March 23, 2021

Further WROP-System Tests are scheduled for April 2021.



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Usage of artificial lift systems and Why it is easy to choose the Multi-Functional WROP-System.

Please read below how complicated it is to make the correct and right decisions for an Artificial Lift System.


Please be aware that all Wells are changing erery time and if you choose for the WROP-System, you can make any choice for lifting the Oil any time without the expensive Workover Rigs or even killing a well prior to change the AL method.



There are approximately 2 million oil wells in operation worldwide. More than 1 million wells use some type of artificial lift. More than 750,000 of the lifted wells use sucker-rod pumps. In the US, sucker-rod pumps lift approximately 350,000 wells. Approximately 80% of all US oil wells are stripper wells making less than 10 B/D with some water cut. The vast majority of these stripper wells are lifted with sucker-rod pumps. Of the nonstripper “higher” volume wells, 27% are rod pumped, 52% are gas lifted, and the remainder are lifted with ESPs, hydraulic pumps, and other methods of lift. These statistics indicate the dominance of rod pumping for onshore operations. For offshore and higher-rate wells around the world, the use of ESPs and gas lift is much higher.

Selecting an artificial lift system

To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field vary broadly across the industry. The methods include:

  • Operator experience
  • What methods are available for installations in certain areas of the world
  • What is working in adjoining or similar fields
  • Determining what methods will lift at the desired rates and from the required depths
  • Evaluating lists of advantages and disadvantages
  • “Expert” systems to both eliminate and select systems
  • Evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value basis

These methods consider:

  • Geographic location
  • Capital cost
  • Operating cost
  • Production flexibility
  • Reliability
  • “Mean time between failures”

In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. Also, the equipment and services available from vendors can easily determine which lift method will be applied. However, when significant costs for well servicing and high production rates are a part of the scenario, it becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. See Artificial lift selection methods. If the “best” lift method is not selected, such factors as long-term servicing costs, deferred production during workovers, and excessive energy costs (poor efficiency) can reduce drastically the net present value (NPV) of the project. Typically, the reserves need to be produced in a timely manner with reasonably low operating costs. Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project. Good data are required for a complete present-value analysis, and these data are not always broadly available.

Environmental and geographical considerations may be overriding issues. For example, sucker-rod pumping is, by far, the most widely used artificial lift method in onshore US operations. However, in a densely populated city or on an offshore platform with 40 wells in a very small deck area, sucker-rod pumping might be a poor choice. Also, deep wells producing several thousands of barrels per day cannot be lifted by beam lift; other methods must be considered. Such geographic, environmental, and production considerations can limit the choices to only one method of lift; determining the best overall choice is more difficult when it is possible to apply several of the available lift methods.

Artificial lift method selection should be a part of the overall well design. Once the method is selected, the wellbore size required to obtain the desired production rate must be considered. Many times, a casing program has been designed to minimize well-completion costs, but it is later found that the desired production could not be obtained because of the size limitation on the artificial lift equipment. This can lead to an ultimate loss of total reserves. Even if target production rates can be achieved, smaller casing sizes can lead to higher long-term well-servicing problems. If oil prices are low, it is tempting to select a small casing size to help with current economics. Obviously, wells should be drilled and completed with future production and lift methods in mind, but this is often not the case.

Reservoir pressure and well productivity

Among the most important factors to consider when selecting an artificial lift system are current and future reservoir pressure and well productivity. If producing oil or liquid rate is plotted (X axis) against producing bottomhole pressure (BHP) [Y axis], one of two inflow performance relationships (IPR) usually is seen. Above the bubblepoint pressure, the liquid rate vs. pressure drop below the reservoir pressure (drawdown) is linear. Below the bubblepoint pressure, a relationship similar to that described by Vogel[1] occurs. Fig. 1 illustrates production vs. drawdown relationships as a single IPR with a bubblepoint of 750 psig and an average reservoir pressure of 2,000 psig. If the necessary data are available, a single-phase IPR expression for either gas or liquid flow is available from radial-flow equations. Gas deliverability curves show a nonlinear dependence of gas rate similar to the liquid rate vs. pressure on a Vogel curve.[1] Liquid-rate IPR curves can have a gas-to-liquid ratio associated with the liquid rate, and gas deliverability curves can have a liquid production (e.g., bbl/MMscf/D) associated with the gas rates. Our discussion will focus on IPRs with liquid production as a function of the flowing BHP.

  • Fig. 1—IPR with bubblepoint pressure of 750 psi.

