The Cambrian Basal Sandstone Unit in central Alberta — an investigation of temperature distribution, petrography, and hydraulic and geomechanical properties of a deep saline aquifer

Recent geothermal exploration indicated that the Cambrian Basal Sandstone Unit (BSU) in central Alberta could be a potential target formation for geothermal heat production, due to its depth and extent. Although several studies showed that the BSU in the shallower Western Canada Sedimentary Basin (WCSB) has good reservoir properties, almost no information exists from the deeper WCSB. This study investigated the petrography of the BSU in central Alberta with help of drill cores and thin sections from six wells. Porosity and permeability as important reservoir parameters for geothermal utilization were determined by core testing. The average porosity and permeability of the BSU is 10% and <1 × 10−14 m2, respectively. A zone of high porosity and permeability was identified in a well located in the northern part of the study area. This study presents the first published geomechanical tests of the BSU, which were obtained as input parameters for the simulation of hydraulic stimulation treatments. The BSU has a relatively high unconfined compressive strength (up to 97.7 MPa), high cohesion (up to 69.8 MPa), and a remarkably high friction coefficient (up to 1.22), despite a rather low tensile strength (<5 MPa). An average geothermal gradient of 35.6 °C/km was calculated from about 2000 temperature values. The temperature in the BSU ranges from 65 to 120 °C. Results of this study confirm that the BSU is a potential geothermal target formation, though hydraulic stimulation treatments are required to increase the permeability of the reservoir.

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An Integrated Microfacies and Well Logs-Based Reservoir Characterization of Yamama Formation, Southern Iraq

Iraqi Journal of Science ◽

10.24996/ijs.2021.62.10.16 ◽

2021 ◽

pp. 3570-3586

Author(s):

Mohanad M. Al-Ghuribawi ◽

Rasha F. Faisal

Keyword(s):

Reservoir Characterization ◽

Water Saturation ◽

Effective Porosity ◽

Well Logs ◽

Petrophysical Properties ◽

Reservoir Properties ◽

Thin Sections ◽

Porosity And Permeability ◽

South Of Iraq ◽

Southern Iraq

The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

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Petrophysical Properties of Nahr Umar Formation in Nasiriya Oil Field

Iraqi Journal of Chemical and Petroleum Engineering ◽

10.31699/ijcpe.2020.3.2 ◽

2020 ◽

Vol 21 (3) ◽

pp. 9-18

Author(s):

Ahmed Abdulwahhab Suhail ◽

Mohammed H. Hafiz ◽

Fadhil S. Kadhim

Keyword(s):

Gamma Ray ◽

Water Saturation ◽

Oil Field ◽

Well Logs ◽

High Porosity ◽

Reservoir Properties ◽

Petrophysical Parameters ◽

Resistivity Logs ◽

Lithology Prediction ◽

Porosity And Permeability

Petrophysical characterization is the most important stage in reservoir management. The main purpose of this study is to evaluate reservoir properties and lithological identification of Nahr Umar Formation in Nasiriya oil field. The available well logs are (sonic, density, neutron, gamma-ray, SP, and resistivity logs). The petrophysical parameters such as the volume of clay, porosity, permeability, water saturation, were computed and interpreted using IP4.4 software. The lithology prediction of Nahr Umar formation was carried out by sonic -density cross plot technique. Nahr Umar Formation was divided into five units based on well logs interpretation and petrophysical Analysis: Nu-1 to Nu-5. The formation lithology is mainly composed of sandstone interlaminated with shale according to the interpretation of density, sonic, and gamma-ray logs. Interpretation of formation lithology and petrophysical parameters shows that Nu-1 is characterized by low shale content with high porosity and low water saturation whereas Nu-2 and Nu-4 consist mainly of high laminated shale with low porosity and permeability. Nu-3 is high porosity and water saturation and Nu-5 consists mainly of limestone layer that represents the water zone.

