Custom low-ECD reservoir drilling fluid solves complex field challenges

Reactive clays in North Sea wells created a long-standing challenge with pack-offs and stuck pipe. Wells drilled in the field had multiple incidents, and every well required at least one sidetrack. The circumstances were further complicated by a very narrow pore pressure/fracture gradient (PP/FG) margin.

The issues were mitigated, costs were reduced, and production was improved significantly with an innovative reservoir drilling fluid strategy developed specifically for the well conditions.

A rigorous and collaborative testing process customized the fluid system and carefully planned the rig-site execution. A two-fold approach applied a low equivalent circulating density (ECD), non-aqueous fluid (NAF), along with a change from a gravel pack-compliant expandable completion to a stand-alone screen (SAS) completion.

ORGANOCLAY-FREE NAF

Reactive shale in the target well prompted a change from water-based drilling fluids used in offset wells. The potential for wellbore degradation in the horizontal reservoir section, along with high-angle doglegs required a sufficiently inhibitive, lubricious fluid to stabilize the shale and facilitate running the screens.

To reduce completion cost, an open-hole sand screen completion was selected to replace the gravel pack-compliant expandable completions being used in the field. A series of laboratory slurry tests showed running the stand-alone sand screens would have minimal impact on well productivity and would fulfil all the well objectives as set out during the planning phase.

In these conditions, it was necessary to control mud weight and inhibition, based on the specific wellbore conditions. The narrow PP/FG margin presented concerns at high fluid densities; a fracture gradient of 3,572 psi (12.5-ppg EMW) could require 12.0-ppg fluid density to maintain wellbore stability.

The solution used Halliburton’s BaraXcel NAF to drill the reservoir and install the screens. The organoclay-free NAF uses a fatty acid and polymer fluid design to produce a unique fragile gel structure to lower downhole losses, reduce the volume of costly base oil, and improve return reservoir permeability.

The NAF system enabled trouble-free drilling at a reduced ECD, while a customized base brine and bridging agent package eased removal of the acid-soluble solids phase to improve production at lower cost. The customization used high-density calcium bromide brine in the water phase of the NAF to reduce solids loading, control ECD, and inhibit clay reaction. The fluid system also provided the lubricity needed to negotiate high-angle hole sections when running the sand screen.

BESPOKE FLUID SOLUTION

Fig. 1. A bespoke non-aqueous drilling fluid system has helped an operator overcome challenges with pack-offs and stuck pipe in a North Sea well.

Using an NAF weighted with barite was problematic. In the open-hole completion, there was no simple means to remove barite that could block formation pores and impair production during the clean-up and test with screen plugging highlighted as a major risk with any non-acid soluble weighting agent used in the drilling fluid. The need for added solids to be acid-soluble led to specification of a ground marble-sized bridging agent to enable remedial reservoir treatments, if necessary. This approach ultimately proved perceptive and successful, Fig. 1.

Reduced solids loading made it possible to use the fluid for drilling and screen running. This dual-purpose use proved effective, and helped eliminate operational costs associated with fluid displacements and wellbore cleanup.

At high densities, the organoclay-free NAF was less likely to exceed the narrow PP/FG margin than a standard NAF, due to its stable rheology across a wide temperature range, pronounced shear-thinning properties, and high, fast-breaking gel strengths. The flat rheology and fragile gel structure minimizes ECD without compromising hole cleaning or increasing the risk of weight material sagging. The rheology has little shear stress drop-off at low and ultra-low states, and viscosity is consistent across a range of operating temperature and pressures. The organoclay-free systems also minimize formation shock by avoiding large increases in circulation pressures, when gels are broken after a static period.

While a need for 12-ppg fluid density was foreseen, the NAF could be weighted to a maximum of 10.6 ppg, using the weighting agent alone. To increase density, the water phase was changed from a calcium chloride base with a density of 11.3 ppg to a calcium bromide base with a density of 14.2 ppg.

The change achieved 12-ppg density while maintaining low rheological properties. It also lowered solids loading, which reduced potential completion damage from screen plugging and erosion.

A calcium bromide emulsifier was used to stabilize the brine-in-oil emulsion and improve the dispersion characteristics of the aqueous phase droplets. This primary emulsifier was an addition to the standard NAF fluid emulsifiers.

