Selection of Artificial Lift Types

ARTIFICIAL LIFT METHODS

1. INTRODUCTION AND SELECTION CRITERIA

This module will introduce the topic of artificial lift - a production engineering topic of increasing importance in field development. The reasons leading to this increasing importance in the field development process will be reviewed. The main factors influencing the selection of the most important artificial lift techniques will be highlighted.

A brief description will then be given of all the common artificial lift techniques (rod pumps, electric submersible pumps, progressive cavity pumps and hydraulic pumps) apart from gas lift.

Hydrocarbons will normally flow to the surface under natural flow when the discovery well is completed in a virgin reservoir. The fluid production resulting from reservoir development will normally lead to a reduction in the reservoir pressure, increase in the fraction of water being produced together with a corresponding decrease in the produced gas fraction. All these factors reduce, or may even stop, the flow of fluids from the well. The remedy is to include within the well completion some form of artificial lift. Artificial lift adds energy to the well fluid which, when added to the available energy provided “for free” by the reservoir itself, allows the well to flow at a (hopefully economic) production rate.

2. THE NEED FOR ARTIFICIAL LIFT

Artificial lift is required when a well will no longer flow or when the production rate is too low to be economic. Figure 1(a) illustrates such a situation - the reservoir pressure is so low that the static fluid level is below the wellhead. 

Question: Is it possible for this well to flow naturally under and conditions.

Answer: Yes: If the well productivity Index is sufficiently high and the produced fluid contains enough gas that the flowing fluid pressure gradient gives a positive wellhead pressure. But, the well has to be "kicked off" (started flowing) by swabbing or other techniques.

Figure 1(b) shows how installation of a pump a small distance below the static fluid level allows a limited drawdown (Dp') to be created. The well now starts to flow at rate q. N.B. the static and flowing pressure gradients in figures 1(a) & 1(b) are similar since frictional pressure losses in the tubing are small at this low flow rate.

It can be readily seen that the same production rate will occur when the pump is relocated to the bottom of the tubing, provided the pressure drop across the pump, and hence the drawdown, remains the same. The advantage of placing the pump near the perforations is that the maximum potential production can now be achieved {figure 1(c)} by imposing a large drawdown (DP") on the formation and “pumping the well off” by producing the well at q2 is slightly smaller than the AOF. Artificial lift design requires that the pump to be installed is matched to the well inflow and outflow performance. 

Figure 1c Installation of pump suction below the perforations maximises potential drawdown and production rates

3. REVIEW OF ARTIFICIAL LIFT TECHNIQUES

The most popular forms of artificial lift are illustrated in figure 2. They are:

(i) Rod Pumps - A downhole plunger is moved up and down by a rod connected to an engine at the surface. The plunger movement displaces produced fluid into the tubing via a pump consisting of suitably arranged travelling and standing valves mounted in a pump barrel.

(ii) Hydraulic Pumps use a high pressure power fluid to: (a) drive a downhole turbine pump or (b) flow through a venturi or jet, creating a low pressure area which produces an increased drawdown and inflow from the reservoir.

(iii) Electric Submersible Pump (ESP) employs a downhole centrifugal pump driven by a three phase, electric motor supplied with electric power via a cable run from the surface on the outside of the tubing.

(iv) Gas Lift involves the supply of high pressure gas to the casing/tubing annulus and its injection into the tubing deep in the well. The increased gas content of the produced fluid reduces the average flowing density of the fluids in the tubing, hence increasing the formation drawdown and the well inflow rate.

(v) Progressing Cavity Pump (PCP) employs a helical, metal rotor rotating inside an elastomeric, double helical stator. The rotating action is supplied by downhole electric motor or by rotating rods.

