Shale Intervals Research Articles

Integrated reservoir characterization of a Utica Shale field

We performed an integrated multidisciplinary study for reservoir characterization of a Utica Shale field in eastern Ohio covered by a multiclient 3D seismic data set acquired in 2015. Elastic seismic inversion was performed in-house for effective reservoir characterization of the Utica Shale, which covers the interval from the top of Upper Utica (UUTIC) to the top of Trenton Limestone. Accurate, high-fidelity inversion results were obtained, including acoustic impedance, shear impedance, density, and VP/VS. These consistent inversion results allow for the reliable calculation of geomechanical and petrophysical properties of the reservoir. The inverted density clearly divides the Point Pleasant (PPLS) interval as low density from the overlying UUTIC Shale interval. Both Poisson's ratio (PR) and brittleness unmistakably separate the underlying PPLS from the overlying Utica interval. The PPLS Formation is easier to hydraulically fracture due to its much lower PR. Sequence S4 is the best due to its higher Young's modulus to sustain the open fractures. The calculated petrophysical volumes indisputably delineate the traditional Utica Shale into two distinctive sections. The upper section, the UUTIC, can be described as having 1%–2% total organic carbon (TOC), 3.5%–4.8% porosity, 10%–24% water saturation, and 40%–58% clay content. The lower section, PPLS, can be described as having 3%–4.5% TOC, 5%–9% porosity, 2%–10% water saturation, and about 15%–35% clay content. Both sections exhibit spatial variation of the properties. Nevertheless, the underlying PPLS is obviously a significantly better reservoir and operationally easier to produce.

Hydrocarbon source rock potential evaluation of the Late Paleocene Patala Formation, Salt Range, Pakistan: Organic geochemical and palynofacies approach

Organic geochemical and palynofacies analyses were carried out on shale intervals of the Late Paleocene Patala Formation at Nammal Gorge Section, western Salt Range, Pakistan. The total organic carbon content and Rock-Eval pyrolysis results indicated that the formation is dominated by type II and type III kerogens. Rock-Eval \({T}_{\mathrm{max}}\) vs. hydrogen index (HI) and thermal alteration index indicated that the analysed shale intervals present in the formation are thermally mature. \(S_{1}\) and \(S_{2}\) yields showed poor source rock potential for the formation. Three palynofacies assemblages including palynofacies-1, palynofacies-2 and palynofacies-3 were identified, which are prone to dry gas, wet gas and oil generation, respectively. The palynofacies assessment revealed the presence of oil/gas and gas prone type II and type III kerogens in the formation and their deposition on proximal shelf with suboxic to anoxic conditions. The kerogen macerals are dominated by vitrinite and amorphinite with minor inertinite and liptinite. The kerogen macerals are of both marine and terrestrial origin, deposited on a shallow shelf. Overall, the dark black carbonaceous shales present within the formation act as a source rock for hydrocarbons with poor-to-moderate source rock quality, while the grey shales act as a poor source rock for hydrocarbon generation.

Comprehensive stability analysis of an inclined wellbore embedded in Colorado shale formation for thermal recovery

Thermal processes have been widely used to recover heavy oil from oil-sands reservoirs, where the overburden shale undergoes cyclic heating and cooling processes. During thermal operations, thermally induced pore pressure can be developed in the shale formation around a thermal well and thermal pore pressure may lead to plastic yielding in the shale. In this study, integrated characterization results on anisotropic thermal-hydro-mechanical (THM) properties of Colorado shale with different clay fractions are presented. Low strength shale intervals along a borehole are identified and the characterized results are used to conduct a stability analysis on an inclined wellbore during thermal operations. The effect of thermally induced pore pressure in Colorado shale on the integrity of a thermal well is investigated using 3D THM-coupled finite element analysis with the consideration of shale's transversely isotropic (TI) elastic characteristics. The results indicate that the wellbore can lose the confinement in high clay fraction shale intervals due to the thermal operation. The mechanisms can be caused by the thermal pore pressure-induced shear plastic yielding behavior in the Colorado shale formation. Tensile fracturing behavior is less likely to happen. The consideration of anisotropy in elastic properties is important in characterizing the shale's stress path in the analysis. Compared with the result based on the TI elastic model, the result based on the isotropic elastic model gives less plastic yielding zone which underestimates the risk.

