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An integrated approach was taken to utilize geochemistry information extracted from cuttings and produced oil samples to monitor vertical drainage between stacked reservoirs as well as to optimize well density in multi-bench cube development in the Montney play.Oil extracts from cuttings were profiled using high-resolution multi-dimensional gas chromatography (GCXGC) identifying 2,000+ compounds. Key reservoir properties such as indicators of oil saturation and matrix permeability were calculated using oil signatures extracted from cuttings. Subsequently produced oil were profiled using the same GCXGC method. Drainage frac height (DFH) and quantitative vertical production allocation by zone was conducted by building a geochemistry-based model and correlating the produced oils back to their contributing intervals represented by the cuttings.In this Montney case study, two neighboring pads with different cube designs were investigated. Pad 1 is a 12-well pad with 4 target benches and a stacked wellbore placement pattern, whereas Pad 2 is a 6-well pad with 3 target benches and a staggered wellbore placement pattern. Cuttings and produced oil samples were collected from both pads at every development bench, and geochemical DFHs and production allocations were estimated. The geochemical index from cuttings were in-line with the porosity log and wetness balance log collected while drilling. Based on the geochemical production allocation, both Pad 1 and Pad 2 showed vertical fracture growth was not constrained within the target bench. As a result, more vertical overlaps were detected which leads to a more severe vertical communication problem observed on Pad 1 where wellbores were vertically stacked above or below each other.In this study, the geochemical fingerprinting result was used to calibrate microseismic events. The quantitative production allocation allowed us to filter out any non-effective events and realistically capture the productive stimulated rock volume for optimizing well spacing and landing depth. Last but not least, the geochemical production allocation was successfully integrated with other reservoir surveillance data such as interference well testing.

This study integrates microseismic hydraulic fracture mapping with geochemical production profiling to understand the interaction between mechanical stratigraphy, fracture geometry, and effective drainage for wells landed in different benches of the STACK play in Oklahoma. Microseismic monitoring was used to map the extents of the hydraulic fracture system contacted during stimulation, while high resolution geochemical analysis or ‘fingerprinting’ was used to assess how different formations in the reservoir were draining. Microseismicity showed that hydraulic fracture growth from an Upper Meramec well rapidly cover the entire Meramec interval with some growth downward into the Woodford. Conversely, microseismicity initiating from a Woodford well clustered in that layer and grew upward into the Lower Meramec with time. Geochemical profiling closely matched the microseismic depth distributions for the associated well landing zones. Similar to the microseismic hydraulic heights from both Upper and Lower Meramec wells consistently produced from the entire Meramec, with additional recovery from the Woodford. Woodford landed wells produced Woodford oil with some production also coming from the Lower Meramec, also consistent with the microseismic depths. These production profiling trends were found to be very consistent across multiple sets of wells drilled into the same target formations. Integrating mapping of hydraulic fracture growth with geochemical assessment of the effective drainage within the hydraulically contacted zones provides unique insights into the reservoir contact and drainage. Understanding the mechanical stratigraphic controls on hydraulic fracture height growth relative to the reservoir drainage is key to informed decisions on wine-rack configurations for optimal reservoir drainage.

Reconstruction of the diagenetic evolution of reservoirs is one of the most significant tasks in oil and gas exploration and development. Assessing the accurate timing of diagenetic events is critical to better understand the process of reservoir evolution, but the isotope dating of diagenetic events is technically challenging. This paper uses three case studies in the sedimentary basins in China to demonstrate the promising application of recently developed LA-(MC)-ICPMS in-situ U-Pb geochronology. Our results show that the new U-Pb dating method provides a reliable and efficient chronological approach to determine the absolute ages of diagenetic events. For example, the U-Pb age data of the Cambrian carbonate reservoir in the Tarim Basin reveals three diagenetic events at 526±14, 515±21, and 481±4.6 Ma, respectively. It is worth noting that microscopic observations are particularly important for improving the success rate of U-Pb dating. In addition, the recent progress and future prospects in the in-situ U-Pb dating method are also discussed in this study, suggesting that this method is currently hindered by the lack of international carbonate standards for data correction.

