Optimizing hydrocarbon production and waste management from unconventional oil and gas extraction requires an understanding of the fluid-rock chemical interactions. These reactions can affect flow ...pathways within fractured shale and produced water chemistry. Knowledge of these chemical reactions also provides valuable information for planning wastewater treatment strategies. This study focused on characterizing reservoir reactions through analysis of produced water chemistry from the Marcellus Shale Energy and Environmental Laboratory field site in Morgantown, WV, USA. Analysis of fracturing fluids, time-series produced waters (PW) over 16 months of operation of two hydraulically fractured gas wells, and shale rocks from the same well for metal concentrations and multiple isotope signatures (δ2H and δ18O of water, δ7Li, δ11B, 87Sr/86Sr) showed that the chemical and isotopic composition of early (<10 days) PW samples record water-rock interactions during the fracturing period. Acidic dissolution of carbonate minerals was evidenced by the increase in TOC, B/Na, Sr/Na, Ca/Na, and the decrease in 87Sr/86Sr in PW returning in the first few days toward the 87Sr/86Sr signature of carbonate cement. The enrichment of 6Li in these early (e.g., day 1) PW samples is most likely a result of desorption of Li from clays and organic matter due to the injection of fracturing fluid. Redox-active trace elements appear to be controlled by oxidation-reduction reactions and potentially reactions involving wellbore steel. Overall, PW chemistry is primarily controlled by mixing between early PW with local in-situ formation water however certain geochemical reactions (e.g., carbonate cement dissolution and desorption of 6Li from clays and organic matter) can be inferred from PW composition monitored immediately over the first ten days of water return.
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•Sr/Na, Ca/Na, B/Na, and 87Sr/86Sr of early produced water (PW) reflects carbonate dissolution.•Elevated trace metal contents suggest oxidation of sulfide minerals by fracturing chemicals.•6Li enriched early PW is due to desorption of 6Li from clays and organic matter.•Change in PW chemistry is a result of mixing between fracturing fluid and local formation water.•Fractured reservoir under oxidizing condition during fracturing period moves toward reducing environment during production.
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GEOZS, IJS, IMTLJ, KILJ, KISLJ, NLZOH, NUK, OILJ, PNG, SAZU, SBCE, SBJE, UILJ, UL, UM, UPCLJ, UPUK, ZAGLJ, ZRSKP
Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To investigate ...reactions during the shut-in period of hydraulic fracturing, experiments were conducted flowing different HFFs through fractured Marcellus shale cores at reservoir temperature and pressure (66 °C, 20 MPa) for one week. Results indicate HFFs with hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing effective fracture volume (fracture volume + near-fracture matrix porosity) by 56–65%. HFFs with reused produced water composition cause precipitation of secondary minerals, particularly barite, decreasing effective fracture volume by 1–3%. Barite precipitation occurs despite the presence of antiscalants in experiments with and without shale contact and is driven in part by addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the significant amount of barite scale formed by HFFs with reused produced water composition could reduce effective fracture volume. Further study is required to extrapolate experimental results to reservoir-scale and to explore the effect that mineral changes from HFF interaction with shale might have on gas production.
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The first ambient measurements using nitrate ion based Chemical Ionization with the Atmospheric Pressure interface Time-Of-Flight mass spectrometer (CI-APi-TOF) for sulphuric acid and neutral cluster ...detection are presented. We have found CI-APi-TOF a highly stable and sensitive tool for molecular sulphuric acid detection. The lowest limit of detection for sulphuric acid was determined to be 3.6 × 104 molecules cm−3 for 15 min averaging. Signals from sulphuric acid clusters up to tetramer containing ammonia were also obtained but these were found to result from naturally charged clusters formed by ion induced clustering in the atmosphere during nucleation. Opposite to earlier studies with cluster mass spectrometers, we had no indication of neutral clusters. The reason is either less efficient charging of clusters in comparison to molecular sulphuric acid, or the low concentration of neutral clusters at our measurement site during these particular nucleation events. We show that utilizing high resolution mass spectrometry is crucial in separating the weak sulfuric acid cluster signal from other compounds.
