Marcellus Shale Gas Wells Research Articles

Analysis of Compositions of Flowback Water From Marcellus Shale Wells by Utilizing Data Mining Techniques

Abstract Volume and salt concentrations in Marcellus flowback water depend on geology, drilling and completions, stimulation and flowback operations. Recent studies include evaluations of geochemical origins based on the compostition concentrations, flowback sampling analysis and numerical studies. However, an in-depth understanding of chemical compositions as well as the changes of compositions is still needed. In this paper, we will first review the literature related to flowback water in Marcellus shale gas wells to fully understand the chemistry, geochemistry, and physics governing a fracture treatment, shut-in, and flowback. We will then gather all public and in-house flowback data, named as 3-week or 3-month flowback in this work, to build a data set of flowback water compositions. After data screening, we will then analyze this database using four different methods: geographical changes over time, linear regression, clustering, and multi-variable analysis. New understandings such as the magnitude and prevailing trends of concentrations for target constituents as well as the correlations among flowback compositions, the differentiation between early and late-time flowback water were obtained and explained on the basis of geochemistry and physics. This helps production companies and other stakeholders to better manage and reuse waste water for energy production.

Maximum Removal Efficiency of Barium, Strontium, Radium, and Sulfate with Optimum AMD-Marcellus Flowback Mixing Ratios for Beneficial Use in the Northern Appalachian Basin.

Mixing of acid mine drainage (AMD) and hydraulic fracturing flowback fluids (HFFF) could represent an efficient management practice to simultaneously manage two complex energy wastewater streams while reducing freshwater resource consumption. AMD discharges offer generally high sulfate concentrations, especially from the bituminous coal region of Pennsylvania; unconventional Marcellus shale gas wells generally yield HFFF enriched in alkaline earth metals such as Sr and Ba, known to cause scaling issues in oil and gas (O&G) production. Mixing the two waters can precipitate HFFF-Ba and -Sr with AMD-SO4, therefore removing them from solution. Four AMD discharges and HFFF from two unconventional Marcellus shale gas wells were characterized and mixed in batch reactors for 14 days. Ba could be completely removed from solution within 1 day of mixing in the form BaxSr1-xSO4 and no further significant precipitation occurred after 2 days. Total removal efficiencies of Ba + Sr + SO4 and the proportion of Ba and Sr in BaxSr1-xSO4 depended upon the Ba/Sr ratio in the initial HFFF. A geochemical model was calibrated from batch reactor data and used to identify optimum AMD-HFFF mixing ratios that maximize total removal efficiencies (Ba + Sr + SO4) for reuse in O&G development. Increasing Ba/Sr ratios can enhance total removal efficiency but decrease the efficiency of Ra removal. Thus, treatment objectives and intended beneficial reuse need to be identified prior to optimizing the treatment of HFFF with AMD.

Detecting and explaining why aquifers occasionally become degraded near hydraulically fractured shale gas wells

Extensive development of shale gas has generated some concerns about environmental impacts such as the migration of natural gas into water resources. We studied high gas concentrations in waters at a site near Marcellus Shale gas wells to determine the geological explanations and geochemical implications. The local geology may explain why methane has discharged for 7 years into groundwater, a stream, and the atmosphere. Gas may migrate easily near the gas wells in this location where the Marcellus Shale dips significantly, is shallow (∼1 km), and is more fractured. Methane and ethane concentrations in local water wells increased after gas development compared with predrilling concentrations reported in the region. Noble gas and isotopic evidence are consistent with the upward migration of gas from the Marcellus Formation in a free-gas phase. This upflow results in microbially mediated oxidation near the surface. Iron concentrations also increased following the increase of natural gas concentrations in domestic water wells. After several months, both iron and SO42- concentrations dropped. These observations are attributed to iron and SO42- reduction associated with newly elevated concentrations of methane. These temporal trends, as well as data from other areas with reported leaks, document a way to distinguish newly migrated methane from preexisting sources of gas. This study thus documents both geologically risky areas and geochemical signatures of iron and SO42- that could distinguish newly leaked methane from older methane sources in aquifers.

