Protecting the Reservoir With Surfactant Micellar Drill-in Fluids in a Carbonate-Contained Formation
- Tianping Huang (Baker Hughes Inc) | James B. Crews (Baker Oil Tools) | David Clark (Baker Hughes)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 1.7 Pressure Management, 2 Well Completion, 1.6.9 Coring, Fishing, 1.11 Drilling Fluids and Materials, 1.6 Drilling Operations, 4.2.3 Materials and Corrosion, 2.4.5 Gravel pack design & evaluation, 1.8 Formation Damage, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.5 Drill Bits, 5.4.10 Microbial Methods, 3.2.4 Acidising, 2.7.1 Completion Fluids, 1.10 Drilling Equipment, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.2.3 Fluid Loss Control, 5.8.7 Carbonate Reservoir
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Conventional water-based drill-in fluids contain high molecular weight polymers and different size-distribution solid particles to reduce fluid loss and carry drilling debris back to surface during the drilling process. The polymers and solid particles in the drill-in fluids usually generate near wellbore formation damage.
This paper introduces a new polymer-free and solids-free surfactant micellar-based drill-in fluid system to drill a carbonate-contained reservoir. This new fluid system contains relatively low reactivity acids mixed with surfactants and internal breakers. The drill-in fluid is designed to have low viscosities in the drillpipe. After the fluid flows out of the drill bit, the acids will react with carbonates in the formation thereby increasing the pH of the drill-in fluids. The higher fluid pH combined with the presence of dissolved divalent ions will cause the surfactants to form elongated micelle structures that will significantly increase fluid viscosity at the bottom of the hole and in the downhole annulus between the drillpipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry non-dissolved drilling debris to the surface. After drilling through the targeted forma-tion, the internal breakers in the viscosified drill-in fluid will break down the fluid viscosity to permit their removal, and the well will produce with very little or no near-wellbore damage.
Different solid particles, such as bentonite, barite, and carbonates, and high molecular weight polymers, such as Xanthan Gum and hydroxyethylcellulose (HEC), have been used for fluid loss control, wellbore stability, and drilling debris carrying in drilling fluids for decades. The solid particles combining with polymers build filter cakes increase fluid efficiency in the drilling process, but the filter cake removal after drilling and formation damage removal in a near-wellbore region are costly and difficult tasks. The conventional methods for filter-cake removal include using solids-free brines through soaking and circulating at high flow rates, which removes only the external filter cake. Different chemicals such as acids, oxidizers, enzymes, chelating agents, or combinations of these chemicals are used to remove formation damage induced by solid particles and polymers in drilling fluids1 ~9.
|File Size||178 KB||Number of Pages||10|