Abstract
The subject block in the Sultanate of Oman using enhanced oil recovery through steam flooding has been operated with various types of artificial lift systems employed to bring fluids to the surface, including sucker rod pumps (SRP), electric submersible pumps (ESP), and progressing cavity pumps (PCP). The selection of the lift method depends on several factors, such as flow rate, wellbore conditions, fluid characteristics, and downhole temperature. ESPs are utilized for wells with flow rates higher than 500 bfpd, while SRPs and PCPs are employed for wells producing 1,000 bfpd or less. Initially, PCPs are used when downhole temperatures are low (120 F) and viscosity is high (> 5,000 cp). However, when the produced fluid temperatures increase beyond the maximum temperature for a PCP and viscosity decreases, the artificial lift method may be switched to SRPs or ESPs, depending on the well's production rate and temperature. The objective of this project is to extend the operating limit of PCPs, allowing them to operate in the well for longer durations and at higher downhole temperatures. This extension may potentially help avoid the cost associated with switching to other forms of artificial lift.
At elevated temperatures, a PCP faces two primary challenges for reliable operation. The first challenge is the temperature limit of the elastomer, and the other is the temperature limit of the steel/elastomer bond, prone to failure at high temperatures, particularly in the presence of water. The PCP pump manufacturer has addressed these issues by formulating a proprietary hydrogenated nitrile butadiene rubber (HNBR) elastomer capable of operating in fluids up to 300°F while maintaining its mechanical properties. To maintain an effective and reliable bond with the stator tube at these elevated temperatures, the manufacturer developed a patented non-circular stator tube design. Unlike traditional circular stators, this unique shape prevents the elastomer from rotating or moving axially within the tube. As a result, it reinforces the adhesive bond between the elastomer and the stator. This innovative design allows the pump to continue lifting fluid to surface even if the adhesive bond is compromised. This resilience is essential for maintaining operations in challenging conditions. Currently, a field trial involving over 40 systems is underway to assess the performance of this pump in this steam flood field.
As of December 2023, over 40 systems have been installed, with 29 still operational at the time of this publication. The longest recorded run life is 850 days, while the Mean Time to Failure (MTTF), calculated using the methods outlined in SPE 190962, stands at 1537 days, and continues to increase. Due to the dynamic nature of the steamflood process, where well temperatures can undergo substantial changes, it has been determined that adjusting rotor sizes is crucial for optimizing performance and reliability. Early failures with this technology were attributed to delaying rotor changes as the well temperature increased and the stator elastomer began to swell due to temperature fluctuations. To address these challenges, the manufacturer implemented improvements, including the introduction of a rotor guide to safeguard the elastomer during rotor insertion in the stator during a rotor change.
This novel PCP bonding technology has exhibited outstanding performance within the 200°F-300°F temperature range, which is considered high for elastomeric PCPs. While the adhesive bond between the rotor and stator may be compromised under extreme conditions, the pump can persistently operate and extract fluid from the well, thereby offering extended run-life and enhanced reliability. Moreover, the new design retains all the advantages of a PCP system, such as tolerance for sand and high-viscosity fluids.
