ESP Upsizing Doubles Well Production
An ESP was installed in a new well. The predicted rate for the well was approximately 2500 bfpd. Well tests indicated a rate of 2500 bfpd and so everybody concluded that the 120 stage ESP was functioning optimally.
An analysis of the operating data was performed which showed that the drawdown caused by the ESP was half of what it should be and that well inflow performance was higher than originally predicted. A workover was performed and an ESP upsizing performed. Production was increased to 5500 bfpd.
Result: ESP problem identified, correct well inflow determined. Workover performed to increase production from 2550 bfpd to 5500 bfpd. Production doubled!
Production Re-established on ESP Well
The production on a well had declined from 1200 bfpd to 1000 bfpd, intake pressure on the ESP had slowly risen. The well tripped on underload, subsequent attempts to restart the ESP resulted in further shutdowns due to underload.
An analysis of the operating data was performed and the problem diagnosed as a plugged pump intake. Acid was bull headed down the tubing, through the ESP. The ESP was then successfully restarted with a production of 1254 bfpd.
Result: Production re-established at higher rate than prior to shutdowns. Workover avoided.
PCP Runlife Increased
In this operation the wells were produced using PCPs, the PCPs were failing on a regular basis, typically in less than 90 days and nobody knew why.
The wells were drilled from pads and typically there were 8 – 15 wells on a single pad. The co-mingled production from all of the wells on the pad was pumped to the main processing station using a multiphase pump.
The multiphase pumps proved to be problematic and a pump failure would result in the backpressure on the wells increasing the tubing head pressure (THP). The PCPs in the wells would then have to pump against this much higher back pressure. The flowline from the casing was tied into the production flowline in order to allow gas to flow up the annulus rather than pump it through the pump. When the THP increased due to the multiphase pump shutdowns the gas from the casing flowline would not be able to enter the production flowline until the casing head pressure (CHP) had increased sufficiently to match the flowline pressure.
Analysis of the operating data showed that when the CHP increased to match the flow line pressure the fluid level in the well was being pushed down until a pump off situation was created, resulting in high gas volumes in the pump, insufficient cooling and damage to the elastomer.
Simultaneously the increased operating pressures were resulting in the PCPs being subjected to a pressure in excess of maximum recommended operating pressure. The high pressures across the pump and pump off conditions were causing the elastomers in the pump to harden resulting in failure of the PCP a few days after a multiphase pump failure.
The operator was advised to protect the PCPs from pump off using a high CHP alarm and trip, to use PCPs with a higher pressure rating and to use a high THP alarm.
Result: PCP failures prevented and runlife improved to in excess of 2 years.
Production on Gaslift Well Increased by 500 BOPD
A gaslift well was analysed using a well test in conjunction with a flowing gradient survey. The analysis showed that injection at the orifice was not possible with the reported gaslift injection pressure.
By increasing the injection pressure to 650 psi, injection at the orifice was achieved and the production increased from 850 bfpd to 1350 bfpd.
Result: Increased production by 500 bpd.
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