(644d) Chemical Controls on Secondary Mineral Precipitation of Fe and Ba in Hydraulic Fracturing Systems

Secondary mineral precipitation in hydraulic fracturing systems has the potential of decreasing porosity and permeability of oil/gas shales potentially resulting in the reduction of production from wells. Two major types of secondary minerals seen in these systems are Fe(III)-bearing precipitates and Ba-sulfate. The primary source of Fe in oil/gas shales is in the form of pyrite, with minor amounts found as Fe in carbonates or clay minerals. Barium however, has several potential sources such as barite and clays in the host rock as well as barite added to drilling muds in order to increase density. To investigate Fe behavior in hydraulic fracturing systems, we reacted four shales from different plays containing differing mineralogies (Marcellus from NY, Barnett, Eagle Ford, and Green River) with synthetic fracturing fluid formulated from a recipe commonly used in the Marcellus region. This low pH fluid (pH = 2) was readily neutralized to circum-neutral pH in reactors containing shale with high quantities of carbonates (Eagle Ford and Green River), but the solution pH remained low (pH 3.5-4) when reacted with low-carbonate, high-clay shales (Marcellus and Barnett). Release of Fe(II) from the pyrite grains in these systems was controlled by the low pH of the fracture fluid. For carbonate-rich shales, released Fe(II) oxidized so rapidly that no Fe was detectable in solution. Imaging of the solids by synchrotron-based x-ray fluorescence (XRF) mapping coupled with x-ray absorption spectroscopy (XAS) show that the Fe(II) released from the pyrite precipitated as large particles (10's of μm's) within 10 μm of pyrite grains and consisted predominately of hematite with minor amounts of magnetite, indicating partial oxidation of the released Fe(II). In contrast, for carbonate-poor shales, released Fe(II) remained in solution for weeks with a significant portion of the Fe(II) (82% for Barnett and 31% for Marcellus) oxidizing and precipitating. The XRF mapping of the Barnett and Marcellus samples showed identical Fe behavior with Fe(III)-(oxy)hydroxides in the forms of ferrihydrite and goethite formed as diffuse precipitates covering the surface of the shale as well as precipitating in the matrix. Because Fe(II) in the carbonate-poor systems can stay in solution for an extended time period, the precipitation of Fe(III)-(oxy)hydroxides can occur at various locations far away from the Fe sources in the shale as opposed to carbonate-rich systems where large particles can occlude micro- and nano-pores deep in the fracture system. Though dissolved O₂ is the primary driver for Fe(II) oxidation in all of these shale systems, the pH buffering capacity of the rock is the most important factor in controlling the style of precipitation (diffuse coatings versus large crystals) as well as the type of Fe(III)-bearing precipitates formed.

Organics, both native to the shale and injected into the subsurface, play a large role in secondary mineral production. In the case of Fe in low pH (2-4) fracturing fluids, Fe(II) oxidation should be retarded. Iron(II) oxidation experiments focusing solely on the interaction of organic material with the fracture fluid showed that at pH 2, in contrast with the bulk shale experiments, Fe(II) did not oxidize. Bitumen, which is the most labile organic material in oil/gas shales, is readily extracted from the shales by organics common to fracture fluid. When bitumen (extracted from either Marcellus or Green River shale) was added to the Fe(II)/fracture fluid system, a significant amount of Fe(II) oxidized over a 48 hour period (upwards of 40%). Thus, bitumen released from the shale during hydraulic fracturing has the ability to override the Fe oxidation inhibition effect of acidic solutions. Barium on the other hand has no redox-dependent chemical reactions in these systems. Simplified experiments were conducted to address barite precipitation in the presence of various organic chemicals found in fracture fluids, formation waters, and produced waters. These experiments also investigated the effect of ionic strength (0.8mM and 1.8M) as well as pH (2 and 7). In all cases, low pH completely inhibited the precipitation of barite. Varying the ionic strength in control reactors (no added organics) showed that high ionic strength retarded barite precipitation compared to the low ionic strength reactor, but did not inhibit precipitation of barium-bearing phases. At low ionic strength, we found no difference in barite precipitation rates in the presence of acetate, methanol, or ethylene glycol; however, kerosene and polyethylene glycol had a mild retardation effect. These results are surprising since chemicals such as ethylene glycol are injected as an anti-scaling agent. Though other organics, such as citrate and guar gum, did not completely stop the precipitation of barite, they did severely retard precipitation. Interestingly, when experiments with ethylene glycol were conducted at high ionic strength, barite precipitation was completely inhibited, suggesting a significant change in complexation of either Ba or SO₄ to the ethylene glycol molecule, which could inhibit nucleation or poison the crystal surface. These results show that organics used in hydraulic fracturing operations have a significant and at times unexpected impact on the production of secondary mineral phases that can reduce porosity and permeability in the subsurface and potentially negatively impact production and the life of a well.