This paper discusses two high-temperature-resistant polymers (Polymers A and B) that have been developed as thermally stable, dual-functional viscosifiers and fluid-loss additives. Polymer A was designed for monovalent brines, while Polymer B works for divalent brines. These polymers enable the formulation of brine-based drill-in fluids that are stable at high to ultra-high temperatures, which is a significant improvement when compared to conventional biopolymer-based drill-in fluids. When combined, the two polymers work synergistically to further reduce fluid loss in monovalent brines.
The two thermally stable polymers were readily incorporated into various drill-in fluid formulations containing either monovalent or divalent brines over a broad range of densities. These drill-in fluids exhibited exceptional thermal stability and showed no stratification after static aging at 400°F for three days or at 375°F for seven days. A minimal change in fluid behavior was observed when comparing the rheological properties of the un-aged and aged samples. The samples provided excellent fluid-loss control, even after aging. A synergistic effect was observed between Polymers A and B when used in monovalent brines to further reduce the HPHT fluid loss with no negative impact on fluid rheology. Core flow tests showed that both fluids were non-damaging after acid-breaker treatment. It is anticipated that these polymers will extend the envelope to which water-based drill-in fluids can be successfully used to drill high- and ultra-high-temperature reservoirs. Recent successful field trial of the divalent brine-based fluid as a testing fluid further proved the robustness of these fluids for these reservoirs.
Reservoir drill-in fluids are specifically designed to avoid excessive fluid penetration and solid invasion into production zones so as to minimize formation damage. With wellbore temperatures increasing, the drive to develop thermally stable drill-in fluids has increased dramatically over the last few years. Oil-based or synthetic-based drill-in fluids can meet temperature requirements easily, but are often not desirable for drill-in applications. Brine-based drill-in fluids usually use bio-based polymers as viscosifiers, but they are not suitable for high temperature applications because most bio-based polymers break down at temperatures above 300°F. Most synthetic polymers available in the market are difficult to hydrate in concentrated brine solutions, and they are not so thermally stable because of hydrolysis, especially when the temperature is above 350°F. This paper describes the application of two uniquely developed polymers in brine-based drill-in fluids that demonstrate outstanding performance at temperatures greater than 400°F.
Polymer 1 is designed to work with monovalent brines, and polymer 2 is intended for divalent brines. Using these two polymers, thermally stable, brine-based drill-in fluid formulations were prepared with densities ranging from 10.5 to 18 ppg. Various brine and weighting agent combinations were investigated to keep the total amount of solids low for the various fluid densities tested. Calcium carbonate (CaCO3) was used as a bridging and weighting agent for low density fluids, and manganese tetroxide (Mn3O4) was used for high density fluids. All fluids were prepared using a multimixer, and the fluid viscosity was examined with a direct-indicating viscometer. Return permeability testing was conducted on both a lower permeability Kirby sandstone core and a higher permeability Berea sandstone core.
Both polymers provided very good rheology and solid suspension capability, as well as very good fluid loss control. The drill-in fluids made with these two polymers were statically aged at 400°F for 72 hours after conditioning the fluid by hot-rolling for 16 hours at 150°F. The viscosity of the fluids was well maintained after aging, and the high temperature (350°F/500 psi) fluid loss was less than 15mL and 10 mL for polymer 1 and polymer 2, respectively. The thermally stable brine-based drill-in fluids demonstrated high return permeability values, indicating minimal formation damage on the tested cores.
High temperature brine-based drill-in fluids are limited by the availability of thermally stable viscosifiers and fluid loss control additives. The newly developed polymers 1 and 2 provide thermal stability up to 400°F for 72 hours, which has not been achieved with previous bio-based polymers or other synthetic polymers.
High performance (HP) water-based drilling fluids are particularly advantageous compared to conventional water-based systems because they provide faster penetration rates, enhanced hole cleaning, greater shale inhibition, and improved wellbore stability. Most high performance water-based drilling fluids only tolerate operating temperatures up to 300°F because they depend on biopolymer-based viscosifiers. Deeper exploration in extreme high temperature reservoirs (>300°F) requires new drilling fluid technologies. A new high performance, high temperature water-based drilling fluid that is both thermally and rheologically stable at 400°F was developed to meet these demands.
