Academic literature on the topic 'Shale gas – Ecca Group'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the lists of relevant articles, books, theses, conference reports, and other scholarly sources on the topic 'Shale gas – Ecca Group.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Journal articles on the topic "Shale gas – Ecca Group"
1
Geel, C., S. Nolte, and E. M. Bordy. "Geomechanical properties of the Permian black shales in the southern main Karoo Basin: lessons from compositional and petrophysical studies." South African Journal of Geology 124, no. 3 (September 1, 2021): 735–50. http://dx.doi.org/10.25131/sajg.124.0026.
Full textAbstract:
Abstract Permian black shales from the lower Ecca Group of the southern main Karoo Basin (MKB) have a total organic carbon (TOC) of up to ~5 wt% and have been considered primary targets for a potential shale gas exploration in South Africa. This study investigates the influence of shale composition, porosity, pressure (P) and temperatures (T) on their geomechanical properties such as compressive strength and elastic moduli. On average, these lower Ecca Group shales contain a high proportion, ~50 to 70 vol%, of mechanically strong minerals (e.g., quartz, feldspar, pyrite), ~30 to 50 vol% of weak minerals (e.g., clay minerals, organic matter) and ~0 to 50 vol% of intermediate minerals (e.g., carbonates), which have highly variable mechanical strength. Constant strain rate, triaxial deformation tests (at T ≤100°C; P ≤50 MPa) were performed using a Paterson-type high pressure instrument. Results showed that the Prince Albert Formation is the strongest and most brittle unit in the lower Ecca Group in the southern MKB followed by the Collingham and then the Whitehill Formation. Compressive strength and Young’s moduli (E) increase with increasing hard mineral content and decrease with increasing mechanically weak minerals and porosity. On comparison with some international shales, for which compositional and geomechanical data were measured using similar techniques, the lower Ecca Group shales are found to be geomechanically stronger and more brittle. This research provides the foundation for future geomechanical and petrophysical investigations of these Permian Ecca black shales and their assessment as potential unconventional hydrocarbon reservoirs in the MKB.
2
Baiyegunhi, Christopher, Zusakhe Nxantsiya, Kinshasa Pharoe, Temitope L. Baiyegunhi, and Seyi Mepaiyeda. "Petrographical and geophysical investigation of the Ecca Group between Fort Beaufort and Grahamstown, in the Eastern Cape Province, South Africa." Open Geosciences 11, no. 1 (July 17, 2019): 313–26. http://dx.doi.org/10.1515/geo-2019-0025.
Full textAbstract:
Abstract The outcrop of the Ecca Group in the Eastern Cape Province was investigated in order to reveal petrographic and geophysical characteristics of the formations that make up the group which are vital information when considering fracking of the Karoo for shale gas. The petrographic study reveals that the rocks of the Ecca Group are both argillaceous and arenaceous rock with quartz, feldspar, micas and lithics as the framework minerals. The sandstones are graywackes, immature and poorly sorted, thus giving an indication that the source area is near. The observed heavy minerals aswell as the lithic grains signify that the minerals are of granitic, volcanic and metamorphic origin. The porosity result shows that of all the formations that make up the Ecca Group, the Whitehill Formation is the most porous with an average porosity of about 2.1% and also least dense with an average dry density of about 2.5 g/cm3. The least porous unit is the Ripon Formation with porosity of about 0.8% but has the highest dry density of approximately 2.8 g/cm3. The magnetic map shows some ring-like structures which coincide with dolerites that were mapped in the field. As revealed by the depth slices result, dolerite intrusions are pervasive in the northern part of the study area, extending to a depth of about 6000 m below the ground surface. The appearance of dolerite intrusions at the targeted depth (3000 - 5000 m) for gas exploration could pose a serious threat to fracking of the Karoo for shale gas.
3
Mosavel, H., D. I. Cole, and A. M. Siad. "Shale gas potential of the Prince Albert Formation: A preliminary study." South African Journal of Geology 122, no. 4 (December 1, 2019): 541–54. http://dx.doi.org/10.25131/sajg.122.0036.
