Artificial Lift

Rod pumping unconventional wells is becoming increasingly challenging due to unpredictable downhole environments. Many unconventional wells exhibit significant deviation accompanied with corrosion making them difficult to rod lift without exposing downhole equipment to unpredictable damage mechanisms – specifically the rod string.

The use of rod rotators is key to extend the life of sucker rod string couplings in all intentionally and not intentionally deviated wells. Its applicability has proved to be a low-cost solution, giving an even wear on sucker rod couplings, extending considerably their run time.
One of the major issues with conventional cable actuated rod rotators is the integrity of the cable, its installation and proper maintenance. It’s common to heard from operators losing the cable connection and ending up on a premature failure on sucker rod couplings due to localized wear.

The Downstroke Pump and Special or Unusual Sucker Rod Pumps Explained This paper will explain the author’s theory of operation of the pump that lifts fluid on the downstroke, using the weight of the rods, and its loading of the sucker rod string and pumping unit. Other special sucker rod pumps will be likewise explained, using the author’s understanding, including the family of double displacement type pumps, compound compression ratio pumps, traveling barrel pumps, and others.

The capability of a gas lift system is heavily dependent upon the available gas lift injection pressure. Gas lifting a well from the deepest point of the formation results in higher drawdown pressure, more production with less lift gas, and less gas lift equipment yielding a more efficient system. However this cannot always be achieved because of limited injection pressure, limited gas injection rate and/or limitations of the gas lift equipment. In a gas lift project, what size compressor is needed to deliver the desired production?

Mechanical rod rotators have been used as part of the beam lift artificial lift system since the concept was first patented in the late 1930’s. By rotating the rods, the frictional wear surface can be distributed around the circumference of the rod, versus on a single side of the rod. By distributing the wear surface, the rod life will be significantly extended. In the same way, the industry has used tubing rotators to derive this same benefit on the tubing, distributing the wear around the inner circumference of the tubing.

Plunger Assisted Gas Lift (PAGL) in the Permian Basin Over the last few years Gas Lift has become a popular artificial lift choice for producing unconventional wells in the Permian Basin. Gas Lift is a good choice for producing wells with high bottom-hole pressures (BHP) and high gas liquid ratios (GLR). Gas Lift is also a good choice for wells that produce solids or have deviated wellbores. Gas Lift however like all artificial lift choices has an optimum range which typically tends to be above five hundred barrels per day.

Understanding rod loading is vital to reducing failure rates in reciprocating rod lift systems. By changing the minimum stress and using the modified stress analysis instead of the modified goodman diagram, manufacturers are “tricking” you into using high tensile strength and/or premium sucker rods in your rod designs. This presentation will attempt to explain rod loading why most rod lift applications do not require or need  high strength and/or premium sucker rods.

When rod pump wells are operated in corrosive environments, corrosion induced sucker rod parts can lead to premature well failure and expensive, repeat workovers. Many corrosion mitigation solutions exist to combat this type of failure, including metallurgy, chemical inhibitor, and epoxy coatings, but they can be costly and not all solutions are appropriate for all types of wells.

Sucker rod pumping is largely regarded as the final artificial lift method in a well’s lifecycle. Until now, the industry standard application of sucker rod pumping systems has been up to 400 barrels per day fluid production. With the industry advancing towards deeper wells and increasingly aggressive production targets, the challenge of meeting these application parameters while decreasing costs has become forefront to an operator’s requirements for profitability and in some cases, survival.

Due to the ESP motor’s inefficiencies, heat is produced when converting power from electrical to shaft power. This generated heat is either transferred to the surroundings (i.e., through the producing fluids) or absorbed by the motor. In the absence of proper cooling, the motor temperature keeps increasing until either the motor fails or it reaches a temperature high enough to transfer the generated heat to its surroundings. According to the Arrhenius rule, equipment life is expected to reduce in half for every 18°C increase.