Shale Gas in Poland

An example of interpretation of the Silurian and Ordovician shale formations in the Baltic Basin in Poland regarding determination of potential sweet spots is presented. Short geological information shows the position of shale gas play. Description of the data—laboratory measurement outcomes (petrophysical and geochemical) and well logging—presents results available for analyses. Detailed elemental analyses and various statistical classifications show the differentiation between sweet spots and adjacent formations. Elastic property modelling based on the known theoretical models and results of comprehensive interpretation of well logs is a good tool to complete information, especially in old wells. Acoustic emission investigations show additional characteristic features of shale gas rock and reveal that acoustic emission and volumetric strain of a shale sample induced by the sorption processes are lower for shale than for coals

Stratigraphy, depositional environments, and petroleum potential of the Three Forks Formation -- Williston Basin, North Dakota

The hydrocarbon potential of the Three Forks Formation in North Dakota is poorly known due to limited stratigraphic, geochemical, and petrophysical data. This study presents a methodology and results of a reservoir characterization study of the stratigraphy, lithofacies distribution, petroleum potential, and paleo-environments of the Three Forks Formation in North Dakota as a potential for hydrocarbon exploration with the principal objective to evaluate the Three Forks Formation’s potential for future developments. The detailed lithology is computed by employing a probabilistic interpretation approach calibrated with lab results and five major lithofacies of the Three Forks Formation in North Dakota, which display a variety of diagenetic characteristics including dolomitization and precipitation of hematite, are identified and presented. These facies correlate well with electrofacies predicted by employing principal component analysis and clustering techniques to selected lithology-sensitive logs. Hydrocarbon source rock analysis, including type and quantity of kerogen, and thermal maturity on all five facies using Rock-Eval 6 pyrolysis and LECO TOC shows that these facies have poor to fair petroleum potential and contain immature Type II and Type III kerogens. In addition, samples from three lithofacies are analyzed by thin section and SEM petrography, plus combined bulk and clay XRD analyses and key aspects controlling the porosity and permeability of this formation are revealed by focusing on the detailed mineralogy, rock type, diagenetic mineral distribution plus overall reservoir quality and the fluid sensitivity. Results show that the Three Forks mineralogy is dominated by dolomite, along with substantial hematite, monocrystalline quartz and mica flakes with trace feldspar, calcite, and pyrite. EDX spectra show that the element distribution is influenced by the lithotype composition, mainly Ca, Mg, and Fe with additional Si, Al, and K. Three stages of the dolomitization process are identified and discussed. Clays mainly consist of illite together with minor chlorite, and kaolinite and are associated with the scattered clasts of quartz and feldspars. The reservoir quality is controlled by intercrystalline, rare micro-vuggy, plus microporosity types that result from diagenetic and depositional events. Six members of the Three Forks are identified and log-derived porosities, water saturations, and net-togross values for each Member calculated and areas with high reservoir quality and potential pay zones highlighted. Also, core data are quantitatively compared with results from the Archie, Simandoux, Modified Simandoux, Indonesia, and Dual-Water models. A proposed depositional model is constructed based on detailed core examination and petrographical analysis and sufficient evidence is provided to show that the Three Forks Formation is of peritidal to sabkha-like origin. A proposed hypothesis is that dolomitization commenced soon after deposition and was pervasive that no original carbonate texture is detectable

Woodford Shale enclosed mini-basin fill on the Hunton Paleo Shelf. A depositional model for unconventional resource shales

