Performance Report: Brazil: First application of the BREAKDOWN system utilizing D-SOLVER EXTRA chelant

Challenge: A well in the UK sector of the North Sea came on stream as a Rotliegendes gas producer in September 1998. A production logging tool run indicated water ingress at the base of the perforations with a rising water interface. The proposed sidetrack aimed to enter the Rotliegendes at an angle of 90°, with a 500‐ to 2000‐ft (152‐ to 610‐m) reservoir section to increase wellbore contact with the reservoir to maximize reserves recovery. The well would be completed with a 230‐micron standalone premium screen. Formation or completion impairment would need to be avoided to maximize productivity, minimize drawdown and discourage water encroachment.

Solution: A 9.0‐lb/gal (1.08‐SG) FLOPRO NT fluid would be designed to seal the formation face and minimize filtrate invasion while delivering optimum drilling performance. 1‐2% KLA-STOP NS additive would be used to minimize low‐gravity‐solids (LGS) buildup and help maintain a pristine filter cake. The BREAKDOWN chelant/enzyme‐breaker system was chosen for its ability to fully remove the FLOPRO NT filter cake from the sandface, while controlling breakthrough time. This would ensure that the well did not take losses prior to pulling out of the hole with the washpipe and closing the Fluid Loss Control Valve (FLCV). The FLOPRO NT reservoir drilling fluid/ BREAKDOWN breaker yielded positive results in an independent return permeability study.

Result: An 8½‐in. hole was drilled with VERSACLEAN LT oil‐base mud through the Haisborough group and Zechstein sequence. The 7‐in. liner was set, and a 6‐in. hole was drilled through the Leman Sandstone reservoir with the FLOPRO NT system. A solids‐free FLOPRO NT fluid was displaced into the well prior to running screens. The 9.0‐lb/gal (1.08‐SG) BREAKDOWN breaker was spotted after the screens and packer had been run. The BREAKDOWN breaker allowed the 2⅞‐in. washpipe to be pulled from inside the screens and the FLCV to be closed without losses to the formation.
An average permeability of 2 mD was expected, but the logging‐while‐drilling (LWD) resistivity tools showed a better reservoir section in terms of porosity. As a result, permeability values were expected to increase. The well test analysis reported an average value of 10 mD. The field well test analysis revealed no skin damage.

After reaching TD, the open hole section was displaced to FLOPRO SF† fluid at 150 m (492 ft) above the casing shoe. At that depth, the casing was displaced to brine and the riser indirectly displaced to seawater and then brine.

The drill sting was pulled out and screens were run in hole. When the screens reached TD, the well was displaced to 1.14 SG (9.5 lb/gal) brine. On producer wells, the breaker was spotted after gravel packing. On injectors, which were stand alone screen completions, the BREAKDOWN breaker system was spotted after displacement.

The volume pumped was double the open hole volume of 1.164 SG (9.7 lb/gal) breaker (100% excess). After spotting the breaker, the washpipe was pulled at maximum speed to above the fluid loss control device, while the breaker started working on the filter cake.

After confirmation that the fluid loss control valve was closed, any excess breaker was reversed out and put back into MPT tanks. All captured breaker was sent back to town for proper disposal.

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