One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

A multiyear study of water wells in rural areas during intensive development in the Utica Shale found that some had high levels of methane (CH4), but chemical testing showed that was not the source of that gas. Based on the carbon isotopes identified in the well water samples collected by researchers, the methane was from shallower depths. This biogenic gas was likely produced by bacteria in places like the soil and in coal seams, according to the study in the June 2018 issue of the journal Environmental Monitoring and Assessment. There are "production-scale coalbed CH4 reserves in the study area but no active coal bed gas wells," it said. That finding contradicts the arguments of fracturing opponents who say hydraulic fracturing leads to methane contamination of groundwater aquifers.

A comprehensive 3-year scientific study into the air, water and soil impacts of hydraulic fracturing in Queensland coal seams has found few to no impacts on air quality, soils, groundwater, and waterways. The study also found current water treatment technology used for treating water produced from coal seam gas wells is effective in removing hydraulic fracturing chemicals and naturally occurring (geogenic) chemicals to within relevant water quality guidelines. Research objectives for "Air, Water and Soil Impacts of Hydraulic Fracturing in the Surat Basin, Queensland," conducted by the CSIRO's Gas Industry Social and Environmental Research Alliance (GISERA), were developed in response to community concerns about the potential for chemicals used in hydraulic fracturing operations to affect air quality, soils, and water resources. The study analyzed air, water, and soil samples taken before, during, and up to 6 months after hydraulic fracturing operations at six coal seam gas wells in the Surat Basin in Queensland. GISERA Director Damian Barrett said that the research was an Australian first and provided unique insights into the impacts of hydraulic fracturing in Australia.

Drilling and completion operations introduce microbial contaminants into the reservoir via numerous pathways including drilling muds and hydraulic fracturing fluids. Uncontrolled microbial growth in the reservoir can lead to reduced flow and production rate of hydrocarbons due to accumulation of biofilm and plugging. Microbial contaminants can also lead to microbially influenced corrosion (MIC) of topside and downhole production equipment, causing undesirable impacts to capital spending and operational efficiency. As a mitigation strategy, biocides are often added to hydraulic fracturing fluids to control microorganisms which cause these operational issues. Oilfield service laboratories often receive water samples from the field to provide recommendations on the most optimum biocide use and concentration. The standard industry method (NACE TM-0194) used for measuring biocide performance is based on a time-kill test in which water collected from the field is spiked with bacteria. Biocides are added at desired concentrations and samples are withdrawn to determine log reductions. Bacterial levels are often determined by ATP so results can be collected within minutes.

A wide number of biocides are available for oil and gas operations. They differ primarily by mechanism of action, speed of kill, and interaction with other components of fracturing fluids. As the NACE method relies on rapid activity, misleading test results are often observed with preservative biocides which are intended for slow-release / long-term activity. Preservatives are utilized for extended protection of the well and reservoir after drilling and/or completion operations, not for the rapid reduction of microbes in a water sample. Therefore, as current methods are intended for rapid-kill biocides, novel methods are required to demonstrate the efficacy of preservatives.

Methods were designed primarily to demonstrate efficacy of preservative treatment for waters used in hydraulic fracturing. Using culture-based methods, biocides were added to water samples that were incubated at elevated temperatures and challenged periodically. Glutaraldehyde was an effective preservative at 55 °C, providing antimicrobial efficacy for >7 days. 4,4-dimethyloxazolidine (DMO) was effective for 4 weeks or more, with improved efficacy at elevated temperature.

The methods described in this work can differentiate rapid-kill from preservative biocides, be performed at a service company laboratory, and provide results within an "actionable" period (approximately 7-10 days) of time.

