Reduced Drilling Mud Losses

Reduced Drilling Mud Losses

Loss of drilling fluids is one of the leading causes of non-productive time and drilling problems. An estimate two decades ago showed that cost associated with drilling fluid loss exceeded $1B annually. Invasion of drilling fluid filtrate and suspended solids into a near-wellbore region during drilling operations leads to formation damage and can cause wellbore instability, severe permeability impairment, and a substantial decline in production. In addition, invasion of wellbore fluids often masks the data acquired by most logging tools and has a detrimental impact on formation evaluation. These issues are partially circumvented using lost circulation materials (LCMs), which plug formation pores or fracture throats, form a filter cake, and reduce filtrate flux into formation. Bridging occurs when the size of particles is approximately 1/3 that of a pore opening, and there exists an optimum LCM size range that makes them effective at sealing a respective size. Several recent studies have shown that drilling muds that combine conventional LCM with particles in the nanometer domain can dramatically reduce drilling fluid loss and form a thinner, stronger and less permeable filter cake, compared to drilling fluids containing LCM alone. Due to their small size and high surface area, finely dispersed nanoparticles (NPs) are able to form tighter packing structures and effectively fill the gaps between the micron-sized particles that would otherwise permit fluid flow. Subsequently, this leads to lower permeability and reduced filtrate flux. Furthermore, NPs and their agglomerates can also serve as bridging agents in the case of micro- or nanopores, as was demonstrated in experiments on shales.

Field test implementation

Through 2014, nine full-scale field tests were conducted in horizontal wells in Alberta, Canada, in partnership with a local drilling fluids company. The results were compared to control wells, which included historic high-temperature, high-pressure (HTHP) fluid loss filtration and total mud losses from offset wells in the area provided by the mud company. For consistency, all the wells used in the analysis were drilled using the same rig and crew. Lithology in all the cases was represented by fine-grained to conglomeratic sandstone, shale, and coal, with a pay zone in the Cardium formation. Since the control and test wells employed a similar drilling program and invert emulsion drilling fluid, it was assumed that any significant and consistently reproducible deviation from the average control values was due to the presence of the nanoparticle technology. Field data for the test wells, shown in Fig. 1, was collected by the mud company representative as well as the nFluids R&D team to further improve experimental accuracy of the results.


Figure 1 An impact of the 1st generation nForcer™ nanoparticle additive on the total drilling mud losses per 100 m drilled.


Nine full-scale field tests were completed in Alberta demonstrating up to 30% reduction in total mud volume losses during drilling. Field results were consistent with lab experiments based HTHP fluid loss observations. Meanwhile, the impact on the basic mud properties was within an acceptable range encountered during normal drilling operations.

After completing these field tests, nFluids has made significant product development breakthroughs:

  • Simplified the manufacturing process while reducing manufacturing costs by 50%.
  • Increasing the field concentration of the liquid product from 5% to 20%.
  • In conjunction with partners, created a new 70%+ solid product.
  • More than doubled the HTHP fluid loss performance in the lab from 30% to 70%+.

nFluids has successfully scaled up the manufacturing process to commercial quantities and is now ready to field test our 2nd generation technology.

2nd generation technology HTHP fluid loss reduction laboratory test results


Figure 2 An impact of the 2nd generation nForcer™ nanoparticle additive on HPHT fluid loss in commercial oil-based drilling fluids.

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