Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO 2 ) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles"). Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO 2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO 2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.

Surfactants are important components in fracturing fluids for helping ensure higher productivity from unconventional reservoirs. Conventional wisdom suggests that surfactant mixtures generally exhibit better performance than individual surfactants. Additionally, the synergism between surfactants increases with the degree of charge difference. Some current commercial surfactants were formulated by mixing nonionic and anionic surfactants (S n/a ), but few were formulated by mixing cationic and anionic (S a/c ) surfactants because of the risk of precipitation or formulation instability. This paper discusses binary mixtures of S a/c surfactants prepared with different mole ratios to determine their synergisms; mixtures of nonionic/anionic (S n/a ) and nonionic/cationic (S n/c ) surfactants are also compared. Surface/interfacial properties [maximum surface excess concentration (Γ max ), minimum molecular area (A min ), critical micelle concentrations (CMC), and Gibbs free energy (ΔG)] and interaction parameters (β m and β s ) in both the mixed micelle and interface were quantified to demonstrate the synergistic effect between various surfactants. Additionally, the potential application of these mixtures for unconventional treatments was examined with regards to emulsion behavior and column-packed oil recovery testing. The results for the S a/c surfactant mixtures show that, compared to parent species, Γ max of the S a/c system is approximately one order of magnitude higher (corresponding to one order of magnitude lower in A min ). The resultant CMC is approximately two orders of magnitude lower than the parent species, and the ΔG of S a/c is more negative. Notably, the interaction parameters further indicate that strong synergism exists for the S a/c system at various mole ratios in both mixed micelle and monolayers at the interface (with an optimized ratio at 2/3), while, for the S n/a system, weak synergism was identified in the mixed micelle at the mole ratio of 3/2. No synergism was observed for the S n/c system. Additionally, phase behavior testing indicated that a weak emulsion was formed in the presence of the S a/c using Eagle Ford crude oil. Column-flooding testing also revealed improved oil recovery of the S a/c system compared to individual species. The synergistic effect between S a/c surfactant mixtures, as well as the laboratory results of the emulsion behavior and oil recovery, suggests a new practice for applying S a/c surfactant blends for unconventional applications.

The water-sensitive nature of shale is traditionally thought to be a factor of the clay content of the rock. Because current practices to mitigate formation damage entail the use of brines to control the osmotic potential of stimulation fluids, we posited that not all brines will induce the same response from Bentonite, Illite, and more importantly shale. Current industrial practices to mitigate permeability damage in source rock shale reservoirs typically entail the use of sodium-, potassium-, calcium-, tetramethyl ammonium-, and/or choline chloride salt brines to control the rate of cation exchange between formation clays and stimulation fluids. Industrial and literature precedent suggests that below a critical salt concentration (CSC) osmostically-driven cation-exchange between injected fluid and the formation is the primary damage mechanisms for both swelling and migrating clays; however, above the CSC, the potential still exists for crystalline swelling and mechanical destabilization. Examining various clays and clay laden formation materials revealed that certain cations, even above their CSC, will induce formation damage. To accurately assess the effect and permanency of various brines when introduced to pure clay as well as shales, a statistically relevant laboratory protocol has been developed to evaluate the role differing cations play in shale preservation. The clay and formation cuttings were evaluated for swelling and mechanical stability, then subjected to dynamic experiments using sandpack, coreflow, and API conductivity testing methods. The evaluated formation materials were diagnosed with computed tomography (CT), scanning electron microscopy (SEM), and energy-dispersive X-ray spectroscopy to diagnose permeability damage mechanisms for given treatment fluids and formation material composition. This paper seeks to advance the existing understanding of the damage mechanisms involved when brine containing stimulation fluids are introduced to shale reservoirs. Currently, there is a lack of consensus on the significance of the identity of the ideal salt-cation treatment to preserve permeability in shale reservoirs. The authors have probed the effect various brines have on clay and unconventional material, which compliments the current body of literature related to shale inhibition.