Full textAbstract:
Abstract Recent investigations of the shale gas potential in the main Karoo Basin have concentrated on the Whitehill Formation within the Ecca Group. This study focuses on the shale gas potential of the underlying Prince Albert Formation using the parameters of volume porosity, permeability, total organic carbon (TOC), vitrinite reflectance and Rock-Eval data. Shale samples were retrieved from three surface localities in the southern part of the main Karoo Basin and from core of three boreholes drilled through the Prince Albert Formation near Ceres, Mervewille and Willowvale. The sampling localities occur near the borders of the prospective shale gas areas (“sweet spots”) identified for the Whitehill Formation. Kerogen was found to be Type IV with hydrogen indices less than 65 mg/g. Shale porosities are between 0.08 and 5.6% and permeabilities between 0 and 2.79 micro-Darcy, as determined by mercury porosimetry. TOC varies between 0.2 and 4.9 weight % and vitrinite reflectance values range from 3.8 to 4.9%. Although the porosity and TOC values of the Prince Albert Formation shales are comparable with, but at the lower limits of, those of the gas-producing Marcellus shale in the United States (porosities between 1 and 6% and TOC between 1 and 10 weight %), the high vitrinite reflectance values indicate that the shales are overmature with questionable potential for generating dry gas. This overmaturity is probably a result of an excess depth of burial, tectonic effects of the Cape Orogeny and dolerite intrusions. However, viable conditions for shale gas might exist within the “sweet spot” areas, which were defined for the Whitehill Formation.
4
Geel, Claire, Hans-Martin Schulz, Peter Booth, Maarten deWit, and Brian Horsfield. "Shale Gas Characteristics of Permian Black Shales in South Africa: Results from Recent Drilling in the Ecca Group (Eastern Cape)." Energy Procedia 40 (2013): 256–65. http://dx.doi.org/10.1016/j.egypro.2013.08.030.
Full text
5
Hohne, D., F. de Lange, S. Esterhuyse, and B. Sherwood Lollar. "Case study: methane gas in a groundwater system located in a dolerite ring structure in the Karoo Basin; South Africa." South African Journal of Geology 122, no. 3 (September 1, 2019): 357–68. http://dx.doi.org/10.25131/sajg.122.0025.
Full textAbstract:
Abstract In the past few years numerous assumptions were made on groundwater in the Karoo Basin and related shale gas development, but not many baseline studies were conducted on groundwater and on boreholes where methane currently occurs. This article focuses on one of these boreholes (BHA) in the Ubuntu Local Municipality area, located close to a dolerite ring structure, which is releasing methane gas. Water samples were analysed for macro and trace elements, environmental isotopes and methane concentrations. Chemical analyses results indicate that groundwater at this borehole may be a mixture between deep groundwater, shallow groundwater and meteoric water. A rise in the groundwater level and subsequent flowing artesian conditions that was observed, support the theory that mixing between deeper groundwater from the Ecca Group and shallower water from the Beaufort Group is taking place. These water level reactions could be due to possible seismic activity within close proximity to the dolerite ring structure and/or due to recharge and interflow to BHA.
6
Schulz, H. M., B. Linol, M. de Wit, B. Schuck, I. Schaepan, and R. Wirth. "Early diagenetic signals archived in black shales of the Dwyka and Lower Ecca Groups of the southern Karoo Basin (South Africa): Keys to the deglaciation history of Gondwana during the Early Permian, and its effect on potential shale gas storage." South African Journal of Geology 121, no. 1 (March 1, 2018): 69–94. http://dx.doi.org/10.25131/sajg.121.0004.
Full text
7
Baiyegunhi, Christopher, and Kuiwu Liu. "Sedimentary facies, stratigraphy, and depositional environments of the Ecca Group, Karoo Supergroup in the Eastern Cape Province of South Africa." Open Geosciences 13, no. 1 (January 1, 2021): 748–81. http://dx.doi.org/10.1515/geo-2020-0256.
