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Deployment of Cesium Formate Drill-In and Openhole Completion Fluid in the Martin Linge High Pressure, High Permeability Gas Reservoir Enhances Total's Operational Efficiency and Radically Improves Well Performance. 

Eirik Jøntvedt and Mikkel Fjeldheim, Total E&P Norge; Johan Løchen, Siv Howard, Stuart Leon, and Christian Busengdal, Cabot Specialty Fluids; Knud Richard Gyland, M-I SWACO, Schlumberger Norge

SPE-189550-MS presented at the SPE International Conference and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 7-9 February 2018.

Abstract

This paper summarizes the experiences of Total E&P's first use ever of a low-solids cesium formate reservoir drill-in and screen-running fluid. The unique 2.07 SG formate brine-based mud system was used by Total E&P Norge as reservoir drill-in fluid (RDF) and screen running fluid in a Brent high permeability, high pressure gas well No. 4, in the Martin Linge field on the Norwegian Continental shelf. The fourth gas well was the first Martin Linge well completed openhole with 250-micron stand-alone sand screens (SAS). The previous Martin Linge gas wells were drilled and completed with 230-micron expandable sand screens (ESS), using non aqueous based mud (NABM).

The low-solids cesium formate fluid was chosen for its known ability to produce easily through sand screens. The final fluid formulation, which consisted of concentrated cesium/potassium formate brine, included xanthan gum, high-temperature modified starch, and calcium carbonate bridging material, successfully underwent a series of qualification testing, including fluid loss control, rheology, formation damage, and production screen testing (PST).

The main benefits seen with the formate fluid system compared with the solids laden NABM fluid systems when drilling the 8 1⁄2-in. reservoir sections were significantly higher rate of penetration (ROP) with lower weight on bit (WOB), better drilling dynamics, significantly lower (0.016 SG) equivalent circulating density (ECD), 35% lower stand pipe pressure (SPP), and 5°C lower bottom hole circulating temperature (BHCT).

The drilling fluid properties were easily maintained within specifications. Compared with the NABM, the main benefits were improved rheology, lower solids content, and much thinner, non-elastic filter cake.

Improved wellbore stability was experienced for the well No. 4 compared with previous reservoir sections, and there was no indication of poor hole cleaning during drilling, tripping, or during lower completion operations, and no stuck-pipe incidents were experienced. In the previous reservoir sections, a stuck-pipe incident had been experienced in a coal section, requiring a sidetrack to be drilled.

The only performance issue with the formate fluid was its higher mechanical friction, which caused a 25% increase in drilling torque compared with the previous sections drilled with NABM.

A short cleanup of the well was conducted before the well was suspended. Despite the shorter cleanup time of the well No. 4 compared with the previous wells, the well's stipulated productivity index (PI) was twice as high. The pressure build-up response indicated full connection to the reservoir and no indication of partial plugging, which had been the problem during the cleanup attempts of the previous gas wells.

Disregarding the significant increase in fluid cost compared to the previous reservoir sections that were drilled and completed with NABM, well No. 4 was a technical and commercial success based upon drilling and tripping operations, completion operations, and cleanup results.

To read the full paper, download from www.OnePetro.org

 

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