem of

applying that system to the particular well. the more basic question, however, is how do we

determine what is the proper type of artificial lift to apply in a given field. Each of four major types

of artificial lift will be discussed a little later by one of the panel members. this introduction willattempt to look at some of the reservoir and well factor that should be taken into consideration in

making this initial basic decision on the type of artificial lift to use.

There are certain environmental and geographical considerations that may be overriding issues.

For example, sucker rod pumping is by far the most widely used artificial lift method in the United

States. However, if we are in the middle of densely populated city or on an offshore platform with

forty wells contained in a very small deck area, sucker rod pumping may be eliminated as a viable

means of lift to be considered. these geographic an environmental considerations may

considerations that need to be taken into account when these conditions are not predetermining

factors.

among the important factors to consider are reservoir pressure and well productivity. if producing

rate Vs. producing bottom-hole pressure is plotted, one of two relationship will usually occur.

Above bubblepoint pressure, it will be a straight line. Below bubblepoint pressure, a curve as

described by vogel will occur. These two types of productivity relationship are shown in figure 1.

Some types of artificial lift are able to reduce the producing pressure to a lower level than other

types. The reward for achieving a lower producing pressure will depend on the type of productivity

relationship. For example, a well in a reservoir whit 2000 psi reservoir pressure and a producing

pressure of 500 psi will be producing 75 percent of the maximum rate if the well has a straight line

productivity relationship. On the other hand, if it is following a vogel curve relationship, it will be

producing 90 percent of the maximum rate. the characteristics of the reservoir fluids must also be

considered. Paraffin is a much more difficult problem with some kinds of lift than others the

production of solids from the formation along with the well fluids needs to be considered. Sand

can be very detrimental to some types of lift and much less so on others. The producing gas-liquid

ratio is very important to the lift designer. Gas is a significant problem to all of the pumping

methods. Gas lift, on the other hand, utilizes the energy contained in the produced gas and simply

supplements this source of energy.


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Another factor that needs to be considered is the long term reservoir performance. Two

approaches have frequently been taken in the past, both of which, in my opinion, are extreme and

wrong. In some cases we predict long term reservoir performance and install artificial lift

equipment that can handle the well over its entire life. This frequently led to the installation of

oversized equipment in the anticipation of ultimately to producing large quantities of water. As a

result, the equipment may have operated at poor efficiency due to underloading over a significant

portion of its total life. The other extreme is to design for what the well is producing today and not

worry about tomorrow. This can lead to change after change after change in the type of lift

equipment installed in the hole. We may operate efficiently short term but spend large amounts

of capital dollars in changing equipment. The design engineer must consider both long term and

short term aspects. Our aim is to maximize the overlife efficiency of the operation. This may or

may not anticipate a lift system change in the future.

Sucker Rod Pumping

Sucker road pumping systems are the oldest and most widely used type of artificial lift for oil wells.

In fact, approximately 85 percent of artificially lifted wells are produced by beam pumping

equipment. About 79 percent of the oil wells make less than 10 barrels of oil per day and are

classified as stripper wells. A vast majority of these stripper wells are lifted with sucker rod pumps.

Of the remaining 26 percent, about 20 percent are lifted with sucker rod pimping systems, 28

percent are flowing and the remaining 52 percent are lifted by gas lift, submersible electric pumps

and subsurface hydraulic pumps.

Sucker rod systems should also be considered for lifting moderate volumes from shallow depths

and small volumes from intermediate depths. If the well fluids do not contain hydrogen sulfide, or

if specialty sucker rods are used, it is possible to lift 1,000 barrels from about 7,000 feet and 200

barrels from approximately 14,000 feet. If the well fluids contain hydrogen sulfide, sucker rod

pumping systems can lift 1,000 barrels of liquid per day from 4,000 feet and 200 barrels per day

from 10,000 feet.

Most of the parts of the sucker rod pumping system are manufactured to meet existing standards,

which have been established by the American Petroleum Institute. Numerous manufacturers can

supply each part, and all interconnecting parts are compatible.

The sucker rod string, parts of the pump and unanchored tubing are continuously subjected to

fatigue. Therefore, the system must be more effectively protected against corrosion than any-

other lift system to insure long equipment life.

Sucker rod pumping systems and crooked holes are often incompatible.

The ability of sucker rod pumping systems to lift sand is limited.

Paraffin and scale can interfere with the efficient operation of sucker rod pumping systems.


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If the gas- liquid separation capacity of the tubing-casing annulus is too low, or if the annulus is not

used efficiently, and the pump is not designed and operated properly, the pump will operated

inefficiently and tend to gas lock.

