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

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.

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

2014 ◽  
Vol 51 (8) ◽  
pp. 783-796 ◽  
Author(s):  
Simon Weides ◽  
Inga Moeck ◽  
Jacek Majorowicz ◽  
Matthias Grobe
Keyword(s):  
Geothermal Gradient ◽  
High Porosity ◽  
Reservoir Properties ◽  
Geothermal Heat ◽  
Hydraulic Stimulation ◽  
Deep Saline Aquifer ◽  
Thin Sections ◽  
Geomechanical Properties ◽  
Western Canada Sedimentary Basin ◽  
Porosity And Permeability

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.

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

2014 ◽  
Vol 675-677 ◽  
pp. 1363-1367 ◽  
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.

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

2018 ◽  
Vol 18 (4) ◽  
pp. 141-147 ◽  
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.

Dolomitization of the Lower Ordovician Watts Bight Formation of the St. George Group, western Newfoundland: evidence of hydrothermal fluid alterationGeological Survey of Canada Contribution 20080544.

2009 ◽  
Vol 46 (4) ◽  
pp. 247-261 ◽  
Author(s):  
James Conliffe ◽  
Karem Azmy ◽  
Ian Knight ◽  
Denis Lavoie
Keyword(s):  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Second Phase ◽  
High Porosity ◽  
Mixing Zone ◽  
Ocean Water ◽  
Lower Ordovician ◽  
Saddle Dolomite ◽  
Porosity And Permeability ◽  
Intercrystalline Pores

The Watts Bight Formation in western Newfoundland consists of a Lower Ordovician succession of shallow-water carbonates and has been extensively dolomitized. These dolomites occur as both replacements and cements and are associated with complex changes in the rock porosity and permeability. Early replacement micritic dolomites (D1) are finely crystalline and indicate that dolomitization began during early stages of diagenesis. The calculated δ18O values of the earliest (D1) dolomitizing fluids (–6.4‰ to –9.5‰ VSMOW, Vienna Standard Mean Ocean Water) fall between the estimated δ18O values of Tremadocian seawater and meteoric waters and suggest mixing-zone dolomitization. A second phase of coarsely crystalline (up to 400 μm) dolomite (D2) replaces D1 dolomite and early calcite and is associated with enhancement in porosity and permeability through the development of intercrystalline pores. A late-stage saddle dolomite (D3) and late burial calcite cements significantly occluded the pores in some horizons. Petrography, fluid inclusions, and geochemistry show that D2 and D3 dolomites formed from warm (65–125 °C) saline (10 to 25 eq. wt.% NaCl + CaCl2) hydrothermal fluids. The calculated δ18Ofluid of D2 ranges from –4.5‰ to 3.6‰ VSMOW, and for D3 dolomites, calculated δ18Ofluid ranges from 1.4‰ to 8.4‰ VSMOW, suggesting an influx of basinal brines. The occurrence of high porosity associated with D2, combined with the laterally sealing tight limestone beds, presence of favourable source rocks, and thermal maturation, may suggest that the Watts Bight carbonates are possible potential hydrocarbon reservoirs and suitable targets for future hydrocarbon exploration in western Newfoundland.

CRETACEOUS OF THE EROMANGA BASIN — IMPLICATIONS FOR HYDROCARBON EXPLORATION

1984 ◽  
Vol 24 (1) ◽  
pp. 358 ◽  
Author(s):  
P. S. Moore ◽  
G. M. Pitt
Keyword(s):  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Existing Structures ◽  
Carbonate Cements ◽  
Fine Grain ◽  
Structural Growth ◽  
Porosity And Permeability ◽  
Shale Reservoirs ◽  
Eromanga Basin