One of the primary drivers of global warming is the exponential increase in CO2 emissions. According to IPCC, if the CO2 emissions continue to increase at the current rate, global warming is likely ...to increase by 1.5 °C, above pre-industrial levels, between the years 2030 and 2052. Efficient and sustainable geologic CO2 sequestration (GCS) offers one plausible solution for reducing CO2 levels. The impermeable shale formations have traditionally served as good seals for reservoirs in which CO2 has been injected for GCS. The rapid development of subsurface organic-rich shales for hydrocarbon recovery has opened up the possibility of utilizing these hydraulically fractured shale reservoirs as potential target reservoirs for GCS. However, to evaluate the GCS potential of different types of shales, we need to better understand the geochemical reactions at CO2–fluid–shale interfaces and how they affect the flow and CO2 storage permanence. In this review, we discuss the current state of knowledge on the interactions of CO2 with shale fluids, minerals, and organic matter, and the impact of parameters such as pressure, temperature, and moisture content on these interactions. We also discuss the potential of using CO2 as an alternate fracturing fluid, its role in enhanced shale gas recovery, and different geochemical tracers to identify whether CO2 or brine migration occurred along a particular fluid transport pathway. Additionally, this review highlights the need for future studies to focus on determining (1) the contribution of CO2 solubility and the impact of formation water chemistry on GCS, (2) the rates of dissolution/precipitation and sorption reactions, (3) the role of mineralogical and structural heterogeneities in shale, (4) differences in reaction mechanisms/rates between gaseous CO2vs. brine mixed CO2vs. supercritical CO2, (5) the use of CO2 as a fracturing fluid and its proppant carrying capacity and (6) the role of CO2 in enhanced hydrocarbon recovery.
The friction and wear performance of 0–2wt.% graphene oxide (GO) dispersions in water were studied on diamond-like carbon vs. stainless steel contact by a pin-on-disk tribometer. The wear surfaces ...were characterized using contact profilometry, X-ray spectroscopy, optical microscopy, scanning electron microscopy, energy dispersive spectroscopy, and Raman spectroscopy. The friction coefficient decreased 57% (from 0.14 to 0.06) compared to pure water, when 1wt.% of GO and 10N normal load were applied. A minimum wear for the counter ball was detected when pure water was used. GO additives reduced the corrosive effect on the counter ball. The main tribological mechanism of GO additives in water was observed to be the embedding of GO sheets on the counter ball surface forming a lubricating layer and binding water molecules into the contact.
•Graphene oxide improved water lubrication in DLC-stainless-steel high load contact.•The friction coefficient decreased 57% compared to pure water.•GO embedded on steel counter surfaces.
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GEOZS, IJS, IMTLJ, KILJ, KISLJ, NUK, OILJ, PNG, SAZU, SBCE, SBJE, UL, UM, UPCLJ, UPUK
Carbon dioxide sequestration in deep saline and depleted oil geologic formations is feasible and promising; however, possible CO2 or CO2-saturated brine leakage to overlying aquifers may pose ...environmental and health impacts. The purpose of this study was to experimentally define a range of concentrations that can be used as the trace element source term for reservoirs and leakage pathways in risk simulations. Storage source terms for trace metals are needed to evaluate the impact of brines leaking into overlying drinking water aquifers. The trace metal release was measured from cements and sandstones, shales, carbonates, evaporites, and basalts from the Frio, In Salah, Illinois Basin, Decatur, Lower Tuscaloosa, Weyburn-Midale, Bass Islands, and Grand Ronde carbon sequestration geologic formations. Trace metal dissolution was tracked by measuring solution concentrations over time under conditions (e.g., pressures, temperatures, and initial brine compositions) specific to the sequestration projects. Existing metrics for maximum contaminant levels (MCLs) for drinking water as defined by the U.S. Environmental Protection Agency (U.S. EPA) were used to categorize the relative significance of metal concentration changes in storage environments because of the presence of CO2. Results indicate that Cr and Pb released from sandstone reservoir and shale cap rocks exceed the MCLs by an order of magnitude, while Cd and Cu were at or below drinking water thresholds. In carbonate reservoirs As exceeds the MCLs by an order of magnitude, while Cd, Cu, and Pb were at or below drinking water standards. Results from this study can be used as a reasonable estimate of the trace element source term for reservoirs and leakage pathways in risk simulations to further evaluate the impact of leakage on groundwater quality.
