Artificial Lift

In 2015 a proprietary quenched and tempered sucker rod product line was introduced to the North American market. Field results showed a considerable improvement of reliability and performance of the two proprietary rod grades (Critical Service, CS, and High Strength, HS versions) versus previously installed rod grades. The performance and reliability of over 300 installs are tracked and used to provide input to R&D and Product Development teams to continuously improve the products with the goal of further increasing run life and performance.

Automation has been used for many years now as a means for oil and gas operators to optimize sucker rod pump wells. Traditional automation for rod pump wells involved operating the well at a fixed speed and idling the well based on a preprogramed time (time clocks) or fillage (pump off control). However, utilizing a Variable Frequency Drive (VFD)is a more sophisticated method to allow operators to increase their runtime by detecting when there is less fluid to produce and slowing the unit down, accordingly.

One of the benefits of utilizing a Sucker Rod Pump for artificially lifted oil and gas wells is that they can achieve total drawdown the casing fluid above the downhole pump. This allows for the artificial lift method to maximize the production of the well by minimizing the back pressure on the reservoir caused by the fluid level in the casing anulus. However, in some cases the original design of the sucker rod pump system may not be able to achieve the capacity required to drawdown the entire fluid level in the casing anulus.

Gas lift is long known to be an effective and versatile form of artificial lift and is widely used in oil and gas production. The gas lift process is dependent on gas pressures not naturally available from oil and gas production facilities. Rather gas must be pressurized through use of a compressor and thus compressors are a vital component to the gas lift process. Unfortunately, some operators have experienced unsatisfactory levels of compressor runtime, particularly during periods of cold weather. When the compressor is down, well production suffers.

Rod pumps often fail due to gas and solid interference. When the system’s check valves are unable to displace these solids or gas it can cause failure and significant damage to the overall rod pump system, such as intense ball rattling, plugged cages, inefficient pump fillage, and fluid pounding. 

Rod pump failures often times exceed the failures rates of other downhole products, such as sucker rods and tubing. The largest section of the rod pump, and most costly to replace, is the pump barrel. Barrels of all different shapes and sizes, material grades and coating options are available to the market. The available coatings have been questioned for their durability while also being limited in their applications. Chrome barrels and NiCarb surface coatings are widely available but often times cannot be used in Acid Jobs (Chrome) or in heavy abrasive environments (NiCarb).

Main objective of this paper is to introduce oil and gas industry the new E3000 and E1000 pump models across multiple wells in the Permian and Delaware Basins in term of performance, and operation improvements. It is intended to show a reader pump performance enhancement and comparison to older models based on operator required production rates, pump loads, power consumption and other electrical and mechanical parameters that of the focus when designing and selecting an ESP. 

Sucker rods are simple in form and function, however, they operate in a sophisticated engineered system over great lengths without direct visibility. Because of this, we as engineers must do our best in predictive efforts to provide the best configuration for the highly dynamic system.

Rod string design software utilizes complex math to compute stress loading throughout the system. Design software w/ deviation included incorporates well-bore geometry to estimate ancillary loads throughout the design, i.e.: side-load & drag load from rod-on-tubing contact.

Since becoming a Lift Specialist in November of 2019, it was very clear we had significantly higher failure frequencies on wells with 4.5” liner, 2 3/8” tubing, and 1.75” tubing pumps vs other configurations. My knowledge is solely based on South Plains and the problems we faced.

Given several pumping cycles worth of surface card data, the dv8 advanced diagnostics model is solved and the rod displacements, axial loads and sideloads are calculated, starting from the polished rod and propagating to the pump. From the axial load, the rod stress is computed. The points along the rod string are then analyzed using a modified Goodman diagram applicable to the type of rod string used. The maximum stress experienced by the rod is compared to the maximum allowable stress to determine if the rod string is overloaded. Review of case studies and results are published.