Full textAbstract:
Abstract The stratigraphy of the Ecca Group has been subdivided into the Prince Albert, Whitehill, Collingham, Ripon, and Fort Brown Formations in the Eastern Cape Province, South Africa. In this article, we present detailed stratigraphic and facies analyses of borehole data and road-cut exposures of the Ecca Group along regional roads R67 (Ecca Pass), R344 (Grahamstown-Adelaide), R350 (Kirkwood-Somerset East), and national roads N2 (Grahamstown-Peddie) and N10 (Paterson-Cookhouse). Facies analysis of the Ecca Group in the study area was performed to deduce their depositional environments. Based on the lithological and facies characteristics, the stratigraphy of the Prince Albert, Whitehill, Collingham, and Fort Brown Formations is now subdivided into two informal members each, while the Ripon Formation is subdivided into three members. A total of twelve lithofacies were identified in the Ecca Group and were further grouped into seven distinct facies associations (FAs), namely: Laminated to thin-bedded black-greyish shale and mudstones (FA 1); Laminated black-greyish shale and interbedded chert (FA 2); Mudstone rhythmite and thin beds of tuff alternation (FA 3); Thin to thick-bedded sandstone and mudstone intercalation (FA 4); Medium to thick-bedded dark-grey shale (FA 5); Alternated thin to medium-bedded sandstone and mudstone (FA 6); and Varved mudstone rhythmite and sandstone intercalation (FA 7). The FAs revealed gradually change of sea-level from deep marine (FA 1, FA 2, FA 3 and FA 4, FA 5, and FA 6) to prodelta environment (FA 7). This implies that the main Karoo Basin was gradually filling up with Ecca sediments, resulting in the gradual shallowing up of the water depth of the depositional basin.
8
BAIYEGUNHI, Christopher, Kuiwu LIU, Nicola WAGNER, Oswald GWAVAVA, and Temitope L. OLONINIYI. "Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province, South Africa: Implications for Shale Gas Potential." Acta Geologica Sinica - English Edition 92, no. 3 (June 2018): 1193–217. http://dx.doi.org/10.1111/1755-6724.13599.
Full text
9
de V. Wickens, H., and D. I. Cole. "Lithostratigraphy of the Kookfontein Formation (Ecca Group, Karoo Supergroup), South Africa." South African Journal of Geology 120, no. 3 (September 1, 2017): 447–58. http://dx.doi.org/10.25131/gssajg.120.3.447.
Full textAbstract:
Abstract The Permian Kookfontein Formation forms part of the upper Ecca Group in the southwestern part of the main Karoo Basin of South Africa. It occupies a stratigraphic position between the underlying Skoorsteenberg Formation and the overlying Waterford Formation, with its regional extent limited to the cut-off boundaries of the Skoorsteenberg Formation. The Kookfontein Formation has an average thickness of 200 m, coarsens upwards, and predominantly comprises dark grey shale, siltstone and thin- to thick-bedded, fine- to very fine-grained, feldspathic litharenite. Characteristic upward-coarsening and thickening successions and syn-sedimentary deformation features reflect rapid deposition and progradation of a predominantly fluvially-dominated prodelta and delta front slope environment. The upward increase in the abundance of wave–ripple marks further indicates a gradual shallowing of the depositional environment through time. The upper contact with the Waterford Formation is gradational, which indicates a transition from deposition in an unstable upper slope/shelf margin environment to a more stable shelf setting.
10
Wickens, H. de V., and D. I. Cole. "Lithostratigraphy of the Skoorsteenberg Formation (Ecca Group, Karoo Supergroup), South Africa." South African Journal of Geology 120, no. 3 (September 1, 2017): 433–46. http://dx.doi.org/10.25131/gssajg.120.3.433.
Full textAbstract:
Abstract The Middle Permian Skoorsteenberg Formation is part of the Ecca Group (Karoo Supergroup) of South Africa. It is also known as the ‘Tanqua fan complex’ due to its origin as a deep-water sedimentation unit associated with a prograding deltaic system. The Skoorsteenberg Formation crops out over approximately 650 km2 along the western margin of the Main Karoo Basin. It thins out in a northerly and easterly direction and therefore has a limited extent with cut-off boundaries to the south and north. It is underlain by the Tierberg Formation and overlain by the Kookfontein Formation, the latter being limited to the regional distribution of the Skoorsteenberg Formation. The Skoorsteenberg Formation has a composite thickness of 400 m and comprises five individual sandstone packages, separated by shale units of similar thickness. The sandstones are very fine- to fine-grained, light greyish to bluish grey when fresh, poorly sorted and lack primary porosity and permeability. The Tanqua fan complex is regarded as one of the world’s best examples of an ancient basin floor to slope fan complex associated with a fluvially dominated deltaic system. It has served as analogue for many deep-water systems around the world and continues to be a most sought after “open-air laboratory” for studying the nature of fine-grained, deep-water sedimentation. The fan systems are essentially tectonically undeformed, outstandingly well exposed and contain an inexhaustible amount of information on the deep-water architecture of lower slope to basin floor turbidite deposits.
