Wireline technique solves high-pressure North Sea sampling dilemma

Offshore staff

HOUSTON – Baker Hughes (NYSE:BHI) has deployed its Reservoir Characterization eXplorer (RCX) wireline service to obtain pressure samples in a harsh environment North Sea well.

Formation pressures varied from 9,430-15,950 psi (65-110 MPa) and wellbore temperatures reached 363°F (184°C).

“Pipe-conveyed logging was not an option due to the client’s short timeframe and the temperature of this high-pressure/high-temperature (HP/HT) well,” said Dominic Dieseru, UK applications and product line manager, wireline services and completions.

“Baker Hughes used the Deployment Risk Management service to develop a strategy for accessing the wellbore and then recommended a wireline service using high-strength cables and ultra slim-profile standoffs to ease high tension and sticking risks.”

To safeguard well control, the client opted for a mud weight with a 1.5 specific gravity, knowing that a potential 8,000-psi (55.16-MPa) overbalance might occur.

The RCX tool was prepared with an ultra slim-hole kit to maintain maximum tool diameter at 5.2 in. (13.2 cm) for deployment in a 5.625-in. (14.3-cm) borehole. A staged drawdown technique was applied to control the pressure drawdown rate and ensure measurement accuracy and repeatability.

Baker Hughes deployed the RCX tool to a depth below 16,400 ft (5,000 m) in the well, using the derrick-installed power capstan and crush-resistant HP/HT wireline cable, with an outer diameter of 0.490 in. (1.2 cm) and a breaking strength of 30,000 lb.

“The RCX tool provided reliable formation testing services in that well obtaining multiple pressure point stations, conducting repeat measurements to verify the downhole formation pressure,” Dieseru said.

This was achieved via deployment an 8,000-psi (55.16-MPa) differential pump in the string with the ultra slim-hole kit to enable the tool to move in and out of the well with no significant sticking during the operation. The Kevlar fiber-reinforced packer with an elastomer sealing lip ensured the packer withstood repeated high-pressure testing in this well.

Offshore Italy, Baker Hughes has helped an operator address gas production losses.

Liquid loading and the resultant high-pressure drops in a gas well and in the 14-in. (35.5-cm) subsea line connecting two production platforms were causing the losses. The operator had been regularly pigging the subsea line to mechanically remove the loading - Baker Hughes devised an alternative solution.

“A foamer can and will help increase gas production in gas wells that produce too much water and when the gas velocity is not high enough to transport the water out of the well,” said Peter Schorling, operations manager for Continental Europe.

“If this is happening, the kinetic energy of the well is not high enough and the well becomes ‘liquid loaded.’ The foamer decreases the specific weight of the water and makes it possible to transport the water out of the well with the low kinetic energy/gas velocity.”

For this well, field data were collected and input into Baker Hughes’s F.O.A.M. modeling software to help characterize the problem and identify treatment options. “This foam model contains statistical data from real jobs, as well as theoretical formulas,” Schorling explained.

“The combination allows the model to select specific Baker Hughes foamers as solutions. Analysis of a produced fluid sample on this well revealed 100% water without hydrocarbon condensate. Lab testing showed very good foaming efficiency using the F.O.A.M. FMW85250 foamer at 0.2% to 0.5% concentration.”

The liquid volume requiring treatment in the 3.1-mi (5-km) subsea line was calculated at roughly 50 cu m (1,765 cu ft). A foamer treatment was batch applied at a dose of 0.3% of the liquid in the line, and at the wellhead of one of the producing wells feeding into platform B. To address any gas/liquid separation issues, a defoamer was injected at the receiving facilities on platform A and at the central arrival slug catcher.

Gas production at platform B has since increased by 30%, and production through the flowline between the two platforms has risen from 270 cu m/d to 350 cu m/d (9,534 cu ft/d to 12,360 cu ft/d).

10/29/2012