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Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
Phillips, A. J. (Montana State University) | Gerlach, R. (Montana State University) | Cunningham, A. B. (Montana State University) | Spangler, L. (Montana State University) | Hiebert, R. (Montana Emergent Technologies) | Kirksey, J. (Schlumberger Carbon Services) | Esposito, R. (Southern Company)
Novel strategies aimed at increasing underground storage security by sealing unwanted leakage pathways near wellbores are currently under development. One such strategy is to engineer the process known as microbially-induced calcite precipitation (MICP) to achieve mineral-based sealing of fractures and reduction of permeability. Laboratory-based MICP research reported herein has demonstrated the ability to effectively reduce permeability in multiple 2.54 cm (1 inch) diameter Berea sandstone cores, seal fractures in shale cores, and seal a hydraulically fractured, 74 cm (29 inch) diameter sandstone core. This research involves integration of experimental testing and simulation modeling. In all experiments reported, Sporosarcina pasteurii biofilms were established and an injection strategy developed to optimize CaCO3 precipitation induced via enzymatic urea hydrolysis. Permeability reductions of 3-5 orders of magnitude were demonstrated. A field demonstration project successfully sealed a fractured sandstone formation located 341 m (1118 feet) below ground surface with MICP using conventional field delivery technology. MICP is a developing novel technology with the potential to seal fractures to reduce the risk of leakage from the subsurface.
To manage the environmental risk of storing carbon dioxide in geologic formations, unconventional oil & gas resource development and nuclear waste disposal, novel methods are needed to prevent leakage of subsurface fluids to functional overlying drinking water aquifers or the ground surface. One method currently being explored on multiple scales (from laboratory to field) is the use of microbially-induced calcite precipitation (MICP) [1-8]. This method utilizes microbes that have the capability to alter the chemical environments in host rock pore spaces. One example is the use of ureolytic microorganisms that produce enzymes to create saturation conditions favorable for promoting MICP [9- 11]. MICP has been proposed for a number of subsurface engineering applications including preventing gas leakage by sealing fractures to secure geologic storage of CO2 or other fluids, improving wellbore integrity, and stabilizing fractured and unstable porous media [3, 6, 12-16].
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, "Application of Nanotechnology in Drilling Fluids," by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
The potential to apply water-based drilling fluids confidently in unconventional shale formations has been studied using engineered nanoparticles to minimize shale permeability by physically plugging the nanometer-sized pores. Nanoparticle technology and testing protocols were developed using the Marcellus and the Mancos as shale candidates. Nanoparticles in this study are specifically designed to plug the nanometer-sized shale pores physically, thereby reducing pressure transmission in the shale.
Silica nanoparticles are commercially available and can be engineered to meet all specifications needed for the purpose. The particle size can vary between 5 and 100 nm. The right sizes of nanoparticles can be selected, and, in combination with a correct fluid-loss package, the particles can minimize the fluid/rock interaction. Surface treatment on the nanosilica particle has been discovered to have a major influence on the final performance.
An investigation into using nanoparticles as a drilling-fluid additive to enhance wellbore stability has been successful. The nanomaterial works by virtually shutting off water movement between the formation and wellbore. In shale formations with nanodarcy permeability, such as the Marcellus, the usual drilling-fluid method of relying on a filter cake to reduce fluid loss (or leakoff) cannot be used because a filter cake may not form because of the extremely low permeability of the shale. The solution for this problem is to engineer a nanoparticle that will be added to the drilling fluid to plug the pores of the shale and shut off water loss.
The hurdle to maintaining wellbore stability in shale formations is to control the water interaction with the rock. The water enters the shale through pores, which vary in size from approximately 3 to 100 nm, inducing fractures and, thereby, reducing the stability of the wellbore. By effectively plugging the exposed pores of the rock and not allowing water to enter, wellbore stability is retained. One conventional bridging theory is referred to as the one-third rule of filtration (Abrahm’s theory), where the material used to plug a pore is required to be approximately one-third to one-seventh of the size of median pore opening. There are other theories with varying size requirements for the plugging material; however, none is perfect. An ideal plugging material also will accommodate the variability in pores within the formation.
Shale-swelling pressure and behavior is muds with high membrane efficiency. For contacts and compresses pore fluid at the way to reduce permeability is to form a permeability the oil industry, distinguishing shale features wellbore wall. The pressure away from the barrier at the shale surface or within include clay content, low permeability wall varies with time until a steady-state microfractures. In OBM's, water has to diffuse caused by poor pore connectivity through pressure distribution between near and faraway through a continuous oil phase to reach narrow pore throats, and the large difference pore pressure is established. Cationic polymers, which are in coefficient of thermal expansion between drilling fluid cannot penetrate the shale, strongly adsorbing, also reduce permeability.