In this study, we present a method to monitor inter-well communication and drainage frac height through time based on unique geochemical fingerprint data collected from oils. This method does not require expensive instruments or interfere with production and its results were integrated with independent pressure gauge and well performance data to enable data-driven decisions on well spacing, well stacking and completion designs with different subsurface configurations. Produced oils of 9 horizontal wells over ~20 months and cuttings samples from the vertical section of an adjacent well were collected in the study area located in Midland Basin, Texas. The 9 producing wells were in two DSUs with two different well configurations, one drilled with two landing targets while the other with three. Thousands of chemical compounds that are naturally occurring in the produced oils and oils extracted from the cuttings, were profiled and interpreted geochemically. Drainage frac heights and quantitative production allocation by zone were conducted by building a geochemistry-based model correlating the produced oils back to their contributing intervals represented by the cuttings samples and their vertical depths. The probability of inter-well fluid communication between each of the well pairs was calculated based on the similarity of the geochemical fingerprints in the produced oils of the corresponding wells. Our data showed that the three targets scenario generated significantly more overlapped drainage vertically and vertical well communication than the two targets scenario. Up to ~60% of the drainage frac height of the Middle well in the three targets scenario overlapped with the Upper wells and ~20% overlapped with the Lower wells, while in the two targets scenario the Upper and Lower wells only showed ~40% overlapped vertical drainage. The lateral geochemical similarity index (SIL) calculation showed correlation between higher SIL (stronger lateral well communication) and poorer oil production rates, indicating well communication could impair well performance. The data also showed significant variation of lateral communication through time which was strongest about a month into production and then reduced through time. Even with the same spacing and completion design, the Upper wells showed higher SIL (i.e., more communication) than the Lower wells, indicating geology and completion design parameters such as sand and fluid volume, and clusters should be taken into consideration for future planning. Independent pressure data also supported these observations, providing critical evidence for optimizing the stacking, spacing, and completion designs of future development wells. Geochemical data in the produced oils carry significant information to reveal subsurface fluid flow and well interaction through time. It provides actionable data to support various field development decisions such as well spacing, well stacking, landing target optimization, well sequencing, and completion designs.

The feasibility of storing carbon dioxide (CO2) in geologic formations as a means to mitigate global climate change is being evaluated around the globe. One option that has received limited attention is to store CO2 in shale formations that are currently productive unconventional shale gas plays. While CO2 trapping mechanisms in saline aquifers are primarily structural, capillary, solubility, and mineral trapping, the mechanisms are fundamentally different in gas shales, and CO2 adsorption onto organic materials and clay minerals plays a key role. Shale gas formations have a high content of organic matter that may store significant amounts of adsorbed natural gas, ranging from 20% to 80% of original-gas-in-place (OGIP). Laboratory and theoretical calculations suggest that CO2 is adsorbed preferentially over methane (CH4) onto the organics and could displace the methane (with up to a 5:1 ratio by molecule). This mechanism could be the basis of a new method of carbon capture, utilization, and storage (CCUS) that stores the CO2 in gas shales with the potential added benefit of enhanced gas recovery (EGR). This investigation evaluates the hypothesis of CO2 storage with EGR using reservoir modeling of the Devonian and Mississippian New Albany Shale gas play in the Illinois Basin, USA. The shale was evaluated in terms of CO2 injectivity, storage capacity, and effectiveness, as well as the impact of CO2 injection on methane recovery. The modeling technique employs a dual-porosity, dual-permeability approach, incorporating horizontal wells with multi-stage hydraulic fractures, Darcian and diffusive flow, gas sorption/desorption, hysteresis effects, and CO2 dissolution. Our simulation results demonstrate that CO2 storage in the New Albany Shale is feasible. Approximately 4 × 104 metric tonnes of CO2 could be injected through one horizontal well (having four hydraulic fracture stages) within 5 years with minimal CO2 breakthrough (less than 1% of the injected CO2). Over 95% of the injected CO2 is effectively sequestered instantaneously with gas adsorption being the dominate storage mechanism. Residual trapping and solubility trapping sequester only ∼0.4% and ∼1.1%, respectively, of the injected CO2. Sensitivity tests were conducted on several key geological parameters (total organic carbon content, natural fracture conductivity, and matrix permeability) and engineering parameters (stimulated rock volume and hydraulic fracture conductivity). Among the evaluated factors, CO2 storage effectiveness appears to be dominated by changes in the stimulated rock volume and the total organic carbon content. Incremental CH4 recovery from CO2 injection was not substantial (∼1%) in either the CO2 flood or the huff-n-puff scenario under the simulated reservoir conditions and well designs, possibly because the unstimulated tight shale rock between the CO2 injector and CH4 producer impeded effective mass and pressure communication, which prerequisites for successful EGR. However, in the huff-n-puff scenario, with a similar amount of CH4 produced, a noticeable amount of CO2 was sequestered simultaneously. Assumptions, approximations, and compromises were made in the current modeling work because of gaps in the current knowledge base about various aspects of the gas shale reservoirs. These limitations are discussed in an effort to prioritize future research on this topic using experimental and observational methods, modeling tools, and field tests.