The Cretaceous sequence in the Eromanga Basin covers nearly one-fifth of the Australian mainland and has a maximum thickness of about 2000 m. The lowermost prospective unit is the Neocomian Cadna-owie Formation, which commonly contains hydrocarbon shows and recently yielded oil in Merrimelia 15. Likely source rocks include organic-rich sediments at the base of the overlying Bulldog Shale and Wallumbilla Formation. Future commercial production from the Cadna-owie Formation will be hampered by fine grain size and carbonate cements, resulting in low porosity and permeability. In southwestern Queensland, the Cadna-owie Formation appears to have been locally dissected by prominent channels. If sand-infilled, these channels will represent an interesting stratigraphic play, although they are likely to be mudstone-and diamictite-infilled submarine canyons, similar to those in the Tertiary Latrobe Group, Gippsland Basin. As such, they represent one component of a complex hydrocarbon play that has yet to be evaluated.A third, stratigraphically higher exploration target is the middle Albian Coorikiana Sandstone. Although the marine mudstones which encase the Coorikiana Sandstone are only poor to fair source rocks, hydrocarbon shows are common in the unit, which yielded 9900 m3 of gas per day when tested in Strzelecki 8. The potential of the unit is limited by poor reservoir quality and marginal oil maturity.The Toolebuc Formation, of middle-late Albian age, is the fourth promising target for significant hydrocarbons. The formation consists of organic-rich mudstone which is oil-shale bearing over large parts of Queensland. Minor oil and gas shows, attributed to early generation from a very rich source rock, suggest that oil production from the Toolebuc Formation may be possible if naturally fractured shale reservoirs can be located. Overall, the Cretaceous sequence in the southwestern Eromanga Basin is considered to have a modest oil and gas potential which should be evaluated in the course of drilling for deeper targets.It is emphasised that knowledge of Cretaceous and Cainozoic stratigraphy is essential in understanding the evolution of the Eromanga Basin. Rapid deposition of up to 2000 m of Cretaceous sediments enabled generation of hydrocarbons in the Jurassic sequence, beginning in the latest Cretaceous and continuing today. Although early, syn-sedimentary structuring and mild epeirogeny are evident in Cretaceous sediments, of far greater significance is a major phase of Early Tertiary folding, due probably to the effects of continental breakup and collision. This greatly enhanced pre-existing structures, produced some very large anticlines, and caused up to 800 m of the Cenomanian Winton Formation to be eroded from elevated areas. A complex interplay between timing of structural growth and maturation of the sequence is thus considered to be a major control on the present distribution of hydrocarbons in the Eromanga Basin.

New equation to decipher the relationship between carbon isotopic composition of methane and maturity of gas source rocks

2021 ◽  
Vol 64 (3) ◽  
pp. 470-493 ◽  
Author(s):  
Jianping Chen ◽  
Xulong Wang ◽  
Jianfa Chen ◽  
Yunyan Ni ◽  
Baoli Xiang ◽  
...  
Keyword(s):  
Isotopic Composition ◽  
Carbon Isotopic Composition ◽  
Source Rocks ◽  
Carbon Isotopic ◽  
Gas Source ◽  
New Equation ◽  
The Relationship

Permeability-porosity transforms from small sandstone fragments

Geophysics ◽  
2006 ◽  
Vol 71 (1) ◽  
pp. N11-N19 ◽  
Author(s):  
Ayako Kameda ◽  
Jack Dvorkin ◽  
Youngseuk Keehm ◽  
Amos Nur ◽  
William Bosl
Keyword(s):  
Pore Space ◽  
Petroleum Industry ◽  
Rock Physics ◽  
Three Dimensions ◽  
Absolute Permeability ◽  
High Porosity ◽  
Drill Cuttings ◽  
Thin Sections ◽  
Numerical Experimentation ◽  
The Absolute

Numerical simulation of laboratory experiments on rocks, or digital rock physics, is an emerging field that may eventually benefit the petroleum industry. For numerical experimentation to find its way into the mainstream, it must be practical and easily repeatable — i.e., implemented on standard hardware and in real time. This condition reduces the size of a digital sample to just a few grains across. Also, small physical fragments of rock, such as cuttings, may be the only material available to produce digital images. Will the results be meaningful for a larger rock volume? To address this question, we use a number of natural and artificial medium- to high-porosity, well-sorted sandstones. The 3D microtomography volumes are obtained from each physical sample. Then, analogous to making thin sections of drill cuttings, we select a large number of small 2D slices from a 3D scan. As a result, a single physical sample produces hundreds of 2D virtual-drill-cuttings images. Corresponding 3D pore-space realizations are generated statistically from these 2D images; fluid flow is simulated in three dimensions, and the absolute permeability is computed. The results show that small fragments of medium– to high-porosity sandstones that are statistically subrepresentative of a larger sample will not yield the exact porosity and permeability of the sample. However, a significant number of small fragments will yield a site-specific permeability-porosity trend that can then be used to estimate the absolute permeability from independent porosity data obtained in the well or inferred from seismic techniques.