To maintain open and conductive fractures in tight-rock shale formations, shale/water interactions should be controlled through chemical or brine treatments. Adequate treatment of an unconventional formation can mitigate or reduce the damaging effects induced by shale (swelling, sloughing, fines migration) or proppant (proppant embedment, breakage, fines migration), which leads to maximized conductivity. This study characterizes shale behaviors with various treatment fluids applied under simulated downhole conditions. Four source rock shale samples, Barnett, Eagle Ford, Mancos, and Marcellus, were characterized and evaluated in contact with chemical and brine treatments to determine the extent of swelling and mechanical stability imparted by each treatment. Conductivity measurements were taken on proppant packs between shale wafers under closure stresses from 2,000 to 10,000 psi. The wafers used during those tests were then analyzed using computed tomography (CT) imaging. Quantification and classification of the damage were used to evaluate the shale formations after application of fresh water and two chemical treatments—a small cationic oligomer and a large cationic polymer additive. Results suggested that chemical and brine treatments do not provide an all-inclusive mechanism to prevent damage for all shale samples, and total clay content or clay type was not the best predictor of water sensitivity. Barnett shale samples contained the most clay, had the highest conductivity, and were most resistant to fluid-induced damage using a small cationic oligomer additive. Conductivity loss for the other three shale formations was primarily attributed to fluid-induced formation damage. In each of these three shales, the mechanism for formation damage resulted from different causes. Clay-induced swelling for Mancos shale resulted in the most significant proppant embedment and was most effectively remedied using a large molecular weight polymer stabilizer treatment. Eagle Ford and Marcellus shales showed pockets of proppant embedment and significant fines migration. Generation of migrating fragment causality was different for these two shales; one contained migrating clays in its mineralogy, while the other was more mechanically brittle and prone to stress-induced fragmentation. The differing mechanism changed the effectiveness of the chemical treatments; Eagle Ford shales were most responsive to large molecular weight polymer stabilizers, whereas Marcellus shales did not change significantly with the chemical treatments evaluated. Selecting the optimal chemical treatment for each formation depends on the mechanism and type of damage. Each reservoir is unique, and improving production begins with customizing treatments to protect the formation materials against the specific damage mechanisms, thus minimizing the negative impact on propped fracture conductivity. Understanding the exact needs of each shale formation allows the treatment fluid to be tailored specifically for the formation as part of the fracturing treatment design, thereby optimizing the treatment effectiveness and cost.

Significant work is ongoing within the industry to determine a best practice for maximizing oil recovery from fractured oil-wet shale reservoirs. Rapid decline curves are often observed and water flooding can be largely ineffective because of negative capillary pressure. The goal of this work is to identify a chemical solution that can maximize oil and gas recovery in unconventional reservoirs by reduction of hydrocarbon adhesion to shale rocks. In order to evaluate an optimal solution, numerous formulations were developed and tested for their impact on adsorption and adhesion on rock and/or sand, changes in interfacial tension, and how the formulation affects the wettability of the formation. Shale rocks were characterized for their surface energy, as this governs the adsorption and adhesion tension of crude oil, water, and chemicals to the solid surface. Formulations were selected that minimized the adsorption on rock and sand surfaces since such adsorption may lead to an increase in the surface tension of fluid pumped into the well and the interfacial tension between the crude oil and fluid. Contact angle measurements were used to determine the Van der Waals and Lewis acid-base components of surface energies for Barnett, Eagle Ford, Niobrara, and Bakken shales. In addition, contact angle measurements and interfacial tension were used to determine the adhesion of crude oil to the rock. Numerous chemical formulations were evaluated to identify products that can decrease the work of adhesion, making oil recovery more efficient (i.e. less work is required to remove oil drops from the rock surface and mobilize them). Competitive adsorption of formulations at the oil-water and rock-water interface was evaluated. The amount of natural surfactants in the oil and their adsorption on the rocks (reversible vs. irreversible) affect whether the rock is oil-wet or water-wet. If the adsorption is reversible, the rock would be more water-wet, resulting in higher oil recovery. Formulations which altered the wettability to water wet rapidly, but reduced the interfacial tension slightly, exhibited the highest oil recoveries. Based on wettability alteration, interfacial tension, and work of adhesion, a novel product was developed that is salt tolerant (in 30% TDS), thermally stable (115°C), and produces high oil recovery (i.e., 60% OOIP). Kinetics were also improved compared to conventional treatments and brine alone. In addition, this product showed a low static adsorption on the Bakken shale (0.20 mg product active/gram rock) and no emulsion tendency.

