Drill-in fluids, also known as reservoir drilling fluids, are specifically designed to help minimize formation damage and facilitate wellbore cleanup. Typical water-based drill-in fluids use brines to achieve a desired fluid density and rely on acid-soluble solids, such as calcium carbonate, for bridging of pore spaces. Biopolymers, such as xanthan gum and crosslinked starch, are generally used as viscosifiers and fluid-loss additives for the drill-in fluids. Unfortunately, these biopolymers begin to degrade at temperatures greater than 275°F. As a result, conventional water-based drill-in fluids are generally limited to wells with temperatures below 300°F. Clay-free, brine-based drill-in fluids for temperatures greater than 300°F still pose challenges in high-pressure/high-temperature (HP/HT) conditions. Novel high density brine-based drill-in fluids have been developed using a specifically designed dual-functional polymer as a thermally stable viscosifier and fluid-loss additive. Divalent brines, such as CaBr2 (14.2 lbm/gal) and CaCl2 (11.6 lbm/gal), were used as the base fluids. The drill-in fluids show similar thixotropic behavior to those biopolymer-based, yet exhibit excellent thermal stability up to 450°F, which is at least 150°F higher than typical drill-in fluids. After static aging at 450°F for 16 hours, the fluids exhibited only slight color change, and no stratification or solid settling was observed. Rheological properties of the aged samples increased slightly compared to samples before aging. The samples still provided excellent fluid-loss control, even after aging, with a measured HP/HT fluid loss less than 10 mL after 30 minutes at 350°F. Core flow testing showed that the drill-in fluid is nondamaging after acid breaker treatment, with a return permeability of 100%.
Novel polymers have been designed and developed as thermally stable dual function viscosifiers and fluid-loss additives for high density brine-based drill-in fluids. These polymers allow for the formulation of clay-and biopolymer-free drill-in fluids that are stable at temperatures up to 450°F. This is a significant improvement compared to conventional drill-in fluids, which use biopolymers and have temperature limits of 300°F. Clay-free drill-in fluid samples were prepared in 14.2-lbm/gal CaBr 2 brine and conditioned by hot rolling at 150°F for 16 hours, followed by static aging at 400°F for 72 hours. The samples prepared with the novel polymers show no color change or stratification after static aging. There was minimal change upon comparison of the rheological properties of the nonaged and aged samples. The samples provided excellent fluid-loss control even after aging, with a measured high-pressure/high-temperature (HP/HT) fluid loss less than 10 mL after 30 minutes at 350°F. This is in stark contrast to biopolymercontaining samples in which solids settling and dark coloration were observed after static aging at 300°F for only 16 hours. This paper presents full testing results of the new HP/HT drill-in fluids, including formulation, fluid properties, and formation damage assessment.
When used for running sand control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid (SRF) has been limited by fluid density. The design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit is discussed. The following parameters were examined as part of the preliminary qualification: rheology performance, long-term stability, fluid loss (filter-cake repair capability), reservoir fluid and drill-in fluid (RDIF) compatibility tests, emulsion breaking test, production screen test (PST) on 275 µm screen, crystallization temperature [true crystallization temperature (TCT) and pressurized crystallization temperature (PCT)], and corrosion rate. The fluid was then tested for formation and completion damage performance, where the high-density, brine-based LSOBCF exhibited minimally damaging behavior in the core-flow tests. As a result of the positive observations made during these wide-ranging laboratory tests, this new high density-based brine was deemed as a good candidate in an LSOBCF for high-density SRF applications. Viable LSOBCF with densities up to 1.50 SG have been designed. This paper details the design and field application of a 1.45 SG LSOBCF. Calcium bromide (CaBr2) brine is commonly used during the discontinuous phase for LSOBCF applications that require fluid densities up to 1.38 SG. For higher density requirements, LSOBCF use a cesium formate brine as a discontinuous phase. Using the new developed brine in the discontinuous phase provides viable LSOBCF up to 1.50 SG. The base brine has a good environmental rating, is pH neutral, and provides improved safety during low-temperature/high-pressure conditions. As a standalone fluid, the new brine can achieve densities up to 1.80 SG, with acceptable TCT and PCT values for North Sea applications without using zinc or formate-based brines. After laboratory qualification, the final fluid formulation was deployed on a dual lateral oil producer well with 9.5 in. horizontal reservoir section lengths of 2315 and 1696 m. After drilling the sections using an engineered low equivalent circulating density (ECD) oil-based RDIF (OB RDIF), each section was sequentially displaced to 1.45 SG LSOBCF. The lower completion, consisting of 5.5 in. screens equipped with autonomous inflow control devices (AICD) and swellable packers, was successfully run to bottom without significant issues. The field application demonstrated evident operational efficiency gains. The positive pre-deployment formation response test (FRT) results have been verified by well productivity data. The process to qualify the brine for first-use application in LSOBCF is described, and laboratory testing (including FRT), mixing and logistical considerations, field execution, and well productivity are discussed.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.