Dissertations / Theses on the topic "Shale gas – Ecca Group"
1
Campbell, Stuart Alexander. "The Ecca type section (Permian, South Africa) : an outcrop analogue study of conventional and unconventional hydrocarbon reservoirs." Thesis, Rhodes University, 2015. http://hdl.handle.net/10962/d1018199.
Full textAbstract:
The Karoo Basin of South Africa holds an estimated 906 billion to 11 trillion cubic meters of unconventional shale gas within the shales of the Whitehill and Collingham formations of the Ecca Group. Evaluation of this potential resource has been limited due to the lack of exploration and a scarcity of existing drill core data. In order to circumnavigate this problem this study was undertaken to evaluate the potential target horizons exposed in outcrops along the southern portion of the Karoo Basin, north of Grahamstown in the Eastern Cape Province. Detailed field logging was done on the exposed Whitehill and Collingham formations as well as a possible conventional sandstone (turbidite) reservoir, the Ripon Formation, along road cuttings of the Ecca Pass. Palaeocurrent data, jointing directions and fossil material were also documented. Samples were analysed for mineralogy, porosity, permeability, and total organic carbon content (TOC). The extensively weathered black shales of the Whitehill Formation contain a maximum TOC value of 0.9% and the Collingham Formation shales contain a maximum TOC value of 0.6%. The organic lithic arkose sandstones of the Ripon Formation are classified as ‘tight rock’ with an average porosity of 1% and an average permeability of 0.05 mD. The Whitehill Formation in the southern portion of the Karoo Basin has experienced organic matter loss due to low grade metamorphism as well as burial to extreme depths, thus reducing shale gas potential. The Ripon Formation is an unsuitable conventional reservoir along the southern basin boundary due to extensive cementation and filling of pore spaces.
2
Chere, Naledi. "Sedimentological and geochemical investigations on borehole cores of the Lower Ecca Group black shales, for their gas potential : Karoo basin, South Africa." Thesis, Nelson Mandela Metropolitan University, 2015. http://hdl.handle.net/10948/d1021201.
Full textAbstract:
In the recent years, the shale gas discourse has become central to discussions about future energy supply in South Africa. In particular, the Permian black shales of the Lower Ecca Group formations in the Karoo Basin are considered potential source rocks for shale gas. The research presented in this thesis advances the understanding of the shale gas potential of mainly the Prince Albert, Whitehill and Tierberg/Collingham Formations. These shale sequences were sampled from eight deep boreholes spread across the main Karoo Basin and geochemically analysed at the GFZ - Helmholtz Centre Potsdam, Germany. Three key questions guided the study, these are: (i) what is the lithology of the sequence; (ii) where in the basin do the shale sequences attain maximum thickness at optimum depth i.e. beneath 1000-1500m; and (iii) and their shale characteristics. To evaluate these, borehole core logging, petrology and organic geochemistry were used extensively. Petrology involved the use of thin section, scanned electron and transmission electron microscopy for mineralogy as well as the identification of sedimentary features, organic matter and nano-scale porosity. These were coupled with standard organic geochemistry techniques such as Rock Eval. analysis, open pyrolysis gas chromatography and thermovaporisation to quantify the free gas, total organic carbon (TOC), present-day gas generative potential and kerogen type. The results show that the Whitehill Formation, away from the CFB and not intruded by dolerite, has the most potential for shale gas. Microscopic studies of this pyritic black shale reveal the occurrence of porous amorphous matter, indicating thermal maturity within the gas generation zone (i.e. > 1.1 percent Ro, 120ºC). The TOC content is consistently high within the Whitehill (exceeding industry requirement of 2 percent), attaining maximum of 7.3 percent. The highest yields of free and desorbed gas, especially methane, were emitted within this formation (S1 and nC1 peaks); mostly within its dolomitic units. In addition, dissolution porosity within dolomite units of the Whitehill Formation was identified as the predominant type of porosity. Thus, it is deduced that the dolomitic units of Whitehill Formation potentially contain the greatest volumes of free gas. HI values attain maximum of 25 mg HC/g TOC, whereas the OI values 26 mg CO2/g TOC. Such low HI and OI values are typically attributed to the dominance of Type IV kerogen, and consistent with overmaturity. Open pyrolysis (GC) show the main the chemical compound of the organic matter to be m-p-xylene, consistent with a mix of Type III, Type I/II and Type IV kerogen. Lithologically, the Whitehill Formation is composed of ~ 35 quartz, 13 percent feldspar, 26 percent illite and ~ 23 percent dolomite with variable amounts of pyrite. The dominance of quartz is directly proportional to the brittleness of the rock. Thus it can be deduced that the Whitehill Formation is relatively brittle and therefore fraccable. Burial trends indicate increasing depth (from ground level) to the top of the Whitehill Formation towards the south and south-eastern portion of the basin. It is in the southern region where thicknesses of this black shale exceeding 50m occur at depths more than 1500m; 1000m beneath fresh water aquifers. It therefore concluded that Whitehill Formation in the southern portion of Karoo Basin, but away from the thermo-tectonic overprint of the Cape Orogeny, is the most probable shale gas reservoir in South Africa.
