Berawala, Dhruvit Satishchandra (Department of Energy and Petroleum Technology, University of Stavanger, Norway and The National IOR Centre of Norway) | Østebø Andersen, Pål (Department of Energy Resources, University of Stavanger, Norway and The National IOR Centre of Norway)
Only 3-10 % of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for CO2 than methane, CH4, which opens possibilities for carbon storage and new production strategies.
This paper presents a new multicomponent adsorption isotherm which is coupled with a flow model for evaluation of injection-production scenarios. The isotherm is based on the assumption that different gas species compete for adsorbing on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles this finite surface area is filled with species taking different amount of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas in place reserves, recovery factors and enhanced gas recovery potential based on contributions from free gas and adsorbed gas components. The isotherm is further coupled with a dynamic flow model with application to CO2-CH4 substitution for CO2-ESGR. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection-production setting representative of lab and field implementation and compare with regular pressure depletion.
The production scenario we consider is a 1D shale core or matrix system intitally saturated with free and adsorbed CH4 gas with only left side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to increase in pressure where CO2 gets preferentially adsorbed over CH4. The injected CO2 displaces, but also mixes with the in situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel further into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism since the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is a result of CO2 being found to take ~24 times less space per mol than CH4.
Seunghwan Baek and I. Yucel Akkutlu, Texas A&M University Summary Source rocks, such as organic-rich shale, consist of a multiscale pore structure that includes pores with sizes down to the nanoscale, contributing to the storage of hydrocarbons. In this study, we observed hydrocarbons in the source rock partition into fluids with significantly varying physical properties across the nanopore-size distribution of the organic matter. This partitioning is a consequence of the multicomponent hydrocarbon mixture stored in the nanopores, exhibiting a significant compositional variation by pore size-- the smaller the pore size, the heavier and more viscous the hydrocarbon mixture becomes. The concept of composition redistribution of the produced fluids uses an equilibrium molecular simulation that considers organic matter to be a graphite membrane in contact with a microcrack that holds bulk-phase produced fluid. A new equation of state (EOS) was proposed to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allowed us to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix ( 10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Hence, hydrocarbon vaporization and desorption develop at extremely low pressures. Consequently, hydrocarbon recovery from these small pores is characteristically low. Introduction Resource shale and other source-rock formations with significant amounts of organic matter, such as mudstone, siltstone, and carbonate, have a multiscale pore structure that includes fractures, microcracks, and pores down to a few nanometers (Ambrose et al. 2012; Loucks et al. 2012). The total amount of hydrocarbons stored is directly proportional to the amount of organic matter.
Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
Lima, C. (Independent Researcher) | Lavorante, L. P. (Independent Researcher) | Williams, W. C. (Louisiana State University) | Beisl, C. (UFRJ-COPPE) | Reis, A. F. C. (Petrobras) | Carvalho, L. G. (Petrobras) | Moriss, M. (Paradigm)
ABSTRACT: This study proposes that a systematic comparison using integrated 3D visualization of all pertinent data (midplate seismicity, geological and geophysical variables) could help in identifying areas vulnerable to injection-induced seismicity in the North American plate. From similar studies of the South American plate in Brazil’s Potiguar basin, it is found that intraplate seismicity occurs at uplifted basin borders (areas over thin, hot, weaker lithosphere) where pre-existing faults are prone to be reactivated by small pressure perturbations. Conversely, central basins (areas over thick, cold, strong lithosphere) are not prone to seismicity. With this model we investigate Oklahoma (Ok) and North Dakota (ND), both intense areas of injection. ND activity, in the central basin, shows no induced seismicity. In contrast, Ok activity, in a regional-scale ravine in the uplifted basin border, has seen a 62.5-fold increase in recent seismicity. Modeling of the Ok region shows reactivation of pre-existing faults with injection pressures of 1.75 MPa (254 psi; 0.7ppg) between 2000-2200m depths, values that agree with wellhead injection pressure field data.
1. INTRODUCTION: THE PROBLEM
A huge increase of seismicity in the tectonically stable U.S. is put into evidence, if we examine the USGS Catalog, 2017 comparing the number of earthquakes of magnitude (Mw) greater or equal to 4 that occurred during 2000-2010 and 2010-2016. For this area, see Fig. 1, we jumped from an average of 6.2 events/yr, during 2000-2010, to an average of 28.8 events/yr, during 2010-2016, roughly a 5-fold increase. For Oklahoma, see Fig. 2, a 62.5-fold increase of seismicity has been observed when comparing these same two periods, including two major events (Mw 5.7, 2011; Mw 5.8, 2016). These recent increases are contemporaneous with the increase in shale production as shown in Figs. 1 and 2. In the stable midcontinent, a roughly 5-fold increase is observed in seismicity during 2010-2016. Again, the increase is contemporaneous with US shale production.
