Artificial Lift

The performance of Harbison-Fischer’s patented Sand Flush Plunger (SFP) was assessed relative to the average runtime for standard API plungers in the HWY 80 field, operated by Pioneer Natural Resources (PNR). The field case study captured information from Harbison-Fischer’s pump-tracker for 5,283 wells and 32,804 workover records dating back to 1989. As of the record date, 1,934 different wells had used an SFP 3,473 times. The analysis focused on 194 wells, for each of whom the data showed at least one failure originated by the pump for each of the two plunger types.

In some of today’s unconventional wells, sucker rod pumping systems are facing challenges related to excessive wear, affecting production and increasing operational costs. One of the reoccurring damages in a sucker rod pumped well occurs near the kick-off point in a deviated well between the coupling and the tubing or between the sucker rod and the tubing; the metal-to-metal contact causes hole-in-tubing failures and operators have been seeking solutions to mitigate or minimize excessive tubing wear in highly deviated wells.

How and where ground wires are connected determines the runtime and successful withstanding of switching and lightning surges. This is extremely evident with lightning protection of electric submersible pumps (ESP).  Electric surge suppressors on the same ground wire can and will interact bidirectionally in a lightning storm. Instances of ESP failures due to improperly installed surge suppression are not uncommon.  Understandably the value of surge suppression has been questioned.

Slippage is required for lubricating the plunger/barrel within beam pumping systems. Increasing pump clearance increases the amount of slippage, which may lead to inefficient operations. Operators could run their field more efficiently through decreasing failure rate and increased electrical cost savings by calculating the optimum design using the Patterson Slippage equation for individual well conditions. This paper will discuss the economic tradeoffs with changing pump clearances and recommend theoretical optimum designs given well conditions.

In 2016, a recommendation was made in EOR to begin utilizing Grade “C” when replacing rods in San Andres wells or wells less than 5,000’ deep. The advantage of the Grade “C” rods believed to be better corrosion resistance, tubing leak reduction, and lower material cost. It was also recommended that “T” coupling be considered as an alternative to Spray Metal (“SM”) couplings as they are softer and should fail preferentially to the tubing.

Evolution of annular gas lift candidates and early results of application in the Delaware Basin. 

As horizontal wells deplete, there becomes a greater need to reduce bottom hole flowing pressure. Methods such as gas lift and jet pumping can be run into the curve but are limited in ability to drawdown bottom hole pressure. On the other hand, Rod pumps are most commonly used but, have difficulty running past a certain degree of wellbore deviation and suffer from gas locking and interference due to the slug flow.  A new gas anchor system has been developed to deploy into the horizontal section of the wellbore and has shown efficient in gas liquid separation.

The Dual Shot Acoustic Technique is used to troubleshoot Gas-lift Wells by looking for pressure communication between tubing and casing.  One gas gun is fired, sending a pressure wave down the tubing. Simultaneously, a second gas gun listens to the casing.  Both microphones are attached to the same input to record the acoustic signal.  The tubing microphone is disconnected immediately after creating the traveling pressure wave at the surface of the tubing, and the microphone on the casing detects signals that pass through defective valves or checks or holes in the tubing.

There are a large number of unconventional wells coming on line every month in the Permian Basin.  Most of these wells will have high bottom-hole pressures and initially flow on their own. However, after the initial flow back phase, pressures and rates decline and the well will begin to liquid load. At this point some type of artificial lift choice needs to be considered. This paper will lay out an artificial lift strategy for many of these wells that will transition from completion to depletion through various artificial lift options as a well’s production and pressures decline.

In today’s ever-more complex and corrosive downhole environment, especially in well sections with high dog leg severities, high water cuts and high sand content, it is challenging to develop a “one size fits all” coupling. Such coupling would need to be engineered to increase the life of the tubing and the coupling itself from basin to basin. Couplings may slap and then rub against the tubing, which consequently causes extremely aggressive angle contact to the tubing by the rod string, leading to coupling wear, coupling-to-tubing wear, and hole-in-tubing fail.