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West Africa Lacustrine Pre-Salt Carbonates: How Interaction of Tectonics and Diagenesis Produced Different Reservoir Facies

10.2118/afrc-2571388-ms ◽

2016 ◽

Author(s):

Paola Ronchi ◽

Giovanni Gattolin ◽

Alfredo Frixa ◽

Chiara Margliulo

Keyword(s):

Congo Basin ◽

High Porosity ◽

Carbonate Platforms ◽

Pore System ◽

Reservoir Properties ◽

Deep Faults ◽

Facies Associations ◽

Porosity And Permeability ◽

Hydrothermal Dolomite ◽

Reservoir Facies

ABSTRACT During the Early Cretaceous South-Atlantic opening, in large lacustrine basins a series of shallow water carbonate platforms grew along lake margins and paleo-highs. These carbonates are giant reservoirs in the Brasil offshore, while in Angola are productive in Cabinda (Lower Congo Basin) and are being explored in the Kwanza Basin with minor success. These carbonates have peculiar facies associations represented mainly by microbialites and coquinas, and are affected by dolomitization which modified the original pore system in different ways. In presence of deep-seated extensional faults, bounding the paleo-highs, the hydrothermal dolomitization affected the reservoir carbonate improving its quality; in fact the hydrothermal dolomite produced the so-called zebra dolomite which is characterized by high porosity and permeability. On the other hand, when there is a limited influx of hydrothermal fluid, some dolomitization is observed, but it did not produce the zebra facies and the poro-perm system has lower quality. These two examples suggest that the understanding of the distribution of deep faults may help in the prediction of the diagenetic effects and resulting reservoir properties.

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Reservoir and sealing properties of the Newark rift basin formations: Implications for carbon sequestration

The Leading Edge ◽

10.1190/tle39010038.1 ◽

2020 ◽

Vol 39 (1) ◽

pp. 38-46

Author(s):

N. V. Zakharova ◽

D. S. Goldberg ◽

P. E. Olsen ◽

D. Collins ◽

D. V. Kent

Keyword(s):

Carbon Sequestration ◽

Atlantic Coast ◽

High Porosity ◽

Rift Basins ◽

Reservoir Properties ◽

Porous Flow ◽

Mafic Intrusions ◽

Porosity And Permeability ◽

Structural Architecture ◽

Newark Basin

The Newark Basin is one of the major Mesozoic rift basins along the U.S. Atlantic coast evaluated for carbon dioxide (CO2) storage potential. Its geologic setting offers an opportunity to assess both the traditional reservoir targets, e.g., fluvial sandstones, and less traditional options for CO2 storage, e.g., mafic intrusions and lavas. Select samples from the basal, predominantly fluvial, Stockton Formation are characterized by relatively high porosity (8%–18%) and air permeability (0.1–50 mD), but borehole hydraulic tests suggest negligible transmissivity even in the high-porosity intervals, emphasizing the importance of scale in evaluating reservoir properties of heterogeneous formations. A stratigraphic hole drilled by TriCarb Consortium for Carbon Sequestration in the northern basin also intersected numerous sandstone layers in the predominantly lacustrine Passaic Formation, characterized by core porosity and permeability up to 18% and 2000 mD. However, those layers are shallow (predominantly above 1 km in this part of the basin) and lack prominent caprock layers above. The mudstones in all three of the major sedimentary formations (Stockton, Lockatong, and Passaic) are characterized by a high CO2 sealing capacity — evaluated critical CO2 column heights exceed several kilometers. The igneous options are represented by basalt lavas, with porous flow tops and massive flow interiors, and a crystalline but often densely fractured Palisade Sill. The Newark Basin basalts may be too shallow for sequestration over most of the basin's area, but many other basalt flows exist in similar rift basins. Abundant fractures in sedimentary and igneous rocks are predominantly closed and/or sealed by mineralization, but stress indicators suggest high horizontal compressional stresses and strong potential for reactivation. Overall, the basin potential for CO2 storage appears low, but select formation properties are promising and could be investigated in the Newark Basin or other Mesozoic rift basins with similar fill but a different structural architecture.

