Through-Tubing-Conveyed ESP Technology Overcomes North Slope Challenges
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Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. However, the unconsolidated nature of the West Sak sands challenges the long-term lifting performance and reliability of conventional ESP systems. The case study in this paper includes the analysis of the two generations of rigless ESP systems, quantifying the success rate in varying conditions in more than 300 rigless ESP replacements in a high-sand, high-deviation environment on Alaska’s North Slope.
Through-Tubing (Rigless) ESP Technology: Generation 1 and Generation 2
In 1998, the operator developed through-tubing-conveyed (TTC) ESP (TTCESP)/TTC progressive-cavity-pump (PCP) (TTCPCP) technology to allow failed pumps (ESP or PCP) to be replaced quickly and economically using conventional equipment without a rig. In this first-generation rigless ESP system, a rig deploys conventionally, on tubing, the electric cable, motor, and seal sections, with a special latching device that allows the pump (only the pump, not the motor or seal) to be pulled and replaced by use of slickline (SL) or coiled tubing (CT), without a rig.
In 2014, a second-generation rigless ESP system was introduced that added the ability to deploy and retrieve the motor and seal using conventional SL equipment, leaving full-bore access to the lower completion and producing zone. In addition to the ability to replace a failed pump or motor, this fully retrievable ESP system brought additional value by allowing simple, low-cost SL, electric-line, and CT access to the lower completion once the ESP was retrieved without the need for a rig.
Fig. 1 shows the progression of through-tubing development from the conventional tubing-conveyed ESP to the TTCESP and, finally, to the Generation 2 wireline-retrievable ESP (WRESP).
A range of completion designs has been implemented over the 20-year history of rigless ESP deployments in Alaska. The earliest wells were 7⅝-in. cased, S‑shaped trajectory designs in which the well deviation returned to vertical to facilitate running the completion. As horizontal (and later, multilateral) completions were implemented, well trajectories became even more challenging, with deviations increasing to 80° with either 7⅝- or 9⅝-in. casing.
Both Generation 1 and Generation 2 systems have been able to pass through dogleg severity of 12°/100 ft and inclinations of 65° with SL, relying on weight and gravity to deploy the equipment to the pump setting depth. When the equipment cannot be deployed because of high deviation, it can be pumped down to the setting depth. CT has been used to run equipment in wellbores with angles greater than 65°.
Over these two decades, sand deposition has been a major challenge because of high sand production in West Sak wells. Sand settling is a function of velocity and the inclination of the flow path. For the through-tubing equipment, the tubing is larger than that seen in conventional completions to allow through-tubing-conveyed equipment to pass (typically 4.5 in. instead of 3.5 in. or smaller). The larger tubing diameter results in fluid-velocity reduction above the pump, which can lead to sand accumulation, particularly in horizontal or high-deviation wells. Sand deposition can also occur in the lower completion below the ESP. In both cases, a flow-stabilized sand dune is created and, upon ESP shutdown, the sand may plug the well, either above or below the ESP. To eliminate this risk, a check valve is run above the ESP to prevent flowback into the pump during shutdowns.
In the Generation 1 design, if a sand blockage was created below the ESP, the sand could not be removed without pulling the tubing with a rig. The Generation 2 design was developed to allow access below the ESP setting depth once the pump, seal, and motor were pulled with SL, allowing full-bore access to clean out sand below the ESP without the necessity of pulling the tubing with a rig. Additionally, Generation 2 systems provided the significant benefit of allowing a failed motor/seal to be replaced without a rig intervention (i.e., rigless).
Generation 1 Rigless ESP Systems: Operating Observations
The mean time to failures (MTTF) for the through-tubing Generation 1 systems are divided into two categories: the through-tubing pump and the rig-deployed bottomhole assembly (BHA). These are further subdivided into TTCESP and TTCPCP systems. For the TTCESP systems, the MTTF for the pump has averaged 2 years and the MTTF for the BHA has averaged 4 years. For the TTCPCP systems, the MTTF for the pump has averaged 1.5 years and the BHA (pump can, seal, and motor) has averaged 5 years.