TESTING PHASE

Three NAF systems were constructed at densities of 9.8 lb/gal, 10.6 lb/gal, and 12.0 lb/gal. This fluid was formulated to cause minimal damage to the formation while meeting other well challenges. The fluid had to be capable of bridging 42-micron sand in the drilling phase, and pass through the 6-5/8-in., 150-micron screen during the completion phase.

The NAF was emulsified with both a standard NAF emulsifier and a calcium bromide emulsifier to optimize emulsion stability. SAG testing was performed to determine weighting solids settlement. The three fluids had a low SAG factor, indicating the rheological profile of the fluid was sufficient to suspend the solids in the fluid.

Permeability plugging tests (PPT) were performed to determine the capability of the solids in the fluid to bridge the porous sands and form a filter cake. The PPT was conducted, using a 40-micron aloxite disc to ensure the fluid provided the optimum bridging across the formation. The formation sands had a permeability of 1,200 to 1,800 mD; for the laboratory testing, the average pore throat was calculated at 42 microns, resulting in the use of a 40-micron aloxite disc.

The 12-ppg NAF fluid bridged the aloxite test disc and exhibited tight fluid loss and a thin, slick filter cake. The maximum marble content tested was 152 ppb in the 12-ppg fluid. Reducing the oil/water ratio to a minimum 65/35 and adding the sized marble achieved the desired density.

The 9.8-ppg NAF fluid with a 64-ppb ground marble concentration did not bridge the 40-micron pores, due to the fluid’s low solid concentration—a product of the calcium bromide base necessary to create a 12-ppg fluid with low rheological properties.

Bridging was improved while maintaining density by increasing the oil/water ratio from 70/30 to 80/20. Increasing the oil content reduced the density, allowing an increase in the sized marble concentration to 80 ppb. At the higher concentration, and with adjusted rheology modifiers, the fluid successfully bridged the pores and the fluid loss was reduced significantly.

Return permeability testing to determine potential drilling fluid damage to the formation was performed, using Bentheimer core samples of 1,200 to 2,000 mD. The tests produced a return of more than 97% for the 12- and 9.8-ppg NAF fluids under the laboratory conditions matched to the expected in field conditions of overbalance, drawdown and confining pressures.

The ability of the fluid to flow through the API 150-micron premium mesh production screen was assessed with a production screen test. Each NAF fluid weight was pumped through the screen multiple times, and there was no indication of screen blockage.

JOB EXECUTION

The fluid design process concluded successfully, with the three NAF formulations optimized to meet target specifications. The 9.8-ppg NAF system was shipped to the rig following a formation integrity test (FIT) performed with a 10.5-ppg fluid to a 12.6-ppg fracture gradient.

Because the previous hole section was drilled with a barite-weighted NAF, the rig had to be cleaned from rig floor to pit room to meet brine specifications and avoid compromising future well production. Planning meetings established strict cleanliness procedures and standards. All barite solids were removed from the surface line and equipment to prevent the introduction of any non-soluble solids to the organoclay-free NAF fluid system.

Fluid density was increased onsite to control wellbore stability prior to, and while drilling out the hole section. This had to be done without increasing the weighting agent concentration, while maintaining an acceptable oil/water ratio and rheological profile. However, the solution of adding CaBr₂ brine required changes in the NAF formulation to maintain emulsion stability, improve filtration control to avoid fluid loss, and retain rheological profile. The complex changes involved addition of emulsifiers, filtration control products, and base oil.

Once completed, well production through a restricted choke during cleanup was 11,000 bopd, but this promising initial rate gradually declined. A remedial acid treatment—facilitated by the acid soluble weighting agent—was performed and the production ultimately exceeded the original cleanup well productivity and planned target.

CONCLUSION

The success of the well shows how a reservoir-first approach provides an effective, custom solution. Selection and customization of BaraXcel NAF through collaboration and rigorous laboratory testing enabled the problematic reservoir section to be drilled, and the sand screens installed without issue.

The well was drilled under budget and the integrated approach cut operational costs 55%, compared to offsets. The well is the first in the field to be drilled to TD without any stuck pipe incidents or a sidetrack. It was also the fastest well to TD. The use of a simplified sand control completion over a gravel pack, and the utilization of the PST specification fluid, mitigated field challenges and resulted in significant savings. Future well campaigns will also include an in-situ treatment to remove any residual acid soluble material prior to the clean-up and flow test back to the host facility.