The company Petrogas E&P was established in 1999 by acquiring onshore block 7 in Oman. Over 23 years, Petrogas E&P has continuously grown by acquiring several blocks in Oman, India, Mozambique, Egypt, Netherlands, Germany, Denmark and in the United Kingdom. The main operations are in Oman, Netherlands and in the UK. Since 2007, Petrogas is the operator of Rima Cluster small fields in southern Oman. Artificial lift, mainly rod driven Progressive Cavity Pumps (PCPs) and Beam Pumps (BPs), is required to produce oil with an average specific gravity of 21 °API to surface. Parted rods are the main reasons of well failures and rods present the weakest part of the completion. Some of the wells in Petrogas Rima show high angles of inclination, complex trajectories and certain levels of hydrogen sulfide (H2S) & carbon dioxide (CO2). Completion failures due to parted rods lead to production deferment and workover interventions because of required rod string replacement. In general, sucker rods are made of a certain grade of steel and these steels are prone to corrosion in an aggressive environment due to the presence of carbon dioxide and sulfide in the crude oil. A coating solution for sucker rods and couplings was implemented to reduce the influence of corrosive environment in some wells. The lower coefficient of friction resulting from the coating reduces the abrasion between the coupling and the tubing. In that way, the risk of tubing holes can be reduced. After a coating solution was implemented in selected problematic wells, the rod run life could in average been tripled with no failures observed as of this writing.
Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations. An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract. The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production. The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.
A field trial has been completed in five oil producing wells, completed with progressive cavity pump (PCP) and under sand co-production scheme with the following objectives: Increasing well uptime by eliminating rotor stuck events and extending time between failures,Reducing locked-in potential associated to slow ramp-up process from initial to target offtake,Reducing the need for operator visits to start or adjust well running conditions after station trips, To achieve this, four wells with very premature failures (less than 6-months) were selected for the trial. One fifth well with high level of depletion was also selected. The target for this last application was to check the impact of reducing fluid level safety factor on pump performance. In all wells, PCP well controllers were installed with self-optimization routines that maintained safe fluid levels above the pump intake while adjusting speed for potential sand ingress. Speed ramp-up time was programmed for completion within two days of start up. First, realtime signals were enhanced to monitor all well parameters that could affect performance, such as tubing head pressure (THP) and casing head pressure (CHP). This information was key to manage the actual fluid levels above the pump, even in gassy wells, allowing safety factors to be reduced by 50% without affecting pump performance. Increase in pump run life by 40 to 140% was observed in the four sandy wells selected. No well interventions were required for sand flushing. Ramp-up time was successfully completed within a day of start-up and after two days production at target was stabilized. After trips, it was found that the well started without the need for operators, as long as power supply was restored. Operator visits were only required for power or signal issues to be fixed, but well was safely kept optimized within those periods. Estimated oil production availability increase from this trial is 12% per well per year. This paper presents the main learnings from applying a self-optimization routine in 5 sandy wells and what is important to consider to achieve cost reduction, increase in well uptime and to reduce the need for manual adjustments/field visits.
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