4. SELECTION OF ARTIFICIAL LIFT CRITERIA

There are many factors that influence which is the preferred form of artificial lift.
Some of the factors to be considered are:

4.1. Well and Reservoir Characteristics

(i) Production casing size.
(ii) Maximum size of production tubing and required (gross) production rates.
(iii) Annular and tubing safety systems.
(iv) Producing formation depth and deviation (including doglegs, both planned and unplanned).
(v) Nature of the produced fluids (gas fraction and sand/wax/asphaltene production).
(vi) Well inflow characteristics. A “straight line” inflow performance relationship associated with a dead oil is more favourable than the curved “Vogel” relationship found when well inflow takes place below the fluid’s bubble point. Figure 4 shows that reducing the flowing bottomhole pressure from 2500 to 500 psi increases the well production rate by 125% for the dead oil. This is more than double the 60% increase expected for the same reduction in bottom hole pressure if a “Vogel” type inflow relationship is followed with a well producing below the bubble point.


Figure 4 Influence of fluid in flow performance on production increase achieved when well drawdown is increased

4.2. Field Location

(i) Offshore platform design dictates the maximum physical size and weight of artificial lift equipment that can be installed.
(ii) The on-shore environment can also strongly influence the artificial lift selection made. For example:
           (a) an urban location requiring a maximum of visual and acoustic impact or
         (b) a remote location with minimal availability of support infrastructure can lead to       different artificial lift types being selected for wells of similar design and producing characteristics.
(iii) Climatic extremes e.g. arctic operations will also limit the practical choices.
(iv) The distance from the wellhead to the processing facilities will determine the minimum wellhead flowing pressure (required for a give production rate). This may, for example, make the choice of an ESP more attractive than Gas Lift. This is because the extra pressure drop in the flowline, due to the injected gas, makes Gas Lift an unsuitable option for producing satellite hydrocarbon accumulations isolated from the main field.
(v) The power source (natural gas, mains electricity, diesel, etc) available for the prime mover will impact the detailed equipment design and may effect reliability e.g. the voltage spikes often associated with local electrical power generation have been frequently shown to reduce the lifetime of the electrical motors for ESP’s.

4.3. Operational Problems

(i) Some forms of artificial lift e.g. gas lift are intrinsically more tolerant to solids production (sand and/or formation fines) than other forms e.g. centrifugal pumps.
(ii) The formation of massive organic and inorganic deposits - paraffins, asphaltenes, inorganic scales and hydrates - are often preventable by treatment with suitable inhibitors. However, additional equipment and a more complicated downhole completion are required unless, for example, the inhibitor can be carried in the power fluid for a hydraulic pump or can be dispersed in the lift gas.
(iii) The choice of materials used to manufacture the equipment installed within the well will depend on the:
     (a) Bottom Hole Temperatures.
     (b) Corrosive Conditions e.g. partial pressure of any hydrogen sulphide an carbon                          dioxide, composition of the formation water etc.
     (c) Extent of Solids Production (erosion).
     (d) Producing Velocities (erosion/corrosion).

4.4. Implementation of Artificial lift Selection Techniques

As discussed the artificial lift design engineer is faced with matching facility constraints, artificial lift capabilities and the well productivity so that an efficient lift installation results. Frequently, the type of lift has already been determined and the engineer has the problem of applying that system to the particular well. A more fundamental question is how to determine the optimum type of artificial lift to apply in a given field.
There are certain environmental and geographical considerations that may be overriding.
For example, sucker rod pumping is by far the most widely used artificial lift method in North America. However, sucker rod pumping may be eliminated as a suitable form of artificial lift if production is required from the middle of a densely populated city or on an offshore platform with it’s limited deck area. There are also practical limitations - deep wells producing several thousands of barrels per day cannot be lifted by rod pumps. Thus, geographic and environmental considerations may make the decision. However, there are many considerations that need to be taken into account when such conditions are not controlling.
Some types of artificial lift are able to reduce the sand face producing pressure to a lower value than others. The characteristics of the reservoir fluids must also be considered. Wax & formation solids present greater difficulties to some forms of artificial lift than others. The producing gas-liquid ratio is key parameter to be considered by the artificial lift designer. Gas represents a significant problem to all of the pumping methods; while gas lift, on the other hand, utilizes the energy contained in the produced gas and supplements this with injected gas as a source of energy.
The “Advantages and Disadvantages of the Major Artificial Lift Methods” are listed and compared in Tables 1& 2.

Table 1 Advantages of major artificial lift methods

Table 2 Disadvantages of major artificial lift methods