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More than 85% of patients with pancreatic ductal adenocarcinoma (PDAC) suffer from cachexia, a debilitating syndrome characterized by the loss of muscle and fat and remains an unmet medical need. While chemotherapy remains an effective treatment option, it can also induce weight and muscle loss in patients with cancer. Gemcitabine combined with nab paclitaxel (GnP) is a first line treatment option for patients with PDAC but its effect on cachexia has not been comprehensively investigated. We interrogated the effects of GnP in a murine model of pancreatic cancer cachexia. Mice were orthotopically implanted with the cachexia inducing pancreatic cell line (KPC) and were administered GnP or vehicle. The controls underwent sham surgery. We defined GnP effects on cachexia and tumor burden by evaluating muscle and cardiac mass and function, fat mass, bone morphometry, and hematology measurements. We completed RNA sequencing and deep proteome profiling in skeletal and cardiac muscle. KPC+GnP reduced tumor burden over 50% and increased survival compared to KPC. KPC vehicle group had more than 15% muscle mass loss and decreased left ventricular mass, this was not present in KPC+GnP when compared to controls. RNA Seq and deep proteomics analyses suggested that muscle and cardiac dysfunction pathways activated in KPC group were either reversed or decreased in KPC+GnP. In all, our data suggests that GnP protects against muscle and cardiac wasting in an experimental model of PDAC cachexia.

We compared two methods for extracting the azimuth of maximum horizontal stress (SHmax) from 3D land-based seismic data generated by a P source and recorded with vertical geophones. In the first method, we used the direct-SV mode that is produced by all land-based P sources. P sources generate SV illumination that radiates in all azimuth directions from a source station and creates SV-P reflections that are recorded by vertical geophones. Unless stratigraphy has steep dip, SV-P raypaths recorded by vertical geophones are the reverse of P-SV raypaths recorded by horizontal geophones. Thus, SV-P data provide the same S-wave sensitivity to stress fields as popular P-SV data do. In the second method, we retrieved P-P reflections and then performed an amplitude-variation-with-azimuth (AVA) analysis of the amplitude-gradient behavior of P-P reflection wavelets. We did this analysis in narrow azimuth corridors to determine the gradient of reflection-wavelet amplitudes as a function of azimuth. This P-P AVA amplitude-gradient method has been of great interest in the reflection seismology community since it was introduced in the late 1990s. Each of these methods, AVA analysis of the gradient of P-P reflection amplitudes and azimuth-dependent arrival times of SV-P reflections, can be used to determine the azimuth of SHmax stress. We compare the results of the two methods with ground truth measurements of SHmax azimuth at a CO2 sequestration site in the Michigan Basin. SHmax azimuths were determined from P-P and SV-P data at three major boundaries at depths of approximately 3500 ft (1067 m), 5500 ft (1676 m), and 7500 ft (2286 m). Two estimates of SHmax azimuth (one using SV-P data and one using P-P data) were made at each stacking bin inside a 24 mi2 (62 km2) image space. The result was approximately 98,000 estimates of SHmax azimuth across each of these three boundaries for each of these two prediction strategies. Histogram displays of PP AVA gradient estimates had peaks at correct azimuths of SHmax at all three depths, but the spread of the distributions widened with depth and split into two peaks at the deepest boundary. In contrast, each histogram of SHmax azimuth predicted by azimuth-dependent SV-P traveltimes had a single, definitive peak that was positioned at the correct SHmax azimuth at all three boundary depths.

