Application of well log analysis to estimate the petrophysical parameters and evaluate the reservoir quality of the Lower Goru Formation, Lower Indus Basin, Pakistan

Jumat

et al. 2021

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The Middle to Late Eocene Mangahewa Formation in the Taranaki Basin has been evaluated for its petroleum system (source potential and reservoir qualities). The Mangahewa Formation is generally interpreted as an alternating marginal to shallow marine environment, with lithologies consisting of sandstone, siltstone, mudstone and bitumonius coal. The pyrolysis results show very good source rock generative potential with total organic carbon content of 0.8-90.02 wt. % and hydrogen index values in the range of 54- 491 mg HC/g TOC, with a predominance of oil- and/or gas-prone, mixed Type II-III kerogen. Organic petrographical data reveal that the humic nature of coals being rich in perhydrous vitrinite whereas shales are rich in alginite and bituminite desplaying frequent of migrabitumens. Biomarker analysis suggests predominantly terrigenous origin, whereas pyrolysis Tmax data (414–447°C) and other maturity indicators such as biomarkers and vitrinite reflectance indicates immature and mature samples. Petrographic analyses show that the occurrence of compaction and cementation is succeeded by leaching of feldspars and dissolution of calcite cement. The reservoir samples exhibit largely good reservoir quality with porosity being the dominant feature. The average porosity value is 15.7%, with 21.4% average water saturation. The source and reservoir units are part of a complete petroleum system of the Mangahewa Formation, with the overlying Turi Formation seal rock. The petroleum processes of maturation, generation, and migration which started since Lower Miocene (18.8 Ma) have been recorded in many stratigraphic traps within the Mangahewa Formation or other faulted structural traps due to migration. The generation process is expected to continue to the present day as the source continues to attain maturity while it does not yet reach the peak generation.

Section: Well Log Interpretationmentioning

confidence: 86%

Source and Reservoir Characteristics of the Eocene Mangahewa Formation in Taranaki Basin, New Zealand: Their implications on petroleum system

Jumat

et al. 2021

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“…On the other hand, Higgs et al (2017) accomplished a reservoir characterization on the same formation of interest utilizing an interdisciplinary method, which include biostratigraphy, log facies and stratigraphic correlation of the formation. Additionally, similar integrated reservoir characterization studies in the Taranaki Basin have previously been made such as Jumat et al (2018), Dong et al (2018), Qadri et al (2019a) and in many other fields such as Shalaby et al (2014aShalaby et al ( , b, 2016Shalaby et al ( , 2018, Shalaby and Islam (2017), Osli et al (2018) and Qadri et al (2019b). According to Cade et al (1994), the performance and presentation of sandstone reservoir are mainly influenced by various factors, such as the textural and diagenetic properties like grain size, sorting type, compaction, cementation and dissolution.…”

Section: Introductionmentioning

confidence: 81%

Integrated reservoir characterization and fluid flow distribution of the Kaimiro Formation, Taranaki Basin, New Zealand

Sapri

J Petrol Explor Prod Technol

2020

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An integrated reservoir characterization study is achieved on the Early to Middle Miocene Kaimiro Formation in the Taranaki Basin, New Zealand, to identify the quality of the formation as a potential reservoir. The Kaimiro Formation is a section of the Kapuni Group in the Taranaki Basin, consisting mainly of sandstone and a range of coastal plain through shallow marine facies. Several methods were accomplished for this study: petrophysical evaluation, sedimentological and petrographical descriptions and well log analysis. Based on the petrophysical study, the Kaimiro Formation is interpreted to have several flow units ranges up to 15 μm. Higher RQI and FZI reflect potential reservoir, while the pore size and pore throat diameters (r35) are found to be within the range of macro- and megapores, on the contrary to macropores related to poor reservoir quality concentrated in Tui-1 well. This is in good agreement with other measurements that show the formation is exhibited to be a good promising reservoir as the formation comprises a good average porosity of 19.6% and a good average permeability of 879.45 mD. The sedimentological and petrographical studies display that several diagenetic features have been affecting the formation such as compaction, cementation, dissolution and the presence of authigenic clay minerals. Although these features commonly occur, the impact on the reservoir properties and quality is minor as primary and secondary pores are still observed within the Kaimiro sandstone. Moreover, well log analysis is also completed to further ensure the hydrocarbon potential of the formation through a qualitative and quantitative analysis. It has been confirmed that the Kaimiro Formation is a promising reservoir containing several flow units with higher possibility for storage capacity.