Abstract Scale deposition and its treatment are crucial part of any thermal recovery method. High temperature variation, phase change associated with steam condensation and flashing, and complex flow dynamics of the wells make the thermal wells more susceptible to scale deposition. Several studies evaluated the type of scales collected from plugged sand screens; however, more investigation is required to address the reservoir conditions and wellbore hydraulics affecting the scaling potential of minerals at downhole conditions. A laboratory workflow combined with a predictive modeling toolbox to evaluate scaling tendency of minerals for different downhole conditions has been developed. First, saturation indices (SI) for different minerals were calculated at reservoir temperature and pressure using water chemistry analysis and the Pitzer theory. Then, the mineral composition of deposited materials collected from thermal wells in Athabasca and Cold Lake area were characterized using Scanning Electron Microscopy (SEM), Energy Dispersive X-Ray Spectrometry (EDS), Total Organic Carbon (TOC) and Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses. Finally, a comparison analysis was performed between predictive and characterization results. The results of SI calculations showed that Mg-based silicates and Fe-based minerals are positive (SI>5) even at high temperatures (T>430 K). This indicates that the possibility of deposition for these minerals is high. Carbonates (calcite and aragonite) minerals are the most common depositing minerals. However, the extent of scaling index of carbonates is controlled by the concentration of Ca, HCO3, and CO3 in the water sample. The characterization results confirm the results of modeling part. The results of SEM/EDS, ICP-MS analyses showed that carbonates, Mg-based silicates, and Fe-based corrosion products are the most common depositing materials among all minerals. The workflow presented in this study will help the industry to evaluate the scaling potential for thermal wells at different downhole conditions to make a proper decision to prevent plugging of the completion tools.

Oilfield waters are often referred to as brines, especially when they contain significant quantities of dissolved salts. They also frequently contain dissolved gases and may contain small quantities of the heavier hydrocarbons found in oils. Water can be present in a surface separator during production, either from liquid water in the zone being tested or by condensation from water vapor in the produced gas, or possibly from both. Water from aquifers or seawater may also need to be analyzed in connection with water-injection activities. The analysis of oilfield waters has a wide range of applications, including identifying the origin of produced water, characterizing aquifer properties, interpreting wireline-log measurements, predicting formation damage from water incompatibility, investigating scaling tendencies in surface and downhole equipment, monitoring fluid movement in reservoirs, identifying the presence of bacteria, evaluating disposal options and environmental compliance, and predicting and monitoring corrosion.

One of the most significant challenges associated with predicting reservoir fluid properties is accounting for the effect of microbial activity, which catalyzes chemical reactions that lead to corrosion and sulfide release during or after hydraulic fracturing operations. The current understanding of microbial populations living in hydraulic fracturing systems is based on a limited number of samples and well sites, necessitating additional research efforts to confirm preliminary findings and identify factors driving the microbial ecology. The project objective is to profile the geochemistry and microbiology of three different oil and gas basins to order increase the understanding of how microbial activity affects reservoir fluids. We evaluated the geochemistry, microbial community structure, and microbial abundance of produced water samples collected from the Marcellus Shale, Permian Basin, and Bakken Formation, which represent three of the most productive oil and gas regions in the United States. We also performed a network analysis in order to visualize the microbial interactions occurring across all the hydrocarbon regions and within specific shale plays. For these analyses, we sampled 155 produced waters to account for inter- and intra-basin heterogeneities.

Results suggested all three shale plays have a high abundance of Halanaerobiaceae, a bacterium with the metabolic potential to contribute to acid production, sulfide production, and biofouling. Less abundant bacterial families including Pseudomonadaceae and Methanobacteriaceae varied between shale plays, demonstrating some regions to have a high potential for biologically driven corrosion and others to have a high potential for biogenic methane generation. Findings from this research will contribute to the development of better predictability in fluid properties, with the goal to limit corrosion, control fouling and souring issues, protect well infrastructure, and minimize unnecessary biocide application. This istudy takes a comprehensive approach to characterizing biogeochemistry of reservoir fluids and compares these results across three distinct basins.

Microbial contamination is a major concern in oil/gas system or industrial water operation where it can result in multiple major corrosion issues and efficiency losses. Chemical treatment is the primary means to control microbial contamination, but due to changes in temperature and water sources, this results in major shifts in the microbial levels and populations which can influence the efficacy of these treatments.

