Artificial Lift

In a reciprocating rod lift application, production tubing failure due to metal-to-metal contact with sucker rod couplings is a common problem in the highly deviated sections of the tubing string. The coupling is forced to be the point of contact against the tubing wall, which causes high friction and excessive tubing wear during the reciprocating motion. This excessive tubing wear typically leads to a hole in the tubing wall, resulting in high workover costs for the producer.

Data from fluid level, dynamometer, pressure, and motor power measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from the tests that lasted several weeks, beginning with well pump down, just after new pump installation and continuing during normal production operation.

Data from acoustic fluid level and surface pressure measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of pressure transient well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from tests that lasted several weeks, beginning with well shut-in, continuing until pressure transient stabilization and afterwards during pump down until normal steady state production operation.

Data from fluid level shots can be very valuable in optimizing the chemical treatment program. For example, selecting continuous treatment vs truck treatment, adjusting flush volumes on truck treated wells, ensuring slip-streams are open and adequately slipping, or raising the SN depth on wells that cannot be pumped down. Just because chemical is being introduced into the backside does not mean it is effectively getting downhole, or getting downhole at all.

Managing extensive Electrical Submersible Pump (ESP) operations and evaluating their performance can be a challenging task, especially in unconventional reservoirs. Varied operational environments, expansive geographical areas, large ESP populations, different declination patterns, diverse fluid properties and well designs and different service providers are some of the complications that operators face every day.

Modern sucker rod pump operations rely on pump-off controller’s, surveillance dashboards, and human intervention to maximize production and pump performance. As a result, rod pump operations often suffer from high manual workload, limited diagnostics and dynamic well conditions. For wells fitted with pump-off controllers and variable speed drives, challenges remain around data gathering and evaluation. Bringing well specific insights to action requires continuous physical supervision to ensure well uptime.

One of the most misunderstood issues in sucker rod pumping is tubing back pressure. The great majority of wells that I have encountered in various fields have back pressure valves installed on the tubing side of a wellhead. However, a great many field personnel do not understand why back pressure is applied, how much to apply, and/or how it affects a well’s performance. This paper will discuss the why, when, and how tubing back pressure is applied along with some misunderstandings and issues of its application. 

The issues of leakage with respect to the clearance between the pump plunger outer diameter (OD) and the pump barrel inner diameter (ID) and other operation conditions have been revisited in this paper using viscoelastic models. Both Poiseuille flow rate due to the pressure difference and Couette flow rate due to the plunger motion have been considered.

This paper proposes a new method to deal with sand and chemical problems in the ESP. The protection system consists of 1) ESP sand separation system that works in two stages assuring the best sand separation efficiency. The first separation stage is composed of a V-wire geometry screened designed based on production. The second stage is a centrifugal system formed by a sand cutting resistance sleeve and a helix that creates a Vortex Effect.

The advent of low-cost IoT systems powered by AI/ML Algorithms provides new production optimization tools available at the well site to achieve the digital transformation in the onshore oil and gas business. The unique capability of well diagnostic at the edge opens new opportunities from artificial lift to production optimization. The goal is to improve overall efficiency by reducing failures, anticipate deteriorating operating performance by timely introducing mitigation options.