Summary In this study, we demonstrate geomechanical modeling with fully automatic parameter calibration to estimate the full geomechanical stress fields of a prospective US carbon dioxide (CO2) storage site, based on sparse measurement data. The goal is to compute full stress tensor field estimates (principal stresses and orientations) that are maximally compatible with observations within the constraints of the model assumptions, thereby extending pointwise, incomplete partial stress measurement to a simulated full formation stress field, as well as a rough assessment of the associated error. We use the Perch site, located in Otsego County, Michigan, USA, as our case study. The input data consist of partial stress tensor information inferred from in-situ borehole tests, geophysical well logs, and processing of seismic data. A static earth model (SEM) of the site was developed, and geomechanical simulation functionality of the open-source MATLAB Reservoir Simulation Toolbox (MRST) was used to model the stress field. Adjoint-based nonlinear optimization was used to adjust boundary conditions and material properties to calibrate simulated results of observations. Results were interpreted through a Bayesian framework. The focus of this paper is to demonstrate how the fully automatic calibration procedure works and discuss the results obtained; it does not attempt a detailed analysis of the stress field in the context of the proposed CO2 storage initiatives. Our work is part of a larger effort to noninvasively determine in-situ stresses in deep formations considered for CO2 storage. Guided by previously published research on geomechanical model calibration, our work presents a novel calibration approach supporting a potentially large number of linear or nonlinear calibration parameters to produce results optimally agreeing with available measurements and thus extend partial pointwise estimates to full tensor fields compatible with the physics of the site.

Three borehole gravity (BHG) surveys were performed in 2013, 2016, and 2018 to monitor the changes in gravity/density as a result of the injection and withdrawal of carbon dioxide ([Formula: see text]) into and out of the Dover 33 carbonate reservoir reef in Northern Michigan. The observed gravity changes and inferred density changes have been modeled to determine the flow and storage zones of the injected [Formula: see text] in the reef. The high quality and low level of uncertainty of the data collected make them useful for delineating the [Formula: see text] plume position over time and for identifying the oil sweeping extent and mechanisms in the Dover 33 reef. The time-lapse gravity results indicate the effects of the changing [Formula: see text] mass within the reservoir, consistent with increasing mass from 2013 to 2016 (following [Formula: see text] injection) and a decreasing mass from 2016 to 2018 (after [Formula: see text] withdrawal). Three-dimensional imaging of fluid migrations in the reef has been obtained by coupling the time-lapse BHG results to a 3D porosity and permeability model. This coupled approach allows the evaluation of the volume of the reef affected by the injection of [Formula: see text] between 2013 and 2016, the efficiency of the oil sweeping between 2016 and 2018, and the location of the residual [Formula: see text] plume in the reef after 2018.

We have determined how to extract the azimuth of maximum horizontal stress (SHmax) in deep rocks by doing a simple 360° mathematical rotation of a downgoing direct-S wavelet generated at the baseplate of a surface-based vertical vibrator. We worked with direct-S wavelets that travel through stressed rocks to a deep horizontal vertical seismic profile (VSP) geophone. We find that the azimuth where a polarity reversal occurs in mathematical rotations of this downgoing direct-S wavelet defines the azimuth of the SHmax in the overlying rocks. We tested this direct-S wavelet rotation method for determining the SHmax azimuth at a site in the Illinois Basin using legacy VSP data acquired in 2013. SHmax azimuths indicated by this simple wavelet-rotation method were determined when vertical vibrators were stationed at zero offset, at far offset, and at different azimuths around a VSP receiver well. These VSP-based SHmax azimuths agreed with the azimuth of the SHmax found by traditional minifrac tests in the VSP receiver well. This simple VSP data analysis procedure for detecting the azimuth of maximum horizontal stress has never, to our knowledge, been reported or discussed in the geophysical literature. This technical finding should be of interest to the worldwide geophysical community, especially to people who need to monitor how stress fields shift when fluids are injected into, or extracted from, deep porous reservoirs.

