These aren’t your grandfather’s mud systems
When Spindletop hands were trampling cows over a watered-down field to generate their version of a lubricating drilling fluid system, the last thing on their minds was formulating the proper rheological profile. Those nascent mud engineers also had no inkling that over the next 113 years, their ultra-rudimentary concoction would steadily evolve into the most critical element for safe, effective drilling in some of the most unforgiving downhole environments.
The evolution of drilling fluids from their bovine-begotten predecessor to finely engineered systems, capable of handling the most inhospitable conditions, was driven home in late September, during the 9th Annual World Oil High-Pressure, High-Temperature (HPHT) Drilling and Completion Conference in Houston. There, briefings ranged from real-world examples of how application-specific water and invert-emulsion muds are helping tame hot and over-pressured wells, to the more exotic, namely the results of latest experimentation with nanotechnology to enhance drilling fluid rheological properties.
Elevated pressure and temperature create havoc with mud rheologies, especially the yield point and, thus, the capacity to suspend drilling solids and clean the hole, as well as the ability to put a cork in fluid loss and head off wellbore instability. These breakdowns are primary contributors to the three times more non-productive time (NPT), and 100% to 200% more well control incidents, in HPHT wells than their more normally pressured and heated counterparts, said Ahmed Zakaria Noah, associate professor of the School of Sciences and Engineering at American University in Cairo, Egypt. One way to reverse those HSE and economic risks, he said, is combining the intrinsically high thermal stability and tensile strength of nanomaterials with the pore plugging capacity of polymers.
Incorporating ultra-thin nanotechnologies in the oilfield fluid cycle is not new. Rice University and the University of Texas’ Advanced Energy Consortium have long been at the forefront of furthering development of nanotechnology, with an initial focus on use in completion fluids and EOR projects. Commercially, M-I SWACO has incorporated nanosilica-based additives in water-based drilling fluids, to block water intrusion and improve shale inhibition in unconventional applications.
In the latest fluid-related nanotechnology research, Noah described how recent lab investigations at the Egyptian university have shown promise in reducing the comparatively elevated well control incidents and NPT that all too often accompany the drilling of HPHT wells. While research demonstrates that using multi-walled carbon nanotubes with polymer nanocomposities effectively maintains cuttings-carrying viscosity and arrests fluid loss at HPHT conditions, Noah concedes the tremendously high costs of the new-age tandem are not for the economically squeamish.
OBM alternatives. For the time being, research into drilling fluids, capable of coping with downhole extremes, continues to focus largely on developing alternatives to conventional oil-based muds, which have become environmentally taboo in many areas. The pickle confronting fluid companies these days is balancing extreme service capabilities with environmental acceptability. That reality was illustrated recently in northern Italy’s Po Valley, where Eni was planning a slim-hole re-entry of a well drilled more than three decades ago, that was expected to deliver up to 15,000 psi and nearly 330°F, BHP and temperatures, respectively. The original well was drilled with oil-based mud, which has since become an environmental no-no.
Consequently, it fell upon Newpark Drilling Fluids to formulate a more environmentally acceptable option that would still meet the rigorous demands. The well design called for whipstocking out of the existing 7-in. production casing at 15,700 ft, drilling a 53/4-in. hole while building angle to 39° and holding at 18,182 ft, followed by a second 60° build section to precede TD at 18,874 ft.
After what was described as an extensive qualifying process, the formulation was accepted. It helped ENI drill the sidetrack in 82 days, some 30% less days than planned.
Dual-use mud. The more extreme the downhole conditions, the harder it is to handle critical equivalent circulating densities (ECD), which falls squarely on the mud system. Typically, HPHT wells bring a challenging combination of low fracture gradients and high pore pressure, producing a narrow drilling window that requires meticulous balancing of mud weight to avoid fracturing the formation or opening a path for well control problems
“In the human body, if pressure is too high or too low, it will cause health concerns,” said Halliburton Baroid’s Jeff J. Miller, global product manager for invert emulsion fluids. “It’s no different when you’re talking about ECD (management) in a well, with all the fluid moving through an annulus and the friction build-up. The first thing we have to do is look at your boundaries. There are only so many strings of pipe you can run in a well.”
Miller described one of the latest iteration’s of Baroid’s invert emulsion-based drilling fluids, which has been employed extensively for ECD control in the deepwater Gulf of Mexico and elsewhere. He also cited an added bonus, when a 16 lb/gal version of the mud was used as a “crossover fluid” in an HPHT well in Norway. The drilling fluid not only got the well down without any budget-shattering problems, but it went on to function as a completion fluid.
“We were able to drill to TD and then used it in the screen completion, saving the operator about $5 million by not having to use a cesium formate (completion) brine,” he said. “We’re seeing quite a bit of difference now, in that you’re no longer just looking at fluids to drill a well, but we’re also looking at these specialized fluids.”