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Towards commissioning the new IGISOL-4 facility Moore, I.D.; Eronen, T.; Gorelov, D. ...
Nuclear instruments & methods in physics research. Section B, Beam interactions with materials and atoms,
12/2013, Volume:
317
Journal Article
Peer reviewed
•The commissioning of the new IGISOL-4 facility.•First successful implantation of neutron-deficient Pd.•In-jet laser ionization of copper demonstrated.
The Ion Guide Isotope Separator On-Line ...facility at the Accelerator Laboratory of the University of Jyväskylä is currently being re-commissioned as IGISOL-4 in a new experimental hall. Access to intense beams of protons and deuterons from a new MCC30/15 cyclotron, with continued possibility to deliver heavy-ion beams from the K=130MeV cyclotron, offers extensive opportunities for long periods of fundamental experimental research, developments and applications. A new layout of beam lines with a considerable increase in floor space offers new modes of operation at the facility, as well as a possibility to incorporate more complex detector setups. We present a general overview of IGISOL-4 and the current status of several projects, including the collinear laser spectroscopy station and the future of neutron-induced fission. Recent milestones from the first commissioning experiments are presented.
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GEOZS, IJS, IMTLJ, KILJ, KISLJ, NUK, OILJ, PNG, SAZU, SBCE, SBJE, UL, UM, UPCLJ, UPUK
•Addition of HCl to sample matrix improves detection of Fe(III) on IC.•Addition of MetPac CC-1 chelating column improves recovery of transition metals in samples with high calcium.•Gradient elution ...of PDCA eluent can improve peak separation and peak symmetry.•Developed IC quantification results were comparable to reported values from certified materials, coal mine drainage and produced waters.
This study outlines the development and subsequent validation of a method using chelation ion chromatography (CIC) pretreatment followed by traditional ion chromatography (IC) and post column UV/vis detection to measure transition metals in fossil fuel wastewaters, such as oil & gas (O&G) brines and coal mine drainage (CMD) waters. Measurement of transition metals is often an important characterization step in the research of environmental and energy systems. IC represents one way to measure these metals with the advantages of being versatile, simple and relatively low cost compared to other analytical methods. However, high concentrations of alkali and alkaline earth metals present in fossil fuel wastewaters will decrease IC detectability of transition metals in these waters. In this study, a CIC method was developed for the analysis of transition metal ions (Fe3+, Cu2+, Ni2+, Zn2+, Co2+, Mn2+, and Fe2+) in fossil fuel associated wastewaters such as Appalachian CMD and O&G wastewaters from the Permian and Bakken shale basins in the United States. CIC system incorporated an on-line chelator column (e.g., the MetPac CC-1) with high selectivity for transition metals over alkali and alkaline earth metals for salt matrix removal prior to transition metal separation and detection. Additional method developments also included acidifying all samples to 2% v/v HCl and using gradient elution rather than isocratic. The recoverability of transition metals in simple salt solutions commonly found in CMD and brine samples (e.g. NaCl, Na2SO4, CaCl2) using CIC was evaluated and compared to that using traditional IC. Our results found that the CIC system significantly improved transition metal recoveries for samples in 10,000 mg/L CaCl2 matrix, reaching 87%-108% recovery for all analytes, as opposed to 2–323% recovery in traditional IC. The limits of detection in this study achieved 10.09–161.2 μg/L, comparable to reported values in similar IC studies. The developed method was also verified with certified water samples, resulting in 89%–111% recoveries in samples with higher analyte concentrations (i.e. >4x the LoDs). The developed method achieved 87%–112% recoveries for most analytes in CMD samples and 72%–138% recoveries for Bakken shale samples, relative to ICP-MS values. Overall, the current IC method can be a very good screening tool for fast and cheap analysis for transition metals at mg/L level, to facilitate selection of samples for more detailed ICP-MS analysis.