We have evaluated the concept of practicing S-wave reflection seismology with legacy 3D seismic data generated by a P-wave source and recorded with only vertical geophones. This type of S-wave imaging is based on the principle that seismic P-wave sources not only produce a downgoing illuminating P wavefield, but they also simultaneously produce a downgoing illuminating SV wavefield that, in almost all cases, is suitable for S-wave reflection imaging. The S-mode used in this study is the SV-P, or converted-P, mode. This mode involves a downgoing illuminating SV wavefield and an upgoing reflected P-mode that is recorded by vertical geophones. In flat-layered stratigraphy, the lengths of the SV and P raypaths in SV-P imaging are identical to the lengths of the SV and P raypaths in P-SV imaging with P-sources and 3C geophones. P-SV imaging of deep rocks has been practiced for more than two decades; SV-P imaging is a new concept. SV-P data should provide the same options for investigating deep rocks as do P-SV data. We have determined one of the equivalences between SV-P data extracted from vertical-geophone data and P-SV data extracted from horizontal geophones: that both modes react to azimuth-dependent variations in the S velocity in anisotropic rocks. Azimuthal variations in the SV-P traveltime can be used to define the polarization direction of the fast-S-wave mode, which is also the azimuth of the maximum horizontal stress (SHmax). Our investigation demonstrates a noninvasive method for monitoring changes in the SHmax azimuth across a CO2 storage reservoir, or any targeted porous rock, as fluids are cycled into, and then out of, that rock’s pore space.

The Northern Michigan Basin (NMB) Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Integrated Pre-Feasibility Project is part of the U.S. Department of Energy’s (DOE) CarbonSAFE initiative. The objective of the NMB CarbonSAFE pre-feasibility project was to assess the feasibility of an integrated, commercial-scale carbon dioxide (CO2) storage complex in the NMB, which includes one or more deep saline geologic formations with sufficient capacity to permanently store at least 50 million metric tons of CO2 over a 20- to 30-year period. Subsurface injection of CO2 into depleted oil reservoirs for enhanced oil recovery (EOR) was also evaluated in the pre-feasibility study as an additional geologic storage mechanism because there are hundreds of depleted pinnacle reef reservoirs in the NMB, along with an established CO2-EOR operation, a feature that distinguishes this area from most other locations in the United States. Additionally, these reefs are co-located with the most favorable saline formations in the basin – the St. Peter sandstone and the Bass Islands dolomite – making stacked storage a real possibility. The study demonstrates that there are multiple locations in the northern Michigan study area that could support a commercial-scale storage complex with either saline storage or associated storage via CO2-EOR in the depleted pinnacle reefs alone (i.e., each storage mechanism has sufficient capacity alone) or via a combination of the two storage mechanisms. The term stacked storage refers to the concept of using both mechanisms together, in the same area, to achieve the required storage capacity. Key sites were identified in the northern part of the southern Michigan Peninsula that had sufficient geologic storage, nearby CO2 sources, a favorable social and economic setting, and a strong developed team.

A Distributed Temperature Sensing (DTS) system, along with a five-level, behind-casing pressure sensing array was installed as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP) large-scale carbon dioxide (CO2) storage test in a depleted Niagaran pinnacle reef oil reservoir in Northern Michigan. The reef is being monitored during its initial reservoir fill-up period as CO2 is being injected to raise the reservoir pressure for enhanced oil recovery (EOR). DTS data are analyzed with results from the initial injection of ˜101,000 metric tons of CO2, injected between January 2017 and December 2018. This paper discusses the results of real-time DTS combined with multi-level pressure monitoring. The collection, processing, and interpretation of large amounts of data from fiber-optic-based DTS provides an opportunity to obtain high-resolution information on migration of CO2 in the reservoir.

The Midwest Regional Carbon Sequestration Partnership has been investigating various reservoir characterization and modeling technologies as part of its commercial-scale implementation of carbon dioxide injection for geologic storage in multiple Silurian carbonate pinnacle reefs in northern Michigan, USA. This paper compares multiple reservoir modeling approaches for history-matching oil production and CO2 injection responses, and estimating associated storage, to characterize these small spatial footprint depleted reef reservoirs. The three approaches considered are: fully compositional simulation, black-oil with pseudo-miscibility treatment, and capacitance resistance modeling (CRM). Modeling results from three reefs illustrating each modeling approach are presented, and their applicability and limitations with respect to data needs and modeling objectives are discussed.

