Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 471
Author(s):  
Joanna Wong ◽  
Mohammad Bahar
Keyword(s):  
Shale Gas ◽  
Resource Assessment ◽  
Poor Quality ◽  
Organic Content ◽  
Source Rocks ◽  
Geochemical Data ◽  
Geochemical Parameters ◽  
The Monte Carlo Method ◽  
Petrophysical Logs ◽  
Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 452
Author(s):  
Joanna Wong ◽  
Mohammad Bahar
Keyword(s):  
Shale Gas ◽  
Resource Assessment ◽  
Poor Quality ◽  
Organic Content ◽  
Source Rocks ◽  
Geochemical Data ◽  
Geochemical Parameters ◽  
The Monte Carlo Method ◽  
Petrophysical Logs ◽  
Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

scholarly journals Geology and transitional shale gas resource potentials in the Ningwu Basin, China

2018 ◽  
Vol 36 (6) ◽  
pp. 1482-1497
Author(s):  
Qiang Xu ◽  
Fengyin Xu ◽  
Bo Jiang ◽  
Yue Zhao ◽  
Xin Zhao ◽  
...  
Keyword(s):  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Sedimentary Environment ◽  
Organic Content ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Lower Paleozoic ◽  
Gas Source ◽  
Average Porosity ◽  
Pore Types

We analyzed the tectonic evolution characteristics, sedimentary environment, geochemical characteristics, petrological characteristics, and gas-bearing properties of three mudstone sections of the Lower Paleozoic in Ningwu Basin, NE China, and determined the geologic characteristics and resource potential of the transitional facies shale gas. Geochemical analysis of the organic carbon content, kerogen macerals, and vitrinite reflectance of the shale samples showed that the total organic content was generally over 2.0%, the main organic type was type III, and the vitrinite reflectance values (Ro) were between 1.20 and 1.90%. Thus, the mudstones are good shale gas source rocks. The thickness of the three mudstone sections was approximately 30–70 m, and the average porosity was 3.10%. The pore types were diverse with good reservoir capacity. The shale gas resources of the Carboniferous-Permian transitional facies estimated by the volumetric method were approximately 2798.97 × 108–4643.09 × 108 m3. Through a comparison with shales in SW China, where shale gas has been successfully exploited, we determined the preferred criteria for favorable shale gas areas, as well as favorable areas for shale gas enrichment.

scholarly journals SHALE GAS SWEET SPOT POTENTIAL OF TUNGKAL GRABEN, JAMBI SUB-BASIN SOUTH SUMATERA BASIN

2019 ◽  
Vol 42 (3) ◽  
pp. 109-114
Author(s):  
Taufik Ramli ◽  
M. Heri Hermiyanto Z ◽  
Andy Setyo Wibowo
Keyword(s):  
Shale Gas ◽  
Organic Geochemistry ◽  
Primary Source ◽  
Organic Content ◽  
Source Rocks ◽  
Sweet Spot ◽  
Gas Generation ◽  
Spot Area ◽  
Total Potential ◽  
Gas Bearing

The Tungkal Graben is located in Jambi Sub-basin, the northern part of South Sumatera Basin. This basin is known as one of the largest hydrocarbons producing basin in Indonesia. There are several proven source rocks in the South Sumatera Basin. The paralic shales and coal horizon of Talangakar Formation (TAF) are known as primary source rock in this basin and considered as a reservoir of shale gas-bearing in Tungkal Graben Area as well. This study used surface geological data that was collected from the southern foot of Tiga Puluh Mountain as the outcrop analogy and subsurface data (existing well and seismic data) in Tungkal Graben Area. This study applied integrated methods including environmental deposition analysis, organic geochemistry analysis, petrophysical analysis, seismic interpretation, sweet spot delineation, and volumetric of gas in place (GIP) calculation. TAF observed both on the outcrop and well is transition deposit that consists of the dominance of shale and siltstone with interbedded of coal, sandstone, and limestone. Shale and siltstone of TAF have characteristic which is appropriate as a shale gas bearing, with sufficient organic content richness, suitable kerogen type, its maturity entering the early gas generation and proper brittleness index (BI). The sweet spot area is an area that has met the criteria for potential shale gas and determined by pay zone criteria. Depend on the criteria, Net to gross for shale gas is 0.158, early gas generation estimated at a depth of 10250 feet, and sweet spot area reaches 8.9 x 108 ft2. Thus, the total potential of shale gas resources from the calculation using the Ambrose method is 2.12 TCF.

THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA

1993 ◽  
Vol 33 (1) ◽  
pp. 123 ◽  
Author(s):  
B. J. Warris
Keyword(s):  
Western Australia ◽  
Early Carboniferous ◽  
Poor Quality ◽  
Source Rocks ◽  
Structural Development ◽  
Hydrocarbon Migration ◽  
North West ◽  
Canning Basin ◽  
Made In ◽  
Carnarvon Basin

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.