Contamination of oil and gas operations by sulfate-reducing prokaryotes acid-producing prokaryotes, and facultative anaerobic prokaryotes can significantly reduce hydrocarbon quality, compromise asset integrity, and cause plugging in the formation. Complete treatment of these contaminants requires the use of biocides capable of retaining efficacy in the extreme conditions common in deep subsurface wells. This study investigates the interactions of several common oil and gas biocides with shale to determine their suitability for use in the downhole environment. Each biocide was submitted to studies analyzing (1) shale's effect on chemical stability and aqueous availability of the biocides, and (2) resulting biocidal efficacy on common facultative anaerobes. The chemical availability study was performed using high performance liquid chromatography, and the comparative biocidal efficacy study was performed using standard microbial viability assays. Due to variances in complexity of hydraulic fracture networks, the degree of adsorption was also measured as a function of shale surface area. The panel of biocides showed a variety of responses to exposure to shale. Surface-active, cationic biocides rapidly associated with shale preferentially over water, significantly reducing the availability of these compounds in the aqueous phase. Accordingly, their efficacy against planktonic bacteria substantially diminished. Across the range of shale types (surface area and reservoir source) tested, all surface-active biocides lost efficacy. Most biocides that rely on electrophilic reactivity (rather than surface activity) for efficacy against microorganisms showed little to no interaction with solid shale, and biocidal potency was not compromised. These results provide guidance for selection of biocides that will remain stable, chemically available, and ultimately efficacious in the extreme conditions of a subsurface shale reservoir.

The Eagle Ford formation, often referred to Eagleford Shale , is a complex one. Some field personnel involved with drilling this formation argue that in their experience Eagle Ford formation is not "shale" at all; however, they do not offer a morphological, mineralogical, and mineralogical reason supporting their claim. To design, plan, engineer, and carry out an economically viable drilling, completion, and production, we need a deeper understanding of both general and local characteristic of the Eagle Ford formation, whether shale or not! Following this goal, with the help of industry, we received on loan, full cores of Eagle Ford formation, and began our tests and analysis. Using an interdisciplinary approach, it is the object of this paper to characterize the formation in depth. Having learned from our several decades of shale studies, our analyses include but are not limited to: (1) determining solubility of Shale specimen in de-ionized water, (2) using ion selective electrodes, measure the potential, Eh, Temperature, and Hydraulic Potential over the submerged portion of specimen, (3) setting up a video system to record all measurements with time to see (a) which ion leaves the mass of specimen first at a given instance of time and (b) to see whether the timing of this event coincides with the release of first bubble of gas and appearance of fractures in the shale mass, (4) analyzing the slopes of Eh vs. Time (5) examining the possible beneficial and non-beneficial effects of bacterially produced minerals, i.e. combined carbonate-silicates, Marcasite/Pyrite (FeS 2 ), on hydrocarbon development in source rock, and finally (6) determining how these interactive, bio-geo-chemo-systems could affect the mechanical properties of the Eagleford formation. Our results show: (a) Na + diffuses from specimen to water first, almost instantaneously, next is Ca +2 , from ½ to several-hours, and Mg +2 up to 20-hours, (b) gas bubbles appear about 0-2-hours after Na + release, (c) time for ionic permeability to reach equilibrium (steady-state) is within the range of 20-50 hours depending on the concentration of and type of release of, (d) pH remains acidic between 5.5 and 6.5, (d) diffusion of Na ion from specimen to water appear to initiate first at the pressurized fissility planes (planes of weakness), which is rapid at the beginning but slows down thereafter, possibly indicating activation of the small and smaller pores in the specimen, (e) the bacterium, shown by arrows in Fig 10 , converts Fe II to FeIII then to Marcasite crystals, along with secretion of associated minerals, where these minerals could act as thermal insulator and allowing maturation of the hydrocarbons in-situ to continue, and (f) in this process it appears that the excess supply of H 2 S, the by-product hydrogen, along with growth of crystals, all lead to pressure build-up in the fissility planes, thus prying them open. The Shale plates, due to dissolution of cement bonding them, appear unable to bond back, which could be attributed to the presence of water and sulfuric acid, reacting with the rock material, rendering it thin, weak, and brittle. Understanding these results could determine a more favorable drilling strategy for constructing a stable wellbore, mitigating lost circulation, designing a better fracturing method, designing a more compatible completion and fracturing fluid, and implementing better corrosion mitigation while producing the well.