Conventional reservoir monitoring techniques in Carbon Capture & Storage (CCS) and CO2-Enhanced Oil Recovery (EOR) sites include surface and bottomhole pressure and temperature monitoring at injection and monitoring wells, along with flow rate measurements of injected CO2. In this paper, novel monitoring techniques involving a realtime distributed temperature sensing (DTS) system and multi-depth behind-casing pressure and temperature sensors are evaluated at a CO2-EOR reef in the Northern Niagaran Pinnacle Reef Trend (NNPRT). Data from these monitoring technologies are evaluated for the purpose of monitoring bottomhole conditions in response to injection of CO2 at a nearby injection well and monitoring migration of injected CO2 within the storage formation after the monitoring well was converted to an injection well.

The Regional Carbon Sequestration Partnership program in the United States, funded by the Department of Energy’s National Energy Technology Laboratory (NETL), is a widely recognized program for advancing Carbon Dioxide Capture, Utilization, and Storage (CCUS) technologies. The Midwestern Regional Carbon Sequestration Partnership (MRCSP) is one such Partnership covering 10 states across midwestern and northeast coastal USA. Since its inception in 2003, MRCSP has completed Phase I (2003-2005) involving assessment of regional emission sources and sequestration sinks and Phase II (2005-2011) involving multiple small-scale pilot tests to evaluate the feasibility of CCUS across the region. Under Phase III, which started in 2009, the MRCSP team has focused on detailed evaluation of a large-scale demonstration project of CO2 Enhanced Oil Recovery (EOR) and associated storage. Work has also continued on the assessment of storage potential across the region by the MRCSP team. This paper provides the overarching final conclusions of the large-scale test and implications for commercial deployment. The test was conducted in the CO2-EOR fields in northern Michigan, in the Silurian age carbonate reef complex, operated by Core Energy, LLC. The CO2 supply for the EOR is from processing of the natural gas from overlying Antrim Shale formation. The CO2 is pipelined about 16 km to the injection wells and a central processing facility. The overall reef complex consists of more than 800 fields, but EOR started in a single field in the mid-1990s and has currently expanded to ten fields. In 2012, MRCSP started a comprehensive program of characterization, measurement, accounting, modeling, and monitoring to research all aspects relevant to CO2 utilization and storage in the complex with a goal of injecting at least 1 million metric tons of CO2. The reef complex includes fields which have undergone EOR (late-stage life cycle), those undergoing EOR (operational), and those where injection is underway sans production (new fields). This allowed MRCSP to deploy an evolving portfolio of characterization, monitoring, and modeling approaches, which could be customized based on individual field settings (geologic, size, production history, well configurations, and EOR plans) and incorporate lessons learned from initial reefs. The large-scale test and the MRCSP Phase II were concluded in 2020 and an extensive set of final technical and topical reports are available for future researchers and commercial CCUs developers. With the conclusion of the MRCSP Program, Battelle has started a new program to enable and accelerate CCUS deployment, called the Midwest Regional Carbon Initiative (MRCI, midwestccus.org), which covers 20 states across midwestern and northeastern US.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is one of seven regional partnerships established in October 2003 as part of the U.S. Department of Energy’s (DOE’s) Regional Carbon Sequestration Partnership (RCSP) program to assess the technical and economic viability and public acceptability of carbon sequestration in the U.S. The MRCSP Phase III project injected over 1 million metric tons (MT) of CO2 into a group of Silurian (Niagaran)-age pinnacle reef reservoirs in Otsego County, Michigan (USA) that are operated by Core Energy, LLC [1]. There are over 800 pinnacle reefs in northern Michigan, and collectively, these geologic features have enough capacity to store several hundred million MT of CO2. Moreover, most of the reefs are depleted oil- or gas-reservoirs having previously undergone primary production in the 1970s and 1980s; therefore, they offer the opportunity to achieve CO2 storage through enhanced oil recovery (CO2-EOR) (associated storage) and via geologic sequestration (injection alone without production). A key objective of the MRCSP Phase III project was to evaluate the effectiveness of various monitoring technologies for use in associated storage or sequestration projects in the Niagaran pinnacle reefs. Over the period 2013 to 2020, the MRCSP Phase III project conducted monitoring using eleven different technologies for their effectiveness for CO2 plume delineation, assessing geochemical interactions, well integrity, leak detection, induced seismicity, land deformation, and mass balance accounting in the group of study reefs operated by Core Energy. This paper discusses the effectiveness of selected monitoring technologies that had the goal of detecting/delineating the extent of CO2 in the subsurface. The results are relevant to others planning or currently conducting CO2 sequestration or associated storage projects in similar carbonate reef reservoirs.