ADDRESSING RESERVOIR HETEROGENEITY BY INTEGRATION OF GEOCHEMISTRY AND PETROPHYSICAL LOGS IN CARBONATE PROSPECTS

2021 ◽  
Author(s):  
Kemal C. Hekimoglu ◽  
◽  
Filippo Casali ◽  
Antonio Bonetti ◽  
◽  
...  
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Geochemical Data ◽  
Reservoir Properties ◽  
Formation Evaluation ◽  
Geomechanical Properties ◽  
Reservoir Rocks ◽  
Production Allocation ◽  
Petrophysical Logs ◽  
Geochemical Analyses

Formation evaluation challenges in highly fractured, stacked reservoirs with multiple source rocks and structural complexities that have complicated charging histories are common in the Middle East. Finding additional pay zones, understanding the contribution of individual oils to the overall production, or evaluating the compartmentalization within the reservoir by resolving the heterogeneity of the reservoir rocks are to name but a few. This work tries to understand the challenges posed by the subsurface complexities and attempts to find answers through physical evidence, using both onsite data acquired during drilling and data gathered through organic and inorganic laboratory measurements. Formation evaluation challenges are mostly attributed to formation heterogeneity, which we have aimed to address through the integration of petrophysical and geochemical data within this work. This project encompasses the integration of petrophysical and geochemical analyses of the reservoir rocks. Geochemical data have provided the ability to make maturity, richness, and other character interpretations and will be combined with important petrophysical properties of the carbonate intervals to predict reservoir heterogeneities. These interpretations could support perforation interval selection on subsequent wells in the field through the understanding of the mobility of the oils and, ultimately, production allocation. Best practices for thermally extracting hydrocarbons from drill cuttings, quality-controlling advanced mud gas data, and interpretive processes together with the entire workflow followed will also be elaborated. The analysis has the objectives of establishing results to support completion decisions through understanding reservoir quality, reservoir fluid communication, and compartmentalization specific to the basin studied. The petrophysical reservoir properties such as hydrocarbons in place, mobility of the oils, porosity, permeability, fracture intensity, geomechanical properties (brittle vs. ductile), and production allocation will be tied in to geochemical analyses to this extent. The focal point of the work is ascertaining and characterizing both the reservoir properties using a number of integrated analytical techniques on DST oil samples of 12 offset wells and rock cuttings, as well as petrophysical logs and advanced mud gas data. The concepts, tools, and methods that have been demonstrated for evaluating crude oils, natural gases, and petrophysical characteristics of the rocks are applicable to many problems in petroleum production and field development as well as exploration efforts.

Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin

2015 ◽  
Author(s):  
Jamal A. Madi ◽  
Elhadi M. Belhadj
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Lower Silurian ◽  
History Of ◽  
Oil Gas

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya

2016 ◽  
Author(s):  
David M. Katithi ◽  
David O. Opar
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Shale Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Mature Stage ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Gas Generation ◽  
Gas Targets

ABSTRACT The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.

Stratigraphic evolution and source rock potential of a Lower Oligocene to Lower–Middle Miocene continental slope system, Hellenic Fold and Thrust Belt, Ionian Sea, northwest Greece

2013 ◽  
Vol 151 (3) ◽  
pp. 394-413 ◽  
Author(s):  
A. MARAVELIS ◽  
G. MAKRODIMITRAS ◽  
N. PASADAKIS ◽  
A. ZELILIDIS
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Middle Miocene ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Thrust Belt ◽  
Lower Oligocene ◽  
Geochemical Parameters ◽  
Fold And Thrust Belt

AbstractThe Western flanks of the Hellenic Fold and Thrust Belt are similar to the nearby prolific Albanian oil and gas provinces, where commercial volumes of oil have been produced. The Lower Oligocene to Lower–Middle Miocene slope series at this part of the Hellenic Fold and Thrust Belt provides a unique opportunity to evaluate the anatomy and source rock potential of such a system from an outcrop perspective. Slope progradation is manifested as a vertical pattern exhibiting an increasing amount of sediment bypass upwards, which is interpreted as reflecting increasing gradient conditions. The palaeoflow trend exhibits a western direction during the Late Oligocene but since the Early Miocene has shifted to the East. The occurrence of reliable index species allowed us to recognize several nannoplankton biozones (NP23 to NN5). Organic geochemical data indicate that the containing organic matter is present in sufficient abundance and with good enough quality to be regarded as potential source rocks. The present Rock-Eval II pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is of type III kerogen. A terrestrial origin is suggested and is attributed to short transportation distance and accumulation at rather low water depth. The succession is immature with respect to oil generation and has not experienced high temperature during burial. However, its eastern down-slope equivalent deep-sea mudstone facies should be considered as good gas-prone source rocks onshore since they may have experienced higher thermal evolution. In addition, they may have improved organic geochemical parameters because there is no oxidization of the organic matter.

