Artificial Lift

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.

Incomplete fillage conditions where the downhole pump does not completely fill up with incompressible liquid have been widely accepted to have detrimental effects on pumping efficiency and moreover the equipment longevity in sucker rod pumping applications. Methods of synchronizing the pump displacement to the wells inflow and thus reducing incomplete fillage has been of keen interest to the industry. During operation, surface sensors are used to monitor polished rod load and position to obtain a surface load vs position graph.

This paper introduces a technology for handling solids above the discharge of the ESP pump that increases the run time of the well and prevents premature failure due to plugging or damage to the pump parts thus contributing to the reduction of carbon emissions and environmental impact. Additionally, the new technology was engineered to allow fluid injection through the tubing and its components can be dissembled after pulling it, providing the production engineers with valuable information about the downhole conditions.

Following Best Recommended Practices adds value, this paper will discuss selected Best Practices.
1. Tensile strength historically is used as an essential criterion in rod selection. The primary cause of sucker rod failures is not due to exceeding the tensile strength threshold but is due to compression from the polished rod velocity exceeding the plunger velocity. Value can be added from loading up rod strings.

With the data collected over many years, we can show how we have improved the gas lift valve tear down process, and how that data collected from this process has increased longevity of wells in each, individual area. While following the API Standards of gas lift valve expectancies, both in initial installs as well as reporting once valves are pulled, data is paramount. The ability to provide extensive data, that tracks trends across formations, mandrel types, valve types, and a myriad of other parameters better enables the operator to make the best choices going forward in their wells.

Unconventional reservoirs bring new challenges for Electrical Submersible Pump (ESP) Systems, such as rapid decline and high gas production. As these conditions can add obstacles to the operators to efficiently produce the wells, the industry is always looking for opportunities to improve ESP performance. This study analyzes the performance of some successful ESP Applications installed to produce from Unconventional wells in the Permian Basin, Delaware and Midland Basin. Showing what we have done differently as best practices to increase the ESP runlife. 

The efficiency of most artificial lift systems is reduced significantly whenever the tubing and the annulus are in communication due to the presence of unwanted holes or leaks developed in some of the hardware used in the installation. Detection of the problem from analysis production records must be followed with field tests that verify the diagnostic before proceeding with repair operations.