Lower Palaeozoic petroleum systems of the Baltic Basin in northern Poland: A 3D basin modeling study of selected areas (onshore and offshore)

We have developed a Lower Palaeozoic petroleum systems analysis in the selected zones of the Polish section of the Baltic Basin (onshore and offshore), which we carried out to assess the potential of shale rock formations as unconventional reservoirs. The areas of the Baltic Basin, which we analyzed represent a diversity of shale formations burial depths and thus different advancement of sediments compaction and organic matter transformation. Methods of dynamic petroleum systems modeling were applied with a 3D modeling workflow (PetroMod suite software). We considered an extensive array of data, including results of geochemical and petrophysical laboratory measurements, geophysical borehole data and, in selected locations — 3D seismic data. Five potentially perspective shale rock intervals (Silurian [2], Ordovician [2], and Upper Cambrian [1]) are identified and interpreted in terms of their geochemical and petrophysical properties. We calibrated the petroleum system models in terms of proper reproduction of diagenetic processes (pore pressure and porosity), thermal conditions (vitrinite reflectance, temperature), and kerogen kinetic model (organic matter transformation ratio, types of hydrocarbons generated). The results of the petroleum system simulations reveal that for the predominant part of the analyzed area, the achieved level of kerogen thermal maturity determines the generation of liquid hydrocarbons, which results in the present-day saturation of shale formations mainly with crude oil. We concluded that the highest generation yields as well as present-day hydrocarbons in place are observed for Ordovician Sasino Formation (onshore and offshore), Silurian/Llandovery Jantar member (onshore), and Upper Cambrian (alum shales) formation. Furthermore, a significant variation in the mass/volumes of accumulated hydrocarbons is observed within each of the shale formations being considered.

Connotation and strategic role of in-situ conversion processing of shale oil underground in the onshore China

Abstract In-situ conversion processing (ICP) of shale oil underground at the depth ranging from 300 m to 3 000 m is a physical and chemical process caused by using horizontal drilling and electric heating technology, which converts heavy oil, bitumen and various organic matter into light oil and gas in a large scale, which can be called “underground refinery”. ICP has several advantages as in CO2 capture, recoverable resource potential and the quality of hydrocarbon output. Based on the geothermal evolution mechanism of organic materials established by Tissot et al., this study reveals that in the nonmarine organic-rich shale sequence, the amount of liquid hydrocarbon maintaining in the shale is as high as 25% in the liquid hydrocarbon window stage (Ro less than 1.0%), and the unconverted organic materials (low mature-immature organic materials) in the shale interval can reach 40% to 100%. The conditions of organic-rich shale suitable for underground in-situ conversion of shale oil should be satisfied in the following aspects, TOC higher than 6%, Ro ranging between 0.5% and 1%, concentrated thickness of organic-rich shale greater than 15 meters, burial depth less than 3 000 m, covering area bigger than 50 km2, good sealing condition in both up- and down-contacting sequences and water content smaller than 5%, etc. The shale oil resource in China's onshore region is huge. It is estimated with this paper that the technical recoverable resource reaches 70−90 billion tons of oil and 60−65 trillion cubic meters of gas. The ICP of shale oil underground is believed to be a fairway to find big oil in the source kitchen in the near future. And it is also believed to be a milestone to keep China long-term stability of oil and gas sufficient supply by putting ICP of shale oil underground into real practice in the future.

