A shale's tale: performance drilling with formates
"If you're drilling shale, think formates." This is the message from growing field experience and research into compatibility between shale and formate fluids. In the last year, two new studies have further established formate fluids' voracity for drilling through shale.
Tests on shales from the Tor/Ekofisk fields show that formate fluids facilitate fast, safe drilling while stabilizing wellbores and cuttings
Stabilizing North Sea shales
The first study (SPE 184661-MS) looks at wellbore stabilization in the Tor/Ekofisk wells located in the Danish sector of the North Sea. The authors completed an extensive wellbore stability investigation focusing primarily on improving shale-fluid compatibility. A review showed that wellbore cavings at Tor/Ekofisk in the Lark/Horda shales occur after three to five days of openhole time due to mud-pressure invasion. Whether oil-based or water-based muds are used makes no difference – both are equally limited in providing longer-term shale stability.
- Accretion of only 0.3%, which is the second lowest of all fluid formulations tested and is only outperformed by a modified OBM. Low accretion translates into low bit-balling tendency and high rate of penetration (ROP).
- 86% cuttings recovery in the cuttings disintegration test, which is on par with modified OBMs and the best results from high-performance water-based muds (HP WBMs).
- The pressure-transmission-test (PTT) delay factor was the highest of all muds tested with a value 12.5 higher than OBM. This means that wellbore cavings would occur after forty to sixty days rather than three to five days with OBMs. For comparison, the best-performing HP WBM only gave a delay factor 2.2 higher than OBM.
- The thick-walled-cylinder-test collapse pressure was the highest observed at an average value of 2139 psi, which is very close to the shale’s native strength range. For comparison, OBM yielded a low collapse pressure of 1724 psi and the best-performing HP WBM yielded 2022 psi, more than 100 psi below the formate result.
Why do formates aid shale drilling?
Interestingly, the second research study (AADE-17-NTCE-111) looks at why formate fluids drill so well. It identifies five shale-stabilizing factors that lead to formate fluids’ “excellent shale drilling qualities.”
Favorable clay-swelling inhibition: Alkali metal ions, in particular cesium, have strong repulsive hydration forces that suppress swelling pressures between clay platelets to provide excellent cuttings and wellbore stability.
Low mud-pressure penetration: Pressure transmission in shales leads to time-delayed borehole instability. Elevated viscosity in formate fluids’ filtrates can slow pressure transmission. Operators use this delay to increase openhole time, which provides the opportunity to drill the section, run casing and cement it without instability problems, as shown in the Tor/Ekofisk study.
Osmotic backflow strengthens boreholes: Depending on water activity and shale properties, formate fluids can strengthen boreholes by counterbalancing hydraulic flow into the shale and reducing pore pressure. Effectively, the high-salinity of formate fluids creates osmotic back flow from the shale to the drilling or completion fluid.
Osmotic dehydration: Osmotic back flow has a further benefit; by dehydrating the outer shale layer, bit-balling and cuttings accretion are decreased, which explains why ROP is so high in countless shale sections drilled by formate fluids as illustrated by DMK’s experience drilling shale in Canada (see Formate Matters issue 9).
Excellent lubricity:Cesium and potassium formates in particular are highly lubricious. This beneficial quality minimizes friction, improves torque and drag, and increases force transmission to the bit, thus improving ROP and bit life.