Microorganisms contribute to souring and corrosion in oil and gas field systems. Biocides and/or nitrate can be used to mitigate the negative effects associated with these microbial activities. In order to determine the success of or the need for these measures we use a number of analytical tools on aqueous or solid field samples: (i) spectrophotometric and HPLC assays are used to monitor key analytes (sulfate, sulfide, nitrate, nitrite and others), (ii) microbial assays are used to determine numbers and activities of key microbes and (iii) sequencing of PCR amplicons, typically of a portion of the 16S rRNA genes is used to determine microbial community compositions in field samples. The trick is to combine the information to arrive at a comprehensive view of what is happening and what action may be needed. For instance, a shale gas and a shale oil field in North West Canada, appear to have similar water chemistry. Both are highly saline but halophilic (salt loving) SRB were only found in samples from the shale oil not in those from the shale gas field, which appears related to the different temperatures in these fields of 30-35°C and 75-100°C, respectively. Hence, mitigation measures aimed at killing bacteria downhole may be appropriate for these shale oil but not for these shale gas environments.

Shale gas development relies heavily on multi-stage hydraulic fracturing (HF) to maximize the economic viability of each new well. Industry is making a concerted effort both to recycle and re-use produced brine from fracturing operations and to use alternate water sources for well operations. Some experts foresee almost all produced brines being treated and reused within the next five years. Texas A&M Global Petroleum Research Institute (GPRI) has been one of the leaders in promoting new technology to reach these goals. In the past decade we have conducted a number of field trials in different shale plays to a) identify technologies and determine their effectiveness, b) field test advanced monitoring and measurement techniques, and c) integrate the technologies into one cost-effective program for the industry. This paper presents results from these trials that compare different types of filtration media used to remove hydrocarbons, filtration techniques to remove suspended solids and nano filtration materials to stabilize ultrahigh salinity brines making them compatible with today's fracturing fluid designs. In addition to describing cost effective brine treatment, we have provided a venue for testing advanced analytical techniques that provide rapid ways to measure the effectiveness of such water treatment. Measuring hydrocarbon content in the brines aids in selection of optimal treatment and monitoring of its effectiveness. New fluid imaging techniques characterize particulates in brines and can help to optimize filtration requirements. Biological monitoring can determine effectiveness of solids removal practices and helps in selection of appropriate bacterial control. This paper will discuss the need to utilize on-site, real-time analysis of produced water and frac flow back brine to allow faster and more accurate characterization of the oil and gas waters being cycled back to unconventional gas development. The benefits of the technology come from improved procedures to characterize and mitigate the risks of HF at drilling and hydraulic fracturing sites. Better monitoring and treatment can help to counter the mounting concerns of legislators, regulatory agencies, and the general public as well as aid the economic development of our natural gas resources.