The exploration of unconventional hydrocarbon resources of the Woodford Shale in Oklahoma (USA) has focused on characterizing this formation as an entirely open marine deposit. The impact of recognizing the enclosed mini-basin fill settings remains under-explored. To better understand these effects, I propose a detailed integrated study to highlight how these depositional variations occur. It is necessary to perform a workflow that involves multidisciplinary integration of geological, geochemical (both organic and inorganic) and geophysical characterizations to identify the characteristics of these deposits, how they vary vertically in the stratigraphic section of the Woodford Shale (internal variations in organic matter content and type; variability of the major heavy elements; and differences in mineralogy), and how they are laterally dissimilar by analyzing and comparing different Woodford locations in the Oklahoman petroleum provinces. The enclosed mini-basin fill settings occur locally in areas of thicker (gross thickness greater than 200 ft) and more organic-rich Woodford Shale (greater than 5.5 % on average of total organic carbon TOC). By understanding the context of regional sea-level fluctuations in the Upper Devonian time, it is observed that the Woodford Shale is deposited upon a pre-existent carbonate platform, where this platform was previously eroded by karstification or incised valley development during regional sea level drops at the pre-Woodford time. These karst/incised valley-forming processes formed a regional erosional unconformity, which allowed the development of sinkholes, pockets, and pods with more accommodation space for Woodford Shale sediment deposition in enclosed mini-basin fill settings. These erosional unconformities can be identified in outcrops, cores, well logs, and on 3D seismic data sets. I propose that the localized and discontinuous enclosed mini-basin fills settings represented silled constricted oceanic circulation with higher bottom-water euxinia (high free sulfur), which had better conditions for accumulation and preservation of clay and organic matter particles than did the well-circulated, open marine settings. I interpret that these depositional differences provide recognizable patterns in bed thickness and organic matter variations inside the Woodford Shale. I propose that areas in Oklahoma with thicker Woodford enclosed mini-basin fill settings are stratigraphical variations that could economically produce more oil and gas than other areas deposited under more open marine conditions or thinner enclosed mini-basin fill intervals. I capture these intervals by determining which ones contain more organic matter, more hydrogen, lower oxygen, more amorphous organic matter (more oil-prone than gas prone), the differences in paleo water chemistry (water column stratification, higher water salinity, higher levels of anoxia and euxinia). I recognize that these enclosed mini-basin fill geochemical characteristics are combined with the identification of enrichments in detrital quartz and relatively high depletions in the clay content of the lithofacies. The enclosed mini-basin fill deposits not only accumulate more organic matter but present different petrophysical and mechanical characteristics that, when modeled, simulated and compared with reported production, recover higher volumes of hydrocarbons under the standard unconventional petroleum industry operational practices

Reservoir Characterisation of Gas Shale through Sedimentary, Mineralogical, Petrophysical and Statistical Rock Types Evaluation

The successful exploration and production of the gas shale reservoirs can help to face the current energy crisis. However, shale is a fine-grained heterogeneous rock, so its exploration and development are challenging. This research has provided an integrated method for analysis, evaluation, and synthesis of potential gas shale formations in the Canning Basin, Western Australia. The results form a valuable case study that is applicable to many other sedimentary basins throughout the world

A comparative study of the hydrocarbon generation potential of Korean and Australian tertiary/cretaceous sedimentary basins

The southern and southeastern Korean Continental Shelf basins and the Gippsland Basin in southeastern Australia both contain thick Tertiary sedimentary sequences. The Gippsland Basin has more than 3.7 billion barrels of recoverable oil whereas commercial reservoirs remain to be discovered in the Korean basins. The tectonic settings, depositional environments, burial and thermal histories of both the Korean basins and Gippsland Basin, are in many ways, broadly similar. Each area has a non-marine, coal-bearing sequence overlain by a thick marine sequence. In both areas the best source rocks are associated with the thick non-marine sequences

Basic properties and exploitation strategies of source rock strata

Source rock strata are filled and aggregated with large-scale continuous hydrocarbon resources, including significant volumes of in-place retained, short-distance migrated and potentially generated hydrocarbons. Source rock strata simultaneously possess the properties of reservoirs and hydrocarbon source rocks, known as source-reservoir coexisting systems. Reservoir properties refer to the physical properties concerning the storage and transmission of oil and gas, while hydrocarbon source rock properties refer to the physicochemical properties related to governing the generation, retention and expulsion of oil and gas in the source rock strata. These properties fundamentally determine the technical path for the successful exploitation of petroleum and natural gas in the source rock strata. With regard to reservoir properties, in-depth research and development of the advanced energy-storing fracturing technology can aid the construction of complex fracture networks to overcome the limitations in the connectivity properties of source rock strata. Focusing on the hydrocarbon source rock properties, an underground in-situ conversion technology should be created and developed to alleviate the shortcomings of organic matter quantity and maturity properties of the source rock strata. Furthermore, selecting the appropriate exploitation path based on the property characteristics can promote the achievement of commercial and sustainable development of oil and gas in the source rock strata.Document Type: PerspectiveCited as: Yang, Z., Zou, C., Fan, Y., Wu, S., Liu, H., Wei, Q. Basic properties and exploitation strategies of source rock strata. Advances in Geo-Energy Research, 2023, 10(2): 77-83. https://doi.org/10.46690/ager.2023.11.0

Lithological and facies analysis of the Roseneath and Murteree shales, Cooper Basin, Australia

