Provenance and sedimentary environment of the Ek2 shale in the Cangdong Sag, the central Bohai Bay Basin, China

The second member of the Kongdian Formation (usually abbreviated as the E k2 shale) is one of the most significant exploring targets for shale oil at the Cangdong Sag of the central Bohai Bay Basin. It consists of siliceous shale, mixed shale, and calcareous shale. To better understand why organic matter accumulated in the E k2 shale, we have analyzed major and trace elemental compositions to reconstruct the provenance and sedimentary environment. Tectonic discriminatory diagrams suggest that the tectonic setting of the parental rocks for the E k2 shale belonged to the Continental Island Arc. The distribution patterns of trace elements and rare earth elements + yttrium (REEs + Y) are close to the intermediate igneous rock. The ratios of Al2O3/TiO2 ranging from 21.41 to 27.59 with a mean value of 23.93 also demonstrate a parental rock of the intermediate igneous rock. Siliceous and mixed shales indicate K2O/Al2O3 of 0.17–0.29, chemical index of weathering of 28.79–97.79, plagioclase index of alteration of 38.24–95.57, and chemical index of alteration of 40.29–80.23. These weathering proxies denote that the E k2 shale underwent a low weathering degree in an arid climate and a high weathering degree in a semiarid climate. The V/(V + Ni) ratios and pyrite framboids indicate an anoxic sedimentary condition. The δ18O values of carbonate minerals in the E k2 shale range from −9.8‰ to 0.7‰, and they are positively correlated to the δ13C values. The Sr/Ba ratios, δ18O, and chemical mineral associations indicate that siliceous and mixed shales were deposited in a fresh to brackish anoxic water column under a semiarid climate. Whereas calcareous shale was deposited in a saline to hypersaline anoxic water column under an arid climate.

Miocene Turbidite Sequence as Potential Reservoir and Source Rock Of Mamberamo Basin: An Insight From Fieldwork in Metaweja Area, Central Mamberamo District, Papua

The geology of the Metaweja area is characterized by the turbidite sequence which are deposited in the deep-sea environment during the Miocene and exposed to surface due to the latest deformation. The research was conducted to identify the potential source rock and reservoir rock within the turbidite deposits. In the study area, there are three types of rock units, calcareous shale units formed in the Late Miocene, Sandstone unit and interbedded siltstone-sandstone unit that were deposited in Middle Miocene. Measured section was carried out at the several stations in order to analyze the turbid current deposition mechanism. Measured section of the alternating unit of sandstone - siltstone are observed at several places where the unit has intercalation of shale, coal and iron oxide. Some syn-depositional sedimentary structure also found within this unit. The carbonate shale unit has good total organic content (TOC) ranging from 0.51wt% to 2.56wt%. Pyrolysis analysis has S2 value 1.31 mg/g to 1.34 mg/g, Hydrogen Index (HI) 35 mgHC/g to 49 mgHC/g, Oxygen Index (OI) 35 mgHC/g to 49 mgHC/g, Tmax 430 °C to 434 °C and Vitrinite Reflecteance index (Ro) 0.32% to 0.54%. The carbonate shale characterized as the type III kerogen which prone gas source rock and interpreted as immature to early mature source rock. The petrography analysis of alternating rocks of sandstone - siltstone has characteristics of sandstones with 44% of volcanic lithic fragment composition, 20% matrix 10% clay size fragments, secondary porosity reaches 10% and 13% cement carbonate calcite. Based on the petrography analysis, this unit could be interpreted as reservoir rock, although we need further analysis for the Permeability measurement.

