Artificial Lift

This paper will discuss the two API pump designations the rod pump and the tubing pump. The rod pump is occasionally referred to as an insert pump and has three variations; stationary barrel top anchor, stationary barrel bottom anchor, and traveling barrel bottom anchor. Available modifications that are not covered under API but are commonly used to improve run time or efficiency will be discussed. Several special design pumps will be described along with their advantages. A reader will be able to recognize the standard API pump designs, API designs with modifications, and specialty pumps.

Different types of forces NOT accounted for by the wave equation are 1) Mechanical Friction, 2) Piston Force on polished rod due to tubing back pressure and 3) True Vertical Rod Weight.  Mechanical friction due to 1) Over-tight Stuffing Box, 2) Down hole sticking due to Severe Dog Leg in wellbore profile and 3) Friction from Paraffin along a section of the rod strong.

Understanding wave dynamics can help improve rod design and operation. This presentation will illustrate the nuances of rod design and analysis through the use of visual representations of these abstract wave concepts. Dimensions such as time, rod loading, dynamic rod position, rod depth, dynamic rod stretch, rod velocity, etc. can be rendered against each other to create interactive plots in a three dimensional environment. These plots, while abstract in and of themselves, can provide intuitive clues as to the timing and location of key events during a pump cycle.

Tubing leaks have historically accounted for nearly half of the failures in the Hess Bakken wells. The root cause of these leaks is coupling on tubing wear; the non-metallic guides wear out, which results in spray metal couplings contacting the production tubing. To address this problem, the company installed ToughMet® 3 TS95 sucker rod couplings in over 650 wells, reducing the failure rate in the field. Data analytics was used to analyze the MTBF history over the last four years.
   

Gas lift is becoming a popular form of artificial lift in the Permian Basin for long horizontal wells that make high gas rates. Unfortunately the decline curves on most horizontal wells are not ideal. As the rates and pressure quickly drop gas lift starts to become inefficient and we are forced to make artificial lift changes in order to preserve base production. Rod pumps have always been the end of life application for artificial lift but it has been proven that pumping in horizontal wells can be very costly due to wellbore conditions.

The most common form of artificial lift is sucker-rod pumping.  One of the main elements of rod lift system design is the selection of a downhole pump.  This study examines the various factors that affect the selection and design of downhole rod pumps. Downhole rod pumps are made up of five main components: barrel, plunger, balls and seats, seating assembly, and valve rod or pull tube.  Understanding the various well and system design factors that are examined when selecting each of these components is a crucial part in the design of the downhole pump.

Automation of rod pumping systems has been a part of the oil and gas industry for over 65 years.  Starting with time clocks in the 1950s, the invention of the pump-off controller in the 60s, and variable speed drives in the early 2000s, the amount of technology available to both control and analyze the system has increased and improved drastically. Several of the driving factors to automate include high initial production rates, followed by a steep decline, gas slugging, high degrees of rod and tubing friction, and paraffin build.

Rod wear and corrosion have a complex relationship that is often misunderstood of oversimplified.  This paper provides a technical framework and provides empirical evidence of principles that clarify this complex relationship.  In particular, this paper will review stress levels and metal failure mechanisms that dispel many commonly held beliefs.  A better understanding of these principles will lead to opportunities to reduce an operator’s total operating footprint.

Downhole sucker rod pump clearance changes from shop conditions to bottom hole conditions due to bottomhole pressure and temperature that the pump components are subjected to. Presented here are equations to estimate the change in dimensions of the plunger and barrel of top and bottom hold down pumps at bottomhole pressure and temperature conditions.

Pumping wells hard involves a tradeoff between operating cost and production. Increased idle time or holding additional back pressure on the reservoir can decrease production but pumping a well harder will likely increase failure frequency. The existing reservoir pressure has a significant impact on the potential change in production.  Pump-Off Controllers (POCs) are used to regulate run time on many wells operated in Permian Basin water floods and are accepted as a failure reducing and cost saving tool.