Artificial Lift

This paper presents new research methods, designs, and field testing of a new type of mechanical gas separator for electric submersible pumping (ESP) systems that increases the operating flow range and separation efficiency performance, while decreasing erosion problems and improving reliability. 

The objective of this paper is to present oil and gas industry the advancement and improvement of the Baker Hughes ESP phase system on wells with relatively high GLR, moderate water cut, and suggest considering the presented design system in comparable wells for an extended run-life. Paper presents run-life analysis and comparison of a conventional design versus the phase system in terms of power consumption, cost savings, and reductions of the emissions due to differences in surface power consumption between two different ESP systems.

Continuous sucker rod had been used for many years in sucker rod pump applications. However, several challenges have limited its acceptance in the past. The availability of service equipment, welding methodology, and selection of metallurgy all contributed to premature failures and operator frustration with the timeliness of installation and repairs.

This session will explore and introduce a hydraulic drive and transmission system harnessing natural gas engines, to achieve variable speed control, regardless of the power infrastructure available at the well site. 

When paired with an automatic Pump-Off Control system and a De-Gas Compressor, which is available with a dual drive transmission option, the patented hydraulic drive system eliminates the need/ cost of electricity at the well site, achieves lower operating costs, and optimizes production by as much as 40%.

Surface coatings are often needed for sucker rod pump components to protect them from the harsh downhole environments of corrosives, formation solids, and even treatment chemicals. Most coatings have both positive and negative characteristics in protecting from each of the downhole aggressors, therefore further precautions must be taken to ensure the survival rate of components, given the economics of wellbore interventions. 

Extending the run life of wells with Electrical Submersible Pumps (ESP) becomes a crucial need since it is one of the most economically expensive types of ALS. Following the need, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump.

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?