Artificial Lift

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.

Long lateral, high-rate wells in the Permian basin present unique challenges to maximize rate relative to ensuring flow stability with gas lift. Annular flow gas lift has offered a transitional lift method between high rate casing flow and traditional tubing flow gas lift to maximize well production. However, annular flow and annular flow gas lift have presented a more aggressive corrosion profile on the exterior of 2 7/8" L80 production tubing than anticipated.

Since its’ introduction to the unconventional oil and gas realm in 2017, Single Point High Pressure Gas Lift (referred to as HPGL going forward) has emerged as one of the top artificial lift choices for operators in the Permian and MIDCON basins. It has become a proven technology with over 1,600 applications to date as more operators are choosing it as their primary form of artificial lift for their unconventional assets. 

Annular flow gas lift has rapidly become a popular method of initial artificial lift in the
Permian Basin. The evolution of wells, over time, has resulted in higher flow rates due to
advancements; this includes horizontal, multi-staged improvements in frac technology. Smaller casing strings are often installed to save on well costs, but this can limit the type of artificial lift system that can be installed, and ultimately, the flow rates attainable from the well. Annular flow options offer a larger flowing area and less of a pressure loss versus tubing flow applications.

The temperature allocation along the well plays a crucial role in the design performance and troubleshooting analysis of gas-lifted wells. The temperature of injection gas at each valve depth should be well-known to establish the gas flow rate spread across every valve. As gas temperature across the valve and production fluid temperature will be utilized to evaluate nitrogen pressure inside the bellow of the valve. Therefore, the temperature is the main factor in evaluating nitrogen-charged gas lift valve closing and opening pressures.