3
Mosavel, Haajierah. "Hydrocarbon potential of the Prince Albert Formation, Ecca Group in the main Karoo Basin, South Africa." University of the Western Cape, 2020. http://hdl.handle.net/11394/8342.
Full textAbstract:
Philosophiae Doctor - PhDThis thesis focusses on the hydrocarbon potential of the Prince Albert Formation in terms of its shale gas potential. Unconventional gas production from hydrocarbon-rich shale formations, known as “shale gas”, is one of the most rapidly expanding trends in onshore oil and gas exploration and exploitation today. In South Africa, the southern portion of the main Karoo Basin is potentially favourable for shale gas accumulation and may become a game changer in the energy production regime of the country. The Prince Albert Formation was selected for research, since previous studies in South Africa have focused on shale from the Whitehill Formation, which together with the underlying Prince Albert Formation, occur within the lower Ecca Group in the main Karoo Basin.
2023-08-16
4
Adamu, Mohammed Bello. "Mineralogical & petrophysical characterisation of gas shale, Colorado Group, Western Canada Sedimentary Basin." Thesis, University of Newcastle Upon Tyne, 2012. http://hdl.handle.net/10443/1422.
Full textAbstract:
The Colorado Group mudstones within the Western Canada Sedimentary Basin (WCSB), have been characterised for their shale gas potential using a range of mineralogical, geochemical (LECO and Rock-Eval), and petrophysical (lithology, porosity, pore size distributions and microfabric) techniques in order to gain an understanding of the shales’ characteristics as suitable source rocks and reservoirs for shale gas. Semi-quantitative mineralogy of the shales was computed using a chemometric technique developed in this study, combining Attenuated Total Reflection Fourier Transform Infra-red Spectroscopy (ATR-FTIR) and multivariate Partial Least Squares (PLS) analysis. The technique estimates quartz, total clay (illite-smectite, kaolinite, chlorite) and total carbonate (calcite, dolomite) to within 5% absolute of true value and demonstrates potential application for high sample throughput and thus high density sampling strategies for ultra-high resolution or multi-well studies. The mineralogy of the Colorado Group shales shows that clay minerals dominate the composition of each Formation, followed by quartz. Minor amounts of calcite, dolomite and feldspars are also present. Grain size data indicate that the Colorado Group lithology consists of substantial amount of clay-grade plus fine silt materials dominated by grains <10μm deposited as floccules. Pore size distributions are predominantly unimodal with an average mean pore radius (rmean) value of 50nm, although some samples exhibit bimodal pore size distributions reflecting mixture of mudstones and silt size materials. The pore size distributions of the Colorado Group Formations are generally influenced by the relative percentages of clay and silt, as well as by the level of compaction. Clay-rich sediments tend to be unimodal with tight pore size distributions while sediments with both clay-sized and silt materials tend to have broader and occasionally bimodal pore size distributions. The unimodal porosity nature of the Colorado Group formations, and the dominance of clay-sized and silt sediments may promotes the adhesion of gas molecules, which makes these sediments optimal for gas adsorption. Integration of the various data revealed that the Colorado Group depositional system is complex with widely changing seaway conditions showing no simple correlations between mineralogy, grain size and organic facies, or their spatial variation from palaeosource. The presence of sands and reworked shell fragments indicate a dominantly advective transport of sediments within the Colorado Group. Mud and clay cements are observed throughout the Upper Colorado Group, whereas calcareous cements are present only within the Second White Specks Formation, Medicine Hat Member and First White Specks Member. Laminations of calcareous coccoliths within the Second White Specks Formation typically display calcite overgrowths. Calcite overgrowths are also observed within mudstones in the basal part of the Medicine Hat Member. Such differences in appearance show the occurrence of temporal and lateral facies changes; the presence of facies changes is an important factor that can affect shale gas production patterns within a single, seemingly laterally-continuous lithological unit. High TOC (>2wt. %) and Type II kerogen appear to indicate that biogenic gas may be a dominant component of the total gas-in-place in the Colorado Group. The Middle Carlile member is likely the best shale gas target within the Upper Colorado Group. The Carlile Formation and Verger Member also appear to have the highest sorption capacity, based on a dominant clay sized fractions. However, mudstones within all formations and members display moderate to high clay minerals (fluid sensitivity), have poor fraccability and contain clay and mud cements. The presence of muddy siltstone within Middle Carlile member and its high potential for gas adsorption is likely to make the unit a viable target for possible horizontal drilling for gas shale.