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Reservoir Physical Property and Controlling Factors for the Lower Youshashan Formation in Youshashan-Dawusi Area, Southwestern Qaidam Basin

Applied Mechanics and Materials ◽

10.4028/www.scientific.net/amm.675-677.1363 ◽

2014 ◽

Vol 675-677 ◽

pp. 1363-1367 ◽

Cited By ~ 1

Author(s):

Guo Min Chen ◽

Quan Wen Liu ◽

Min Quan Xia ◽

Xiang Sheng Bao

Keyword(s):

Qaidam Basin ◽

Sedimentary Environment ◽

Physical Property ◽

Controlling Factors ◽

Reservoir Rock ◽

High Porosity ◽

Delta Front ◽

Thin Sections ◽

Rock Types ◽

Porosity And Permeability

The core data, casting thin sections and scanning electron microscopy are used to study the clastic reservoir characteristics and controlling factors of reservoir growth. It indicated that the main reservoir rock types are lithic arkose, Feld spathic sandstone, and a small amount of feldspar lithic sandstone, and with compositional maturity and low to middle structural maturity. Moreover, the primary reservoir space types are mainly intergranular pores, secondary are secondary pores, and reservoir types belong to the medium-high porosity and permeability, and the average porosity and permeability of lower Youshashan formation are 17.70% and 112.5×10-3μm2 separately. Furthermore, the reservoir body is mainly sand body result from deposits of distributary channel and mouth bar of which belong to the braided delta front, and the planar physical property tends to be better reservoir to worse reservoir from northwest to southeast. Finally, mainly factors to control the distribution of reservoir physical property, are the sedimentary environment and lithology, were worked out.

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Porosity and Permeability Measurements Integration of The Upper Cretaceous in Balad Field, Central Iraq

Iraqi Geological Journal ◽

10.46717/igj.54.1b.3ms-2021-02-21 ◽

2021 ◽

Vol 54 (1B) ◽

pp. 24-42

Author(s):

Fawzi Al-Beyati

Keyword(s):

Image Analysis ◽

Log Analysis ◽

Core Analysis ◽

Well Log ◽

Reservoir Properties ◽

Thin Sections ◽

Core Samples ◽

Porosity And Permeability ◽

Well Log Analysis ◽

Porosity Range

The corrected porosity image analysis and log data can be used to build 3D models for porosity and permeability. This can be much realistic porosity obtainable because the core test data is not always available due to high cost which is a challenge for petroleum companies and petrophysists. Thus, this method can be used as an advantage of thin section studies and for opening horizon for more studies in the future to obtain reservoir properties. Seventy-two core samples were selected and the same numbers of thin sections were made from Khasib, Sa`di, and Hartha, formations from Ba-1, Ba-4, and Ba-8 wells, Balad Oilfield in Central Iraq to make a comprehensive view of using porosity image analysis software to determine the porosity. The petrophysical description including porosity image analysis was utilized and both laboratory core test analysis and well log analysis were used to correct and calibrate the results. The main reservoir properties including porosity and permeability were measured based on core samples laboratory analysis. The results of porosity obtained from well log analysis and porosity image analysis method are corrected by using SPSS software; the results revealed good correlation coefficients between 0.684 and 0.872. The porosity range values are 9-16% and 9-27% for Khasib and Sa’di in Ba-1 Well, respectively; 10-21%, 9-25%, and 16-27% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 11-24% and 15-24% for Khasib and Hartha in Ba-8 Well, respectively according to petrographic image analysis. By using the laboratory core analysis, the porosity range values are 12-26% and 17-24% for Khasib and Sa’di in Ba-1 Well, respectively; 6-28% and 14-27% for Sa’di and Hartha in Ba-4 Well, respectively; and 17-19% and 15-24% for Sa’di and Hartha in Ba-8 Well, respectively. Finally, the well log analysis showed that the porosity range values are 11-16% and 7-27% for Khasib and Sa’di in Ba-1 Well, respectively; 4-18%, 21-26%, and 16-19% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 9-24% and 15-23% for Khasib and Hartha in Ba-8 Well, respectively. The permeability range values based on laboratory core analysis are 1.51-8.97 md and 0.29-2.77 md for Khasib and Sa’di in Ba-1 Well, respectively; 0.01-24.5 md and 0.28-6.47 md for Sa’di and Hartha in Ba-4 Well, respectively; and 0.86-2.25 md and 0.23-3.66 for Sa’di and Hartha in Ba-8 Well, respectively.

