Artificial Lift

Sucker rod pump or “rod pump” is a common method of artificial lift for oil and gas wells in the United States. For decades well analysts and production engineers have looked at surface and downhole dynamometer cards to diagnose various downhole and surface equipment issues alike. In more recent years, helpful rod pump diagnostic tools have aided well analysts and production engineers in training and the analysis of downhole dynamometers utilizing generalized libraries with known behavior for downhole dynamometer cards.

Mechanical Friction in a sucker rod lifted well acting on the rods is not modeled by the wave equation, resulting in the excess frictional loads and horsepower being displayed in the plot of the load versus position at any point along the rod string from the surface to the pump.  When the plunger stops at positions other than at the beginning, top, and end of the stroke, then sticking down hole is frequently the cause.

An overview of the ongoing investigation and analysis into several aspects of gas lift and hole in tubing failures in Delaware Basin. Subjects of investigation will include fluid composition investigation, bacterial corrosion investigation, solids and erosion investigation, and materials and design investigation. Practices regarding the investigation of these failures will be outlined and the limitations thereof will be explained. We will be focusing on corrosion/erosion mechanisms, tubing/GLV design, and the number of different methods taken to date to identify root causes. 

Surface coatings are commonly used in many industries including oil and gas with the aim of hardening the part surfaces to improve wear resistance without compromising the corrosion resistance. Sucker rod pumps employ several parts with coated surfaces as well, including the pump barrels. Both standardized surface modifications and specialty applications for pump barrels are readily available in the market for different well conditions, including extreme well solids and H2S or CO2 service.

As companies seek to optimize performance of rod pumped wells, they examine common problems which may include improper rod string spacing resulting in rod pump damage, rod failures and cable failures of pump off control (POC) wired load cells. Traditional methods of adjusting rod strings requires removal of rod clamps and exposes field personnel to pinch, fall and struck-by hazards.  To mitigate this risk, some E&P companies require a third-party to adjust rod string spacing, resulting in significant expense. 

Sucker rods are subjected to cyclic stress which leads to fatigue failure. It is well known that the shot peen process increases the fatigue life on metal parts. Although several manufacturers implemented shot peening in the sucker rod manufacturing for years, optimal parameters that yield a dramatic increase in fatigue life require extensive studies on both input parameters and comparative fatigue testing.

With the increase in horizontal completions and multi-stage sand fracturing, sand problems and the detrimental affect that arises from excess sand production have increased significantly over recent years. The simple fact remains that although both ESP and rod pumps can handle some amounts of sand, they are both liquid pumps and excessive sand production reduces system efficiency and shortens the effective life span of the pumps. This has resulted in higher maintenance costs and reduces run times which are costly to producers.

Workover operations effectively probe the wellbore using the rods or tubing. Friction encountered as the rods or tubing pass through the wellbore can be measured at surface. By applying wave equation methods to eliminate surface dynamics, a measure of friction acting along the remaining rods can be quantified. Because the workover process methodically removes rods, a map of friction through the wellbore can be obtained. The act of pulling rods is virtually identical to a deep rod part, and each pull of the rods eliminates friction previously acting below the remaining rods.

A process for modeling multivariate Electric Submersible Pump data in a central host system is proposed in to support managing fields by exception by using artificial intelligence models to identify failure modes and operating conditions. The AI model enables operators to immediately identify failure modes and operational conditions, as it is continuously analyzing, facilitating quicker decision making. It also increases the number of wells an operator can effectively manage, and can be used as an educational tool, empowering users to interpret complex ESP trends.

Field case studies for Harbison-Fischer’s latest enhanced Back Pressure Regulator (BPR) has increased production for multiple operators in the Permian Basin. Back pressure regulators have operated successfully under rod lift conditions in wells that include intermittent flow, low fluid production, and a wide range of gas production. But when tested in wells with Electrical Submersible Pumps (ESP), constant production rates between 2,000 and 3,000 BPD, and large amounts of sand, it caused accelerated wear that resulted in costly cleaning jobs and unsafe working conditions at the wellsite.