Evaluating Formation Damage Predictions Drawn from HPHT Core Flooding Tests on Brent Group Sandstone Reservoir Cores with Heavy Formate Drill-in Fluids: A Case Study from the Huldra Field

Downs, John (Formate Brine Ltd) | Fleming, Niall (Statoil ASA)

OnePetro 

Abstract

The existing literature provides little guidance on the relevance of formation damage or return permeability results obtained from reservoir-conditions core flood testing on sandstone cores with heavy formate fluids. The drilling and completion in open hole of all six production wells in the Huldra field with heavy formate fluid provided a rare opportunity to appraise the results from HPHT core flood testing carried out on Ness (North Sea Brent Group) sandstone reservoir cores as part of the original drilling fluid qualification process for the Huldra development program.

Low- and high-permeability sandstone core plugs obtained from the productive Ness reservoir formation in the Huldra field were subjected to static and dynamic exposure to heavy formate drill-in fluids under HPHT reservoir conditions at 350 psi overbalance for a period of 296 hours. The cores were then exposed to short-duration drawdowns under HPHT reservoir conditions to simulate the very early phase of production start-up. The permeability impairment results obtained in these laboratory tests were compared against the production performance data for six Huldra field wells drilled and completed with sand screens in open hole in Brent Group sandstones with the same heavy formate fluids.

The reservoir-conditions (11,400 psi, 150°C) core flooding test with a SG 1.92 formate drill-in fluid sample from a Huldra well drilling job reduced the permeability of a 1416 mD Ness core by 37.8%. The same fluid reduced the permeability of a 2.8 mD Ness core by 65.9%. Repeating the same reservoir-conditions core flooding tests with a fresh SG 1.92 formate drill-in fluid sample prepared in the laboratory gave very similar results. In all cases the permeability of the cores was restored to original levels by soaking the wellbore face of the cores at balance for 24 hours with 15% acetic acid under reservoir conditions. The full restoration of permeability by non-invasive soaking of the core faces with dilute organic acid at balance suggested that the source of the tractable impairment was residual CaCO3/polymer filter cake still pressed onto the core face after lengthy drilling fluid exposure at overbalance and a very short clean up by drawdown.

The six Huldra production wells were drilled with SG 1.92 formate fluid at 37°-54° inclinations through the Tarbert, Ness, Etive and Rannoch reservoir formations and completed in open hole with 300-micron single-wire-wrapped screens. The wells cleaned up naturally during production start-up, without the need for acid treatment, resulting in skins that were at the low end of the expected range. The Hudra field was shut down in 2014 after producing 17.3 GSm3 of gas, representing an 80% recovery of the original gas in place.

This has been a useful first appraisal of a set of historical return permeability test results obtained with heavy K/Cs formate fluids. As more data become available from other HPHT gas condensate fields developed entirely with heavy formate brines (e.g. the Kvitebjørn and Martin Linge fields) it may become possible to assign some predictive value to the results of return permeability tests with these fluids.

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