Elsevier

Fuel

Volume 303, 1 November 2021, 120815
Fuel

Full Length Article
Geochemical reactions and alteration of pore architecture in saturated shale after injection of stimulation fluid

https://doi.org/10.1016/j.fuel.2021.120815Get rights and content

Highlights

  • Aqueous geochemical trends indicate silicate dissolution and clay precipitation.

  • Mineralogic evidence limited to calcite dissolution and barite precipitation.

  • Shale controlled redox despite injection of oxidizing stimulation fluid.

  • Stimulation fluid + formation water mix evolved from acidic pH (2.3) to ~6 in 24 hrs.

  • Formation water ± organic matter shields micro- & mesopores from stimulation fluid.

Abstract

Pore architecture regulates fluid flow between unconventional shale reservoir and hydraulically-induced fractures. Imbibition of stimulation fluid may change this architecture and alter hydrocarbon flow. Hydrothermal experiments were conducted at reservoir conditions (125 °C, 45 MPa) to test two hypotheses: 1) Shale, not stimulation fluid, dominates the geochemistry of an unconventional reservoir containing formation water; and 2) Mineral dissolution and precipitation induced by stimulation fluid is transient and manifests across micro-, meso-, and macro-scales of pore architecture. Experiments replicated a shut-in well in the Cretaceous Baxter Shale, Green River Basin, Wyoming USA. Stimulation fluid was injected into one experiment after formation water (I = 0.35 mol/kg, pH = 6.4) and core reacted for 48 days. This novel approach equilibrated rock and formation water and saturated pores with formation water before introducing stimulation fluid. The second experiment served as a control. Trends of aqueous calcium, silica and aluminum in the injection experiment suggest transient dissolution of calcite and feldspar and/or quartz as well as clay and barite precipitation; mineralogic evidence was limited to calcite dissolution and barite precipitation. The rock maintained reducing conditions (Eh = +0.08 to −0.16 V) despite injection of oxidizing stimulation fluid (Eh = 1.1 V). pH of the stimulation fluid-formation water mixture evolved from 2.3 to pre-injection values (~6) within 24 h. Results indicate that mineral dissolution and precipitation manifest in macropores with barely detectable alteration to micro- and mesopores. Formation water or organic matter in pores may have inhibited access of stimulation fluid to micro- and mesopores

Introduction

Interest in mudstone and shale has exploded with the advent of horizontal drilling and hydraulic fracturing of unconventional hydrocarbon reservoirs. Induced fractures provide pathways for hydrocarbons, and the pore architecture regulates hydrocarbon flow between rock and fractures. We define pore architecture as a unique, identifiable pore space composite in the rock that encompasses micro-, meso-, and macropores of different geometries, sizes and shapes, along with topology (connectivity) across the hierarchy of pores [1]. Pore architecture encompasses common petrophysical properties of porosity and permeability and influences processes such as diffusion and geochemical reactivity. In contrast to porosity in most sandstones, which is dominated by macroscale pores, mudstone and shale porosity is dominated by micro- and mesoscale pores [2].

Although the term ‘shale’ is widely used, the term “mudstone’’ more properly describes fine-grained sedimentary rocks [3]. Shale is a field term for fine-grained, indurated, fissile sedimentary rocks whereas a mudstone is a rock in which greater than 50% of its grains are clay and silt size (<62.5 µm). Confusion arises because the two terms are used interchangeably and because the terms ‘shale gas’ and ‘shale oil’ are ingrained in the literature. In this paper we use the term ‘mudstone’ unless context merits otherwise.

The shale revolution has motivated a variety of field, laboratory, and computational studies to evaluate mechanical, petrophysical, geochemical, mineralogic, and other properties of mudstone and shale. In particular, laboratory experiments have been performed to evaluate how stimulation fluid may interact with and potentially alter the geochemistry and mineralogy of mudstones. Experiments have reacted mudstone with de-ionized water, NaCl solutions, or stimulation fluids containing chemical additives used in hydraulic fracturing (e.g., [4], [5], [6], [7], [8]). Most of these experiments focused on mineral dissolution and precipitation using batch reactors [9], [10], [11], [12], [13], [14], [15], [16], [17], [18], [19], but a few used coreflood apparatus [20], [21]. Stimulation fluid in most of these experiments was both acidic and oxidizing. Carbonate began to dissolve in most experiments [4], [6], [8], [9], [10], [11], [12], [15], [17], [20], [21], [22]; silicate minerals also began to dissolve and new aluminosilicate phases precipitated in a few [9], [10], [14], [15], [22]; and pyrite began to dissolve, iron was oxidized, and Fe(III)-(oxy)hydroxide precipitated in several (e.g., [8], [9], [11], [14], [16]).

One laboratory study integrates petrophysical analysis with geochemical and mineralogic evaluation of reactions between NaCl solution proxies for stimulation fluid and Marcellus and Eagle Ford Shales [14]. Carbonates and pyrite began to dissolve and Fe(III)-(oxy)hydroxide and clay precipitated in these experiments. Porosity in the Marcellus Shale increased from 4% to 5%–7% and permeability (initially 1.3 × 10−5 md) approximately doubled. Porosity in the Eagle Ford Shale also increased, from 3% to 4%–5%, but permeability (6.7 × 10−6 md) did not change.