Conference papers on the topic "Shale gas – Ecca Group"
1
Adams, S. "Shale Gas Resource Assessment of the Organic-rich Ecca Group Shale of the Karoo Basin: Prospective Area Delineation and Resource Estimation." In Fifth EAGE Eastern Africa Petroleum Geoscience Forum. European Association of Geoscientists & Engineers, 2021. http://dx.doi.org/10.3997/2214-4609.2021605024.
Full text
2
Bhan*, U. "Geochemical Studies of Black Shales for Shale Gas Prospects of the Semri Group, Vindhyan Basin, Exposed around Maihar Area." In Second EAGE/SPE/AAPG Shale Gas Workshop in the Middle East. Netherlands: EAGE Publications BV, 2014. http://dx.doi.org/10.3997/2214-4609.20142262.
Full text
3
Kenderes, Stuart M., Mary J. Seid, and F. Brett Denny. "GEOCHEMICAL AND STABLE ISOTOPE COMPARISON OF NEW ALBANY SHALE GROUP SOURCE ROCKS AND CHARACTERIZATION OF SHALE-GAS POTENTIAL ALONG THE WESTERN MARGIN OF THE ILLINOIS BASIN." In 50th Annual GSA North-Central Section Meeting. Geological Society of America, 2016. http://dx.doi.org/10.1130/abs/2016nc-275369.
Full text
4
Song, Lianteng, Zhonghua Liu, Chaoliu Li, Congqian Ning, Yating Hu, Yan Wang, Feng Hong, et al. "PREDICTION AND ANALYSIS OF GEOMECHANICAL PROPERTIES OF JIMUSAER SHALE USING A MACHINE LEARNING APPROACH." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0089.
Full textAbstract:
Geomechanical properties are essential for safe drilling, successful completion, and exploration of both conven-tional and unconventional reservoirs, e.g. deep shale gas and shale oil. Typically, these properties could be calcu-lated from sonic logs. However, in shale reservoirs, it is time-consuming and challenging to obtain reliable log-ging data due to borehole complexity and lacking of in-formation, which often results in log deficiency and high recovery cost of incomplete datasets. In this work, we propose the bidirectional long short-term memory (BiL-STM) which is a supervised neural network algorithm that has been widely used in sequential data-based pre-diction to estimate geomechanical parameters. The pre-diction from log data can be conducted from two differ-ent aspects. 1) Single-Well prediction, the log data from a single well is divided into training data and testing data for cross validation; 2) Cross-Well prediction, a group of wells from the same geographical region are divided into training set and testing set for cross validation, as well. The logs used in this work were collected from 11 wells from Jimusaer Shale, which includes gamma ray, bulk density, resistivity, and etc. We employed 5 vari-ous machine learning algorithms for comparison, among which BiLSTM showed the best performance with an R-squared of more than 90% and an RMSE of less than 10. The predicted results can be directly used to calcu-late geomechanical properties, of which accuracy is also improved in contrast to conventional methods.
5
Xiong, Xiaofei, and James Jia Sheng. "An Optimized Experimental Investigation of Foam-Assisted N2 Huff-n-Puff Enhanced Oil Recovery in Fractured Shale Cores." In SPE Symposium: Petrophysics XXI. Core, Well Logging, and Well Testing. SPE, 2021. http://dx.doi.org/10.2118/208431-ms.