A multi-scale flow model for production performance analysis in shale gas reservoirs with fractal geometry

Shale gas reservoirs can be divided into three regions, including hydraulic fracture regions, stimulating reservoir volume regions (SRV regions), and outer stimulating reservoir volume regions (OSRV regions). Due to the impact of hydraulic fracturing, induced fractures in SRV regions are often irregular. In addition, a precise description of secondary fractures in SRV regions is of critical importance for production analysis and prediction. In this work, the following work is achieved: (1) the complex fracture network in the SRV region is described with fractal theory; (2) a dual inter-porosity flow mechanism with sorption and diffusion behaviors is considered in both SRV and OSRV regions; and (3) both multi-rate and multi-pressure solutions are proposed for history matching based on fractal models and Duhamel convolution theory. Compared with previous numerical and analytic methods, the developed model can provide more accurate dynamic parameter estimates for production analysis in a computationally efficient manner. In this paper, type curves are also established to delineate flow characteristics of the system. It is found that the flow can be classified as six stages, including a bi-linear flow regime, a linear flow regime, a transition flow regime, an inter-porosity flow regime from the matrix to the fractures in the inner region, inter-porosity flow regime from matrix to fractures in the outer region, and a boundary dominant flow regime. The effects of the fracture and matrix properties, fractal parameters, inter-porosity flow coefficients, and sorption characteristics on type curves and production performance were studied in detail. Finally, production performance was analyzed for Marcellus and Fuling shale gas wells, in the U.S.A. and China, respectively.

Elucidating Environmental Fingerprinting Mechanisms of Unconventional Gas Development through Hydrocarbon Analysis.

Hydraulic fracturing is an increasingly common technique for the extraction of natural gas entrapped in shale formations. This technique has been highly criticized due to the possibility of environmental contamination, underscoring the need for method development to identify chemical factors that could be utilized in point-source identification of environmental contamination events. Here, we utilize comprehensive two-dimensional gas chromatography (GC × GC) coupled to high-resolution time-of-flight (HRT) mass spectrometry, which offers a unique instrumental combination allowing for petroleomics hydrocarbon fingerprinting. Four flowback fluids from Marcellus shale gas wells in geographic proximity were analyzed for differentiating factors that could be exploited in environmental forensics investigations of shale gas impacts. Kendrick mass defect (KMD) plots of these flowback fluids illustrated well-to-well differences in heteroatomic substituted hydrocarbons, while GC × GC separations showed variance in cyclic hydrocarbons and polyaromatic hydrocarbons among the four wells. Additionally, generating plots that combine GC × GC separation with KMD established a novel data-rich visualization technique that further differentiated the samples.

Temporal dynamics of halogenated organic compounds in Marcellus Shale flowback

The chemistry of hydraulic fracturing fluids and wastewaters is complex and is known to vary by operator, geologic formation, and fluid age. A time series of hydraulic fracturing fluids, flowback fluids, and produced waters was collected from two adjacent Marcellus Shale gas wells for organic chemical composition analyses using ultrahigh resolution mass spectrometry. Hierarchical clustering was used to compare and extract ions related to different fluid ages and many halogenated organic molecular ions were identified in flowback fluids and early produced waters based on exact mass. Iodinated organic compounds were the dominant halogen class in these clusters and were nearly undetectable in hydraulic fracturing fluid prior to injection. The iodinated ions increased in flowback and remained elevated after ten months of well production. We suggest that these trends are mainly driven by dissolved organic matter reacting with reactive halogen species formed abiotically through oxidizing chemical additives applied to the well and biotically via iodide-oxidizing bacteria. Understanding the implications of these identified halogenated organic compounds will require future investigation in to their structures and environmental fate.