A novel synthetic polymer was developed for use in a new HP water-based mud (WBM). The new fluid system was hot rolled at 150°F for 16 hours to condition the fluid before testing. The conditioned fluids were subjected to dynamic or static aging conditions, with temperatures ranging from 300 to 400°F. The viscosity and pH values were determined with a direct indicating viscometer and pH meter, respectively. The Anton Paar viscosity was measured using the CC. 27 cup and bob geometry. The fluid loss properties of the fluids were determined by high pressure/high temperature (HP/HT) filtration at 350°F according to the API recommended practice.
This paper provides an overview of the current high performance drilling fluid chemistry, as well as the detailed study of the high temperature, high performance water-based drilling fluid formulated with 10.0 to 17.0 lbm/gal densities that exhibits a stable rheological profile. For example, a 14.0 lbm/gal formulation aged at 150°F for 16 hours provided a plastic viscosity (PV) of 29 cp and a yield point (YP) of 22 lbf/100 ft2. After static aging for 48 hours at 400°F, the fluid provided a PV of 27 cp and YP of 24 lbf/100 ft2. The new fluid maintains viscosity, adequate suspension, low shear strengths, shale stability, and filtration control up to 400°F, and the fluid is resistant to contamination.
This clay-free system uses a novel synthetic polymer viscosifier and filtration control agent, enabling the removal of thermally labile biopolymers without the addition of clay-based viscosifiers; it is environmentally acceptable for both land and offshore drilling and can be formulated with either chloride containing or non-chloride containing salts. The new fluid formulation provides reliable thermal stability that can function in extreme high temperature wells, while preserving the benefits of HP water-based drilling fluids.
Growing demands to operate in harsh high temperature environments require robust drilling fluid performance to drill in such conditions. Water-based drilling fluids offer significant environmental advantages compared to invert-emulsion fluids (IEFs). High performance (HP) water-based drilling fluids are particularly advantageous compared to conventional water-based systems because they offer faster rates of penetration (ROPs), enhanced hole cleaning and shale inhibition, and improved wellbore stability. Most HP water-based drilling fluids can only tolerate operating temperatures up to 300°F attributed to a strong dependence on biopolymer-based viscosifiers. Thus, deeper exploration in extreme high temperature reservoirs (>300°F) requires new drilling fluid technologies. A new high performance, high temperature water-based drilling fluid that is thermally stable at 400°F has been developed to meet these demands.
The new fluid system was fully formulated using a multimixer, and the resulting fluids were hot rolled at 150°F for 16 hours to condition the fluid before testing. The conditioned fluids were then further subjected to dynamic or static aging conditions with temperatures ranging from 300 to 400°F. The aged fluid viscosity was examined using a direct-indicating viscometer, and the pH was determined with a pH meter. The fluid loss properties of the fluids were determined by both API filtration and high-pressure/high-temperature (HP/HT) filtration at 350°F in according with the API recommended practice.
This paper presents the detailed study of the high performance, high temperature water-based drilling fluid formulated with 10.0-17.0 lbm/gal densities. The fluid exhibits a stable rheological profile. For example, a 14.0 lbm/gal formulation aged at 150°F for 16 hours yielded a plastic viscosity of 29 cp and a yield point of 22 lbm/100 ft2. After static aging for 48 hours at 400°F, the fluid gave a plastic viscosity of 27 cp and yield point of 24 lbm/100 ft2. The new fluid maintains stable viscosity, adequate suspension, low shear strength, shale stability, and filtration control up to 400°F.
This thermally stable, clay-free system exhibits good shale inhibition and is environmentally acceptable for both land and offshore drilling. This HP water-based drilling fluid is formulated with a novel synthetic polymer viscosifier and filtration control agent, allowing removal of thermally labile biopolymers without the addition of clay-based viscosifiers. The new formulation provides reliable thermal stability that can readily function in extreme high temperature wells, while preserving the benefits of HP water-based drilling fluids.