Siliciclastic Diagenesis in Paleocene-Eocene Reservoir Sandstones of the Taranaki Basin, New Zealand

1988 ◽  
Vol 6 (2) ◽  
pp. 151-169 ◽  
Author(s):  
G.J. van der Lingen ◽  
G.A. Challis ◽  
P.H. Robinson ◽  
D. Smale ◽  
W.A. Walters
Keyword(s):  
Compaction Pressure ◽  
Source Rocks ◽  
Heavy Minerals ◽  
Reservoir Quality ◽  
Depth Range ◽  
Secondary Porosity ◽  
Carbonate Cement ◽  
Continental Block ◽  
Reservoir Sandstones ◽  
Porosity Development

Present-day producing hydrocarbon reservoirs in the Taranaki Basin occur in the Paleocene-Eocene Kapuni Group, both onshore and offshore. The Kapuni Group has been encountered only in drillholes, the top being at depths ranging from 2 to 4 km. It consists of fluvial, paralic, near-shore and shelf sediments, containing proven and prospective reservoir sandstones with variable grain-size, sorting, porosity and permeability. Compositionally, the sandstones are sub-feldsarenites to feldsarenites, derived from continental block source rocks. Diagenetic features adversely affecting reservoir quality are compaction, pressure solution, clay neoformation, quartz overgrowth and neoformation, and carbonate neoformation. Secondary porosity development enhances reservoir quality, through dissolution of earlier (corroding) carbonate cement, dissolution of calcic plagioclase. quartz dissolution, and grain fracturing. Intrastratal solution of heavy minerals suggests that the Kapuni Group sedimentary sequence had progressed into the thermobaric hydrogeological regime. Kaolinite is an early diagenetic clay mineral, while illite and chlorite are formed later (> 3 km). Quartz overgrowth has only been observed in samples from deeper than 3 km. Carbonate cemented horizons, although of relatively limited occurrence, have been observed over the entire studied depth range. Good secondary porosity development, due to (probable) carobate-cement dissolution has been observed in the gas/condensate reservoir of the Maui Field, and in the Witiora Sandstone (base Kapuni Group) in Tane-1, indicating that potential reservoirs can exist at depths of at least 3.5 km.

scholarly journals The impacts of diagenetic facies on reservoir quality in tight sandstones

2020 ◽  
Vol 12 (1) ◽  
pp. 1060-1082
Author(s):  
Dazhong Ren ◽  
Liang Sun ◽  
Rongxi Li ◽  
Dengke Liu
Keyword(s):  
Pore Structure ◽  
Ordos Basin ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Carbonate Content ◽  
Porosity Evolution ◽  
Carbonate Cement ◽  
Pore Structures ◽  
Diagenetic Facies ◽  
The Impact

AbstractThe impact of diagenetic minerals and the characteristics of pore structures on reservoir qualities has been studied separately in the past years. However, the difference in the reservoir quality with different pore structures and having same or similar content of diagenesis minerals has not been ascertained. In this study, based on the core samples derived from Chang 6 member in the Ordos basin, various tests were performed to examine the sandstone diagenesis and investigate the pore structure. The results showed that there were five diagenetic facies by diagenetic and pore structure analyses, and the best reservoir quality rocks were found to have relatively low percentage of illite, carbonate cement, pore-filling chlorite, authigenic quartz, and relatively high proportion of intergranular pores. Smectite-to-illite reaction and chemical compaction were main sources for quartz cementation at 60–120°C, and carbonate content was found to increase toward source rocks. The porosity depth trends significantly affected the diagenetic facies. The diagenetic and the pore structure pathways of various diagenetic facies were reconstructed by integrated petrographic, mineralogical, and pore system data. This study provides insights into the porosity evolution and diagenetic pathways of various diagenetic facies of tight sandstones, and the influence of diagenesis minerals and pore structures on their reservoir quality.

Oil migration makes the difference: regional distribution of carbonate cement δ13C in northern North Sea Tertiary sandstones

Clay Minerals ◽  
2000 ◽  
Vol 35 (1) ◽  
pp. 69-76 ◽  
Author(s):  
C. I. Macaulay ◽  
A. E. Fallick ◽  
R. S. Haszeldine ◽  
G. E. McAulay
Keyword(s):  
North Sea ◽  
Regional Distribution ◽  
Distribution Patterns ◽  
Source Rocks ◽  
Oil Migration ◽  
Bacterial Fermentation ◽  
Carbonate Cement ◽  
Carbonate Cements ◽  
Reservoir Sandstones ◽  
Northern North Sea

AbstractCarbonate cements in Tertiary reservoir sandstones from the northern North Sea have distinctive carbon isotopic compositions (δ13C). Oil migration up faults from deeper structures and biodegradation of oil pools are factors of particular importance in influencing the δ13C of carbonate cements in these sandstones. As a result, δ13C can be used as an exploration guide to locating the positions of vertical leakoff points from the Jurassic source rocks. The histogram distribution of δ13C in these carbonate cements is trimodal, with peaks at around −26, −3 and +12‰ (ranges −22 to −30, +2 to −10 and +8 to +18‰, respectively). Bacterial processes played major roles in determining this distribution, with oxidative biodegradation of oil resulting in carbonate cements with very negative compositions and bacterial fermentation resulting in the positive δ13C cements. δ13C distribution patterns may be used to differentiate Tertiary reservoir sandstones from Jurassic in the northern North Sea, and these regional carbonate cement δ13C datasets allow geologically useful inferences to be drawn from δ13C data from new sample locations.