The units that compose the volcano-sedimentary fill are Early Devonian to Late Cretaceous. The sedimentary fill has a maximum drilled thickness of 2,377 m (de Santa Ana et al., 2006b), but according to geophysical information (gravimetric, magnetotelluric and seismic), in some sectors, basement may reach depths near 3,500 m (Rodriguez et al., 2015; Marmisolle, 2015; Mira, 2015). Four main sequences can be recognized in the volcanosedimentary fill of the Norte Basin (de Santa Ana et al., 2006a,b; Veroslavsky et al., 2006), from base to top: Paleozoic sedimentary rocks: - Early Devonian sequence, including braided-delta and sandy shelf deposits, shallow marine shelf shales and littoral sandy plains.
Some sedimentary rocks may reveal compromising behavior in civil works,owing their peculiar response to weathering phenomena, related with their structural pattern associated to own physical genesis characteristics. The evidence of such effects has appointed to the need of geotechnical tests, in order to collect and to analyse the whole of their properties providing their nature, and aiding the interpretation of their behaviour in practice. Besides, the collected data will certainly be applied in future projects where similar rocks occur. The tests may lead to the specifications improvement, yet poorly in Brazil, suited the material in question.
As unconventional resources such as Shale Gas and Coal Bed Methane become mainstream, many companies are looking towards the next generation of resource types. Coal to Liquids, Oil Shale, Underground Coal Gasification and Microbial Coal Conversion are examples of resource types that are being assessed and in the early stages of commercial exploitation within the Asia Pacific region. How can companies looking to exploit such resources assess their projects within a common framework? Such projects run the risk of falling between the cracks of petroleum assessment guidelines such as the SPE-PRMS and mining guidelines such as JORC.
These resources often do not occur naturally as hydrocarbons. They typically involve a mining, or in-situ, extraction process followed by a direct or indirect upgrading process whose end product is a saleable liquid product such as synthetic crude oil. In some cases, in-situ extraction is possible. Whilst such mining and upgrading processes are clearly included within the SPE-PRMS for such deposits as tar sands and bitumen (which are already naturally occurring hydrocarbons), the situation is less clear when the raw material is not naturally occurring hydrocarbons.
Coal to Liquids involves mining the coal/lignite followed by an upgrading process to produce synthetic hydrocarbons. Oil Shale is essentially an immature kerogen-rich source rock which requires artificial maturation to generate hydrocarbons. Various techniques are available, either in-situ or mining followed by an upgrading process at the surface. Underground Coal Gasification is an in-situ process used in non-mined coal seams to generate gases including methane through injection of oxidants and steam to fuel an underground combustion process. Another emerging technology is microbial coal conversion.
Although they do not fully satisfy all of the definitions of the SPE-PRMS, the authors believe that the principles of the SPE-PRMS can be used to assess such resources. The project can be evaluated as a whole i.e. from mined raw material through upgrading process to saleable end product.
Further clarity and definition within the SPE-PRMS would assist such assessments. Overlap and integration with JORC and other mining codes would also aid understanding and transparency. There are also challenges required during the assessment of such projects. Traditional petroleum industry skills must be supplemented with expertise in mining and product upgrading in order to perform a full analysis. With many companies in the Asia-Pacific region, especially Australia and China, assessing such resources and looking to commercialise them, improvements in their understanding and assessment would be beneficial to all stakeholders.
Rodríguez, Pablo (Exploración y Producción ANCAP) | Marmisolle, Josefina (Exploración y Producción ANCAP) | Soto, Matías (Exploración y Producción ANCAP) | Gristo, Pablo (Facultad de Ciencias) | Benvenuto, Andrés (Exploración y Producción ANCAP) | de Santa Ana, Héctor (Facultad de Ciencias) | Veroslavsky, Gerardo (Exploración y Producción ANCAP)
This paper presents a study result of the integration of new gravimetric and geologic data (superficial mapping and deep geology from wells), acquired in the Norte Basin (southernmost part of the Paraná Basin) blocks Pepe Núñez and Clara. The results in both cases showed a good correlation between the final gravimetric model and the main structural and stratigraphic features, particularly basement highs and lows, basement nature, depocenters and faults.
The Paraná Basin (Zalán et al., 1990) is a large intracratonic basin which extends over more than 1,400,000 km2 in the Northern region of Uruguay, South-central Brazil, Northeast of Argentina and Southeastern Paraguay. The Uruguayan sector is known as Norte Basin, and crops out in an area of about 90,000 km2. Its Early Devonian to Late Cretaceous volcano-sedimentary fill has a maximum drilled thickness of 2,400 m (Bossi, 1996; de Santa Ana et al., 2006b), but according to gravimetric, magnetotelluric and seismic information deeper depocenters (more than 3,500 m thick) may be preserved in some sectors.