Unconventional shale plays have received marked attention over the last five years because of their economic potential for hydrocarbon generation, and yet they are amongst the least understood of all clastic sedimentary rock systems. The Cooper Basin is one of the largest Gondwana intracratonic basins in Australia, extending from northern South Australia into south-western Queensland and covering approximately 130,000 km2. The basin is may be prospective for shale gas, particularly within the lacustrine shales of the Permian Murteree and Roseneath formations. This study investigates lithological characteristics of these two units in relation to reservoir evaluation. Core samples representing the Dirkala-02 and Moomba-46 wells were used for petrographic analysis. A combination of wireline log analysis, thin section petrography, X-ray diffraction and pyrolysis analysis was used to define and characterize four distinct lithofacies facies within the Roseneath and Murteree shales: siliceous mudstone, organic siliceous mudstone, calcareous siliceous mudstone, and silty siliceous mudstone. The siliceous mudstone and organic siliceous mudstone are the most common. Diagenetic siderite occurs in all four lithofacies. A conceptual depositional model is developed for deposition of the Roseneath and Murteree shales. Wireline-log cross plots were interpreted and utilized in the construction of electrofacies. The study was concentrated on the northern portion of the basin between the Nappameri and Patchawarra Troughs in order to understand the nature of lithofacies and variability in reservoir architecture, which was controlled by relative lake level fluctuation. The results of this study will aid in the evaluation of shale gas potential for this portion of the basin, as well as a better understanding of shale gas opportunities in the Cooper Basin more generally

Relating Sonic Velocities, Minimum Horizontal Stress, and Natural Fracture Distribution to Stimulation Efficiency during Completion of the Marcellus Shale MIP-3H Unconventional Well, West Virginia, USA

Log data from the Marcellus Shale Energy and Environment Laboratory (MSEEL) was acquired along the lateral of the MIP-3H well. This unconventional shale-gas well was completed within the Marcellus Shale just above the Cherry Valley Limestone, a thin limestone member separating organic rich units of the Marcellus. The geomechanical moduli, Poisson’s Ratio (PR) and Young’s Modulus (YME), were generated using compressional and shear sonic logs to indicate zones of increasing brittleness for each of the 28 stages along the 6124 ft. (1867m) horizontal lateral. Brittle reservoir rock is more readily fractured during hydraulic stimulation than more malleable rock. Stages with geomechanically homogeneous clusters were more likely to have evenly distributed energy during stimulation. Natural fractures formed during maturation of the Marcellus Shale are interpreted to have initiated during the Permian and are distributed along the wellbore. The contrast between calcite and shale in Schlumberger Quanta Geo logs facilitated fracture identification, and 1600 calcite-filled and a few open pre-existing fractures were recognized along the horizontal portion of the well. Research conducted suggests that all pre-existing fractures are reactivated during hydraulic stimulation and contribute to the complex fracture network. Because these fractures are reactivated during the hydraulic fracturing process, natural fracture intensity and distribution within stages can impact the efficiency of stimulation. Minimum horizontal stress (Shmin) is an important factor to consider in the completion process. Cluster placement at locations of equal or similar Shmin allows for fracturing fluid to more evenly disperse across all perforations. Hydraulic stimulation data were obtained with the use of a fiber optic cable. The distributed acoustic sensing (DAS) data allows for a comparison of the energy distribution during stimulation. Comparing geomechanical properties of individual stages to the apparent stimulation efficiency shown in the DAS data can result in improved methods of well completion. This would lead to more geologic approaches to stage and perforation completion rather than geometric. Increased stimulation efficiency could increase production and estimated ultimate recovery from unconventional shale-gas reservoirs

Natural Fracture Evolution: Investigations into the Middle Devonian Marcellus Shale, Appalachian Basin, USA

Optimizing recovery from unconventional shale reservoirs has generated considerable research into optimal recovery methods through hydraulic fracturing design and shale reservoir characterization in the development of long-term hydrocarbon producers. Permeability at multiple scales from nanometer-scale pore sizes and nano-darcy permeability to completion-induced fractures defining a 100’s of meter stimulated reservoir volume plays a significant role in hydrocarbon flow during production in shale reservoirs. Preexisting cemented fractures in unconventional shale reservoirs are abundant and preferentially reactivate during induced hydraulic fracturing treatment to create necessary large-scale permeability. While previous investigations have significantly improved our knowledge of shale reservoirs, it has also highlighted the need for increased understanding of the geologic evolution and effect on hydraulic stimulation of pre-existing cemented fractures. This three-part dissertation examines natural fractures from four middle Devonian Marcellus Shale wells across the Appalachian basin through integration of visual core observation, thin section petrography, spectral gamma ray logs, borehole image logs, petrophysical logs, elemental data, and X-ray computed tomography cores. The research goals are: (1) to establish clues to assess natural fracture development in source rocks from kerogen maturation, relative timing, and hydrocarbon migration; (2) to investigate the relationship of natural fractures in wells of varying thermal maturity levels, and preferential fracture distribution in various clay types and redox environments; and (3) to characterize mineralized natural fractures in 3D using a medical CT-scan core to quantify volume and assess connectivity. This research indicates that overpressure from kerogen expulsion of hydrocarbon creates numerous cemented fractures filled with calcite and bitumen that achieve orientations related to the geologic burial stresses during their evolution, predominant in clay-rich units of certain redox conditions, cluster at geomechanical boundaries, and have inconsistent 3D volume changes within the core