Role of water−rock interaction in the geochemical evolution of Marcellus Shale produced waters

Knowledge of geochemical processes that occur during hydraulic fracturing of shale resources for natural gas recovery can provide insight into in situ mineral precipitation and dissolution reactions that affect shale pore and fracture networks, and ultimately the ability to recover natural gas. Measurement of dissolved chemical species in produced waters, which serve as indicators of water-rock reactions in the reservoir, is one approach for monitoring subsurface geochemistry. However, an ability to distinguish effects of water-rock reactions versus reservoir fluid mixing on chemical concentration and speciation in produced waters requires experimental investigation to better understand natural geochemical tracer behavior.In this study, we explored Li, Sr, and U as geochemical tracers of ion−exchange and mineral dissolution reactions occurring during a series of flow-through laboratory experiments designed to evaluate mineral reactions occurring in shale reacted with hydraulic fracturing fluid (HFF). The experiments, reported in detail in a separate study (Paukert Vankeuren et al., 2017), were designed to emulate shut-in conditions (period after hydraulic fracturing but before production when HFF remains in the reservoir to allow for opening of new fractures for hydrocarbon recovery) for Marcellus Shale undergoing hydraulic fracturing in southwestern Pennsylvania, USA. In the companion study presented here, effluent samples from the core flood experiments were analyzed for changes in Li isotopes (δ7Li), radiogenic Sr isotopes (εSrSW), and U concentration as possible unique geochemical tracers to indicate water-rock reaction. Experimental and reactive transport modeling results demonstrated that the peak of U in experimental effluents is derived from dissolution of U-containing calcite, which may explain the pulse of U observed in produced water collected from hydraulically fractured Marcellus Shale on the first day of flowback. Experimental results also showed that changes in δ7Li values and εSrSW from the flow-through experiments differ from values measured in a time series of produced waters from Marcellus Shale gas wells. Thus, although ion−exchange and mineral dissolution and precipitation reactions result in an observable change in Sr isotope signals in laboratory experiments, this change may not be identifiable in produced waters in the field due to complications associated with geologic heterogeneity and overprinting of other signals such as fluid mixing and transport. While U shows some promise as a tracer of HFF-shale reactions, particularly carbonate dissolution, it may be necessary to continue searching for other tracers present in produced waters to aid in elucidating in situ water-rock reactions of interest.

Marcellus Wells: Ultimate Production Accurately Predicted From Initial Production

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180234, “Marcellus Wells: Ultimate Production Accurately Predicted From Initial Production,” by Frank Male, Michael P. Marder, John Browning, and Svetlana Ikonnikova, The University of Texas at Austin, and Tad Patzek, King Abdullah University of Science and Technology, prepared for the 2016 SPE Low- Permeability Symposium, Denver, 5–6 May. The paper has not been peer reviewed. In this work, the authors perform automatic decline analysis on Marcellus Shale gas wells and predict ultimate recovery for each well. A minimal model is used that captures the basic physics and geometry of the extraction process. A key discovery is that wells can have their estimated ultimate recovery (EUR) predicted early in life with surprising accuracy. Introduction There are many challenges to production in the Marcellus, ranging from the regulatory and price environment to the highly variable responses of rock to hydrofracture treatment. The complete paper’s primary goal is to generate scenarios for future gas production from the Marcellus by use of varying gas prices and other assumptions. The first step in this process is determining technically recoverable reserves, which requires deciding how much each well will produce over its lifetime. To do this, the authors use recovery- factor curves that describe total recovery in terms of two parameters: total gas in the stimulated reservoir volume (SRV) and the characteristic time to boundary-dominated flow (BDF). Most wells produce following these recovery curves, but not all. Upon examining production data, the authors found that several hundred wells have very slow decline for the first several years, slower than the production decline expected from linear flow. In discussions with multiple operators, the authors found that this is attributable to production choking. There have been several analytical and numerical models developed to predict production from horizontal, hydrofractured shale gas wells. This paper uses the scaling model developed by Patzek et al. (2013) to build recovery-factor curves to describe production for Marcellus wells. Fitting production of 5,275 wells, 404 wells are found that experience boundary-dominated flow. Among these wells, 175 are horizontally drilled. The original gas inside the SRV for these wells is compared with initial production, and a very high correlation is found. This correlation is used to estimate gas production for the remaining wells. Among the entire set of wells, an average EUR of 3.6 Bscf is estimated, with the middle 60% having EURs between 6.6 and 1.8 Bscf. The model for flow to the wellbore is detailed in the complete paper.