The Lower Toarcian Serrone Marls (Northern Apennines, Italy): A 3.5 Myr record of marl deposition in the aftermath of the T-OAE

The early Toarcian sedimentary record is frequently characterized by the occurrence of marls, shales, and organic rich facies comprising the Toarcian oceanic anoxic event (T-OAE), which are broadly synchronous to the emplacement of the Karoo-Ferrar large igneous province (LIP) with a main pulse at ~181.7 Ma. Here we describe the chronology and rock magnetic properties of the early Toarcian Marne del Serrone Formation (Serrone Marls) from the Monte Serrone section in the Northern Apennines of Italy, and interpret them as reflecting the local environmental response to the transient CO2 rise and accelerated hydrological cycle most likely induced by the emplacement of the Karoo-Ferrar LIP. The studied 62 m-thick section is characterized by a succession of micritic limestones and marls, interrupted by a few slumps, and contains a record of the T-OAE represented by posidonia beds and a ~40 cm-thick black shale interval. The age of the section has been constrained using magnetostratigraphy and ammonite biostratigraphy to the Spinatum to Variabilis zones. Rock-magnetic properties have been used to characterize fluctuations in the magnetite and hematite input throughout the section. Spectral analysis of continuous IRM2.5T and IRM0.1T/IRM2.5T records indicates a duration of the studied marly interval of ca. 3.5 Myr, regarded as a first-order estimate of the duration of the response of the environmental system (hydrological cycle) to the transient climate perturbation triggered by the emplacement of the Karoo-Ferrar LIP, and a duration of the Bifrons zone of ca. 3.4 Myr.

Refining the Jurassic-Cretaceous boundary: Re-Os geochronology and depositional environment of Upper Jurassic shales from the Norwegian Sea

Limited chronological information for Upper Jurassic rocks hampers precise age assignment of the Jurassic-Cretaceous (J/K) boundary. This study presents Re-Os geochronology, Rock-Eval pyrolysis and geochemical data for Upper Jurassic rocks in the Nordland VII area, offshore northern Norway. Four intervals of organic-rich shale were investigated, two from the Krill and one from the Alge Member of the Hekkingen Formation and one from the underlying Måsnykan Formation (drilled cores 6814/04/U-01 and 6814/04/U-02). Rock-Eval pyrolysis data indicate immature organic matter with mixed (Type II/III) oil-gas potential in these units. Among the four intervals, Re-Os isochroneity prevails only for the Hekkingen Formation samples; data from the shale interval in the otherwise sand-rich Måsnykan Formation, deposited in a shoreface-to-foreshore marine environment, are not isochronous. Non-isochroneity of the samples from relatively proximal setting is attributable to non-conservative elemental (desorption of Os from sediments to dissolved phase) and isotopic exchange of Os at this depositional site. The Re-Os isochron age for the Alge Member (153.2 ± 7.3 Ma (Model 3); MSWD = 29; n = 9) is consistent with its biostratigraphic Kimmeridgian age (152.1–157.3 Ma). A Re-Os isochron for the lower part of the Krill Member yields an age of 144.5 ± 1.4 Ma (Model 3; MSWD = 3.7; n = 10) with an initial 187Os/188Os ratio of 0.552 ± 0.007. Given the interval's lower Tithonian biostratigraphic age, the Re-Os age suggests that the J/K boundary must be a few Myr younger than its currently assigned age of ~145.0 Ma (2017/02 time scale; www.stratigraphy.org). A Re-Os model age for shales from the upper part of the Krill Member places an upper age limit for the J/K boundary at 142 (±2) Ma. Hence, the J/K boundary is between 142 Ma and 144.5 Ma.Fe and S concentrations for the Hekkingen Formation show strong correlation and the S/Fe slope (~1.19) mimics the stoichiometric S/Fe ratio for pyrite (~1.15). A Fe-S-TOC ternary diagram for these samples points to an iron-limiting, sulphidic depositional environment. Anoxic to sulphidic depositional conditions for the Hekkingen shales are also evident from relatively higher authigenic enrichment of Mo compared to U. Unlike the Hekkingen Formation, shales from the more sandy Måsnykan Formation have lower S/Fe ratios and lower enrichment factors for redox-sensitive elements, indicating relatively oxygenated marine conditions during deposition.

