The Fluid Evolution of Ancient Carbonate Reservoirs in Sichuan Basin and Its Implication for Shale Gas Exploration

Sichuan Basin is the only successful basin for shale gas exploration in China. In addition to the main shale in the Lower Silurian Longmaxi formation, the lower Cambrian Qiongzhusi shale is an important potential formation. However, it was once considered that shale gas is difficult to enrich because of its poor sealing conditions and hydrocarbon migration to adjacent reservoirs. With the increasing research on hydrocarbon generation and reservoir in shale of Qiongzhusi Formation in recent years, it has become an important exploration target in Sichuan Basin. The enrichment of oil and gas is closely related to fluid activities. Limited by the degree of exploration, there is little analysis of fluid activities in Qiongzhusi Formation, and there is little analysis of shale gas enrichment potential from the perspective of fluid. The hydrocarbon generated from Qiongzhusi shale in the rift could migrate laterally to the uplift area and form a reservoir in Dengying Formation. The fluid activities from source rock to reservoir are basically the same. Therefore, this paper reconstructed the history of hydrocarbon activities in Dengying reservoirs based on fluid inclusion analysis. Then the fluid activity process in Qiongzhusi shale was studied, and its enrichment conditions of shale gas was discussed. The results show that the hydrocarbon activities of Dengying Formation can be divided into three stages: 1) oil charging stage, 2) oil cracking gas generation stage and 3) gas reservoir adjustment stage. The first stage is under normal pressure, and the second and third stages developed overpressure with pressure coefficients of 1.3 and 1.2, respectively. High pressure coefficient is an important indicator of shale gas enrichment. Because the source rock of Qiongzhusi Formation has always been the main source rock of Dengying Formation, it can supply hydrocarbon to Dengying Formation only with overpressure in gas generation stage. Therefore, overpressure in the last two stages of gas generation indeed existed. As long as the sealing condition of shale itself is not particularly poor, shale gas “sweet points” would be formed. Therefore, the thick shale in Deyang-Anyue rift is the focus of shale gas exploration in Qiongzhusi Formation.

Download Full-text

Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

Energies ◽

10.3390/en14092679 ◽

2021 ◽

Vol 14 (9) ◽

pp. 2679

Author(s):

Yuying Zhang ◽

Shu Jiang ◽

Zhiliang He ◽

Yuchao Li ◽

Dianshi Xiao ◽

...

Keyword(s):

Source Rock ◽

Shale Gas ◽

Sichuan Basin ◽

Gas Content ◽

Potential Zone ◽

Hydrocarbon Generation ◽

Gas Generation ◽

Longmaxi Formation ◽

Siliceous Shale ◽

Organic Pores

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m3/t and 3.719 m3/t, and the total gas contents were between 0.44 m3/t and 5.19 m3/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas.

Download Full-text

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

10.2118/spe-172966-ms ◽

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.

Download Full-text

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

10.2118/afrc-2557372-ms ◽

2016 ◽

Cited By ~ 1

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.

Download Full-text

Oil And Gas Generation History Based On Burial History Reconstruction And Thermal Maturity Modeling Of Petroleum Systems In Northern Iraq

Journal of Petroleum Research and Studies ◽

10.52716/jprs.v10i4.370 ◽

2020 ◽

Vol 10 (4) ◽

pp. 95-120

Author(s):

Rzger Abdulkarim Abdula

Keyword(s):

Source Rock ◽

Late Cretaceous ◽

Oil And Gas ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Thermal Maturity ◽

Burial History ◽

Gas Generation ◽

Northern Iraq ◽

Oil Generation

Burial history, thermal maturity, and timing of hydrocarbon generation were modeled for five key source-rock horizons at five locations in Northern Iraq. Constructed burial-history locations from east to west in the region are: Taq Taq-1; Qara Chugh-2; Zab-1; Guwair-2; and Shaikhan-2 wells. Generally, the thermal maturity status of the burial history sites based on increasing thermal maturity is Shaikhan-2 < Zab-1 < Guwair-2 < Qara Chugh-2 < Taq Taq-1. In well Qara Chugh-2, oil generation from Type-IIS kerogen in Geli Khana Formation started in the Late Cretaceous. Gas generation occurred at Qara Chugh-2 from Geli Khana Formation in the Late Miocene. The Kurra Chine Formation entered oil generation window at Guwair-2 and Shaikhan-2 at 64 Ma and 46 Ma, respectively. At Zab-1, the Baluti Formation started to generate gas at 120 Ma. The Butmah /Sarki reached peak oil generation at 45 Ma at Taq Taq-1. The main source rock in the area, Sargelu Formation started to generate oil at 47, 51, 33, 28, and 28 Ma at Taq Taq-1, Guwair-2, Shaikhan-2, Qara Chugh-2, and Zab-1, respectively. The results of the models demonstrated that peak petroleum generation from the Jurassic oil- and gas-prone source rocks in the most profound parts of the studied area occurred from Late Cretaceous to Middle Oligocene. At all localities, the Sargelu Formation is still within the oil window apart from Taq Taq-1 and Qara Chugh-2 where it is in the oil cracking and gas generation phase.