The Research and Application of Cementing Isolation Technology in High Porosity and Permeability of Developed Clastic Rock Reservoir in Tarim Basin

2021 ◽  
Author(s):  
Hongtao Liu ◽  
Zhengqing Ai ◽  
Jingcheng Zhang ◽  
Zhongtao Yuan ◽  
Jianguo Zeng ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Water Layer ◽  
High Porosity ◽  
Self Healing ◽  
Cement Slurry ◽  
Clastic Rock ◽  
Pump Rate ◽  
Porosity And Permeability ◽  
Zonal Isolation ◽  
High Pump

Abstract The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer. To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied. The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency. The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.

scholarly journals Analysis of the charging process of the lacustrine tight oil reservoir in the Triassic Chang 6 Member in the southwest Ordos Basin, China

2017 ◽  
Vol 54 (12) ◽  
pp. 1228-1247
Author(s):  
Zhengjian Xu ◽  
Luofu Liu ◽  
Tieguan Wang ◽  
Kangjun Wu ◽  
Wenchao Dou ◽  
...  
Keyword(s):  
Ordos Basin ◽  
Source Rocks ◽  
Driving Mechanism ◽  
Tight Oil ◽  
Geological Time ◽  
Tight Sandstone ◽  
Main Production ◽  
The Ordos Basin ◽  
Homogenization Temperatures ◽  
Quartz Grains

With the success of Bakken tight oil (tight sandstone oil and shale oil) and Eagle Ford tight oil in North America, tight oil has become a research focus in petroleum geology. In China, tight oil reservoirs are predominantly distributed in lacustrine basins. The Triassic Chang 6 Member is the main production layer of tight oil in the Ordos Basin, in which the episodes, timing, and drive of tight oil charging have been analyzed through the petrography, fluorescence microspectrometry, microthermometry, and trapping pressure simulations of fluid inclusions in the reservoir beds. Several conclusions have been reached in this paper. First, aqueous inclusions with five peaks of homogenization temperatures and oil inclusions with three peaks of homogenization temperatures occurred in the Chang 6 reservoir beds. The oil inclusions are mostly distributed in fractures that cut across and occur within the quartz grains, in the quartz overgrowth and calcite cements, and the fractures that occur within the feldspar grains, with blue–green, green, and yellow–green fluorescence colours. Second, the peak wavelength, Q650/500, and QF535 of the fluorescence microspectrometry indicate three charging episodes of tight oil with different oil maturities. The charging timings (141–136, 126–118, and 112–103 Ma) have been ascertained by projecting the homogenization temperatures of aqueous inclusions onto the geological time axis. Third, excess-pressure differences up to 10 MPa between the Chang 7 source rocks and the Chang 6 reservoir beds were the main driving mechanism supporting the process of nonbuoyancy migration.

scholarly journals Linking Depositional Environments and Diagenetic Processes to Porosity Evolution and destruction in the Arab Formation reservoirs, Offshore oilfields of Qatar

2020 ◽  
Author(s):  
Fadhil N. Sadooni ◽  
Hamad Al-Saad Al-Kuwari ◽  
Ahmad Sakhaee-Pour ◽  
Wael S. Matter
Keyword(s):  
Depositional Environments ◽  
Oil Reservoir ◽  
Secondary Porosity ◽  
Future Directions ◽  
Thin Sections ◽  
Intergranular Porosity ◽  
Porosity Evolution ◽  
Diagenetic Processes ◽  
Exploration And Production ◽  
The Impact

Introduction: The Jurassic Arab Formation is the main oil reservoir in Qatar. The Formation consists of a succession of limestone, dolomite, and anhydrite. Materials and methods: A multi-proxy approach has been used to study the Formation. This approach is based on core analysis, thin sections, and log data in selected wells in Qatar. Results: The reservoir has been divided into a set of distinctive petrophysical units. The Arab Formation consists of cyclic sediments of oolitic grainstone/packstone, foraminifera-bearing packstone-wackestone, lagoonal mudstone and dolomite, alternating with anhydrite. The sediments underwent a series of diagenetic processes such as leaching, micritization, cementation, dolomitization and fracturing. The impact of these diagenetic processes on the different depositional fabrics created a complex porosity system. So, in some cases there is preserved depositional porosity such as the intergranular porosity in the oolitic grainstone, but in other cases, diagenetic cementation blocked the same pores and eventually destroyed them. In other cases, diagenesis improved the texture of non-porous depositional texture such as mudstone through incipient dolomitization creating inter-crystalline porosity. Dissolution created vugs and void secondary porosity in otherwise non-porous foraminiferal wackestone and packstone. Therefore, creating a matrix of depositional fabrics versus diagenetic processes enabled the identification of different situations in which porosity was either created or destroyed. Future Directions: By correlating the collected petrographic data with logs, it will become possible to identify certain “facio-diagenetic” signatures on logs which will be very useful in both exploration and production. Studying the micro and nano-porosity will provide a better understanding of the evolution and destruction of its porosity system.

Sign in / Sign up

Export Citation Format

Share Document