Full textAbstract:
Abstract Sustainable development of shale reservoirs and enhanced oil recovery have become a challenge for the oil industry in recent years. Shale reservoirs are typically characterized by nano Darcy-scale matrix, natural fractures, and artificially fractures with high permeability. Some of earlier studies have confirmed that gas huff-n-puff has been investigated and demonstrated as the most effective and promising solution for improving oil recovery in tight shale reservoirs with ultra-low permeability. Fractures provide an advantage in enhancing recovery from shale reservoirs but they also pose serious problems such as severe gas channeling, which led to rapid decline production from a single well. More studies are needed to optimize the process. This paper studies the method of foam-assisted N2 huff-n-puff to enhance oil recovery in fractured shale cores. The influence of foam on oil recovery was analyzed. The effect of matrix permeability, cycle number and production time on oil recovery are also considered. The shale core used in the experiment was from Sichuan Basin, China. For the purpose of comparation and validation, two groups of tests were conducted. One group of tests was N2 huff-n-puff, and the other was foam-N2 huff-n-puff. In the optimization experiment, matrix permeabilities were set as 0.01mD, 0.008mD and 0.001mD, cycle numbers ranged from one to five, the production time is designed to be 1 hour and 24 hours respectively. During the puff period of experiments, the history of oil recovery was closely monitored to reveal the mechanism. During a round of gas injection of fractured shale cores, foam-assisted N2 huff-n-puff oil recovery is 4.59%, which is significantly higher than that of N2 huff-n-puff is only 0.0126%, and the contrast becomes more obvious with the increase of matrix permeability. The results also showed that the cumulative oil recovery increased as the number of cycles was increased, with the same experimental conditions. There is an optimal production time to achieve maximum oil recovery. The cycle numbers, matrix permeability, and production time played important roles in foam-assisted N2 huff-n-puff injection process. Therefore, under certain conditions, foam-N2 huff-n-puff has a positive effect on oil development in fractured shale.
6
Zhou, Qiumei, Robert Dilmore, Andrew Kleit, and John Yilin Wang. "Evaluating Fracturing Fluid Flowback in Marcellus Using Data Mining Technologies." In SPE Hydraulic Fracturing Technology Conference. SPE, 2015. http://dx.doi.org/10.2118/spe-173364-ms.
Full textAbstract:
Abstract Natural gas recovery from low permeability unconventional reservoirs – enabled by advanced horizontal drilling and multi-stage hydraulic fracture treatment - has become a very important energy resource in the past decade. While evaluating early gas production data in order to assess likely rate decline and ultimate gas recovery has been reported in literature, flowback water recovery has been given little consideration. Fracture fluid flowback is defined herein as aqueous phase produced within three weeks following a fracture treatment (exclusive of well shut-in time). Field data from Marcellus Shale wells in Northeastern West Virginia indicated about 2-26% of the fracture fluid is recovered during flowback. However, stimulation of gas shale is a complex engineered process, and the factors that control the volumetric flowback performance are not well understood. The objective of this paper is to use post-hoc analysis to identify correlations between fracture fluid flowback and attributes of well completion and geological setting, and to identify those factors most important in predicting flowback performances. To accomplish this objective we selected a representative subset of 187 wells for which complete data are available (from a full set of 631 wells), including well location, completion data, hydraulic fracture treatment data and production data. The wells were classified into four groups based on geological settings. For each geological group, engineering and statistical analyses were applied to study the correlation between flowback data and well completion through traditional regression methods. Important factors considered to affect flowback water recovery efficiency include number of hydraulic fracture stages, lateral length, vertical depth, proppant mass applied, proppant size, fracture fluid volume applied, treatment rate, and shut-in time. The total proppant mass, proppant size and shut-in time have relatively large influence on volumetric flowback performance. The new results enable one to estimate flowback volume in a spatial domain, based on known geological conditions and completion parameters, and lead to a better understanding of flowback behaviors in Marcellus Shale. This also helps industry manage flowback water and optimize production operations.
7
Krisnabudhi, A. "New Insight Into Berau Sub-Basin North East Borneo: Basin Evolution and Tectonostratigraphy and Their Implication to New Exploration Play Concept." In Digital Technical Conference. Indonesian Petroleum Association, 2020. http://dx.doi.org/10.29118/ipa20-g-489.