Low Oil Prices Increase Value of Big Data in Fracturing

Shale operators are searching for insights to get the most value from hydraulic fracturing at a time of low oil prices. Discovering these insights requires a closer analysis of well data in order to make more cost-effective field development decisions. “We are often working with short-term data and need to find a way to turn that into long-term well performance,” said Craig Cipolla, a senior completions engineering adviser at Hess, who spoke at the recent 2015 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas. Companies such as Hess and Noble Energy have invested in drilling test wells with hopes of recuperating costs by optimizing future treatments. “These [ studies] require significant resources and manpower, and we can only do a limited number of these, if any at all in some cases,” Cipolla said. Southwestern Energy has taken a different approach. It takes less expensive measurements and feeds them into models that are custom-built to be more predictive for the given play. The company already has made cost-saving adjustments to its operations based on the results of its models. Each approach aims to make fracturing more profitable, whether by improving recovery or finding ways to achieve the same level of production at a lower cost. Productivity Index Southwestern has created long-term flow simulations of its Marcellus Shale gas wells from what reservoir engineering manager and technical lead Michael Lynch called “nearly free data.” His team learned from simulations that proppant loading was one of the most important variables for productivity. Wells with high proppant loading overperformed by 40% compared with the company’s 30-well production average in the Marcellus, and those with low proppant loading underperformed by 20%. The team also found that close spacing between fracture stages in its Marcellus assets did not significantly drive productivity. So to save money, the company has been using a wider spacing of up to 500 ft and more proppant per stage. The main measurement that Lynch and his colleagues use to populate flow simulations is the initial productivity index, which is determined by shutting the well in and slowly opening the choke over the course of 2 to 3 days after breaking through to gas.

Trace metal distribution and mobility in drill cuttings and produced waters from Marcellus Shale gas extraction: Uranium, arsenic, barium

Development of unconventional shale gas wells can generate significant quantities of drilling waste, including trace metal-rich black shale from the lateral portion of the drillhole. We carried out sequential extractions on 15 samples of dry-drilled cuttings and core material from the gas-producing Middle Devonian Marcellus Shale and surrounding units to identify the host phases and evaluate the mobility of selected trace elements during cuttings disposal. Maximum whole rock concentrations of uranium (U), arsenic (As), and barium (Ba) were 47, 90, and 3333mgkg−1, respectively. Sequential chemical extractions suggest that although silicate minerals are the primary host for U, as much as 20% can be present in carbonate minerals. Up to 74% of the Ba in shale was extracted from exchangeable sites in the shale, while As is primarily associated with organic matter and sulfide minerals that could be mobilized by oxidation. For comparison, U and As concentrations were also measured in 43 produced water samples returned from Marcellus Shale gas wells. Low U concentrations in produced water (<0.084–3.26μgL−1) are consistent with low-oxygen conditions in the wellbore, in which U would be in its reduced, immobile form. Arsenic was below detection in all produced water samples, which is also consistent with reducing conditions in the wellbore minimizing oxidation of As-bearing sulfide minerals.Geochemical modeling to determine mobility under surface storage and disposal conditions indicates that oxidation and/or dissolution of U-bearing minerals in drill cuttings would likely be followed by immobilization of U in secondary minerals such as schoepite, uranophane, and soddyite, or uraninite as conditions become more reducing. Oxidative dissolution of arsenic containing sulfides could release soluble As in arsenate form under oxic acidic conditions. The degree to which the As is subsequently immobilized depends on the redox conditions along the landfill flow path. The results suggest that proper management of drill cuttings can minimize mobilization of these metals by monitoring and controlling Eh, pH and dissolved constituents in landfill leachates.