Joint geophysical and geochemical evaluation of source rocks – A case study in Sayun-Masila basin, Yemen

Integration of geophysical and geochemical approaches is used for qualitative and quantitative evaluation of source rocks. The Upper Jurassic rocks in the Sayun-Masila basin are used as a case study due to its high hydrocarbon potentiality. Stratigraphically, these rocks could be differentiated from base to top into: Shuqra, Madbi and Nayfa formations. The total organic carbon (TOC) values were determined in the shale and/or carbonate intervals of these formations from four studied wells by the ΔlogR method using sonic, resistivity and gamma-ray log data. Then the discriminant analysis was applied in differentiating source from non-source rocks. Also, the effect of the burial and thermal histories on the organic material maturation and the oil and/or gas generation was studied through the application of two analytical methods, namely, the level of organic metamorphism (LOM) and the time-temperature index (TTI), depending on the corrected temperature logs integrated with the time and depth data. The reliability of the obtained results has been confirmed and combined with the results supplied from geochemical analyses. The Upper Jurassic sediments are found to be oil–prone source rock in a mature stage. The Madbi Formation is considered as the most effective source rock. The burial and thermal histories of the basin in four modeled wells showed that mature oil generation window and hydrocarbon expulsion would have been initiated in the depocenters from Upper Jurassic Madbi Formation source rock during Late Cretaceous to Middle Miocene time.

The first data on the porous space structure of the Domanik shales as a potential object for EOR applying

The resources of shale oil, contained in the organic matter of the wood deposits, can be considered as a source of profitable production of hydrocarbons, when modern EOR technologies are used. As a result of the primary studies of the pore space structure, it is revealed that two types of porous space are prevailing in the studied samples of the Domanik oil shales. The most prevailing is intrakerogen porosity with pore volumes of 5 × 10-8 1 × 10-6 mm3. The volumetric reconstruction of the structure of this pore space shows that the voids are confined directly to micro lenses of organic matter. The second type of the found void is represented by leaching cracks. It is characteristic of more carbonate varieties of the Dominik oil shale with spotted structure. It is the oil shale intervals with such cracks that are of greatest interest to the EOR, since they consist of a large area with smaller pores and through which pressurization and spread of various agents are possible to occur in order to increase the oil recovery.

Overpressure estimation and productivity analysis for a Marcellus Shale gas reservoir, southwest Pennsylvania: A case study

It is well established that geology, geomechanics, and completion play an important role in gas productivity from shale formations. In particular, overpressured shale — along with higher fracture intensity — generally correlates with higher production rates. Conventional pore-pressure prediction techniques do not work well for black shale formations, primarily because a basin has often experienced multiple episodes of tectonic activity and subsequent overpressure generation; secondly, because the recorded petrophysical logs for pore-pressure estimation are significantly affected by the presence of organic content and gas. Overpressure mechanisms and distribution are studied for the Middle Devonian Marcellus Shale Formation of the Appalachian Basin in Pennsylvania to understand their relationship with well productivity. A sonic velocity-density crossplot does not reveal a clear picture of overpressure generation, primarily due to complex geologic history and distinct compositional variation between Marcellus Shale and overburden shale. 1D pore pressure was estimated from sonic velocity using traditional methods with pressure reference trend for the Marcellus Shale interval in the drilled wells and calibrated to the available in situ pressure measurements. 3D pore pressure was then estimated with upscaled 1D pore-pressure profiles and 3D seismic velocity data. Results suggest that the area having higher overpressure of about 160 psi produces about 55% more gas than the lower overpressure area. Further, understanding the spatial variation of overpressure in the study area may facilitate better field development planning.