Tight formations with extremely low matrix permeabilities, such as gas shale, can produce at economical rates is due to inborn fissures and fractures introduced during hydraulic stimulation. Hydraulic fracturing in gas shale can connect/generate these microfractures, causing them to become much more complex fracture networks. These microfractures have much more contact area with the matrix and therefore hold the majority of the productivity potential of gas shale. Slickwater fracturing has been proved to be an effective method by which to increase the recovery of shale gas reservoirs. Friction reducer is the primary component of this fluid. It can decrease the flowing friction in macro tubing. Lab tests and field applications have addressed this issue thoroughly. However, the flow characteristics of this solution in microfractures are not clear. The present study will show how this solution flows in microfractures by employing micro-sized fracture model. FR solution is a shear thinning fluid. Rather than reducing flow friction, with the FR fluid in a 1000 μm height, 50 width μm and 4.14 cm length microfracture, the injection pressure did not decrease but rather increased 36%. The impact of FR solution concentration was found to be more obvious at low velocities. At the same shear rate, the apparent viscosity is higher in large microfractures. At the same velocity, large microfractures have higher residual resistance factors. Through the analysis of fluid emulsion particle size and shale matrix pore size, this FR solution will not go into the matrix pores easily, but can block the pore entrance to prevent the fluid from leak off and to protect the formation from contamination during slickwater fracturing.

Hydrogen sulfide (H 2 S) is found in many shale gas fields. It is important to remove the H2S to allow for safe transport of the produced gas and to reduce corrosion concerns. The H 2 S concentration present in the gas is typically low enough that it becomes uneconomical to utilize a regenerative facility such as an amine plant. For this reason, liquid H 2 S scavengers are the most common mitigation strategy, with nitrogen-based triazines being the most commonly utilized scavenging chemistry. Hydrogen sulfide scavengers can be introduced by direct injection 2 into mixed production or separated wet gas pipelines. They can also be reacted with H 2 S in scavenger flooded contact towers. Applications utilizing towers consume less H2S scavenger; however, the use of contact towers introduces additional capital costs in the operation. Often when high pH, triazine-based H2S scavengers are used, calcium carbonate scale deposition can occur because of neutral pH brine, requiring the facility to be shut in and treated with mineral acids. The reaction product of triazine with H 2 S can be difficult to dispose of, which increases facility operating costs (e.g. separate disposal tanks and dedicated disposal wells for spent scavenger). A novel, fast-acting, non-triazine based H2S scavenger has been developed. This new H 2 S scavenger reacts quicker and has better efficiency than other non-nitrogenous based scavengers (e.g. glyoxal). The neutral pH of the new product eliminates the concern for calcium carbonate deposition that is often experienced with triazine-based scavengers. The new scavenger has been tested for thermal stability and compatibility with other production chemicals. The product has the ability to partition in oil and water phases, making it a more versatile scavenger. Finally, the new product has a better environmental profile than other commonly used H2S scavenger chemistries. A field trial was conducted using the new non-triazine H2S scavenger. The trial included direct injection into mixed production and separated wet gas lines. Innovative engineering solutions were devised to apply the new H 2 S scavenger. The combination of the novel application methodology, with the new H2S scavenger chemistry, resulted in a more cost-effective means of treating sour shale gas than is currently achieved with conventional triazine-based H2S scavengers utilizing contact tower applications.

Shale gas has become an increasingly significant source of natural gas in the United States. It is puzzling to many that most of the shale gas wells decline very rapidly. Our study shows that in hydraulic fracturing of shale-gas wells operators often use "slick water". The "slick-water", as carrier fluid, comprises plain water and some combination of polymer gel, gel breakers, cross-linkers, and surfactant or surfactant/water alone. However, in lessons learned from the oil field personnel and our own years of research and field practice, we see that first Polymers in general upon hydration retain a water layer for a long time, second Shale absorbs or allows this water layer in the shale body under suction (negative) pressure, then, it converts the suction pressure to swelling pressure reaches which closes the micro fractures, and third, to complicate the matters, some surfactants simply disperse the shale-clays. The net effect of these mechanisms is rapid production decline. One of the most important mechanisms is water absorption. Shale absorbs water due to the capillary effects of micro fractures and the shale-clay potential. However, there is no model to show the relationship among capillary effect , the shale-clay type potential, the morphology of the shale aggregate , and finally the production decline . We propose a model which connects the above mentioned four elements together and shows the way to the root cause of rapid production decline. Based on the results we conclude: first the proposed model shows a good correlation between the above four elements in terms of shale fractal dimension and the shale hydration index, all used for calculating the excess hydration stress, and second the excess hydration stress accelerates micro fracture closure, hence the rapid gas production decline. The benefits of our work follows: one is the combined HHI and the shale fractal dimension can be used to optimize the shale hydraulic fracture conductivity toward long term gas production and the other is the correlation offered here shows it to be a better method for measuring the shale-water activity by using the shale characteristics, namely, the shale water content, the Hydration Index , and the shale fractal dimensions .

