Valemon, operated by Statoil, is a high-pressure/high-temperature (HP/HT) gas/condensate field on the Norwegian Continental Shelf. Production started at the beginning of 2015 from a development consisting initially of cased-and-perforated wells. However, during early field development, the orginal concept was for a standalone-screen (SAS) lower completion. A potassium/cesium (K/Cs) formate water-based system with a density of 2.02 specific gravity (sg) was considered as a candidate drilling-and-completion fluid for the wells completed with screens, one of which could potentially be suspended in formate brine for up to 10 months before the arrival of the platform and before cleanup and the onset of production. An unknown was the possibility for any near-wellbore interaction with these fluids during extended contact and the possible detrimental impact on productivity. Computational-fluid-dynamics (CFD) modeling was performed to determine the length of time formate would be in contact with the near wellbore, demonstrating that, especially for the lower-permeability intervals, a contact time of approximately 45 days was a possibility. In light of this, a sequence of corefloods was performed that involved extended soaks in formate along with preand post-test analyses to identify potential damage mechanisms. Those identified included kaolinite dissolution, precipitation of barium and cesium silicate, and swelling of kaolinite because of the incorporation of potassium and cesium into the kaolinite lattice. To confirm the findings from the CFD and coreflood modeling, a field review was made of Statoil's experiences with suspending wells for extended time in formate before cleanup and production. The field review demonstrated positive experiences in the use of formates in suspended wells with respect to productivity. Lower than expected productivity was experienced for some wells, but this could not be related conclusively to the use of formates. This paper provides an overview of lessons learned from coreflooding, CFD modeling, and actual field data on wells suspended in formate before cleanup and production.

A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling fluid filtrate loss volumes. This paper will examine the factors which contributed to alterations in the core samples. A series of corefloods were carried out using core from 2 formations and different drilling fluids. Separate tests were carried out using drilling fluid alone and the full operational sequence. Filtrate loss and permeability measurements combined with interpretative analyses to understand what happened in the near-wellbore. Micro-CT "change maps" gave 3D visualisations of the thickness of operational fluid cakes and extent of retention/clean-up – valuable insights into factors that influence hydrocarbon recovery. All drilling fluids tested had "normal" filtrate loss volumes, with one having notably higher losses with a particular formation. Normally this would be considered a bridging issue and "fixed", but those tests showed comparable or slightly lower alterations in permeability. Analysis showed that, despite deeper constituent infiltration, they were not contributing significant extra damage or retention; the nature of the drilling fluid attachment and cake seemed to be more relevant here than depth of invasion. Other examples will illustrate that the impact of drilling fluid infiltration and retention can range widely, and that there are more key factors than simply filtrate loss volume. Results showed that focusing on the metric of filtrate loss alone may increase risk during drilling fluid selection. Understanding the relationship between filtrate loss, permeability/inflow alteration, retention/clean-up after production is important in selecting fluids as well as giving a better understanding of where improvements can be made. 3D visualisations of the alterations caused by drilling fluid allow conclusions to be drawn when previously there would be speculation.

Valemon, operated by Statoil, is a HPHT gas/condensate field on the Norwegian Continental Shelf. Production started at the end of 2014 from a development consisting initially of cased & perforated wells. However, during early field development the orginal concept had been for stand alone screens (SAS) lower completion. K/Cs formate water based system with a density of 2.02sg. was considered as a candidate drilling and completion fluid for the wells completed with screens, one of which could potentially be suspended in formate brine for up to 10 months prior to the arrival of the platform and before clean up and the onset of production. An unknown was the possibility for any near wellbore interaction with these fluids during extended contact and the possible detrimental impact on productivity that this could have. Computational fluid dynamic (CFD) modelling was performed to determine how long formate would be in contact with the near wellbore and this demonstrated that, especially for the lower permeability intervals, a contact time of approximately 45 days was a possibility. In light of this, a sequence of corefloods was performed involving extended soaks in formate along with pre- and post test analyses to identify potential damage mechanisms. Those identified included kaolinite dissolution, precipitation of Barsium and cesium silicate, and swelling of kaolinite due to the incorporation of potassium and cesium into the kaolinite lattice. To confirm the findings from the CFD and coreflood modelling, a field review was made of Statoil's experiences with suspending wells for extended time in formate prior to clean up and production. The field review demonstrated positive experiences in using formates in suspended wells with respect to productivity. Lower than expected productivity was experienced for some wells but this could not be conclusively related to use of formates. The paper provides an overview of lessons learned from coreflooding, CFD modelling and actual field data on wells suspended in formate prior to clean-up and production.

A study was carried out to examine formation damage mechanisms caused by drilling fluids in tight reservoirs in several onshore oil fields in Abu Dhabi. Three phases of compatibility corefloods were carried out to identify potential to improve hydrocarbon recovery and examine reformulated/alternate drilling muds and treatment fluids. Interpretation was aided by novel Nano-CT quantifications and visualisations. The first phase examined the current drilling muds and showed inconsistent filtrate loss control alongside high levels of permeability alteration. These alterations were caused by retention of drilling mud constituents in the near-wellbore and incomplete clean-up of drilling mud-cakes. Based upon these results, reformulated and alternate drilling muds were examined in Phase 2, and there was a positive impact upon both filtrate loss and permeability, although the Nano-CT quantifications and visualisations showed that drilling mud constituents were still having an impact upon permeability. Candidate treatment fluids were examined in Phase 3, with all having a positive impact and the best performance coming from 15% HCl and an enzyme-based treatment. The interpretative tools showed that these treatments had removed drilling mud-cakes, created wormholes, and bypassed the areas where constituents were retained. The compatibility corefloods on tight reservoir core, alongside high-resolution quantifications and visualisations, therefore identified damaging mechanisms, helped identify potential to improve hydrocarbon recovery, and identify treatment fluid options which could be used in the fields.