Integrated shale-gas reservoir characterization: A case study incorporating multicomponent seismic data

The objective of this case study is to predict geologic properties of a shale reservoir interval to guide production and completion planning for successful development of the reservoir. The conditioning, analysis, and blending of the converted-wave (PS) seismic data into a quantitative interpretation (QI) workflow are described in detail, illustrating the successful integration of geologic information and multiple seismic attributes. A multicomponent 3D seismic survey, several wells with dipole sonic logs, and a multicomponent (3C) 3D vertical seismic profile are available for the study. For comparisons of the incremental value of PS data, the QI workflow is completed entirely using only PP data and then modified and redone to incorporate information from the PS data. Predictions of the geologic properties for both workflows are assessed for accuracy against the existing well log and core evidence. Determining reservoir properties of the shale units of interest is important to the successful placement of horizontal wells for efficient multistage hydraulic fracturing and maximum gas production. Although conventional interpretation of conventional seismic data can only provide reservoir geometry, the quantitative analysis of prestack multicomponent data in this study reveals detailed distinctions between reservoir units and relative measures of porosity and brittleness bulk properties within each unit. Using all of the elastic properties derived from the seismic data analysis allowed for the classification of lithological units, which were, in turn, subclassified based on unit-specific reservoir properties. The upper reservoir units (Muskwa and Otter Park) were shown to have more variability in brittleness than the lower reservoir unit (Evie). Validation at a reliable well control confirmed these distinctive units and properties to be very high resolution and accurate, particularly when the PS data were incorporated into the workflow. The results of this method of analysis provided significantly more useful information for appraisal and development decisions than conventional seismic data interpretation alone.

Biomarkers stratigraphy of Irati Formation (Lower Permian) in the southern portion of Paraná Basin (Brazil)

This study covers the application of biomarkers as stratigraphic markers in a Lower Permian marine section from the Paraná Basin, southern Brazil. The biomarker variations reveal changes in sedimentary environment that were not detected by sedimentological and paleontological methods and will contribute to high resolution stratigraphy. The Irati Formation contains two lithostratigraphic units: (1) the lower unit (Taquaral Member) is composed of shales, deposited in a marine epicontinental to restricted environment and (2) the upper unit (Assistência Member) which consists of carbonates interbedded with shales and organic-rich shale intervals deposited in a restricted marine environment. The biomarker differences observed in the Taquaral Member can be explained by two different types of organic matter. The lower and upper parts are characterized by a high relative abundance of high molecular weight n-alkanes, C27 (17α) trisnorhopane, C31 αβR homohopane, high hopanes/steranes ratio, and low hydrogen index values. This facies contains greater relative amount of terrestrial organic matter. The low hopanes/steranes ratio, together with the high hydrogen index values and amorphous organic matter relative proportion observed in the middle part of the Taquaral Member indicate a more marine organic matter contribution. In the Assistência Member based on gammacerane/C30 αβ hopane ratio, C28ααα (20R) methylcholestane/C29ααα (20R) methylcholestane ratio, total organic carbon, hydrogen index values, palynofacies and sedimentary structures it was possible to distinguish changes in salinity and redox conditions. The bituminous shales intervals were deposited in an anoxic environment (high total organic carbon, high hydrogen index values, high preserved amorphous organic matter content) with lower salinity (lower gammacerane/C30 αβ hopane and C28ααα (20R) methylcholestane/C29ααα (20R) ethylcholestane ratios) on the other hand, the limestones intervals were deposited in an aerobic environment (low total organic carbon, low hydrogen index values, high oxidized organic matter content) with higher salinity (higher gammacerane/C30 αβ hopane and C28ααα (20R) methylcholestane/C29ααα (20R) methylcholestane ratios).

Impact of Paleosalinity, Dilution, Redox, and Paleoproductivity on Organic Matter Enrichment in a Saline Lacustrine Rift Basin: A Case Study of Paleogene Organic-Rich Shale in Dongpu Depression, Bohai Bay Basin, Eastern China

Saline, lacustrine rift basins (SLRBs) can contain very productive shale oil plays, in which “sweet spots” are closely related to organic-rich shale intervals. However, organic matter enrichment in...