Because of commodity pricing, the production from organic rich shales such as Barnett, Woodford, Eagle Ford and Marcellus has shifted significantly away from the dry natural gas window into the more profitable condensate and liquid hydrocarbon (oil) windows. The current production practices, however, are based mainly on field experience of the operators and far from being a methodological approach for an optimized production. This is mainly due to the fact that our understanding of condensation, capillarity and multi-phase flow dynamics in shale reservoirs is at an infancy stage. It is currently not known, for example, if and where the condensation takes place in the reservoir, and what is the impact of the shale matrix on the this phenomenon. In this paper we argue that answering these questions using conventional laboratory measurement techniques is a difficult task because the fluid properties and the phase behavior of the hydrocarbons could be influenced by the nanoporous nature of these rocks. Monte Carlo simulations are conducted to investigate pure hydrocarbon vapor-liquid coexistence and critical properties under confinement. The results show a pore size dependence of these thermo-physical properties. Phase diagrams generated using ternary (C 1 , C 4 , and C 8 ) mixtures under reservoir conditions show a two-phase envelop shift due to pore size dependence. We show the importance of the results performing a shale gas in-place calculation using Ambrose's equation where the equation of state parameters, z-factor, gas formation volume factor, and adsorbed-phase density values are all adjusted for a range of effective pore size. The corrections on the free and the sorbed gas in-place estimates are significant. Furthermore, we predicted reserves from wet gas, condensate, and volatile oil reservoirs using compositional flow simulation. It is shown that the liquid production from nanoporous rocks is enhanced due to a significant decrease in the bubble point and dew point pressures.

At realistic surfactant concentrations used in fracturing fluid additives, the differences in the average strengths of shale exposed to solutions of these additives are not sufficient to establish a direct correlation between the chemical effect of the surfactants and the mechanical strength of the formation. Prior studies of formations with high quartz content suggest that the adsorption of surfactant on the surface alters formation strength. In this study, using Mancos shale samples, the rock mineralogy, total organic carbon and cation exchange capacity of the Mancos shale samples were determined in order to characterize the shale. Adsorption tests to study the interaction of the shale and aqueous fluid mixture were also carried out using surface tension measurements. The uniaxial compressive strengths and indirect tensile strengths of about 100 rock samples exposed to different fluid environments were measured using unconfined compression and Brazilian tests respectively. Microseismic events, possibly due to microfracture generation or growth, are known to continue for some time as stresses relax after shutdown of hydraulic fracture pumps. Hence, the study of the role of surface chemical effects in compression and tensile fracturing is important in determining whether rock/fluid chemistry can be exploited to improve the growth of conductive microfractures.

Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often non-aqueous based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBM) for drilling many of these gas reservoirs. Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers water-based muds formulated specifically for a given shale play has been pursued. Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology, but also well drilling program plans, environmental factors and other reservoir-specific considerations. Applying appropriate drilling fluid chemistries based on this detailed analysis has led to the successful field deployment of a number of new shale fluids. Details of the process utilized for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales are presented in this paper. Full laboratory development and testing is described. Additionally, field trial results are presented that show specially-designed WBMs can provide comparable performance to NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.

