Krishna M. Ravi

Drill-Cutting Removal in a Horizontal Wellbore for Cementing

For effective zonal isolation. drill cuttings and gelled, dehydrated drilling fluid (GDDF) should be removed from the wellbore before a cement job, but such removal can be a challenge when the wellbore is deviated and the casing is not centered. This paper discusses simulated wellbore experiments that investigated the effect of different factors on the removal of drill cuttings and GDDF from a horizontal well bore. The parameters studied included eccentricity. flow rate. hole size. casing size. fluids pumped as flush/spacer. and pipe movement. The results showed that below a certain flow rate. the drill cuttings and GDDF could not be dislodged from the wellbore. In field applications. this flow rate must be known so that job designers can selectively design flushes that will effectively dislodge the drill cuttings and GDDF. As expected. eccentricity also alters the velocity profile in the narrow side of the annulus. and geometry was also a factor in removal efficiency. The experimental setup. procedure, and results are discussed in detail. Flow rates needed to dislodge the drill cuttings and GDDF are also discussed. A numerical analysis of the fluid flow in wide and narrow annuli was also performed.

Deepwater cementing challenges

Oil and gas wells are being drilled in increasingly deep waters and demand increasingly efficient execution. The water temperature gradient from surface to seabed is non-linear and the properties of shallow formations vary from location to location. These factors add further challenges to the already difficult issues in deepwater drilling. They impact the design of cementing operations more than is generally recognized. In particular, the intrinsic properties of cement slurry such as heat of hydration is generally ignored and standard testing methods are inadequate. The purpose of this study was to investigate and optimize cementing operations; particularly those related to shallow surface casings in deepwater wells. The following issues will be addressed: ○ the temperature of the slurry during placement ○ the temperature of the slurry during wait-on-cement (WOC) ○ the get strength development of the slurry to prevent fluid influx ○ the compressive strength development of slurry to detennine earliest safe time to release the conductor (or determine the support of other shallow casing strings) Both numerical and experimental simulations were used. Temperatures were numerically simulated and were then validated using both laboratory and field data. Intrinsic properties of the slurry such as heat of hydration and heat capacity were used together with appropriate boundary conditions in a numerical simulation of the temperature during slurry placement and WOC. A large-scale experimental setup was built in the laboratory to simulate: ○ The thick cement sheath in deepwater shallow casing annuli. ○ Loose sand/silt surrounding the cement sheath and its dimension relative to the cement sheath. ○ Seabed temperature, e.g. -2 °C at a depth of 800 meters in the North Sea. The slurry temperature was monitored during curing in the large-scale test setup. There was good agreement between the slurry temperature measured in the large-scale test setup and the numerical study. The simulated temperature is referred to as Simulated Slurry Temperature, or SST. SST is specific to the slurry design and the well parameters. Slurry was cured in a UCA using both SST and the conventional seabed temperature. Based on this work, recommendations for releasing the conductor were made for an offshore job in Norway in 800 metres of water. The cement job was successfully completed based on these recommendations with a significant saving in rig time. Laboratory tests, numerical simulation and results from a field job are discussed in this paper.