Diagenetic variation at the lamina scale in lacustrine organic-rich shales: Implications for hydrocarbon migration and accumulation

Lacustrine carbonate-rich shales are well developed within the Mesozoic-Cenozoic strata of the Bohai Bay Basin (BBB) of eastern China and across southeast Asia. Developing an understanding of the diagenesis of these shales is essential to research on mass balance, diagenetic fluid transport and exchange, and organic-inorganic interactions in black shales. This study investigates the origin and distribution of authigenic minerals and their diagenetic characteristics, processes, and pathways at the scale of lacustrine laminae within the Es4s-Es3x shale sequence of the BBB. The research presented in this study is based on thin sections, field emission scanning electron microscope (FESEM) and SEM-catholuminescence (CL) observations of well core samples combined with the use of X-ray diffraction (XRD), energy dispersive spectroscopy, electron microprobe analysis, and carbon and oxygen isotope analyses performed using a laser microprobe mass spectrometer. The dominant lithofacies within the Es4s-Es3x sequence are a laminated calcareous shale (LCS-1) and a laminated clay shale (LCS-2). The results of this study show that calcite recrystallization1 is the overarching diagenetic process affecting the LCS-1, related to acid generation from organic matter (OM) thermal evolution. This evolutionary transition is the key factor driving the diagenesis of this lithofacies, while the transformation of clay minerals is the main diagenetic attribute of the LCS-2. Diagenetic differences occur within different laminae and at variable locations within the same lamina level, controlled by variations in mineral composition and the properties of laminae interfaces. The diagenetic fluid migration scale is vertical and responses (dissolution and replacement) are limited to individual laminae, between zero and 100 μm in width. In contrast, the dominant migration pathway for diagenetic fluid is lateral, along the abrupt interfaces between laminae boundaries, which leads to the vertical transmission of diagenetic responses. The recrystallization boundaries between calcite laminae act as the main migration pathways for the expulsion of hydrocarbons from these carbonate-rich lacustrine shales. However, because the interaction between diagenetic fluids and the shales themselves is limited to the scale of individual lamina, this system is normally closed. The occurrence of abnormal pressure fractures can open the diagenetic system, however, and cause interactions to occur throughout laminae; in particular, the closed-open (C–O) diagenetic process at this scale is critical to this shale interval. Multi-scale C–O systems are ubiquitous and episodic ranging from the scale of laminae to the whole basin. Observations show that such small-scale systems are often superimposed onto larger ones to constitute the complex diagenetic system seen within the BBB combining fluid transport, material and energy exchange, and solid-liquid and organic-inorganic interactions.

Molybdenum record from black shales indicates oscillating atmospheric oxygen levels in the early Paleoproterozoic

The early Paleoproterozoic witnessed Earth9s first major oxygenation, referred to as the Great Oxidation Event or GOE. The GOE began around 2.45 billion years ago (Ga) and progressed over hundreds of millions of years, as evidenced by multiple redox indicators, before coming to an abrupt end by ca. 2.06 Ga. The details of the GOE and the extent of oxygenation are still not resolved, however, and it is not clear how redox conditions across the GOE compare with those during the middle Proterozoic. In order to investigate the evolution of deep-ocean redox conditions during the GOE, we present Mo concentration and isotope data together with Fe speciation values for three key organic matter-rich shale units of the early Paleoproterozoic age (2.32–2.06 Ga). In addition, we present a new graphical representation of modeling suggesting that the oceanic Mo isotope system is highly sensitive to the balance between anoxic/suboxic and euxinic conditions until deep-ocean oxygenation, similar in scale to modern ocean oxygenation, is reached. Our approach indicates rising, yet oscillating atmospheric oxygen at 2.32 Ga, leading to an abrupt increase in Mo supply to the oceans and large Mo isotope variations under non-steady state conditions. The low seawater δ98Mo value based on the ca. 2.32 Ga black shales (0.32 ± 0.58‰) suggests that the oceans were still largely anoxic with locally developed euxinic conditions. Between 2.2 and 2.1 Ga, during the peak of the Lomagundi carbon isotope excursion, we observe higher δ98MoSW values (1.23 ± 0.36‰) together with lower Mo concentrations in euxinic shales ([Mo] = 6.3 ± 9.0 ppm). We suggest that a decrease in the continental Mo input flux in the later part of the GOE was the main cause of this trend. Lower sulfide availability on the continents after protracted sulfide weathering associated with the early stages of the GOE, and efficient Mo removal in poorly oxygenated oceans under weakly euxinic conditions would both have contributed to the contraction of the Mo oceanic reservoir. By ca. 2.06 Ga, the Mo isotope composition of seawater, as inferred from euxinic black shale intervals, became significantly lighter (0.70 ± 0.21‰), reflecting an increased rate of quantitative Mo removal due to the more widespread development of strongly euxinic conditions. Counterintuitively, seawater Mo concentrations recovered, likely due to an increase in the Mo input, which in turn might reflect enhanced weathering of organic carbon-rich shales deposited during the Lomagundi Event.

