Skip to search form Skip to main content You are currently offline. Some features of the site may not work correctly. It seeks to identify the injection lines that lead to clusters with at least one active injector well, where a preselection of the producing wells candidate for the change of ALS is carried out according to the characteristics of the production fluid at surface and the IPR curve developed from real data of the field, verifying the values of these aspects in a matrix. View PDF. Save to Library. Create Alert.

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See our User Agreement and Privacy Policy. See our Privacy Policy and User Agreement for details. Published on Jun 4, Maximizing production in high gaswells produced with artificial lift systems is one of the greatest challenges operators face daily. Multiple shutdowns and frequent Gas Locking negatively affect the runlife and profitability of ESP systems.

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Generally, an eBook can be downloaded in five minutes or less Be the first to like this. No Downloads. Views Total views. Actions Shares. Embeds 0 No embeds. No notes for slide. Diaz bakerhughes. Has designed a first-to-industry intelligent solution to solve the problems caused by gas locking in ESP systems: a variable speed drive with built-in gas control software that can mitigate and clear gas locking, manage draw down to minimize formation face damage, and avoid gas locking during extended gas slugs to improve production.

The case history presents a mature well with water injection secondary recovery. Keywords: Gassy wells, submersible pumping, gas control, smart variables.

Introduction Electrical submersible pumping ESP systems are a form of artificial lift developed, installed and operated to help operators companies to maximize production flow rates while reducing investment. This technology provides an effective and economical means of lifting fluids for different well and reservoir conditions. Operators are using more often ESP technology in their fields as flexibility of this technology has led them to produce almost all conditions including abrasives, high gas-oil-ratio, high temperature, viscous and higher depths.

Furthermore, every year new advances are presented and tested in the field, to overcome those new production challenges that operators have to face to increase production and optimize operational costs.

All these reasons motivate operators to increase year after year the share of ESP among other artificial lift technologies. When approaching a high gas application, there are three different strategies that must be considered to select and size adequately the well completion and the ESP to produce the required flow rates expected by operators.

These strategies are in accordance with a defined flow path of processes, such as avoiding, separating and handling free gas. Avoiding is defined as performing all the necessary modifications in the well completion in order avoid the entrance of free gas into the pump intake, therefore avoidingfrom any harmful effects.

Examples of this strategy are: setting the equipment below perforations andinstalling inverted shrouds, diptubes, gas avoiders or even reducing the flow rates. The second strategy refers to separating; this implies the use of a gas separator, a device used for expelling the low density fluid into the casing annulus after entering the ESP admission. Finally, the handling strategy refers to all those methods and procedures used to increase the ability of the pump to handle gas and to reduce all harmful effects when gas has already entered the pump.

Several technologies for gas handling have been developed such as charge pumps, multiphase pumps and special operation control modes among others. In addition, an invaluable resource has been added which let operators detect and react to gas lock conditions automatically, with no interventions at the well site. These features assure a higher production, higher runlife and a better and improved recovery in those reservoirs with dynamic changes, such as gas unconventional or high gas applications.

After 30 days of test, operational parameters improved significantly adding more production, better drawdown and fewer shutdowns to this well. It is one of the oldest oil producer fields in Colombia. Figure 1 shows location of the field in Colombia. Then, production was initiated in Tropical Oil Company became an affiliate of the Standard Oil Company in , and the concession reverted to the Colombian government in Figure 1. Localization of field Cira-Infantas. Gas accumulation in the low pressure side.

Initially,mostofthewellsproductionwasachievedbynatural flow, and then artificial lift methods were implemented, starting with Gas Lift and later using beam pumps. Awaterinjectionprojectwasinitiatedininorder to recover reservoir pressure and enhance oil recovery.

The waterflood showed a favorable response, and the project was successfully expanded to other areas of the field.

Ecopetrol and occidental agreed to pursue a phased approach in the partnership. The partnership started in From a structural point of view, La Cira-Infantas is composed oftwostructures:intheNorth,whichisananticlinecalledthe Cira, and in the South, called the Infantas.

As an important feature, the Infantas structure is structurally higher than the Cira structure. Reservoir pressure has been estimated to be about psi at a datum of 3, ft. The API gravity of the oil produced range from The most important issue to remark is that the reservoir pressures have decreased to around psi in some areas. Currently, La Cira-Infantas field has around wells which count for all different well trajectories and well purposes, such as deviated producers, vertical producers, deviated injectors and vertical injectors.

The artificial lift systems used currently are the beam pump and PCP in number of wells. However, more ESPs have been used in the last years in order to increase production according to expectations and overcome new restrictions, such as gas production and high deviated wells where conventional systems have demonstrated to have limitations, has installed more than ESP have been installed since Effects of gas in applications with ESP The purpose of the ESP is to lift and produce the fluid to surface at the required flow rate by the operator.

Some limiting factors are the available space downhole in the well and the fluid properties when evaluating wells with high gas-oil ratio; these two factors need to be handled by the technology installed downhole. However, the presence of free or dissolved gas in the column is not necessarily a negative concern: gas lightens the fluid gradient density of the mixture in the tubing and therefore reduces the pump load with an effect equivalent to a gas lift; in other words, more gas into the fluid requires less discharge pressure to be generated by the pump.

The real challenge when operating with ESP in high has-oil ratio is, moving the gas from the annular space to the tubing through the pump with any harmful effect. In centrifugal pumps, multiphase fluids do not remain homogenous due to the difference of density between the liquid and gas phase, segregating them very quickly and generating several challenges that need to be handled by the pump, such assignificant performance degradation.

When the fluid has more gas, the total volume of fluid handled by the pump, might increase dramatically and the lift produced by each stage will be reduced significantly according the pump curve. As a result, production at the surface might be affected. This effect is considered with a suitable selection and sizing. When some gas bubbles segregate from the fluid, tend to group on the lowpressure side of the impeller.

This gas pocket might interfere with the flow, leading to a reduced production at surface. At this point, there is still production and different procedures to follow. If the effect worsens, a gas lock occurs. As gas accumulates in the low-pressure side, it might completely block the flow path in the vanes, avoiding any fluid moving through it.

Figure 3 shows this situation. As the liquid production decreases, gas separation improves and higher pressures help recover lost performance and production, and the overall process starts again with accumulation of gas up to get a new gas locking, both processes repeat cyclically bringing in some important consequences to consider: a.

Loss of production at surface b. The pump rotates without flow, generating a temperature increase in the motor, seal section, pump, motor lead and power cable as heat transfer from the ESP is eliminated. This might lead to a reduced runlife according to the Arrhenius life-stress model. Loss of lubrication in the system components as dielectric oil, might have a lower temperature rating. Crystallization of polymers if high temperature exceeds ratings.

Thermal cycling might deteriorate insulation and lead to failures. Changes in tolerances and major wear. Under this context, it is imperative to size, select and operate all ESP equipment avoiding the harsh effects of gas into pumps, as longer runlife and better performance is expected. Portfolios for avoiding, separating and handling gas must be mixed and used to get maximum performance in high gas-oil-ratios.

Figure 3. Excessive accumulation of gas in the impeller generating a gas lock. When operating in Frequency mode, the controller will attempt to operate at the user programmed frequency with any feedback; it means that other operational parameters might be changing with no control.

When operating in PID mode, the controller will attempt to vary its output frequency in order to maintain a given feedback for example PIP or current. The setpoint of PIP or Current, dictates which control value or input signal will be used as the target that the controller will attempt to reach and maintain.


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