Full textAbstract:
Understanding the evolution of the basin and tectonostratigraphy is the key role to reveal all geological aspects and potential hydrocarbon resources. Northeast Borneo has many hydrocarbon resources especially in Mahakam delta. However, Berau sub-basin remains unclear due to lack of G&G data. This paper presents a new concept of tectonostratigraphy and basin evolution based on subsurface and surface data integrated with thin section as well as radiolaria analysis to determine the age of such basin. Present-day aerogravity data shows that Berau sub-basin has two depocenters trending N-S and E-W and is bordered by Mangkalihat High (MKH) in the south and Rajang Embaluh Group (REG) in the west area. The metamorphic belt in REG area was formed in Early Jurassic (190 Ma), meanwhile in MKH, the ophiolite sequence was formed during Middle-Late Jurassic based on the presence of Holocrptocanium sp. in chert interbedded with mudstone. Based on the analysis, Berau sub-basin experienced subduction to obduction during Early Jurassic to Late Jurassic. In Cretaceous, Berau sub-basin is filled with conglomerate, shale and quartz sandstone of Telen and Benggara Fm. that has provenance from MKH and REG area. In Paleogene, major breakup unconformity can be seen on the seismic section and spread across the basin overlaid by shale with tuff of Eocene-Oligocene Sembakung Fm. The deposition of Sembakung Fm is controlled by extensional regime caused by subduction rollback in NW Borneo. The carbonate sequence has dominated this area in Late Oligocene to Early Miocene. Following the collision of Kuching high in Middle -Late Miocene, the deposition was dominated by deltaic sediment due to regional regression phase. In Plio-Pleistocene period, Berau sub-basin consists of carbonate and deltaic sediment from Domaring and Sajau Fm. In this time structural reactivation and inversion due to transpressional system with SE-NW pattern had controlled Berau sub-basin. Based on the evolution of Berau sub-basin, four hydrocarbon plays are identified in this paper, Mesozoic Play especially in Telen Fm, Paleogene Carbonate Play in Tabbalar & Birang Fm, Middle Miocene Play especially in Latih Fm and Plio-Pleistocene Play in Sajau Fm and Labanan Fm. Working petroleum system in the basin manifested by many oil seeps that can be found in surface and postmortem of several wells data shows commercial to sub-commercial and abundant oil and gas show.
8
Ashayeri, Cyrus, and Donald L. Paul. "A Stochastic Method in Investigating Basin-Wide Underlying Distribution Functions of Decline Rate Behavior for Unconventional Resources." In SPE Western Regional Meeting. SPE, 2021. http://dx.doi.org/10.2118/200879-ms.
Full textAbstract:
Abstract Basin-wide heterogeneity of production in unconventional resources creates additional risk in field development planning. In the past few years, several data-driven models have been developed to increase the accuracy in predicting the recovery from shale gas and tight oil wells. However, many of the machine learning methods with so called "black box" approach provide deterministic results. Therefore, understanding the uncertainty associated with different development scenarios would be difficult to obtain. We have investigated the underlying statistical distribution functions that govern the production rates and decline behavior of unconventional wells. Identification and quantification of these distribution functions provide a strong tool to accurately forecast the cumulative production of a large group of wells in an unconventional basin. By understanding the relationship among geologic characteristics of different sections of the asset, and the impact of varying drilling and completion parameters, capital allocation can be done in a more efficient manner. In this paper, we have identified the statistical distribution parameters of decline behavior is a Power Law model. In doing so, we have used unsupervised clustering techniques to find an optimal number of clusters that enable observing well behaved and identifiable underlying distribution functions. Furthermore, we quantified different types of distribution functions in a trial and error workflow to provide a tool for accurately evaluating the impact of varying geologic parameters on the decline behavior of these wells. Our results show that the leading term (or leading coefficient), which also highly correlates with long term cumulative recovery, demonstrates Gamma distribution, while the power degree (or power coefficient) demonstrate Normal distribution. Peak production rate (maximum average daily rate), terminal rate (rate after switch point), and the time of terminal rate occurrence, all demonstrate Log Normal distribution.
Reports on the topic "Shale gas – Ecca Group"
1
Ferri, F., B. C. Richards, M. McMechan, P. Kabanov, A. Mort, P. Thapa, J. Leslie-Panek, and E. Little. The Devonian-Mississippian Besa River Group of Liard Basin, British Columbia: stratigraphy of a world-class shale gas resource. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2018. http://dx.doi.org/10.4095/312448.
Full text
2
Hamblin, A. P. Detailed outcrop measured sections of the Colorado Group in the Foothills of the Calgary region, Alberta, with reference to shale gas potential. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2010. http://dx.doi.org/10.4095/285362.
Full text