Download Full-text

Simulation of hydrocarbon generation and expulsion for the dark mudstone with Type-Ⅲ kerogen in the Pinghu Formation of Xihu Sag in East China Sea Shelf Basin

10.5194/egusphere-egu21-291 ◽

2021 ◽

Author(s):

Chenjie Xu

Keyword(s):

East China Sea ◽

Source Rock ◽

Open System ◽

Oil And Gas ◽

East China ◽

Hydrocarbon Generation ◽

Gas Generation ◽

China Sea ◽

East China Sea Shelf ◽

Oil And Gas Resources

In order to finely describe the hydrocarbon generation and expulsion process of source rocks and provide reasonable key parameters for quantitative evaluation of oil and gas resources, we carried out a simulation research under semi-open system on hydrocarbon generation and expulsion for the dark mudstone with Type-&#8546; kerogen in the Eocene Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin. The results show that the process of hydrocarbon generation and expulsion can be divided into five stages as follows:<ul><li>Ro = 0.5%~0.7%, oil was generated slowly without expulsion;</li> <li>Ro = 0.7%~1.0%, oil was generated and expelled rapidly;</li> <li>Ro = 1.0%~1.5%, oil began to be cracked into hydrocarbon gas;</li> <li>Ro = 1.5%~2.3%, gas generation predominated;</li> <li>Ro > 2.3%, only dry gas was generated.</li> </ul>Oil expulsion threshold (Ro) of the source rock of this type is about 0.7% (Ro = 0.7%), having a wide gas-window of Ro = 1.0%~3.0%. So it can maintain relatively strong gas generation ability at high- and over-mature stages, belonging to gas-prone source rock. Following the study on experimental results and the characteristics of hydrocarbon generation and expulsion in samples, we established a set of mathematical models for the evaluation of the process and potential of gas generation and oil generation and expulsion of the dark mudstone with Type-&#8546; kerogen in the study area. Compared with the thermal simulation experiment in a closed system, the cumulative yield of oil in the semi-open system is higher and closer to that under actual geological conditions. Accordingly, we may conclude that more oil and gas resources may exist in the Xihu Sag.

Download Full-text

The characteristics of hydrocarbon generation, reserving performances of fine-grained rock, and preservation conditions of coal measure shale gas of an epicontinental sea basin: A case study of the Late Palaeozoic shale gas in the Huanghebei Area of Western Shandong

Energy Exploration & Exploitation ◽

10.1177/0144598718804925 ◽

2018 ◽

Vol 37 (1) ◽

pp. 453-472 ◽

Cited By ~ 1

Author(s):

Ying Li ◽

Zengxue Li ◽

Huaihong Wang ◽

Dongdong Wang

Keyword(s):

Coal Seam ◽

Shale Gas ◽

Late Paleozoic ◽

Organic Carbon Content ◽

Hydrocarbon Generation ◽

Average Content ◽

Gas Generation ◽

Geological Structures ◽

Fine Grained ◽

Western Shandong

In China, marine and land transitional fine-grained rocks (shale, mudstone, and so on) are widely distributed and are known to have large accumulated thicknesses. However, shale gas explorations of these types of rock have only recently been initiated, thus the research degree is very low. Therefore, this study was conducted in order to improve the research data regarding the gas accumulation theory of marine and continental transitional fine-grained rock, as well as investigate the shale gas generation potential in the Late Paleozoic fine-grained rock masses located in the Huanghebei Area of western Shandong Province. The hydrocarbon generation characteristics of the epicontinental sea coal measures were examined using sedimentology, petrography, geochemistry, oil and gas geology, tectonics, and combined experimental testing processes. The thick fine-grained rocks were found to have been deposited in the sedimentary environments of the tidal flats, barriers, lagoons, deltas, and rivers during the Late Paleozoic in the study area. The most typical fine-grained rocks were located between the No. 5 coal seam of the Shanxi Formation and the No. 10 coal seam of the Taiyuan Formation, with an average thickness of 84.8 m. These formations were mainly distributed in the western section of the Huanghebei Area. The total organic carbon content level of the fine-grained rock was determined to be 2.09% on average, and the higher content levels were located in the western section of the Huanghebei Area. The main organic matter types of the fine-grained rock were observed to be kerogen II, followed by kerogen III. The vitrinite reflectance ( Ro) of the fine-grained rock was between 0.72 and 1.25%, which indicated that the gas generation of the dark fine-grained rock was within a favorable range, and the maturity of the rock was mainly in a medium stage in the northern section of the Huanghebei Area. It was determined that the average content of brittle minerals in the fine-grained rock was 55.7%. The dissolution pores and micro-cracks were the dominating pores in the fine-grained rock, followed by intergranular pores and intercrystalline pores. It was also found that both the porosity and permeability of the fine-grained rock were very low in the study area. The desorption gas content of the fine-grained rock was determined to be between 0.986 and 4.328 m3/t, with an average content of 2.66 m3/t. The geological structures were observed to be simple in the western section of the Huanghebei Area, and the occurrence impacts on the shale gas were minimal. However, the geological structures were found be complex in the eastern section of the study area, which was unfavorable for shale gas storage. The depths of the fine-grained rock were between 414.05 and 1290.55 m and were observed to become increasingly deeper from the southwestern section to the northern section. Generally speaking, there were found to be good reservoir forming conditions and great resource potential for marine and continental transitional shale gas in the study area.

Download Full-text

GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

African Journal of Engineering and Environment Research ◽

10.37703/ajoeer.org.ng/q2-2020/03 ◽

2020 ◽

Vol 1 (2) ◽

Keyword(s):

Source Rock ◽

Oil And Gas ◽

Linear Regression Analysis ◽

Sedimentary Basins ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Good Source ◽

Type Iii ◽

Limit Value ◽

The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

Download Full-text