In all of these batch reactor experiments, stimulation fluid and dry rock were combined at the outset, before heating and pressurizing to reservoir conditions (e.g., [4], [5], [6], [7], [8]). This approach emulates interaction of stimulation fluid and dry reservoir rock in a shut-in well. Pores in the rock contain no formation water and stimulation fluid readily imbibes. However, unconventional wells are completed in reservoirs containing formation water. After the well is opened for production, flowback and produced water from these wells is increasingly composed of formation water, not stimulation fluid [23], [24]. The chemistry of these waters exhibits little evidence for pyrite dissolution, iron oxidation, or Fe(III)-(oxy)hydroxide precipitation. Deep saline formations are rock-dominated, closed systems [25] in which the rock controls the geochemistry of the formation water, including the redox state. Pores in the rock are saturated with formation water, thus reactive components in stimulation fluid must diffuse into the rock. To emulate this scenario, stimulation fluid can be injected into an experiment containing formation water and rock saturated with formation water at reservoir conditions [26], [27]. These two experimental approaches represent a continuum between dry reservoirs in which stimulation fluid dominates the geochemistry and reservoirs saturated with formation water in which the rock dominates the geochemistry.

We hypothesize that mudstone dominates the geochemistry of an unconventional reservoir; perturbations induced by injecting stimulation fluid are short lived. Stimulation fluid may initiate acid-base reactions that dissolve carbonates and silicates, but the rock rapidly reasserts geochemical control over these reactions and maintains geochemical control of redox. We also hypothesize that mineral dissolution and precipitation, if induced by stimulation fluid, manifests as volumetric or surface alterations across all scales (micro-, meso-, and macro-) of pore architecture. To evaluate these hypotheses, we performed two hydrothermal experiments that simulated shut-in conditions in a reservoir (125 °C and 45 MPa). Stimulation fluid was injected into one experiment after formation water and mudstone had reacted for 48 days. The second experiment served as a control. In addition to routine geochemical analysis, we measured redox potential to evaluate pyrite dissolution and iron oxidation and gas adsorption to evaluate potential changes in the architecture of 2–105 nm pores. To our knowledge, this is the first published experimental study to inject stimulation fluid into a simulated shut-in reservoir saturated with formation water and the first to measure redox potential in these experiments.

We found that aqueous chemistry in the injection experiment was consistent with dissolution of calcite and feldspar and/or quartz as well as precipitation of clay and barite, but evidence for mineral reaction was limited to calcite dissolution and barite precipitation. Rock and formation water maintained reducing conditions despite injection of oxidizing stimulation fluid. Mineral dissolution and precipitation manifest as an increase in macropore volume with barely detectable alteration to micro- and mesopores. Access of stimulation fluid to micro- and mesopores may have been inhibited by formation water in the pores or by organic matter, diminishing the effect of the stimulation fluid. Surface area increased by 32%, which could be related to changes to the macropores or wettability alteration. The need for deeper understanding of these changes motivated a complementary study by Medina-Rodriguez et al. [1].

Section snippets

Experimental design

Two hydrothermal experiments reacted mudstone and formation water at reservoir conditions of 125 °C and 45 MPa to equilibrate the geochemistry of rock and water and to saturate the pores with formation water. Stimulation fluid was subsequently injected into one experiment. This ‘Injection Experiment’ continued for an additional ~27 days, a typical ‘shut-in’ period for a well completed in a hydraulically-fractured reservoir. Wells are shut in to improve hydrocarbon recovery by increasing

Dissolution of carbonate minerals

Addition of stimulation fluid began to dissolve calcite but not dolomite in the Injection Experiment. Mass balance constrains a mixture of stimulation fluid and formation water in the Injection Experiment to 15% less aqueous calcium and 5% more aqueous magnesium than in formation water immediately before injection (Fig. 2). The first water sample withdrawn from the Injection Experiment after injection of stimulation fluid (0.25 h after injection) contained aqueous calcium and magnesium at these

Conclusions

Hydrothermal experiments were conducted at reservoir conditions (125 °C and 45 MPa) to test two hypotheses:

  • 1)

    The rock dominates the geochemistry of an unconventional reservoir; perturbations induced by injecting stimulation fluid into a gas shale-formation water reservoir are short lived, and

  • 2)

    If mineral dissolution and precipitation is induced by stimulation fluid, it manifests across all scales (micro-, meso-, and macro-) of pore architecture.

Core of the Baxter Shale, an unconventional gas shale

CRediT authorship contribution statement

Matthew G. Edgin: Conceptualization, Methodology, Formal analysis, Investigation, Writing - original draft, Writing - review & editing, Visualization. Bryan Medina-Rodriguez: Methodology, Formal analysis, Investigation, Writing - original draft, Writing - review & editing, Visualization. John P. Kaszuba: Conceptualization, Methodology, Formal analysis, Resources, Writing - original draft, Writing - review & editing, Visualization, Supervision, Project administration, Funding acquisition. Janet

Declaration of Competing Interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Acknowledgements

Edgin acknowledges funding from the Department of Geology and Geophysics at the University of Wyoming, ExxonMobil, the Geological Society of America, and the American Association of Petroleum Geologists. Core was generously provided by Mark Longman and QEP Resources. Edgin appreciates the support of the members of the Experimental Geochemistry Research Group at the University of Wyoming and thanks Dr. Tom McCollom at the University of Colorado for a lab tour as well as advice in how to measure

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