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Book Chapter

Fluid Sensitivity Analyses in Tight Sandstones—When Rocks Behave Badly

By
Margaret Lessenger
Margaret Lessenger
Newfield Exploration, The Woodlands, Texas U.S.A. (e-mails: rimrockpetro@comcast.net, bobby.sullivan@eogresources.com, kwoolf@newfield.com, Darrin.Burton@anadarko.com)
Present address: Rimrock Petrophysics and Analytics, Golden, Colorado U.S.A.
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Bobby Sullivan
Bobby Sullivan
Newfield Exploration, The Woodlands, Texas U.S.A. (e-mails: rimrockpetro@comcast.net, bobby.sullivan@eogresources.com, kwoolf@newfield.com, Darrin.Burton@anadarko.com)
Present address: EOG Resources, Denver, Colorado U.S.A.
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Kurtus Woolf
Kurtus Woolf
Newfield Exploration, The Woodlands, Texas U.S.A. (e-mails: rimrockpetro@comcast.net, bobby.sullivan@eogresources.com, kwoolf@newfield.com, Darrin.Burton@anadarko.com)
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Darrin Burton
Darrin Burton
Newfield Exploration, The Woodlands, Texas U.S.A. (e-mails: rimrockpetro@comcast.net, bobby.sullivan@eogresources.com, kwoolf@newfield.com, Darrin.Burton@anadarko.com)
Present address: Rimrock Petrophysics and Analytics, Golden, Colorado U.S.A.
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Published:
January 01, 2016

Abstract

Reservoir rocks can be highly sensitive to fluids introduced through hydraulic fracturing, water disposal, or waterflood injection. The sensitivity of reservoir rocks to fluids can lead to reduced permeability and permanent formation damage resulting in reduced productivity or injectivity. It is generally assumed that clays are the primary culprit in formation damage caused by swelling, increased clay-bound water, water shock, or denigration. In this chapter, we present results from a two-year effort to understand the fluid sensitivity of tight sandstone reservoirs in the Greater Monument Butte Unit (GMBU) in the Uinta Basin, Utah, U.S.A. Newfield Exploration (NFX) drills and completes approximately 200 wells per year in the field, which is currently under waterflood with injection rates of ~90,000 barrels per day. When we initiated this study, NFX completed wells with fresh water. Pore-scale imaging was the key to designing new core flood experiments that led to optimized completions fluids for the field. Initially, we assumed that potential fluid sensitivity was caused by mixed-layer illite-smectite (I/S). XRD (x-ray diffraction) and SEM (scanning electron microscope) images indicated that some GMBU reservoir rocks contained pore-bridging I/S. We designed initial core flood experiments combined with core nuclear magnetic resonance to identify and quantify clay reactions. The results of these initial tests indicated that the reservoirs were sensitive to lower-salinity completions fluids and a reduction in permeability was observed. We utilized a new approach involving pore-scale imaging to identify the mechanism causing permeability reduction. Comparison of SEM images of minerals in pores before and after fluid placement identified calcite dissolution and fines migration as the cause of permeability reduction. Micro-CT (micro-computed tomography) scans combined with registered EDX (energy-dispersive x-ray spectroscopy) mineralogy provided the context for the severity of the problem, especially in the better reservoir rock. The results of this work challenge a number of commonly held assumptions of rock–fluid sensitivity and have implications on how to design effective fluid sensitivity studies using core. This work involved collaboration between petrophysicists, geologists, engineers, and facilities personnel to design and implement a completions fluid that does not damage multiple reservoirs while remaining cost effective and efficient. This work demonstrates the value of focused science within the context of cost and field operational constraints.

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Contents

AAPG Memoir

Imaging Unconventional Reservoir Pore Systems

Terri Olson
Terri Olson
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American Association of Petroleum Geologists
Volume
112
ISBN electronic:
9781629812755
Publication date:
January 01, 2016

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