Component failures of the Generation 1 system (for both TTCESP and TTCPCP) were typically related to erosive wear of the pump or plugging caused by sand. In these cases, pump replacement was accomplished with SL intervention. However, in the Generation 1 system (in both TTCESP and TTCPCP), tubing-deployed component failures or sand cleanouts below the ESP required a rig workover, typically leading to a loss of 6 to 18 months of production. This drove Generation 2 development to further prolong the time between rig workovers, with the additional benefit of full-bore access to the producing interval below the pump setting depth.
Generation 1 Rigless ESP Systems: Retrieval History
A detailed review of 20 years of wireline-service reports was performed for the through-tubing Generation 1 equipment. This history has been summarized by pump type (ESP and PCP) and well inclination at the ESP setting depth.
In total, for the Generation 1 rigless ESP system, there were 280 successful rigless pump-replacement operations out of 293 attempted for a 96% success rate. These were performed using SL, CT, or wireline tractor, depending on well inclination. This is an impressive result, particularly considering the high deviations and significant sand production in most West Sak wells.
The 13 unsuccessful operations were caused by inability to pull stuck pump, pump-to-motor coupling damage, hard-packed sand, parted pump and rotary gas separator, inability to seat the pump, and packoff sticking. Though it is often predicted that the through-tubing pump will be difficult to pull (particularly in sand-prone areas), field experience shows that this is not the case.
An analysis of the Generation 1 data shows that a total of 380 interventions were required in these wells over the 20-year period. Of these 380 interventions, 280 were resolved with SL interventions. The remaining 100 required a tubing pull (rig) because the rigless intervention was not successful or, in the majority of these cases, the cause of failure could not be addressed with the Generation 1 system.
Of the 100 rig workovers required with the Generation 1 system, 63 could have been resolved with an SL or CT intervention using the additional functionality of the Generation 2 system, avoiding a rig workover. This suggests that running Generation 2 systems vs. Generation 1 systems results in 63% fewer rig workovers. Compared with a conventional ESP, 343 of 380 interventions could have been resolved using SL or CT, resulting in 90% fewer rig workovers.
Generation 2: Successful Performance
The Generation 2 system is identical to the Generation 1 system, with added functionality to allow the retrieval of the motor/seal section through tubing, with one additional SL run. The Generation 2 system is a complete through-tubing rigless ESP system that, once removed through tubing with SL or CT, leaves 3.8-in. full-bore access to the lower completion (production zone).
The commercial deployment of the Generation 2 rigless ESP system began in Alaska in 2014. To date, there have been no failures of either the SL-retrievable portion of the system (pump/motor/seal/wet-connect) or the tubing-deployed portion of the system (downhole side pocket mandrel wet-connect/cable).
The intervention performance of the Generation 2 system has continued the success of the first-generation hardware. As for the first Generation 2 well installation in Alaska in 2014, after almost 5 years of operation, this well has had one entire ESP swap (pump/seal/motor/wet-connect) and three pump-only swaps (four ESP interventions in total). Each of the interventions was proactive, using SL in a live well to replace a pump with degrading performance before it failed. The lost production time was only 2–6 days per intervention. A conventional ESP would have required a rig to pull tubing to replace a failed pump or motor with an associated 6 to 18 months of lost production. In almost 5 years since this Generation 2 system was installed, there have only been 200 hours of downtime (less than 9 days).
Since the introduction of rigless ESP technology in Alaska, more than 300 through-tubing SL, CT, and tractor (i.e., rigless) pump/ESP replacements have been performed at West Sak and geologically analogous fields across the North Slope with a 96% success rate (the intervention was successful without pulling tubing with a rig). These interventions were performed with SL, CT, and tractors depending on the maximum well deviation above the pump setting depth. This technology has reduced production downtime in these high-rate wells while providing low-cost access to perform well interventions.
In addition, the introduction of the Generation 2 system has demonstrated the value of a proactive ESP-operating philosophy. The ability to pull and replace the ESP system efficiently and inexpensively with SL or CT creates the opportunity to nearly eliminate ESP-related downtime by pulling and maintaining ESP systems before failure.
For a limited time, the complete paper SPE 193783 is free to SPE members.
Through-Tubing-Conveyed ESP Technology Overcomes North Slope Challenges
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