Assessing the mechanical integrity of the caprock-reservoir system is necessary to evaluate the practical storage capacity for geologic [Formula: see text] storage. We used a combination of well-log and experimental data to estimate the statistical distribution (mean and variance) of rock mechanical properties of Cambrian-Ordovician strata within the Northern Appalachian region of Ohio and studied their heterogeneity throughout the study area. Empirical correlations between static-dynamic moduli of carbonate and sandstone formations of the Northern Appalachian Basin were developed. The state of stress (the orientation and magnitude of the maximum horizontal stress) for caprock and reservoir formations in the Cambrian-Ordovician sequence was determined at multiple well locations to understand the regional variability of these properties throughout the study area. The maximum horizontal stress ([Formula: see text]) azimuth was estimated from image logs for six wells and S-wave anisotropy data for five wells. The [Formula: see text] magnitude was estimated by analytical and numerical modeling of stresses around the wellbore calibrated to the occurrence of wellbore breakouts and drilling-induced fractures in three wells as a function of depth. The results of assessing the [Formula: see text] magnitude and stress regime in the caprock and reservoirs in the Cambrian-Ordovician sequence using rock mechanical data acquired in this study, well-log data, and drilling data indicate that both parameters vary throughout the study area. In this work, we determined how integrating different types of data from multiple wells allowed us to estimate mechanical properties and characterize the spatial variability (laterally and vertically) of in situ stress for Cambrian-Ordovician caprock and reservoirs throughout the study area. A combination of different methods — numerical, analytical, and stress polygon — is used to estimate the in situ stress magnitude, especially [Formula: see text], regionally on a formation-by-formation basis. The results of this work can be used to improve our understanding the complex nature of stress in the Northern Appalachian Basin.

The MRCSP Michigan Basin Large-Scale Injection Project is evaluating CO 2 storage and utilization in a complex of closed reservoirs at various stages of production and enhanced oil recovery (EOR) life-cycle. Since 2013, MRCSP has successfully injected and monitored the net storage of more than 600,000 metric tons of CO 2 out of the goal of 1 million metric tons. A number of monitoring technologies have been tested, and various modeling approaches are being applied to evaluate CO 2 migration, injectivity, capacity, and containment.

The northern Michigan Niagara reef trend has more than 700 reefs at various stages of the production lifecycle. Five reefs were selected for static earth modeling that display differences in abundance of limestone and dolomite, salt plugging, and compartmentalized, separate pod scenarios. These resulting static earth models demonstrate the efficacy of a new, integrated approach to reservoir evaluation, as well as illustrating the diversity of the geology and diagenesis, and how this complexity influences reservoir potential and behaviour. The developed geologic modeling approaches will be generalized to implement a regional assessment of CO2 storage across the reef complex.