Long term containment of stored CO 2 in deep geological reservoirs will depend on the performance of the caprock to prevent the buoyant CO 2 from escaping to shallow drinking water aquifers or the ground surface. Here we report new laboratory experiments on CO 2 –brine–caprock interactions and a review of the relevant literature. The Eau Claire Formation is the caprock overlying the Mount Simon sandstone formation, one of the target geological CO 2 storage reservoirs in the Midwest USA region. Batch experiments of Eau Claire shale dissolution in brine were conducted at 200 °C and 300 bars to test the extent of fluid-rock reactions. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) analysis indicate minor dissolution of K-feldspar and anhydrite, and precipitation of pore-filling and pore-bridging illite and/or smectite, and siderite in the vicinity of pyrite. We also reviewed relevant reactivity experiments, modeling work, and field observations in the literature in an attempt to help define the framework for future studies on the geochemical systems of the caprock overlain on geological CO 2 storage formations. Reactivity of the caprock is generally shown to be low and limited to the vicinity of the CO 2 –caprock interface, and is related to the original caprock mineralogical and petrophysical properties. Stable isotope studies indicate that CO 2 exists in both free phase and dissolved phase within the caprock. Carbonate and feldspar dissolution is reported in most studies, along with clay and secondary carbonate precipitation. Currently, research is mainly focused on the micro-fracture scale geochemistry of the shaly caprock. More attention is required on the potential pore scale reactions that may become significant given the long time scale associated with geological carbon storage.

We investigated the association between a U.S. National Institutes of Health (NIH) R01 applicant’s self-identified race or ethnicity and the probability of receiving an award by using data from the NIH IMPAC II grant database, the Thomson Reuters Web of Science, and other sources. Although proposals with strong priority scores were equally likely to be funded regardless of race, we find that Asians are 4 percentage points and black or African-American applicants are 13 percentage points less likely to receive NIH investigator-initiated research funding compared with whites. After controlling for the applicant’s educational background, country of origin, training, previous research awards, publication record, and employer characteristics, we find that black applicants remain 10 percentage points less likely than whites to be awarded NIH research funding. Our results suggest some leverage points for policy intervention.

Multi-phase reactive flow and transport modeling is an effective tool for monitoring, verification, and accounting of CO2 sequestration in deep geological formations. In the current study, modeling is performed to simulate large scale CO2 injection (a million tons per year for 100 years) into Mt. Simon sandstone, a major candidate saline reservoir in the Midwest of USA. The long term fate of CO2 was simulated by extending the modeling period to 10,000 years. The results indicate that most of the injected CO2 remains within a radius of 3300 m lateral distribution. Four major trapping mechanisms and their spatial and temporal variations are evaluated in our simulations: hydrodynamic, solubility, residual, and mineral trapping. A strongly acidified zone (pH 3–5) forms in the areas affected by the injected CO2 (0–3300 m), and consequently causes extensive mineral precipitation and dissolution. The predicted long-term fate of CO2 is closely linked to the geochemical reactions conceptualized in the models. In our model, the replenishing upstream water continues to dissolve CO2 long after the injection, which results in total dissolution of hydrodynamically trapped CO2 at the end of 10,000 years. In contrast, most previous models neglected the regional flow after injection and hence artificially limited the extent of geochemical reactions as if in a batch system. Consequently, a supercritical CO2 plume (hydrodynamic trapping) would persist after 10,000 years. The continued supply of acidified water from interaction between replenishing water and CO2 also results in extensive dissolution of feldspars and precipitation of secondary clay minerals, to a much more extent than what predicted in models without including regional flow. However, the prediction of complete dissolution of feldspars in 10,000 years can also result from the artifact that the linear rate laws are used in our model (as well as all previous work), which overestimates the rates of feldspar dissolution near equilibrium. Nevertheless, our simulations indicate the prolonged existence of an acidic brine plume, which suggests long-term risk assessment should transfer from the primary risk of CO2 leakage to secondary risk of acidic plume leakage after all CO2 is dissolved.