Assessing source rock distribution in Heather and Draupne Formations of the Norwegian North Sea: A workflow using organic geochemical, petrophysical, and seismic character

2015 ◽  
Vol 3 (3) ◽  
pp. SV45-SV68 ◽  
Author(s):  
Balazs Badics ◽  
Anthony Avu ◽  
Sean Mackie
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Seismic Data ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Geochemical Data ◽  
Seismic Attribute ◽  
Attribute Analysis ◽  
Seismic Characterization ◽  
Petrophysical Logs

The organic-rich upper Jurassic Draupne and Heather Formations are the main proven source rocks of the Norwegian North Sea. We have developed a workflow for the organic geochemical, petrophysical, and seismic characterization of the Draupne and Heather Formation source rocks in a [Formula: see text] study area in quadrant 25 in the Viking Graben in the Norwegian North Sea. We characterized the vertical and lateral organic richness variations using biostratigraphy, organic geochemical data, and petrophysical logs. The Draupne Formation is a rich (6.5 wt.% total organic carbon [TOC], 360 HI), oil-prone, immature to early oil mature source rock, representing a 25-m-thick condensed section, partly eroded over the Utsira high and thickening to 150–300 m toward the deep grabens. The underlying Heather Formation is also an oil-prone (4.4 wt.% TOC, 270 HI), 30- to 400-m-thick, more mature source rock. To map the TOC distribution using seismic, we performed detailed seismic interpretation and seismic attribute analysis following the petrophysical calibration of TOC with the [Formula: see text] ratio and P impedance on well data. Similar patterns of low-impedance high-TOC areas highlighted and mapped from the petrophysical studies at the Heather level were also observed on seismic relative acoustic impedance and amplitude maps over the study area. The poststack seismic data conditioning (structurally orientated noise reduction) improved the quality of the input megamerge seismic data and allowed the application of colored inversion, structural and fault imaging, as well as multiattribute combination and visualization techniques, which have been efficient in highlighting the distribution of high-TOC areas, structure and fault zones within the study area.

scholarly journals Molecular and Carbon Isotopic Variation during Canister Degassing of Terrestrial Shale: A Case Study from Xiahuayuan Formation in the Xuanhua Basin, North China

Minerals ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 843
Author(s):  
Jia Tao ◽  
Jinchuan Zhang ◽  
Junlan Liu ◽  
Yang Liu ◽  
Wei Dang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Carbon Isotope ◽  
Shale Gas ◽  
Small Variation ◽  
Source Rocks ◽  
Isotopic Variation ◽  
Carbon Isotopic ◽  
Geochemical Parameters ◽  
Shale Reservoirs ◽  
Isotope Variation

Molecular and carbon isotopic variation during degassing process have been observed in marine shale reservoirs, however, this behavior remains largely unexplored in terrestrial shale reservoirs. Here, we investigate the rock parameters of five terrestrial shale core samples from the Xiahuayuan Formation and the geochemical parameters of thirty natural gas samples collected during field canister degassing experiments. Based on these new data, the gas composition and carbon isotope variation during canister degassing are discussed and, further, the relationship between petrophysics and the carbon isotope variation is explored. The results show that methane content first increases and then decreases, the concentrations of carbon dioxide (CO2) and nitrogen gas (N2) peak in the early degassing stage, while heavier hydrocarbons gradually increase over time. Shale gas generated from humic source rocks contains more non-hydrocarbon and less heavy hydrocarbon components than that generated from sapropelic source rocks with similar maturity. Time-series sampling presents an upward increase in δ13C1 value during the degassing process with the largest variation up to 5.7‰, while the variation in δ13C3 and δ13C2 is insignificant compared to δ13C1. Moreover, we find that there is only a small variation in δ13C1 in shale samples with high permeability and relatively undeveloped micropores, which is similar to the limited δ13C1 variation in conventional natural gas. For our studied samples, the degree of carbon isotope variation is positively correlated with the TOC content, micropore volume, and micropore surface, suggesting that these three factors may play a significant role in carbon isotope shifts during shale gas degassing. We further propose that the strong 13C1 and C2+depletion of shale gas observed during the early degassing stage may have resulted from the desorption and diffusion effect, which may lead to deviation in the identification of natural gas origin. It is therefore shale gas of the late degassing stage that would be more suitable for study to reduce analytic deviations. In most samples investigated, significant isotopic variation occurred during the degassing stage at room temperature, indicating that the adsorbed gas had already been desorbed at this stage Our results therefore suggest that more parameters may need to be considered when evaluating the lost gas of shales.

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