“…The corrected porosity is then estimated by using a combination of density and neutron logs (Asquith and Krygowski 2004;Rider 1996) often termed as Neutron-Density Porosity Model within the Interactive Petrophysics 2013. To discriminate the zones of high porosity, a 10% cutoff was applied (Qadri et al 2019b). The neutron tool response was used to estimate the neutron porosity, whereas the Wyllie equation (Wyllie 1963) was used to calculate the density porosity.…”

Section: Methodsmentioning

confidence: 99%

“…For instance, the presence of chlorite prevents the quartz cementation whereas the occurrence of kaolinite can imply to the high porosity zones within the reservoir formation. Kaolinite resulting from acid dissolution during the diagenetic phases also creates secondary porosity (Jiang 2012;Qadri et al 2019b). In addition to the burial diagenetic processes which impede the reservoir quality, few diagenetic phenomena enhance the porosity and permeability using fracturing, cement dissolution, etc.…”

Section: Diagenetic Cement and Reservoir Qualitymentioning

confidence: 99%

“…Various researchers have worked on the reservoir quality evaluation around the globe, by using multiple techniques i.e., structural, sedimentological, or petrophysical analyses. Some of the scientists have used one method (e.g., Qadri et al 2019bQadri et al , 2017Alotaby 2015, etc. ), while others have integrated two or more methods (e.g., Al-Jawad et al 2020;Islam et al 2020;Nabawy et al 2019;Soleimani et al 2017;Islam 2009;Gier et al 2008).…”

Section: Introductionmentioning

confidence: 99%

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Reservoir quality evaluation of the Farewell sandstone by integrating sedimentological and well log analysis in the Kupe South Field, Taranaki Basin-New Zealand

Qadri

J Petrol Explor Prod Technol

et al. 2020

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The study used the sedimentological and well log-based petrophysical analysis to evaluate the Farewell sandstone, the reservoir formation within the Kupe South Field. The sedimentological analysis was based on the data sets from Kupe South-1 to 5 wells, comprising the grain size, permeability, porosity, the total cement concentrations, and imprints of diagenetic processes on the reservoir formation. Moreover, well log analysis was carried on the four wells namely Kupe South 1, 2, 5 and 7 wells for evaluating the parameters e.g., shale volume, total and effective porosity, water wetness and hydrocarbon saturation, which influence the reservoir quality. The results from the sedimentological analysis demonstrated that the Farewell sandstone is compositionally varying from feldspathic arenite to lithic arenite. The analysis also showed the presence of significant total porosity and permeability fluctuating between 10.2 and 26.2% and 0.43–1376 mD, respectively. The diagenetic processes revealed the presence of authigenic clay and carbonate obstructing the pore spaces along with the occurrence of well-connected secondary and hybrid pores which eventually improved the reservoir quality of the Farewell sandstone. The well log analysis showed the presence of low shale volume between 10.9 and 29%, very good total and effective porosity values ranging from 19 to 32.3% as well as from 17 to 27%, respectively. The water saturation ranged from 22.3 to 44.9% and a significant hydrocarbon saturation fluctuating from 55.1 to 77.7% was also observed. The well log analysis also indicated the existence of nine hydrocarbon-bearing zones. The integrated findings from sedimentological and well log analyses verified the Farewell sandstone as a good reservoir formation.