Some types of artificial lift can reduce the producing sandface pressure to a lower level than other artificial lift methods. For pumping wells, achieving a rate that occurs below the bubblepoint pressure requires measures to combat possible gas interference because gas bubbles (free gas) will be present at the intake of the downhole artificial lift installation. In addition to setting the pump below the perforations, such measures include the use of a variety of other possible gas-separation schemes and the use of special pumps to compress gas or reduce effects of “fluid pound” in beam systems. However, the artificial lift method of gas lift is assisted by the production of gas (with liquids) from the reservoir.

The reward for achieving a lower producing pressure will depend on the IPR. With the IPR data available, a production goal may be set. For low-rate wells, the operator would want to produce the maximum rate from the well. For high-rate wells, the production goal can be set by the capacity or horsepower limit of a particular artificial lift method.

In addition to radial flow and IPR expressions for vertical wells, there are several IPR models[2] for horizontal wells. Horizontal wells typically produce several multiples of what a vertical well would produce in the same formation. Artificial lift usually is installed in the near vertical portion of a horizontal well, rarely into the horizontal portion, to reduce slugging and to achieve maximum drawdown.

IPRs can be generated to represent the expected well conditions as the shut-in pressure depletes. When correlated to a reservoir model or a tank material balance, time can be associated with future IPRs. Fig. 2 shows future IPR curves as the reservoir pressure drops as a result of depletion. This particular model shows the productivity index (PI) remaining constant above the bubblepoint as the reservoir depletes. The bubblepoint would not necessarily remain constant with time as modeled here. Reservoir models may be used to predict expected inflow conditions of the wells for the life of the project. Usually this is done only for larger projects. IPR expressions can be modified to show damage or stimulation effects. A test rate or absolute open flow for an IPR increase due to skin removal can be found by multiplying by approximately (7+ s)/7 in which s is the nonrate dependent initial “skin” of the well and the final skin is zero. This approximate ratio is determined by dividing a radial-flow rate equation with no skin by a radial-flow equation with skin. The “7” is approximately the log of 0.472 times the drainage radius over the wellbore radius. More complex relationships show the effects of rate-dependent skin or turbulence. For more discussion, see Formation damage.

  • Fig. 2—IPR with shut-in pressure declining with time.

Reservoir fluids

The characteristics of the reservoir fluid also must be considered. Paraffin buildup can be attacked mechanically when sucker-rod pumping is used, but may require a thermal or chemical method when other artificial lift methods are used. Sand- or solids-laden production, which can rule out the use of plunger lift, can also cause wear with sucker-rod pumps, reciprocating hydraulic pumps, and jet pumps. Gas lift and PCPs produce moderate volumes of solids with only minor problems. The producing gas/liquid ratio is very important to the lift designer. If the percentage of free gas at intake conditions is high, gas interference is a potential detriment to all methods of lift, but it is a benefit to gas lift. High-fluid viscosity hinders most major forms of lift, but the PCP may produce low temperature, shallow, viscous fluids with little difficulty.

Long-term reservoir performance and facility constraints

Two approaches frequently are taken to account for long-term reservoir performance:

  • Design on the basis of anticipated performance
  • Design on the basis of current conditions

If future reservoir performance can be predicted, artificial lift equipment can be installed that can produce up to the largest rate anticipated over the life of the well. This philosophy leads to the installation of oversized equipment, perhaps in anticipation of ultimately producing large quantities of water. Because most artificial lift methods operate at poor efficiency when underloaded, oversized equipment installed because of anticipated high short-term production rates can lead to high energy or operational costs over a significant fraction of the life of the field.

Another extreme is to design only for current conditions without anticipating future production profiles. This can lead to multiple required changes in the size or type of installed lift equipment. Operating efficiently during the short term may be possible, but large amounts of capital for changing equipment may be required later. For example, changing reservoir conditions with time, as shown in Fig. 2, would have to be considered carefully in sizing artificial lift equipment for current conditions and for some future date. Bennet[3] addresses some of the concerns of timing related to artificial lift methods.

The operator should consider both long-term and short-term aspects of an artificial lift plan. The goal is to maximize the present value profit (PVP) of the operation over the life of the field. Frequently, the lift method that produces the most oil is the method that provides maximum PVP. However, if operational costs are significantly high for a particular method, a method that can only produce a lower rate but produces more reliably may be more economical. Changes in a lift method usually are not considered worthwhile, but, if conditions change drastically, other lift methods may need to be implemented.

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