上游油气工程

Ricardo, we just lost Well A-12. The ESP tripped on "underload" at 03:15 this morning. The operators tried to restart twice — both times it tripped immediately. We need to figure out what happened. This well was producing 3,200 BOPD — that's $200,000 a day in revenue. Every hour it's down is costing us $8,300.

Let me pull up the shutdown data from the ESP surface panel. (scrolls through the SCADA trending) OK, here's the pattern. Motor current was stable at 48 amps for the past two weeks. Then yesterday at 18:00, the current started oscillating — first a gradual drop from 48 to 42 amps, then a rapid drop to 18 amps at 03:15. The motor just lost load. When an ESP drops to underload that fast, it usually means one of three things: pump intake is gas-locked, the shaft broke, or the pump stages are worn out and downthrust.

(studying the trend) Looking at the intake pressure — it was stable at 1,200 psi for weeks. Before the trip, the intake pressure actually rose from 1,200 to 1,450 psi. If it were gas lock, the intake pressure would fluctuate wildly. If the shaft broke, the intake pressure would spike suddenly. The gradual intake pressure rise combined with current decline — that's classic pump wear. The impellers have worn down, the pump can't develop head anymore, and it eventually couldn't lift the fluid column. The motor was essentially running unloaded at the end.

How long was this ESP in the well?

14 months. It was set at 2,600 meters, pumping a fluid with about 3% sand content. The original ESP was rated for 24 months run life in clean fluid, but with sand, run life drops significantly. The sand basically sandblasts the impellers. 14 months with 3% sand is actually not bad — the offset wells with similar conditions averaged about 11 months. We're already planning the workover. We have a replacement ESP on the rig. We'll need about 4 days to pull the old ESP, run the new one, and put the well back on production.

Sandra, Well C-07 has been declining for the past month. It was producing 1,800 BOPD on gas lift. Now it's down to 1,100 BOPD — a 39% drop. The gas lift injection pressure is normal at 1,200 psi, and the injection rate is holding at 2 MMSCFD — same as always. But the wellhead flowing pressure has increased from 350 psi to 580 psi. The well is backing up. What's your diagnosis?

If the wellhead pressure is rising but the gas lift injection is steady, the restriction is downstream of the wellhead — in the flowline or at the production manifold. It's not a reservoir issue and it's not a gas lift issue. Li Wei, can you check the pressure at the production manifold for C-07?

(checking the manifold gauge) The manifold inlet pressure for C-07 is 195 psi. Normally it should be around 300 psi with a 580 psi wellhead. So the pressure drop between the wellhead and the manifold is 385 psi over 2.5 kilometers — that's 154 psi per kilometer, way above the normal 30-50 psi/km for this flowline. We have a flowline restriction. Most likely paraffin buildup — this crude has a wax appearance temperature of 45°C and the flowline isn't insulated.

Right. We need to pig the flowline. David, how soon can we schedule a pigging run? And in the meantime, can we inject a wax inhibitor at the wellhead to at least stop more wax from forming?

We can pig it tomorrow morning — I'll coordinate with the pipeline team. For tonight, increase the gas lift rate to 2.5 MMSCFD to compensate for the higher backpressure and maintain production. Not ideal for efficiency, but better than losing 700 barrels. Li Wei, set up the wax inhibitor injection at 50 ppm — that should stabilize the flowline condition until we pig it clean.