Ongoing ocean warming can release methane (CH 4) currently stored in ocean sediments as free gas and gas hydrates. Once dissolved in ocean waters, this CH 4 can be oxidized to carbon dioxide (CO 2). While it has been hypothesized that the CO 2 produced from aerobic CH 4 oxidation could enhance ocean acidification, a previous study conducted in Hudson Canyon shows that CH 4 oxidation has a small short-term influence on ocean pH and dissolved inorganic radiocarbon. Here we expand upon that investigation to assess the impact of widespread CH 4 seepage on CO 2 chemistry and possible accumulation of this carbon injection along 234 km of the U.S. Mid-Atlantic Bight. Consistent with the estimates from Hudson Canyon, we demonstrate that a small fraction of ancient CH 4-derived carbon is being assimilated into the dissolved inorganic radiocarbon (mean fraction of 0.5 ± 0.4%). The areas with the highest fractions of ancient carbon coincide with elevated CH 4 concentration and active gas seepage. This suggests that aerobic CH 4 oxidation has a greater influence on the dissolved inorganic pool in areas where CH 4 concentrations are locally elevated, instead of displaying a cumulative effect downcurrent from widespread groupings of CH 4 seeps. A first-order approximation of the input rate of ancient-derived dissolved inorganic carbon (DIC) into the waters overlying the northern U.S. Mid-Atlantic Bight further suggests that oxidation of ancient CH 4-derived carbon is not negligible on the global scale and could contribute to deepwater acidification over longer time scales. Plain Language Summary Ocean acidity may be enhanced not only due to the oceanic uptake of atmospheric carbon dioxide but also through temperature-driven processes that can mobilize ancient carbon stores and generate additional carbon dioxide. One of these processes is the oxidation of methane derived from seafloor seepage. Here, we investigate if the widespread release and subsequent oxidation of seep methane into carbon dioxide could contribute to the acidification of deep waters along the U.S. Mid-Atlantic Bight. Our results suggest that over short time scales, methane's role in enhancing ocean acidification is small. However, over longer time periods, methane-derived carbon could contribute to deepwater acidification.

Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties which control production and account for fracturability. Multiscale imaging studies from whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, fracture density, pore types, pore connectivity, mineralogy and organic content to the petrophysical response and production characteristics. In this paper we describe examples of the application of a multiscale imaging and analysis method to characterize challenging unconventional reservoirs which incorporates: Geological rock typing and heterogeneity characterization at the core/plug scale (3D imaging and conventional descriptions);  Mineralogy, primary grain structure and porosity/microporosity characterization at the pore scale via a range of 3D imaging technology (CT, micro-CT);  SEM/SEM-EDS/FIBSEM analysis to reveal the nanoporous structure of important pore types (e.g, secondary porosity, microporous matrix, diagenetic minerals including clays);  SEM and micro-CT analysis of wettability (applicable for oil reservoirs);  Integration of image data to generate 3D model structures that honour the primary grain structure and accurately capture the nanoporous regions.The generation of integrated image-based microstructures provides the basis for the computation of key petrophysical and multiphase flow properties which impact on the storage capacity and production characteristics of the samples. Petrophysical properties are first calculated on various pore types at representative scales; these predictions are then upscaled to estimate the contributions to permeability, formation factor and elastic response of the key constituent phases (e.g., porosity and permeability associated with clays, slot-like pores, cement, and partially dissolved minerals (e.g. feldspars)) at the plug scale. Estimation of drainage relative permeability and capillary pressure from 3D image data and modelling are compared and predictions of flow properties derived. These predictions are compared/calibrated to high quality experimental data on the same or sister core material.

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PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.

There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.