Pillar Fracturing Production Enhancement Results for an Unconventional Calcareous Shale in Ecuador

Economical production from low-permeability oil-saturated reservoirs has always been a challenge in a basin known for its mature assets. M2 limestone is a new challenge. To characterize, it was necessary to use the methodology based on shale plays, integrating information from different logs using a proprietary evaluation method. Applying pillar fracturing, creating stable voids between pillars, and hence, infinite-conductivity channels in geomechanically competent candidates resulted in economical production and proved reserves from a low-permeability calcareous shale. Geomechanics, mineralogy, and saturated intervals were addressed by using a combination of rock mechanical properties and mineralogy, carbon/oxygen logs, and X-ray diffraction (XRD) on drilling cuttings. Once the prospective zones in the M2 limestone intervals were selected, a conventional fracturing treatment was designed using a 3-D gridded simulator. The candidate well was evaluated for pillar fracturing by using results from geomechanics and the conventional fracture application. A pumping schedule that included pillar volume, spacer, and tail in stages was then designed. Results from the fracture simulator were loaded in a numerical reservoir simulator, and different development scenarios were evaluated. M2 limestone has shown production potential near areas where volcanic intrusion is present, or indicated hydrocarbon potential by oil shows observed on cuttings and high-gas readings during drilling. The data used for this project was collected during conventional reservoir development but had never been evaluated using an unconventional reservoir approach. XRD analysis and acid solubility tests confirmed that the reservoir does not contain a high-carbonate content nor acid solubility. Diagnostic Fracture Injection Test (DFIT) and minifrac analysis helped to define the size and fracturing technique to be used. Results from this work provided a better understanding of the reservoir; a development plan is needed to improve the investment return for this type of project. Geomechanical evaluation is fundamental to the application and design of pillar fracturing. This fracturing technique was selected because it used 43% less proppant than a conventional job, reduced risk of screen out, and provided higher productivity over a conventional fracturing job. This is the first time that pillar fracturing has been applied in this Ecuadorian reservoir. The production outcome proved reserves of 32°API oil and resulted in the largest fracturing job in Ecuador. Different development scenarios are proposed based on the results from this well. A complete workflow to characterize, design a hydraulic fracture job using proprietary geomechanical candidate selection criteria, and develop an unconventional calcareous shale is presented. The available data are the same as in a conventional reservoir, whereas the evaluation technique, as well as fracture design, is customized to this type of reservoir to attain economical production.

Gas hydrates identification and distribution in Mexican Ridges, Mexico

We mapped gas hydrates, free gas and Bottom Simulating Reflector (BSR) distributions in an area of Mexican Ridges, central Gulf of Mexico, Mexico, revealing the relationship between these three elements and the tectono-stratigraphy. The three elements are more visible when the host rock is a high porosity sandstone because there is a large seismic impedance contrast between solid gas hydrates above and free gas below, which manifests itself on the seismic as a BSR. Gas hydrates are identified in the well as higher resistivity sandstone layers with a strong positive amplitude. When the host rock is has a higher shale content with lower porosity, the impedance contrast is lower and the BSR is weak or not visible. On the other hand, Mexican Ridges are a series of anticlines where gas hydrates and free gas are trapped on the crest after migrates through the dipping layers and faults from synclines where are generated in calcareous shale. The main seal is MTC deposits from Pliocene, when they are not deposited at the crest of anticline there is gas escape o seafloor in form of gas chimney. On this way, we established a complete petroleum system for gas hydrates and free gas on Mexican Ridges.

Influence of interbedded rock association and fracture characteristics on gas accumulation in the lower Silurian Shiniulan formation, Northern Guizhou Province