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Experimental determination of porosity and permeability properties of terrigenous reservoirs for creation and validation of a digital core model

Arctic Environmental Research ◽

10.3897/issn2541-8416.2018.18.4.141 ◽

2018 ◽

Vol 18 (4) ◽

pp. 141-147 ◽

Cited By ~ 1

Author(s):

Ivan Belozerov

Keyword(s):

Pore Space ◽

Experimental Studies ◽

Core Model ◽

High Porosity ◽

Thin Sections ◽

Additional Tool ◽

Digital Core ◽

Reservoir Conditions ◽

Porosity And Permeability ◽

Original Oil In Place

Digital core modelling is a vital task assessing original-oil-in-place. This technology can be seen as an additional tool for physical experiments capable of providing fast and efficient modelling of porous media. The objective of the paper is to determine experimentally the porosity and permeability properties of rocks and justify the possibility of using them for digital core modelling. The paper also validates feasibility of using the results of lithologic and petrographic surveys of thin sections in digital core modelling. The experimental studies of reservoir conditions allowed us to obtain curves of the dependence between the kerosene permeability of the terrigenous reservoir of the Buff Berea field and the temperature and to determine its main porosity and permeability properties. The paper also validates feasibility of applying the results of lithologic and petrographic surveys of thin sections of the reservoir to form the structure of the pore space of a digital core model by machine learning. The choice of this reservoir stems from the fact that the terrigenous sandstones of Berea Sandstone (USA) are characterised by minimal anisotropy of porosity and permeability properties, relatively high porosity and permeability, as well as uniformly sized grains of the composing rocks and good sorting. Oil industry experts therefore consider samples of these rocks to be most suitable for conducting applied research and testing various technologies. The results obtained were used to select the parameters required for modelling filtration flows in a digital model of the core.

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THE INFLUENCE OF SEDIMENTATION AND POST-SEDIMENTATION TRANSFORMATIONS ON THE RESERVOIR PROPERTIES OF THE ROCKS

Visnyk of Taras Shevchenko National University of Kyiv Geology ◽

10.17721/1728-2713.87.02 ◽

2019 ◽

pp. 14-19

Author(s):

V. Khomyn ◽

M. Maniuk ◽

O. Maniuk ◽

A. Popluiko ◽

N. Khovanets

Keyword(s):

Oil And Gas ◽

Scientific Evidence ◽

Gas Content ◽

High Porosity ◽

Reservoir Properties ◽

Quartz Content ◽

Positive Correlation ◽

Median Diameter ◽

Porosity And Permeability ◽

Cover Thickness

The topicality of the research is proved by the scientific evidence of the peculiarities of the sedimentation and post-sedimentation transformations of the rocks in relation to their possible oil and gas content. The productive sediments of the deposits of the interior of the Precarpathian Depression were thoroughly and lithologically researched. The objective implied the study and recognition of the reservoir properties within primary (sedimentation) and secondary (post-sedimentation) factors. The primary ones are as follows: granulity (grains median diameter), sorting, and rock maturity. Consequently, a positive correlation between the grains median diameter and rock porosity has been determined; the very coefficient equals 0.56. Evidently, unlike the well-sorted sandstones, the badly graded ones are marked by poor porosity and permeability. The positive correlation between porosity and clastic quartz content is revealed: should the latter increase, the former will go up as well. Apparently, more mature sandstones are characterized by dramatically high porosity; this factor positively affects the reservoir properties of the rocks. After studying the secondary transformations of the sandy rocks, we have determined that the diagenesis stage is defined by the change of mineral composition. This alteration is mainly caused by organic material decomposition and the appearance of reducing environment. Considering the cover thickness, we have graded the transformations of the fragments of the sandy-aleuritic rocks of the depression. The pattern of the catagenetic changes at various depths has been introduced. In the end, we have inferred that the increasing depth starts influencing the three types of the structures, i.e. incorporating, reclaiming and microstilolite rather gradually. In addition, the declining importance of the conformal structures has been identified. The stress pattern of the catagenetically transformed solid rocks promotes the microfracture within the late catagenesis zones; this factor predetermines the development of decompression zones at the depths exceeding 4 km characterised by good reservoir properties.