Due to the shifts in the number of bacteria and the change in the dominant microbial species, optimal dosage of biocide is very difficult. Inadequate dosage regimen will result in major losses, whilst excess chemical dosage will incur unnecessary costs whilst also increasing the environmental load. A quick, reliable microbial measurement will help identify critical control points in the process and will allow optimization of dosing of the treatment program.

Agar growth, ATP, and media bottle testing have long been the standard for microbial detection, but these can lack the specificity, sensitivity and response time needed to adequately address the changing conditions in the industrial system described. The molecular-based approach, quantitative polymerase chain reaction (qPCR), described in this article, provides a near real-time method to measure bioburden, allowing operational decisions to mitigate issues to occur more rapidly.

Hydraulic fracturing operations are prone to microbial contamination due to the large volumes of water used. Therefore, biocides are often added to hydraulic fracturing fluids to control microorganisms that cause operational problems such as souring, corrosion, and decreased oil and gas production. Selecting an appropriate biocide strategy can be difficult due to the wide range of chemistries available. Oxidative biocides such as hypochlorite or chlorine dioxide (ClO₂) react rapidly with target microorganisms but quickly lose efficacy, particularly in the presence of organic substrates. Electrophilic biocides such as glutaraldehyde, react more slowly but provide activity for longer durations and at elevated temperatures, such as those found downhole.

Previous microbiological field audits demonstrated that ClO₂ was insufficient for control of contamination in hydraulic fracturing injection fluids due to organism regrowth in frac equipment downstream of treatment. Given this field experience and the number of points where contamination can be introduced in the hydraulic fracturing process, we developed a novel two-part method to evaluate biocide efficacy under conditions applicable to the field. The method was used to screen the efficacy of ClO2, glutaraldehyde alone, and a glutaraldehyde/quaternary ammonium (glut/quat) blend. In the first part, biocides were tested against a single challenge of microorganisms isolated from sample water. All three reduced the level of microorganisms after a single challenge. The second part of the method included re-challenging the water over multiple days to better mimic the unique conditions of a frac site and at the well overall. Results indicated that ClO₂ lost efficacy immediately after the first challenge, while glutaraldehyde and glut/quat provided excellent control over 4–5 successive challenges. This novel screening method could be used to optimize biocide programs based on real-world operating conditions.

Summary Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation, and disposal cost of water. However, because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water/rock interactions, which causes formation damage. Therefore, knowledge of flowback water/rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance. This study focuses on investigating flowback water/rock interactions during hydraulic fracturing in Marcellus Shale. Simple deionized water (DI)/rock interactions and complicated flowback water/rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for 3 weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the coreflooding experimental system for 3 hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway. Surface elemental concentrations, mineralogy, and scanning electron microscope (SEM) images of rock samples were characterized. Ion contents, particle size, total dissolved solids (TDS), and zeta-potential in the water samples were analyzed. After flowback water/rock interaction, the surface of the rock sample shows changes in the compositions and more particle attachment. In produced water, Na, Sr, and Cl concentrations are extremely high because of flowback water contamination. Water parameters show that produced water has the highest precipitation tendency relative to all water samples. Therefore, if flowback water without any treatment is reused in hydraulic fracturing, formation damage is more likely to occur from blockage of pores. Flowback water management is becoming very important due to volumes produced in every hydraulic fracturing operation. Deep well injection is no longer a favorable option because it results in disposal of high volumes of water that cannot be used for other purposes. A second option is the reuse of waste water for fracturing purposes, which reduces freshwater use significantly. However, the impurities present in flowback water may deteriorate the fracturing job and reduce or block the hydraulic fracturing apertures. This study shows that a simple filtration process applied to the flowback water allows for reinjection of the flowback water without further complication to the water/rock interaction, and does not cause significant formation damage in the fractures.