The northern Guizhou area, located near the southwestern margin of the Yangtze Block, is a promising area for shale gas exploration and development. The Lower Silurian Shiniulan Formation as a new discovery stratum of natural gas marks an exciting breakthrough in natural gas exploration in northern Guizhou area. Based on several field investigations and samples analyses, the lithology and fracture characteristics were systematically analyzed in the lower Shiniulan Formation, and the reservoir specificity and its influence on natural gas accumulation were determined. The characteristics of the relatively fractures and lithology assemblages were identified as key factors controlling the natural gas accumulation. The lower Shiniulan Formation is deposited as calcareous shale and marlstone with frequent centimeter-scale interlayers. This is reflective of a shallow sea shelf strata with decreasing sedimentary rhythm and gradual weakening of sedimentary changes and developed calcareous shale and marlstone with frequent centimeter scale interlayer changes. The gas reservoir is dominated by calcareous mudstone, controlled by the interbedded rock association (calcareous mudstone and limestone), characterized by the raw-storage and the accumulation-reservoir interbedded system. The reservoir is located in the central part of the syncline and is characterized by strong sealing of the stratum, large proportion of free gas, and high abnormal pressure. The Lower Shiniulan Formation is formed between the shale layer with horizontal fractures and dense limestone with underdeveloped fractures. Among them, the shale section generally develops diagenetic shrinkage fractures, which provide good storage space for natural gas and act as the main body of natural gas. The pore sizes in limestone (2.8 nm) are significantly smaller than those in mudstone (7.5 nm), which results in a good capping and preservation of shale gas. This paper reports on results that are of significance for supplementing the theory of unconventional natural gas accumulation and guiding shale gas exploration in similar areas.

Seismic prediction of lithofacies heterogeneity in paleogene hetaoyuan shale play, Biyang depression, China

Shale lithofacies identification and prediction are of great importance for the successful shale gas and oil exploration. Based on the well and seismic fine calibration, extraction, and optimization of seismic attributes, root mean square (RMS) amplitude analysis is used to predict the spatial–temporal distribution of various lithofacies in the fifth organic-matter-rich interval, and the prediction results are confirmed by the logging data and geological background. The results indicate that in the early expansion system tract, dolomitic shale and calcareous shale were widely developed and argillaceous shale, silty shale, and argillaceous siltstone only developed in the periphery of deep depression. With the lake level rising, argillaceous shale and calcareous shale were well-developed, and argillaceous shale interbedded with silty shale or argillaceous siltstone developed in deep or semi-deep lake. In the late expansion system tract, argillaceous shale was widely deposited in the deepest sag; calcareous shale presented in eastern sag with belt distribution.

Geomechanical characterisation of organic-rich calcareous shale using AFM and nanoindentation

The geomechanical integrity of shale overburden is a highly significant geological risk factor for a range of engineering and energy-related applications including CO$$_2$$ 2 storage and unconventional hydrocarbon production. This paper aims to provide a comprehensive set of high-quality nano- and micro-mechanical data on shale samples to better constrain the macroscopic mechanical properties that result from the microstructural constituents of shale. We present the first study of the mechanical responses of a calcareous shale over length scales of 10 nm to 100 $$\upmu$$ μ m, combining approaches involving atomic force microscopy (AFM), and both low-load and high-load nanoindentation. PeakForce quantitative nanomechanical mapping AFM (PF-QNM) and quantitative imaging (QI-AFM) give similar results for Young’s modulus up to 25 GPa, with both techniques generating values for organic matter of 5–10 GPa. Of the two AFM techniques, only PF-QNM generates robust results at higher moduli, giving similar results to low-load nanoindentation up to 60 GPa. Measured moduli for clay, calcite, and quartz-feldspar are $$22 \pm 2\,\hbox { GPa}$$ 22 ± 2 GPa , $$42 \pm 8\,\hbox { GPa}$$ 42 ± 8 GPa , and $$55 \pm 10\,\hbox { GPa}$$ 55 ± 10 GPa respectively. For calcite and quartz-feldspar, these values are significantly lower than measurements made on highly crystalline phases. High-load nanoindentation generates an unimodal mechanical response in the range of 40–50 GPa for both samples studied here, consistent with calcite being the dominant mineral phase. Voigt and Reuss bounds calculated from low-load nanoindentation results for individual phases generate the expected composite value measured by high-load nanoindentation at length scales of 100–600 $$\upmu$$ μ m. In contrast, moduli measured on more highly crystalline mineral phases using data from literature do not match the composite value. More emphasis should, therefore, be placed on the use of nano- and micro-scale data as the inputs to effective medium models and homogenisation schemes to predict the bulk shale mechanical response.