Artificial Lift

In 2014 Oxy EOR had lost confidence in the accuracy of Fluid Levels in CO2 wells and was not shooting them. Echometer and Oxy collaborated to identify the root cause of the fluid level inaccuracy and resolve the issue through improved procedures and educating personnel. Today trusted fluid level information adds value by improved operational decision making. 

Oxy Resources established the Texas Delaware Team in April 2013 when ~200 wells were purchased in the area of Pecos, Texas.  These primarily vertical wells produce from various commingled Delaware intervals located at 8,000’ to 12,000’ deep. The nature and deviation of these wells have made rod pumping them challenging and failure frequencies have been as high as 1.5 failures/year. Many lessons have been learned in driving the failure frequencies down to the current level of 1.0 failures/year.

In today’s world it can be challenging to locate the downhole well location immediately below the surface location in secondary and tertiary projects. There are several factors that must be considered when picking the surface location that will maximize value including 1) increases cost of building a location and drilling, 2) increases cost of artificial lift and operations, and 3) production rate and reserve impact.  This paper will explore how these factors can be put in an Excel Spread Sheet to assist in picking the location that will maximize value. 

Much work has been done on the operation of beam pump pump-off controllers, but the downtime is normally a simple timer and the optimum downtime is usually set by rule of thumb or trial and error. This paper uses a complete well model coupled with a transient reservoir  model to show that the optimum downtime in terms of total energy used per produced barrel of oil is equal to the wellbore storage time from well test analysis.

To increase recovery rates – the greatest challenge facing the industry – operators must not only look to step-change technologies, but improvements to existing technology. Even incremental increases in recovery rates can impact economics when multiplied across numerous wells. For example, approximately two-thirds of onshore wells use beam operated pump jacks with reciprocating rod pumps. Our objective was to improve the efficiency and reliability of sucker pumps by engineering a new ball valve insert.

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.