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GEOZS, IJS, IMTLJ, KILJ, KISLJ, NLZOH, NUK, OILJ, PNG, SAZU, SBCE, SBJE, UILJ, UL, UM, UPCLJ, UPUK, ZAGLJ, ZRSKP
Natural gas extraction from the Appalachian Basin has significantly increased in the past decade. The push to properly dispose, reuse, or recycle the large amounts of produced fluids associated with ...hydraulic fracturing operations and design better fracturing fluids has necessitated a better understanding of the subsurface chemical reactions taking place during hydrocarbon extraction. Using autoclave reactors, this study mimics the conditions of deep subsurface shale reservoirs to observe the chemical evolution of fluids during the shut-in phase of hydraulic fracturing (HF), a period when hydraulic fracturing fluids (HFFs) remain confined in the reservoir. The experiment was conducted by combining a synthetic hydraulic fracturing fluid and powdered shale core samples in high temperature/pressure static autoclave reactors for 14 days. Shale samples of varying maturity and mineralogy were used to assess the effect of these variations on the proliferation of inorganic ions and low molecular weight volatile organic compounds (VOCs), mainly benzene, toluene, ethylbenzene and xylenes (BTEX) and monosubstituted carboxylic acids. Ion chromatography results indicate that the relative abundance of ions present was similar to that of water produced from HF operations in the Marcellus Shale basin. There was an increase of SO
4
2−
and PO
4
3−
and a decrease in Ba
2+
upon fluid-shale reaction. Major ionic shifts indicate calcite dissolution in two of the fluid-shale reactions and barite precipitation in all fluid-shale reactions. Toluene, xylene, and carboxylic acids were produced in the shale-free control experiment. The most substantial increase in BTEX analytes was observed in reactions with low maturity shale, while the high maturity shale reaction produced no measurable BTEX compounds. Total organic carbon decreased in all reactions including fracturing fluid and shale, suggesting adsorption onto the organic matter (OM) matrix. The results from this study highlight that both the nature of OM and mineralogy play a key role in determining the fate of inorganic and organic compounds during fluid-shale interactions in the subsurface shale reservoir. Overall this study aims to contribute to the growing understanding of complex chemical interactions that occur in the shale reservoirs during HF, which is vital for determining the potential environmental impacts of HF and designing more efficient HFF and produced water recycling techniques for environmentally conscious natural gas production.
Maturity and mineralogy of shale significantly controls dissolution/precipitation reactions and release of organic contaminants during hydraulic fracturing.
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•Mineral scale can impact production during unconventional reservoir development.•Agreement observed between experimental, field, and reaction path modeling results.•Predictive ...geochemical models identified reservoir and wellbore mineral reactions.•Model predictions can be used to design mineral scale prevention treatments.
Mineral precipitation within hydraulically fractured shale may affect fluid flow pathways and impact long-term hydrocarbon production. The ability to predict geochemical reactions causing problematic mineral precipitation will lead to active reservoir management strategies for improving production. Using the Marcellus Shale as a case study, laboratory experiments and reaction path modeling were applied to determine which reactions occur during hydraulic fracturing, shut-in, flowback, and production timeframes. Experimental results indicate that contact between fracturing fluid and shale will result in dissolution of primary minerals (carbonates, quartz, feldspars, kaolinite, chlorite, pyrite) and secondary mineral precipitation over time periods of less than one week. Precipitation of secondary carbonates, barite, iron oxides, feldspars, amorphous silica and clay is likely to occur within the reservoir during shut in and early flowback due to mixing between fracturing fluid and reservoir brine as based on modeling saturation indices using experimental fluid data. Reaction path modeling corroborates the dissolution and precipitation reactions observed experimentally. Comparison of the results to injected and produced waters from a Marcellus Shale well pad in Greene County, PA, USA, shows that the mineral reactions occur during the hydraulic fracturing, shut in, and early flowback periods. The results presented here demonstrate the value in applying experimental approaches to identify mineral precipitation/dissolution reactions that may significantly impact reservoir performance. The good agreement between geochemical models and experimental results provides confidence that numerical models can be applied to screen the potential fluid-mineral and fluid-mixing reactions in unconventional reservoirs that result in undesired mineral scale precipitation.
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GEOZS, IJS, IMTLJ, KILJ, KISLJ, NLZOH, NUK, OILJ, PNG, SAZU, SBCE, SBJE, UILJ, UL, UM, UPCLJ, UPUK, ZAGLJ, ZRSKP
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