Geochemical and isotopic evolution of water produced from Middle Devonian Marcellus shale gas wells, Appalachian basin, Pennsylvania

The number of Marcellus Shale gas wells drilled in the Appalachian basin has increased rapidly over the past decade, leading to increased interest in the highly saline water produced with the natural gas which must be recycled, treated, or injected into deep disposal wells. New geochemical and isotopic analyses of produced water for 3 time-series and 13 grab samples from Marcellus Shale gas wells in southwest and north central Pennsylvania (PA) are used to address the origin of the water and solutes produced over the long term (>12 months). The question of whether the produced water originated within the Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of and activity. These parameters indicate that the water originated in the Marcellus Shale, and can be more broadly used to trace water of Marcellus Shale origin. During the first 1–2 weeks of production, rapid increases in salinity and positive shifts in values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The values and relationships between Na, Cl, and Br provide evidence that the water produced after compositional stabilization is natural formation water, the salinity for which originated primarily from evaporatively concentrated paleoseawater. The rapid transition from injected water to chemically and isotopically distinct water while of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

Assessing changes in gas migration pathways at a hydraulic fracturing site: Example from Greene County, Pennsylvania, USA

Natural gas produced from a zone of thin Upper Devonian/Lower Mississippian sands approximately 1200m above the hydraulically fractured Middle Devonian Marcellus Shale interval was monitored for evidence of gas migration. Gas samples were collected from seven vertical Upper Devonian/Lower Mississippian gas wells and two vertical Marcellus Shale gas wells 2months prior to-, during-, and 14months after the hydraulic fracturing of six horizontal Marcellus Shale gas wells at the study site. The isotopic and molecular compositions of gas from the two producing zones were distinct and remained so during the entire monitoring period. Over the time of monitoring, the molecular/isotopic signatures of gas from the Upper Devonian/Lower Mississippian field did not show any evidence of contamination from deeper Marcellus Shale gas that might have migrated upward from the hydraulically fractured interval. Our results indicate no hydrologic connectivity between the fractured interval and formations 1200m above, which means that contamination of even shallower drinking water aquifers (∼2200m above fractured interval) is unlikely at this study site. While localized consideration for geology and site development practices are extremely important, the monitoring methods used in this study are applicable when trying to understand and quantify natural gas mixing and migration trends.

Temporal Changes in Microbial Ecology and Geochemistry in Produced Water from Hydraulically Fractured Marcellus Shale Gas Wells

Microorganisms play several important roles in unconventional gas recovery, from biodegradation of hydrocarbons to souring of wells and corrosion of equipment. During and after the hydraulic fracturing process, microorganisms are subjected to harsh physicochemical conditions within the kilometer-deep hydrocarbon-bearing shale, including high pressures, elevated temperatures, exposure to chemical additives and biocides, and brine-level salinities. A portion of the injected fluid returns to the surface and may be reused in other fracturing operations, a process that can enrich for certain taxa. This study tracked microbial community dynamics using pyrotag sequencing of 16S rRNA genes in water samples from three hydraulically fractured Marcellus shale wells in Pennsylvania, USA over a 328-day period. There was a reduction in microbial richness and diversity after fracturing, with the lowest diversity at 49 days. Thirty-one taxa dominated injected, flowback, and produced water communities, which took on distinct signatures as injected carbon and electron acceptors were attenuated within the shale. The majority (>90%) of the community in flowback and produced fluids was related to halotolerant bacteria associated with fermentation, hydrocarbon oxidation, and sulfur-cycling metabolisms, including heterotrophic genera Halolactibacillus, Vibrio, Marinobacter, Halanaerobium, and Halomonas, and autotrophs belonging to Arcobacter. Sequences related to halotolerant methanogenic genera Methanohalophilus and Methanolobus were detected at low abundance (<2%) in produced waters several months after hydraulic fracturing. Five taxa were strong indicators of later produced fluids. These results provide insight into the temporal trajectory of subsurface microbial communities after "fracking" and have important implications for the enrichment of microbes potentially detrimental to well infrastructure and natural gas fouling during this process.