The goal of this study was to collect and analyze geologic data for assessment of CO2 storage feasibility in the parts of Appalachian Basin covering eastern Ohio and the adjacent Upper Ohio River Valley with a focus on deeper Paleozoic formations. This included detailed mapping, cross sections, and petrophysics of caprocks and reservoirs along with selected reservoir flow testing in regional injection wells to determine potential intake zones. The workflow was successful in characterizing reservoirs and advancing geologic understanding in the region, all precursors to estimating CO2 storage resources.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is leading an extensive study and monitoring effort of large-scale carbon dioxide (CO 2 ) injection and storage during enhanced oil recovery (EOR) in depleted oil fields in the Michigan Niagara Reef Trend. Detailed monitoring of caprock and reservoir zones is vital for understanding oil, gas, and water saturations and potential migration of CO 2 . Baseline and repeat pulsed neutron capture (PNC) logs were collected as part of the monitoring effort and study for these storage sites. An overview of the development and enhancement of best practices for PNC logging in complex EOR fields is presented.

This paper discusses the use of a 2-D numerical model representing a typical depleted pinnacle reef reservoir to generate synthetic data for multiple CO2 injection periods after a prolonged period of oil and gas production. The data are analyzed with conventional pressure-transient analysis and injectivity-index approaches from petroleum reservoir engineering practice. Pressure falloff data from multiple shut-in periods, with and without boundary effects, indicate that the system response is similar to that of a composite reservoir with different total mobility and total compressibility values in the inner (CO2-rich) and outer (CO2-free) regions. The total mobility of the inner zone can be approximated by the total mobility of the gas phase in the vicinity of the CO2-oil front, while the total mobility of the outer zone corresponds to the total mobility of the oil phase in the undisturbed region. The injectivity index, calculated as injection rate divided by the pressure buildup from reference conditions, yields a quasi-stable value during the transient period which can be correlated to the permeability-thickness product of the injection zone. During the boundary-dominated (pseudo-steady-state) period, a flowing material balance plot can be utilized to determine an apparent injectivity index, which is higher than the true injectivity index because of multi-phase skin effects.

The purpose of this study is twofold: (a) to assess the perceived relevance of the Seven Timeless Principles and guidelines posited by Gregory (1886) for current educators and educators-in-training and (b) to develop and pilot test the instrument needed to accomplish the former. The “Rules for Teachers” Gregory attributes to each of these laws were used as guidelines to develop an assessment instrument. Eighty-four educators and future educators across three universities participated in an online survey using a 4-point Likert scale to evaluate the consistency of Gregory’s guidelines with modern best-teaching practices. Responses were framed within the Timeless Principles, providing a measure of pedagogical universality. Total mean scores for all principles and guidelines were greater than 3.0, suggesting that Gregory had indeed identified foundational principles of teaching and learning that maintain relevance across academic disciplines and in a variety of settings in which learning occurs.

Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO2-EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects.

The objective of the FutureGen 2.0 Project was to demonstrate, at the commercial scale, the technical feasibility of implementing carbon capture and storage in a deep saline formation in Illinois, USA. Over approximately 5 years, the FutureGen Industrial Alliance, Inc. (Alliance) conducted a detailed site-selection process and identified a site for carbon sequestration storage in Morgan County, Illinois. A comprehensive geologic and hydrologic characterization of the storage site was conducted and included the collection of seismic data and the drilling and characterization of a stratigraphic borehole. The characterization data provided critical input for developing a site-specific conceptual model and subsequent numerical modeling simulations. The modeling simulations, coupled with upstream designs of the pipeline and power plant, supported the development of a detailed design that included the injection wells and associated control and monitoring infrastructure. The Alliance used all of these data to develop the required documentation to support the applications for four underground injection control (UIC) permits (one for each proposed well). In August 2014, the U.S. Environmental Protection Agency issued four, first-of-their-kind, Class VI UIC permits for carbon sequestration in the United States to the Alliance. This equated to one permit per planned injection well. The information and data generated under this project have been made publicly available through reports and publications, including this journal and others.