Four main sequences can be recognized in the volcanosedimentary fill of the Norte Basin (de Santa Ana et al., 2006a,b; Veroslavsky et al., 2006), from base to top: Paleozoic sedimentary rocks:
• Early Devonian sequence, including braided-delta and sandy shelf deposits, shallow marine shelf shales and littoral sandy plains.
• Late Carboniferous-Permian sequence, including glacio-fluvio-lacustrine deposits, glacio-marine deposits, deltaic sandstones, marine shales, restricted marine-lagoon shales and limestones, shelf to transitional deposits, and fluvio-aeolian deposits.
Mesozoic volcanic and sedimentary rocks:
• Late Jurassic-Cretaceous sequence, including basaltic flows, fluvio-lacustrine and aeolian sandstones, huge volumes of basaltic flows, basic dykes and sills, and intertrap sandstones.
• Late Cretaceous sequence, including fluvio-aeolian and alluvial-fluvial deposits, calcretes and laterites deposits.
PROBLEMS OF LARGE RELIEF OR WEATHERED SHEAR JOINTS IN GRANITES AND BASALTS IN BRAZILIAN DAM FOUNDATIONS ABSTRACT Large subhorizontal joints have been found in the foundation excavations in basalt and granite of Brazilian Dams. Some spread for hundreds of square meters showed slickensides--polished surfaces plus striations--and laminations interpreted as related to shear displacement, what substantially reduced their shear strength and imposed special reinforcement measures against the potential sliding of overlying concrete structures. The geological characteristics of these discontinuities have raised speculations related to their origin, be it related to mechanisms of bulging, cambering or to some tectonic or primary geological event. Several geologists and engineers from the northern hemisphere including Terzaghi already showed to be concerned with their role in granite foundations while in the southern regions Brazilian authors have found similar occurrences but also affecting individual lava flows of continental flood basalts in the foundations of major dams of the Parana Basin, which they designated under the particular name of "fault-joints". This double-standard designation is self-explanatory of the difficulties involving their origin and related geomechanical properties: faults or just shear joints?
Here we present a regional study of the offshore/onshore Namibia using gravity and magnetic data aiming to bring a new light on the structural configuration of the major Namibian basins. This has been achieved by integrating all the available wells, vintage seismic images and public domain information.
We produced lineament maps at different scales with the aid of gravity and magnetic data enhancements in the attempt of differentiating between regional and local features. In general, volcanic centres and dikes are well recognized as well as two main structural trends: one oriented NW-SE being more prevalent in the offshore, near-onshore and in the Nama basin; the second oriented SW-NE more pronounced in the Owango basin and the Damara Belt.
Satellite derived gravity is also used to delineate the transition zone between continental and oceanic crust (COB). Results are compared with information from seismic and well data to locate the COB on the achieved structural map.
Magnetics was also used to estimate the depth to basement all over the studied area. Major basins and structural elements such as the SW-NE uplift in the Owango basin, a series of sub-basins with a significant depth in the Damara fold belt and the Nama basin, offshore basins and sub-basins plus structural highs were identified and mapped.
2.5D Gravity and Magnetic modeling over key areas was used to validate the structural interpretation. These models integrate interpreted seismic profiles, densities from stacking velocities, wells, refraction seismic interpretations and public domain data.
We found thick piles of sediments could be present below the SDRs in the Walvis and Luderitz basins. While we found the SDRs probably be at direct contact with the continental crust in the Orange basin, generating an important magnetic anomaly, therefore no important sediment accumulation can be inferred below the SDRs in this basin. We also found the Owambo basin in the onshore dipping northward with important dike intrusions in the middle. The Nama basin is characterised by a high magnetised crust with a higher magnetised intrusion generating the large magnetic anomaly at its western end.
Recently, exploration in new venture areas is relying more and more on integrated studies with all the available public domain information, low cost geological and geophysical data. More often the need of analyzing large areas of a regional extent to rapidly evaluate the petroleum potentials is requiring fast tools and large datasets. Gravity and magnetic data have the advantage of continuously cover large areas at a fraction of the costs of conventional seismic or geological field work. This type of data is more than sufficient for determining structural configuration, basement depth and geometry, COB, evaluate sediment thickness and lithologies at regional and basin scale.
Here a regional interpretation of the onshore/offshore Namibia with focus on specific basins was undertaken, mainly using low cost GravMag data and public domain information.