This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199260, “Filter Cake Breaker Evaluation for Water Injectors: Scale Up From Laboratory to Field Deployment,” by Pavithiran Chandran, SPE, Arunesh Kumar, SPE, and Iain Cameron, BP, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19–21 February. The paper has not been peer reviewed.
The complete paper describes the test procedures adopted for evaluating various filter cake breaker formulations and the work conducted to develop the systems to be ready for use in two North Sea fields (Field A and Field B). Water injection wells were planned to provide pressure support to oil producers in the two fields, and water-based drilling fluids were selected to drill the reservoir sections for both. The average permeability is 1000 md for Field A and 50–100 md for Field B. A laboratory study was commissioned to evaluate and optimize filter cake breaker systems for use in water injectors to efficiently remove external and internal filter cake to attain matrix injection without the need for backflow to clean the sandface.
Introduction
Field A was commissioned to drill 18 producers and seven water injectors from a semisubmersible drilling rig. Most of the injector wells are high-inclination, long openhole sections. Fluid density of 1.24–1.48 specific gravity (SG) (10.3–12.3 ppg) was required for wellbore stability.
The Field B development plan included drilling 26 producers and 10 water injectors with an average injection rate target of 40,000 B/D of treated, produced water per well. Most wells are high-inclination to reduce the risk of direct fracture communication between wells. Injectivity indexes of 10–30 BWPD/psi were anticipated. The ability to include backflow/gas-lift capacity in the injector wells to assist cleanup was not included in the operational plan; therefore, direct injection was the preferred design standard.
The injection interval in Field A features high-permeability (approximately 1000-md) zones; the Field B injection interval is considered a low-to-mid-permeability (approximately 100-md) zone. Injection of warm produced water into naturally occurring fractures in Field B injector wells yields poorer performance than when cooler fluids such as seawater are used. Higher downhole temperature and longer fluid residence time in the wellbore on Field B could increase the temperature of the injection fluid and thermally contract the natural fractures. Poor initial injectivity with produced water was identified as a potential risk on these wells, because this could lead to subsequent complications with seawater injection into these zones.
Reservoir Drilling Fluid (RDF) Design and Selection
Water-based RDF was chosen to drill the reservoir section of the water injectors on the basis of its ability to reduce operational complexity in terms of fluids preparation, displacement design, and screen running issues. RDF fluids typically contain a brine phase to achieve required density, xanthan polymer for viscosity, starch for filtration control, sized calcium carbonates for a bridging package, and specialized chemicals to address specific well challenges such as shale inhibitors and lubricants. Water-based RDF is more amenable than invert emulsion fluids to stimulation treatments for cleanup of filter cake and remediation of near-wellbore damage. However, water-based fluids can pose other operational issues such as increased torque and drag and potential for differential sticking, especially while drilling long horizontal wells, as was planned for both fields. A lubricant was included in the fluid used on Field B to manage torque-and-drag issues.
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