Reassessing Artificial Lift Selection in a Challenging Thermal Field

This paper reviews the process for artificial lift selection and highlights the creativity applied to solve operational challenges. Artificial Lift (AL) systems are an essential component of oil and gas production in which wells are not flowing naturally to surface. The typical factors in assessing AL selection in conventional fields are driven by cost, anticipated rates, operating envelopes, depth and also factors such as corrosive elements, sand expectation, anticipated failure rates and operational experience. However, in heavy oil fields, the selection is complicated by additional factors such as Steam Break Through (SBT) and extreme viscosity variation. Many challenges were encountered during the actual operation of "A" East field which required revisiting early assumptions and modifying both lift selection and operating philosophy. The "A" East reservoir has an oil viscosity range between 400 to 400,000 cp at reservoir conditions. In order to deplete the high pressure in the reservoir (~137 bar) and minimize the adverse impact on steam injection quality and efficiency, about 40% of the wells were selected to be cold produced, initially using Progressive Cavity Pumps (PCP) to handle higher viscosities. These selected cold producers would later be converted to Cyclic Steam Stimulation (CSS) using Beam Pumps (BP). Cold production helped to lower the reservoir pressure. The remaining of the field operated with BP using down hole Steam By Pass Pumps (SBPP). The SBPP approach was adopted to minimize conversion time between injector and producer in CSS cycles. Challenges operating the SBPP pumps led to abandoning this approach, however, the insert pump concept continued. There were notable challenges operating the insert pumps as well mostly at the flanks after several steam cycles and various efforts which required a re-evaluation of AL systems available. Metal to Metal Progressive Cavity Pump (M2MPCP) was introduced to mitigate some extreme viscosities encountered in the flanks and reaching viscosities above 15000 cp at 60 C° (see figure 1). There were some operating challenges related to slow optimization and reaction times were mitigated by the introduction of automation using an algorithm-driven approach. Other challenges were related to BP start-ups in thick oil and other pump struggles with gas locking due to SBT. These challenges required adaptations and modifications such as slow start after interventions until heated fluids arrive to the wellbore. In other cases, production choke backs allowing for single phase flow through the pump. Conversion methods between cycles was accelerated by the introduction of stripping tool. Optimization efforts were also challenging and slow and demanded higher than expected manpower, this challenge was addressed by utilizing automation and algorithms which made a significant difference. The selection of a suitable AL system needs to take into consideration the overall requirements at the different developmental stages. Standardization of equipment has advantages such as accumulated experience and reduction of maintenance costs however, there should be some flexibility and variation in Lift system options to address unforeseen operational challenges. This flexibility has allowed maximization of field production potential and has the added benefit of increasing the operating team’s exposure to various lift systems.