Effective microbiological control is an important aspect of a successfully executed fracturing job. Control of bacterial growth is often accomplished through the use of biocides such as glutaraldehyde, particularly in the multi-stage, high-volume fracturing of unconventional shale gas reservoirs. Biocidal additives, which are toxic by necessity, can persist in flowback water, so their use in shale fracturing has come under increasing scrutiny since high biocide concentrations in flowback water increase fluid cost and limit the options for disposal. The case for designing a bactericide program to match, and not exceed, the required amount of bacterial control is clear, but rarely is the bacterial load determined during and after the job to verify this balance. Herein, we report a case study undertaken to evaluate the bacterial load of field mix water and flowback water during and after a large hydraulic fracturing job in the Marcellus Shale. A novel oxidative biocide product was used during the fracturing job that has both an effective fast kill and a low toxicity profile (e.g. HMIS rating of 1,0,0). Because of its rapid biodegradability, there was concern that the effective kill of this biocide would not persist beyond a few days. Industry standard techniques (NACE Std. TMO194-94) for quantifying bacteria were applied to water samples taken during the job and over several weeks of production. The biocide was also evaluated for compatibility with common fracturing additives and for its corrosivity to surface equipment and tubular goods. This study determines that the new biocide does not persist in flowback water beyond a few days. However, analysis of flowback water samples reveals that the bacteria count stays low (less than 10 cells/mL) for up to 81 days after application of this biocide in a slickwater fluid. Additionally, genetic fingerprinting using Denaturing Gradient Gel Electrophoresis Analysis (DGGE) was applied to the bacteria in the initial field mix water to allow comparison to any bacteria detected in the flowback samples. This paper will describe the details of this case study. Since the completion of this case study, we have successfully deployed this technology on treatments in the Barnett, Haynesville, Marcellus, and Granite Wash shale regions. This paper reveals details of a field test and of the efficacy of this biocide as tested in flowback waters from the Piceance and Marcellus Shale basin. The results of the bacteria enumerated from each job site sample are presented. Finally, dosage requirements for biocidal efficacy were optimized for slickwater hydraulic fracturing applications are described.

Biocide efficacy studies targeting extended contact times, 7 days, and elevated temperatures, 80° C, led to the discovery of a synergistic combination of Dimethyl Oxazolidine (DMO) and glutaraldehyde. When applied together in specific ratios, most notably a 1:4 ratio of glutaraldehyde to DMO, these two chemistries exhibited superior performance after extended exposure relative to traditional biocide treatments utilizing chemicals such as THPS, glutaraldehyde, and glutaraldehyde/alkyl dimethy benzyl ammonium chloride (ADBAC) blends. The combination of glutaraldehyde and DMO applied in a 1:4 ratio was able to achieve equal performance with lower combined actives. The result of this synergy has a twofold impact on the environmental footprint: it requires less overall biocide for the same level of control, and DMO has a more favorable eco-toxicity profile compared to conventional organic biocides. Field trials on eleven wells and 4 separate well pads in the Marcellus Shale area were treated with the Glutaraldehyde and DMO combination and evaluated using various microbial detection techniques. The benchmark for performance was set by the prior standard chemical treatment in the same shale formation area which utilized the biocide combination, 42.5% active glutaraldehyde and 7.5% active ADBAC blend. Seven wells on three separate well pads treated with Glut/ADBAC were used for comparison to the test wells. The wells treated with the Glut/ADBAC were all dosed at a rate of 300 ppm active ingredient (600ppm product), and the wells used to test the glutaraldehyde/DMO combination treatment were dosed at 200 ppm active (285ppm product). The results of the field trials showed equal or slightly better performance with the combination treatment while utilizing 33% less active chemical, and yielding a reduction of 50% less biocide product applied.

In recent years a number of laboratory studies on the use of surfactants and microemulsions in hydraulic fracturing of shale formations have been reported. These studies mainly focused on such metrics as improvement in permeability regain and enhancement of fluid recovery from packed columns upon the use of surfactant-containing chemicals. Laboratory studies have also been backed by the documented observations from the field illustrating benefits of using microemulsions for the increase in gas production from shale formations. It is a commonly accepted view that these additives benefit gas production by lowering capillary pressure and altering wetability of shale formation. Although it is recognized that the interaction of surfactants and microemulsions with shale is governed by the energetics of solid/liquid, liquid/gas and solid/gas interfaces, there are practically no studies in which surface energies have been determined for different shales. The surface energy, as well as dispersive, non-dispersive, Lifshitz-van der Waals, and Lewis Acid-Lewis Base components of surface energy of several North American shales have been determined from contact angle measurements. It has been discovered that the surface energy of all shale rocks is rather low, typically in the range of 40-50 mJ/m2 a contribution from non-dispersion ("polar") component of about 8-11 dyn/cm. Consequently, shales are capable of interacting with liquids predominantly via dispersion and Lifshitz-van der Waals molecular interactions, which should substantially influence the orientation of surfactant molecules and microemulsion moieties at the shale surface. Furthermore, there was no significant variation in surface energy of shales from different basins, which suggests that individuality of shale surface chemistry should play only a secondary role in the development of shale-specific chemical treatments, and factors other than surface chemistry should be considered first.