Oil content evaluation of lacustrine organic-rich shale with strong heterogeneity: A case study of the Middle Permian Lucaogou Formation in Jimusaer Sag, Junggar Basin, NW China

Large shale oil resources were recently been found in lacustrine organic-rich shale with strong heterogeneity, however, few studies have been conducted to examine their oil contents, resulting in considerable risks in lacustrine shale oil exploration. The Middle Permian Lucaogou Formation (P2l) shale in Jimusaer Sag is a typical lacustrine deposit with strong heterogeneity, and its shale oil resource shows great potential. Integrated geochemical characterization of 265 core samples were conducted and results show that the P2l shale developed in an anoxic lacustrine with stratified salty water and the organic matter in the upper sub-member shale of the P2l is more oil-prone than that in the lower sub-member shale of the P2l. The hydrocarbon generation potential of the P2l shale decreases with the kerogen types changing from Type I to Type III, however, the residual hydrocarbon contents of the P2l shale increases from Type I to II1 kerogen, and then decreases from Type II1 to III kerogen, this is mainly due to differentiated hydrocarbon expulsion efficiencies among different kerogen types. Based on S1 and TOC values and the S1/TOC ratios, considering the oil enrichment degree, this study classified the shale oil resources in the P2l shale into four categories: enriched, moderately enriched, less efficient, and invalid resources. The enriched and moderately enriched resources are mainly shales with Type II1 kerogen, followed by Type II2 kerogen, and the middle interval of the Lower P2l shale is the most favourable target for further shale oil exploration. The improved evaluation criteria are applicable for evaluating shale oil plays with strong heterogeneity qualitatively and quantitatively in terrestrial lacustrine basins in other parts of the world.

Preliminary source rock evaluation and hydrocarbon generation potential of the early Cretaceous subsurface shales from Shabwah sub-basin in the Sabatayn Basin, Western Yemen

A conventional organic geochemical study has been performed on the shale samples collected from the early Cretaceous Saar Formation from the Shabwah oilfields in the Sabatayn Basin, Western Yemen. The results of this study were used to preliminary evaluate the potential source-rock of the shales in the Saar Formation. Organic matter richness, type, and petroleum generation potential of the analysed shales were assessed. Total organic carbon content and Rock- Eval pyrolysis results indicate that the shale intervals within the early Cretaceous Saar Formation have a wide variation in source rock generative potential and quality. The analysed shale samples have TOC content in the range of 0.50 and 5.12 wt% and generally can be considered as fair to good source rocks. The geochemical results of this study also indicate that the analysed shales in the Saar Formation are both oil- and gas-prone source rocks, containing Type II kerogen and mixed Types II-III gradient to Type III kerogen. This is consistent with Hydrogen Index (HI) values between 66 and 552 mg HC/g TOC. The temperature-sensitive parameters such as vitrinite reflectance (%VRo), Rock-Eval pyrolysis Tmax and PI reveal that the analysed shale samples are generally immature to early-mature for oil-window. Therefore, the organic matter has not been altered by thermal maturity thus petroleum has not yet generated. Therefore, exploration strategies should focus on the known deeper location of the Saar Formation in the Shabwah-sub-basin for predicting the kitchen area.