One of the disadvantages of a beam pumping system is that the polished rod stuffing box can leak.

However, if proper design and operating criteria are considered and followed, that disadvantagecan be minimized.

Gas Lift

Gas lift dominates the Gulf Coast of the USA as a means of artificial lift and is used extensively

around the world. Most of these wells are on constant flow gas lift. Thus, the questions: "Why

choose gas lift?", "Where do you use constant flow?" and "When do you select intermittent lift?"

Constant Flow Gas Lift

Constant flow gas lift is recommended for high volume and high static bottom hole pressure wells

where major pumping problems will occur. It is an excellent application for offshore clastic-type

formations with water drive, or waterflood reservoir with good PI's and high GORs. When high

pressure gas is available without compression or where gas is low in cost, gas lift is especially

attractive. Constant flow gas lift use the produced gas with additional injection allowing the

producing gradient to be lowered so that the well will "flow" much better.

It should be obvious that a reliable, adequate supply of good quality high-pressure lift gas is

mandatory. This supply is necessary throughout the producing life, if gas lift is to be affectively

maintained. In many fields the produces gas declines as the wells water cut increases; thus,

requiring some outside source of gas. Also the wells will produce erratically or not at all when the

lift supply stops or pressure fluctuates radically. Furthermore, poor quality gas will impair or even

stop production. Thus the basic requirement for gas must be met or other artificial lift means

should be installed.

Constant flow gas lift imposes a relatively high bas pressure on the reservoir and is at best only

moderately efficient as compared with most pumping methods. Thus the high back pressure may

significantly increase both capital cost and operating energy costs.

What are the strengths of constant flow gas lift?

1. Gas lift is the best artificial lift method for handling sand or solid materials. Many wellsmake some sand or solid materials. Many wells make some sand even if sand control is

installed. The produced sand causes almost no mechanical problem to the gas lift valve;

whereas, only a little sand play havoc with most pumping methods.

2. Deviated or crooked holes can be gas lifted with only minor lift problem. This is especiallyimportant for offshore platform wells which are directionally drilled.

3. Gas lift permits the use of wireline equipment and such equipment is easily andeconomically serviced. This feature allows for routine repairs through the tubing.


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4. The normal design leaves the tubing full opening. This permits use of BHP surveys, sandsounding and bailing, production logging, cutting paraffin, etc.

5. High formation GOR's are helpful rather than being a hindrance. Thus in gas lift, lessinjection gas is required; whereas, in all pumping methods, pumped gas reduces efficiency

drastically.

6. Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentiallythe same well equipment. In some cases, switching to annular flow can also be easily

accomplished to handle exceedingly high volumes.

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

8. Gas lift has a low profile. The surface well equipment is the same as for flowing wellsexcept for injection gas metering. The low profile is usually an advantage in urban

environments.

9. Well subsurface equipment in relatively inexpensive and repair and maintenance of thissubsurface equipment is normally low. The equipment is easily pulled and repaired or

replaced. Also major well workovers occur infrequently.

10. Installation of gas lift is compatible with subsurface safety valves and other surfaceequipment. Use of the surface controlled subsurface safety valve with the -inch control

line allows easy shut-in of the well.

11.Gas lift will tolerate some bad design assumptions and still work. This is fortunate sincethe spacing design must usually be made before the well is completed and tested.

What are the limitations?

1. Relatively high back pressure may seriously restrict production in continuous gas lift. Thisproblem becomes more significant with increasing depths and declining static BHP's. Thusa 10,000 foot well with a static BHP of 1000 psi and PI of 1.0 would be difficult to lift with

the standard constant flow gas lift system. However, there are some special schemes that

could be tried for such wells.

2. Gas lift is relatively inefficient, often resulting in large capital investments and high energyoperating costs. The cost of compressor are relatively high and are often long delivery

item. Costs in 1981 were found to be $500 to $600 per horsepower for typical land

locations and $100 to $1400 per horse-power for offshore packages. the compressor

presents space and weight design problems when used on offshore platforms. Also, the

cost of the distribution systems onshore may be significant. Increased gas usage also may

increase the size of flow line and separators needed.3. Adequate gas supply is needed throughout life of project. If the field runs out of gas or if

gas becomes too expensive, one may have to switch to another lift method. In addition,

there must be enough gas for easy start-ups.

4. Operation and maintenance of compressors can be expensive. Skilled operator and goodcompressor mechanics are required for successful and reliable operation.


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selection of artificial lift method

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