Gas production from subsurface shales requires fracture technologies in which fracturing fluid, consisting of guar gum-suspended sand, is forced into the fractures to "prop" them open. The guar gum is easily degraded by bacteria both downhole and at the surface, compromising water reuse or disposal. Samples from the Pinedale shale gas field had high activity of mesophilic acid-producing bacteria (APB), converting guar gum to sugars and then to acetic and propionic acids and of heterotrophic nitrate-reducing bacteria (hNRB), using sugars or acids from guar gum as electron donor for nitrate reduction. Activity of sulfate-reducing bacteria (SRB) was considerably lower with guar gum, reflecting a low initial population size of SRB using the organic acids produced by APB for reduction of sulfate to sulfide. The low concentrations of sulfate in the samples (0–0.4 mM; 0–40 ppm) may be the root cause for this low SRB activity. Indeed, most probable numbers (MPNs) of SRB, determined on standard lactate-sulfate medium were 10- to 100-fold lower than those for APB, determined on standard phenol red-glucose medium. Interestingly, lactate-utilizing SRB appeared to be able to grow in APB medium, indicating that some SRB can also maintain themselves by fermentative metabolism, when sulfate is absent. Culture independent surveys of community composition confirmed that the microbial community at Pinedale samples was dominated by classes of fermentative bacteria (APB). Overall, we conclude that monitoring of the MPN of glucose-fermenting APB most accurately reflects microbial activity and associated biofouling at Pinedale. The success of biocide treatment to reduce microbial activity and associated biofouling is, therefore, also more accurately determined with the APB assay than with that for lactate-utilizing SRB.

The practice of slick water fracturing has increased significantly with the advent of horizontal shale stimulation. Many technologies have evolved to improve the practice, including multi-stage fracturing of horizontal wells and simultaneous fracturing, both of which increase frac treatment volumes up to several million gallons of slick water per well. Recent incidents related to interaction of biocides and friction reducers have created concerns for the industry and compelled operators to adopt methods of using biocides with short half-lives, in order to minimize or eliminate biocide contamination in flowbacks reused as frac water. Concurrently, some biocides can crosslink polyacrylamide-based friction reducers, causing severe formation damage, production impairment, and flowbacks that contain cross linked polymers, requiring further chemical treatment and increasing operational costs. This study examines polymers and biocides, along with other additives (oxygen scavengers and scale inhibitors) commonly used in slick water fracturing, and identifies the parameters that could minimize the effectiveness of slick water frac treatments and potentially cause formation damage. To illustrate, this study incorporates a high molecular weight water-based emulsion polyacrylamide as the friction reducer, used in conjunction with various non-oxidizing biocides, with results reflecting positive, negative, or neutral impacts. Experimental results presented in this study are supported by utilizing a 20-gallon capacity friction loop with a Reynolds number of 150,000. Conventional bench top methods were also used. Results indicate that particular biocide-friction reducer systems exhibit significant performance deviations when standard brines or flowback water is used in shale slick water fracturing treatments. Results obtained from this study provide operators a tool to avoid combinations of specific chemicals used in slick water fracturing. Awareness of additive interactions in specific frac fluids used can maximize the effectiveness of treatments, and avoid costly errors that may adversely impair production and jeopardized performance of the biocide. The integrity of the assets on location are thus affected by diminished biocide performance ( Olliver et al , 2005 ). Therefore, any biocide chosen for slick water treatment should be pretested for compatibility with the friction reducers and other chemical additives, in order to insure an incident free operation from a chemical standpoint and minimize the potential for formation damage.