Lower Sinemurian - upper Pliensbachian smaller agglutinated foraminiferal events from the eastern part of the Pieniny Klippen Belt (Transcarpathian Ukraine, Western Carpathians)

Diverse and well-preserved foraminifera are documented from the Sinemurian to Pliensbachian deposits from the Priborzhavske-Perechin Zone in the Ukrainian segment of the Pieniny Klippen Belt. The changes in the smaller agglutinated foraminiferal assemblages are compared with the high resolution ammonite biozonation. The foraminifera are observed in four main facies. In biodetritic marls of the Bucklandi - ?Semicostatum zones a response to increasing low-oxic conditions is recorded. Abloom of small Haplophragmoides spp. predates a barren interval of black shales probably in the Semicostatum Zone that in turn precedes an interval of barren black clays in the Turneri Zone. Above this event the FO of Textularia aff. agglutinans is noted. In the lower part of the Raricostatum Zone a bloom of agglutinated foraminifera and subboreal influx is documented. A rapid decrease in agglutinated foraminifera precedes the Sinemurian/Pliensbachian boundary and continues in the early Pliensbachian Jamesoni Zone. Unfavourable conditions for the agglutinated foraminifera culminate in the Ibex – lower Margaritatus zones and represent an interval barren of agglutinated foraminifera. Impoverished assemblages of agglutinated foraminifera reappear higher in the Margaritatus Zone. The paleoecological interpretations based on morphogroup analysis and the relative abundances of agglutinated foraminifera cast light on paleoclimatic and paleoceanographic changes in the Sinemurian-Pliensbachian stratigraphic record of the eastern part of the Pieniny Klippen Belt.

Wiper Trips Effect on Wellbore Instability Using Net Rising Velocity Methods

Background:This paper discusses the wiper trip effects on well instability in shale formations.Objectives:Problematic shale interval sections have been studied for the time spent on the wiper trip operations. Lifting efficiency and well wall instability change with the time analyzed. Detailed drilling operation, formation heterogeneity, rheological and filtration characteristics of polymer water-based mud are discussed. Physical and chemical properties of the drilled formation and drilling fluid are also studied.Materials and Methods:Wiper trips are analyzed using a typical drawing program to find the relations between the most controllable parameters. For that, two calculation models have been implemented to find the net rising cutting particles velocity in the annular. The relation between the net rising velocity and wiper trips is analyzed. Laboratory works have been done to support the findings of field work.Results:Strong relations have been found between the wiper trip impacts and lithology types of the penetrated shale.Conclusion:A modified drilling program is proposed in relation to changes in casing setting depth and drilling fluid properties that make the operations more efficient in cost and time.

Paleozoic shale gas resources in the Sichuan Basin, China

The Sichuan Basin, China, is commonly considered to contain the world’s most abundant shale gas resources. Although its Paleozoic marine shales share many basic characteristics with successful United States gas shales, numerous geologic uncertainties exist, and Sichuan Basin shale gas production is nascent. Gas retention was likely compromised by the age of the shale reservoirs, multiple uplifts and orogenies, and migration pathways along unconformities. High thermal maturities raise questions about gas storage potential in lower Paleozoic shales. Given these uncertainties, a new look at Sichuan Basin shale gas resources is advantageous. As part of a systematic effort to quantitatively assess continuous oil and gas resources in priority basins worldwide, the US Geological Survey (USGS) completed an assessment of Paleozoic shale gas in the Sichuan Basin in 2015. Three organic-rich marine Paleozoic shale intervals meet the USGS geologic criteria for quantitative assessment of shale gas resources: the lower Cambrian Qiongzhusi Formation, the uppermost Ordovician Wufeng through lowermost Silurian Longmaxi Formations (currently producing shale gas), and the upper Permian Longtan and Dalong Formations. This study defined geologically based assessment units and calculated probabilistic distributions of technically recoverable shale gas resources using the USGS well productivity–based method. For six assessment units evaluated in 2015, the USGS estimated a mean value of 23.9 tcf (677 billion cubic meters) of undiscovered, technically recoverable shale gas. This result is considerably lower than volumes calculated in previous shale gas assessments of the Sichuan Basin, highlighting a need for caution in this geologically challenging setting.