Formation Permeability Damage Induced by Completion Brines

Abstract

Summary In a laboratory study to determine permeability changes induced by floodinglarge Berea and Casper sandstone cores with NaCl and KCl brine, theconcentration of each brine was incrementally increased from 0 to 22 wt% andthen decreased from 22 to 0 wt%. In both sandstones, the permeability to KClbrines increased noticeably with increases in KCl concentration up to 1 0 wt%. Permeability remained at the higher levels throughout the remainder of eachflood until a critically low salinity level was reached, where dispersion ofthe interstitial fines took place. X-ray diffraction (XRD) analysis of theproduced formation fines and scanning electron micrographs of the sandstonepore surfaces indicated that the improved permeability was primarily a resultof alteration of illite in the clay minerals in the sandstones. TABLE 1-FORMATION MINERAL COMPOSITION (wt%)* Mineral Berea Casper Quartz 84 51 Clay minerals 10 17 Kaolinite 76 63 Illite20 34 Chlorite 4 3 Mixed layer Trace Trace 100 100 Dolomite 1 28 Calcite 1 1 Siderite 1 Trace K-Feldspars 3 3 100 100 Introduction To control formation pressure during workover operations, kill-weight fluidsare prepared by suspending insolubles in the fluid or by dissolving solublesalts in water to make a clear brine. Using suspended particles may lead toformation plugging, requiring additional acidizing of the well. Often the bestalternative to control formation pressures during workovers is a kill-weightfluid composed of a clear NaCl or KCl brine. Brine densities up to 9.8 lbm/gal[1174 kg/m] can be produced by NaCl or KCl brines. The composition ofcompletion and injection fluids rarely matches that of the formation water. Because of the difficulty and cost of duplicating the exact formation-watercomposition, a composition contrast often exists between the two fluids. Several authors have reported the effects of various completion brines onsandstone permeability. Their studies were limited to either singular brineconcentrations, a series of low brine concentrations (less than 6 wt%), orhigh-density calcium and zinc bromide brines. Coreflooding experimentsinvestigating the permeability change as NaCl and KCl brine concentrations varybetween 0 wt% and saturation have not been published. Early studies concernedprimarily the relationships between swelling and salinity. As the pore-fluidsalinity decreases, osmotic forces allow water layers to be added to theinterlayer region. The salinity level also affects the bound or crystallinewater on the clay surfaces. Baptist and Sweeney were the first to conclude thatthe absence of 2:1 montmorillonites does not guarantee that a sandstone isinsensitive to water. They reported permeability reductions up to 60% in"non-swelling" cores flooded with fresh water after saturation with 2%NaCl brine. Mungan demonstrated that dispersion of any clay is possible whenmonovalent cations are on the exchange sites. This classifies most sandstonescontaining any type of clay as water-sensitive. Khilar showed that forclay-bearing sandstones, a critical salt saturation (CSS) exists below whichclays start to disperse. Sharma et al. supported the CSS theory bydemonstrating that particle-release and particle-deposition regimes-functionsof the electrostatic potential between the clay and pore-wall surfaces and thefluid velocity exist. The electrostatic potential is controlled partly by theionic strength of the pore fluids. As the pore-fluid salinity declines, ionicstrength decreases to where the release regime dominates the depositionalregime and dispersion occurs. This point closely corresponds to the CSSdetermined by Khilar. Clay Mineral Influences on Permeability Formation permeability changes are often the result of the amount. location, and type of clay minerals in the formation. The amount of clay minerals in aformation can be a misleading indicator of potential permeability changes. Therelative abundance of specific clay types in the matrix and pore spaces must beknown in addition to the total amount of clays present. Moore demonstrated thata sand with less than 4 wt% clay minerals could have an appreciable amount ofits pore spaces (greater than 20%) filled with clay. Almon, showed that somepores may be entirely lined with authigenic clays so that the pore fluids donot contact the large quartz, feldspar, or carbonate grains. Numerous acid jobsand waterfloods have had disastrous results because the engineer or geologistfailed to recognize the importance of the location of certain clay minerals inthe formation. Grim showed the replacement order of one monovalent cation foranother to be Li+ less than Na+ less than K+ less than H+. For example, in porefluids with equal equivalent fractions of K+ and Na+, more K+ will occupy theexchange sites than Na+. Not all the Na+ will be removed. When the claylattices align in booklets, the exchange sites created in the opposing layersare about 2.8 A [0.28 nm] in diameter and 2.4 A [0.24 nm] deep. JPT P. 486^

Permeability Variations in Illite‐Bearing Sandstone: Effects of Temperature and NaCl Fluid Salinity

“…The CSC depends strongly on the cation type within the aqueous solution. K + ‐saturated clay‐bearing sandstones show a significantly lower CSC as compared to that of Na + ‐saturated sandstones (e.g., Azari & Leimkuhler, 1990). Bivalent cations like Ca 2+ and Mg 2+ stabilize permeability down to very low salt concentrations (Gray, 1966; Khilar & Fogler, 1984; Mohan et al, 1993; Mungan, 1968).…”

“…Chemically induced permeability changes in clay‐bearing sandstones related to low‐salinity fluids are well‐known (e.g., Azari & Leimkuhler, 1990; Khilar & Fogler, 1984; Kia et al, 1987; Mohan et al, 1993; Mohan & Fogler, 1997; Mungan, 1968; Omar, 1990; Rahman et al, 1995; Sharma et al, 1985; Yu et al, 2018). Generally, permeability is not reduced unless the salinity is lower than a critical salt concentration (CSC).…”

Use of Acid Precursor as Alternative to Acid Treatment to Drill-In Fluid Filter Cake Removal: FN Case Study

“…Formation damage is also caused by payzone invasion from fines plugging, clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoirrock wettability, and formation of emulsions (Azari and Leimkuhler 1990).…”

Seawater Injection into Clastic Formations: Formation Damage Investigation Using Simulation and Coreflood Studies

“…Several studies indicated that water shock occurs only when the salt concentration in fresh water decreases below a critical salt concentration (CSC), which depends on the characteristics of the rock and the salt involved. In other words, if the formation is saturated initially with brine having salinity above CSC, and the new injected water has salinity value below CSC, clays fines migration occurs (Azari et al, 1990); however, if the initial brine has salinity below CSC, then changing salt concentration of permeating fluid will not trigger fines migration.…”