Effects of magmatic intrusions on temperature history and diagenesis in sedimentary basins – and the impact on petroleum systems

For many volcanic basins, the thermal effect of igneous intrusions is decisive for their petroleum potential because such thermal impact may lead to maturation of organic material in areas that otherwise would remain immature. Many factors contribute to the outcome of such intrusions, and in this thesis the influence of a number of parameters, including sill thickness, timing of emplacement, structural changes of sedimentary basins, lithologies and diagenesis, have been modeled to improve the ability to predict the development of the whole petroleum system as a function of its thermal history. By quantifying the effect of several of these factors, the aim of this project has been to estimate the thermal impact of magmatic intrusions on maturation and diagenesis, from the very first temperature increase in the host rock to the long term influence, in terms of permeability and migration. Sill thickness and timing of emplacement is central in the first Paper where the thermal effect of 0 m, 50 m and 100 m thick sills are compared. The results show large differences on the thermal effect of the tested thicknesses, particularly for 0 m versus 100 m, but also 50 m versus 100 m thick sills. Whereas immature areas in the vicinity of sills that are 50 m thick will remain immature, they become fully matured when the sills are twice as thick. Timing of sill emplacement can be essential, particularly if the source rocks are between two or more sills intruded with a time lapse. Transient thermal effects of normal faulting in basins with magmatic intrusions are in focus in the second Paper. As fault movements occur, the basin momentarily experiences thermal instability in the proximity of the fault zone. How long this thermal instability lasts, depends on several factors, such as the physical properties of the rocks and the time lapse of fault movement. The results show that the largest differences between steady state and transient thermal calculations are found in the hanging wall. If sills intrude shortly after fault movement, the rocks in the hanging wall are colder than the rocks at the same depth in the foot wall. As the thermal effect of magmatic intrusions is dependent on the pre-intrusion host-rock temperatures, the thermal effect of the sills is smaller in the hanging wall than the foot wall due to the lower host rock temperatures. However, if the sills intrude with a time lapse in relation to the fault slip, the sedimentary rocks have become warmer and the effect of the intruding sills is larger. Other factors that influence the thermal effects of sill intrusions in sedimentary basins are fault displacement, time span of faulting and deposition, fault angle, the thermal conductivity of the rocks, specific heat capacity and basal heat flow. How the faults are restored in the modeling process also influences the thermal development in the basin after fault slip. Diagenesis/chemical compaction is the focus of the third Paper. The study quantifies the thermal effect of magmatic intrusions on three different diagenetic processes: the transition of opal A to opal CT to quartz; the smectite to illite transition; and the dissolution and re-precipitation of quartz. All these processes are temperature dependent and may induce deterioration of the reservoir quality by reducing the porosity. Diagenetic alterations can contribute to changes in the physical properties of the rocks. These changes can cause rocks to respond differently to stress conditions in the subsurface. Emplacement of magmatic intrusions influences all the studied diagenetic processes and result in porosity loss of rocks in their proximity. Results show that stresses build up in the stiffer rocks, like the sills and diagenetic altered areas. Such stress accumulations may potentially lead to fault slip or opening of fractures and thus increase the permeability and the potential of fluid migration. Overall, this study shows the need for good representation of the subsurface sill thicknesses and structural development, particularly prior to emplacement of magmatic intrusions. Through magmatic intrusion and their impact on the maturation of organic material, diagenetic processes, location of stress concentrations, and the potential effect on permeability and migration pathways, this study highlights how these factors may have long-term effect on the petroleum system. Other crucial variables are sill thickness and clustering of the sills at multiple levels. The thermal conductivity of host rocks is the factor influencing the transient thermal effects the most, after fault slip and the increased temperatures enhance maturation and diagenesis in their vicinity