Abstract This joint study combines physics-based reservoir simulations with automated screening including data mining and pattern recognition to evaluate the key controls on shale gas performance in Fayetteville, USA based on publicly available data comprising approximately 2000 wells. For data screening automated tools were developed to efficiently process large and rapidly growing data volumes. Workflows include probabilistic prediction of Estimated Ultimate Recovery (EUR) from decline curve analysis, diagnostic mapping, and multi-variate cross correlations. Key data utilized were gas production, well location, reservoir depth, well design and completion detail. Numerical simulations were conducted on 6 selected wells with 2.5 - 3.5 years of production data for history matching, model calibration and sensitivity tests. The models comprise a dual-porosity, dual-permeability approach incorporating multistage hydraulic fractures, Darcy's flow, diffusion and gas adsorption/desorption to predict gas rate and EUR. Key results include:• Average EUR per well has increased more than 5 fold from 2005 to 2009 suggesting a steep learning curve in identification of sweet spots coupled with improved well drilling and completion techniques.• Top performing wells completed since 2009 have an average completion length of ~4,100 ft and comprise 12–13 stimulation stages. However, longer wells, more completion stages and more proppant volumes do not always lead to higher well performance.• High performance wells are concentrated in two areas, providing evidence for geological control, although the performance (dynamic) sweet spots do not necessarily correlate with the resource density (static) sweet spots.• Despite improved drilling and completion techniques and improved subsurface illumination through 3D seismic and micro seismic, a significant number of completed wells still fall in low tier performance categories.• The reservoir simulation models require either the presence of natural fractures or higher matrix permeability (~several uD) in addition to hydraulic fractures and conventionally measured matrix permeability (~10s - 100s nD) to match production history.• Matrix permeability in the range of 10s to 100s nD appears to have limited impact on gas rate in the presence of natural fractures.• Gas desorption can contribute up to ~30% of gas production; desorption occurs early and increases with time.• Modeling results suggest an effective drainage area and an optimal well spacing of ~ 60 acres with current stimulation practices.• EUR predictions from reservoir simulations and automated decline curve analysis yield consistent results given the uncertainties from limited production data.

Water samples from Xikuangshan (China), the world largest antimony (Sb) mine with a Sb mining and smelting history of more than 200 years, were analyzed. These water samples ranged from stream water in the vicinity of the mining and smelting area that received seepage from ore residues to the underground mine-pit drainage. The concentrations of total Sb, Sb (III) and Sb (V) of the samples were determined by HPLC-ICP-MS. In addition, water pH and concentrations of major cations and anions were analyzed. All 18 samples demonstrated total Sb concentrations with ppm levels from 0.33 ppm to 11.4 ppm, which is two to three orders of magnitude higher compared to the typical concentration of dissolved Sb in unpolluted rivers (less than 1 ppb). This is probably the first time that such high Sb contents have been documented with complete environmental information. Distribution of total Sb and Sb species was investigated, taking into account the respective local environment (in the mining area or close to the smelter, etc.). Sb (V) was the predominant valence in all 18 samples. Only trace levels of Sb (III) were detected in 4 of the 18 samples. Geochemical speciation modeling showed the dominant species was Sb(OH)(6)(-). It is also probably the first time that such high Sb contents have been documented in the natural environment with Sb speciation distribution information. Several potential oxidation pathways are also discussed that might have facilitated the oxidation of Sb (III) in the natural environment. Signs of intoxication were observed among local mine workers with extensive exposure to different forms of Sb for a long period of time.

Currently, the U.S. population is undergoing major racial and ethnic demographic shifts that could affect the pool of individuals interested in pursuing a career in biomedical research. To achieve its mission of improving health, the National Institutes of Health must recruit and train outstanding individuals for the biomedical workforce. In this study, we examined the educational transition rates in the biomedical sciences by gender, race, and ethnicity, from high school to academic career outcomes. Using a number of educational databases, we investigated gender and racial/ethnic representation at typical educational and career milestones en route to faculty careers in biomedicine. We then employed multivariate regression methods to examine faculty career outcomes, using the National Science Foundation’s Survey of Doctorate Recipients. We find that while transitions between milestones are distinctive by gender and race/ethnicity, the transitions between high school and college and between college and graduate school are critical points at which underrepresented minorities are lost from the biomedical pipeline, suggesting some specific targets for policy intervention.