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Controls on abnormally high porosity in a deep burial reservoir of the Lingshui Formation in the Qiongdongnan Basin, South China Sea

Interpretation ◽

10.1190/int-2019-0185.1 ◽

2020 ◽

Vol 8 (3) ◽

pp. SM53-SM64

Author(s):

Guangxu Bi ◽

Chengfu Lyu ◽

Qianshan Zhou ◽

Guojun Chen ◽

Chao Li ◽

...

Keyword(s):

Isotopic Composition ◽

Aqueous Fluid ◽

Source Rocks ◽

High Porosity ◽

Secondary Porosity ◽

Thin Sections ◽

Carbonate Cements ◽

Acid Generation ◽

Porosity And Permeability ◽

Homogenization Temperatures

Based on information including porosity and permeability, petrography, the stable isotopic composition of carbonate cements, and homogenization temperatures of aqueous fluid inclusions, we have studied the main factors for the development of abnormally high porosity in the Lingshui Formation reservoir of the Yacheng area. We found the sandstones were mainly subarkose, arkose, and lithic arkose and were texturally and compositionally immature. The research suggested that the sandstones existing close beneath the regional unconformity were formed during the Late Oligocene. Early diagenetic calcite cements leached to form intergranular secondary pores without the precipitation of late-diagenetic calcite cements in most sandstones. The isotopic composition of carbonate cements suggested a significant incursion of meteoric freshwater in the sandstones. Early diagenetic meteoric freshwater leaching reactions provided favorable conduits for the penetration of organic acids during the later period. Thermal fluid activities allowed source rocks to mature rapidly; therefore, the organic acid generation period was extended and feldspars were corroded to form abundant intragranular secondary pores. The abundant corroded minerals and the small amounts of associated authigenic minerals suggested that the dissolution of minerals most likely occurred in an open geochemical system. The dissolution of feldspars and calcite minerals generated an enhanced secondary porosity of approximately 9%–13% in thin sections of these sandstones.

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Impact of Diagenesis on the Reservoir Properties of the Cretaceous Sandstones in the Southern Bredasdorp Basin, Offshore South Africa

Minerals ◽

10.3390/min10090757 ◽

2020 ◽

Vol 10 (9) ◽

pp. 757

Author(s):

Temitope Love Baiyegunhi ◽

Kuiwu Liu ◽

Oswald Gwavava ◽

Christopher Baiyegunhi

Keyword(s):

Oil And Gas ◽

Gas Production ◽

Reservoir Quality ◽

Reservoir Properties ◽

Oil And Gas Production ◽

Thin Sections ◽

Hydrocarbon Reservoir ◽

Porosity And Permeability ◽

The Impact

The Cretaceous sandstone in the Bredasdorp Basin is an essential potential hydrocarbon reservoir. In spite of its importance as a reservoir, the impact of diagenesis on the reservoir quality of the sandstones is almost unknown. This study is undertaken to investigate the impact of digenesis on reservoir quality as it pertains to oil and gas production in the basin. The diagenetic characterization of the reservoir is based on XRF, XRD SEM + EDX, and petrographic studies of 106 thin sections of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 in the basin. The main diagenetic processes that have affected the reservoir quality of the sandstones are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed up by the development of partial pore-lining and pore-filling clay cements, particularly illite. This clay acts as pore choking cement, which reduces porosity and permeability of the reservoir rocks. The scattered plots of porosity and permeability versus cement + clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays.

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