The strontium isotopic evolution of Marcellus Formation produced waters, southwestern Pennsylvania

The production of natural gas and natural gas liquids from unconventional tight shale formations involves hydraulic fracturing and subsequent removal of fluids co-produced with the gas. The chemistry of the returning fluid reflects the original composition of the injection water, mobilized constituents in the shale formation, and co-mingled formation waters liberated by hydraulic fracturing. Produced water from unconventional gas wells tapping the Middle Devonian Marcellus Formation is characterized by high total dissolved solids (TDS), including very high strontium concentrations. In this study, the strontium isotope composition (87Sr/86Sr) was measured in produced waters from four horizontally drilled, hydraulically fractured Marcellus shale gas wells in southwestern Pennsylvania, sampled from the first day after commencement of flowback to as much as 27 months later. The 87Sr/86Sr of the waters tended to change rapidly over the first few days of water return, and then approached (but did not reach) a constant range of values from 0.7113 to 0.7114, which appears to be characteristic of this part of the Marcellus play. In contrast, the concentration of Sr rose more slowly and appeared to hit a steady state value (up to 3000mg/L) by the end of the first year. Taken together with results from earlier work, these data suggest mixing between injected frac fluid and high-TDS formation water, highly enriched in Sr, and isotopically relatively uniform throughout the Marcellus shale gas play. This brine could exist within porous lenses of organic matter in the shale, in pre-existing fractures within the shale, and/or originate from fluids that migrated from adjacent formations at some point during the post-depositional history of the basin.

Geochemical evolution of produced waters from hydraulic fracturing of the Marcellus Shale, northern Appalachian Basin: A multivariate compositional data analysis approach

Multivariate compositional data analysis methods were used to investigate geochemical data for water injected during hydraulic fracturing and for water produced from 19 Marcellus Shale gas wells in the northern Appalachian Basin. The data were originally published as part of an industry report. The analysis was adapted to consider the compositional nature of the data and avoid potentially spurious correlations present in raw concentration data through the application of log-ratio transformations. Techniques such as robust variation arrays, robust principal component analysis, and relative variation plots were applied to log-ratio transformed data. Results from this battery of multivariate tools indicate that two primary processes affect the chemical evolution of the water returned to the surface during the first 90days of production: mixing of injected water with formation brines of evaporated paleoseawater origin and injection of sulfate-rich water during hydraulic fracturing may stimulate sulfate reduction at some sites. Spatial variability in sulfate/alkalinity ratios appears to influence variations in geochemical controls on strontium versus barium with elevated proportions of strontium being found in more bicarbonate-poor environments, while barium is a larger proportion in sulfate-poor areas. Comparison of results using a log-ratio approach versus the more common analysis of concentration data reveals both similarities and some marked differences in the resulting interpretations. Results from this work are important in terms of both demonstrating methods to avoid mathematical inconsistencies from using raw brine geochemical data and to further investigate the geochemical controls on produced waters generated from shale gas reservoirs.

Spatial and Temporal Correlation of Water Quality Parameters of Produced Waters from Devonian-Age Shale following Hydraulic Fracturing

The exponential increase in fossil energy production from Devonian-age shale in the Northeastern United States has highlighted the management challenges for produced waters from hydraulically fractured wells. Confounding these challenges is a scant availability of critical water quality parameters for this wastewater. Chemical analyses of 160 flowback and produced water samples collected from hydraulically fractured Marcellus Shale gas wells in Pennsylvania were correlated with spatial and temporal information to reveal underlying trends. Chloride was used as a reference for the comparison as its concentration varies with time of contact with the shale. Most major cations (i.e., Ca, Mg, Sr) were well-correlated with chloride concentration while barium exhibited strong influence of geographic location (i.e., higher levels in the northeast than in southwest). Comparisons against brines from adjacent formations provide insight into the origin of salinity in produced waters from Marcellus Shale. Major cations exhibited variations that cannot be explained by simple dilution of existing formation brine with the fracturing fluid, especially during the early flowback water production when the composition of the fracturing fluid and solid-liquid interactions influence the quality of the produced water. Water quality analysis in this study may help guide water management strategies for development of unconventional gas resources.