DETRITAL AND AUTHIGENIC MINERALOGY OF THE PRETTY HILL FORMATION IN THE PENOLA TROUGH, OTWAY BASIN: IMPLICATIONS FOR FUTURE EXPLORATION AND PRODUCTION

1995 ◽  
Vol 35 (1) ◽  
pp. 538 ◽  
Author(s):  
B. M. Little ◽  
S. E. Phillips
Keyword(s):  
Reservoir Quality ◽  
Secondary Porosity ◽  
Water Contact ◽  
Thin Sections ◽  
Authigenic Minerals ◽  
Wide Range ◽  
Resistivity Logs ◽  
Exploration And Production ◽  
Reservoir Sandstones ◽  
The Impact

The Pretty Hill Formation in the Penola Trough is a productive gas reservoir in the Katnook, Ladbroke Grove and Haselgrove fields. Thin sections, X-ray diffraction, scanning electron micros­copy and electron microprobe analyses have been used to characterise the mineralogy of core samples from eight wells. The reservoir sandstones are typically fine to medium grained, moderately sorted feldspathic litharenites. Framework grains comprise detrital quartz, feldspars (albite, microcline and anorthite), lithics (dominantly volcanic), mica and accessory minerals. Authigenic minerals of chlorite, laumontite, carbonate, quartz, feldspar, sphene, anatase, glaucony and illite are present in all wells. Kaolinite is restricted to Ladbroke Grove-1. Chlorite, laumontite and carbonate are volumetrically the most important authigenic minerals.There is a wide range in core plug porosity (one to 23 per cent) and permeability (10"3to 103 md) in the reservoir sandstones. In samples with high per­centages of authigenic clays microporosity is im­portant. Regional trends indicate reservoir quality decreases with increasing depth but superimposed on this trend is the influence of the detrital and authigenic mineralogy. Cleaner, coarser sublitharenites and subarkoses have good reservoir char­acteristics but where lithics concentrate in the finer feldspathic litharenites and litharenites deformation of these ductile grains has limited porosity and permeability. Authigenic minerals have both reduced and enhanced reservoir quality. Chlo­rite rims with associated microporosity have decreased the impact of mechanical compaction and inhibited silicification. Pore filling cements of laumontite and carbonate have occluded intergranular pores and replaced grains. Secondary porosity produced by the dissolution of these cements in the gas zones has significantly improved reservoir quality.Other information gained from the mineralogical study could influence future exploration and production. Lack of contrast on resistivity logs between gas and water zones is not due to the mineralogy of the Pretty Hill Formation. However, the restriction of early diagenetic laumontite to the water zones of gas producing wells does indicate the location of the gas-water contact. Laumontite was dissolved from the gas zone by an increase in C02 prior to hydrocarbon migration. Use of acids to enhance permeability in the Pretty Hill Formation should take into account the probable formation damage caused by reactions with the clays. Kaolin- ite could dissolve to produce a silica gel and the high Fe3+ content of the chlorite will result in a gel unless iron chelators are used in the mud acid. The depositional environment of the Pretty Hill Forma­tion has historically been interpreted as braided fluvial stream deposits interfingering with finer grained lacustrine shales and siltstone. However, this model can not explain the presence of glaucony grains, unless the glaucony has been reworked, but there is no unequivocal evidence to support this hypothesis.

scholarly journals Feldspar Dissolution and Its Influence on Reservoirs: A Case Study of the Lower Triassic Baikouquan Formation in the Northwest Margin of the Junggar Basin, China

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-19 ◽  
Author(s):  
Meng Xiao ◽  
Xuanjun Yuan ◽  
Dawei Cheng ◽  
Songtao Wu ◽  
Zhenglin Cao ◽  
...  
Keyword(s):  
Clay Minerals ◽  
Physical Property ◽  
Junggar Basin ◽  
Sedimentary Facies ◽  
Lower Triassic ◽  
Depositional Environments ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Delta Plain ◽  
Feldspar Dissolution

Feldspar dissolution is a common feature in clastic rock reservoirs of petroliferous basins and has an important influence on reservoir quality. However, the effect of feldspar dissolution on reservoir quality varies under different depositional environments and diagenetic systems. The study area in this paper is located in the Baikouquan Formation in the northwestern margin of the Junggar Basin, which is significantly influenced by feldspar dissolution. Based on the analyses of core and thin section observations, QEMSEM, XRD, SEM, CL, fluorescence, and image analysis software combined with logging and physical property data, this study shows that feldspar dissolution in the subaqueous distributary channel of a fan delta plain, which has good original physical properties and low mud contents, significantly improves the properties of the reservoir. The main reasons for this are as follows: (1) the sedimentary facies with good original properties and low mud content is a relatively open system in the burial stage. The acidic fluids needed for feldspar dissolution are mostly derived from organic acids associated with the source rocks and migrate to the good-permeability area of the reservoir; (2) the by-products of feldspar dissolution, such as authigenic clay minerals and authigenic quartz, are transported by pore water in a relatively open diagenetic system and then precipitated in a relatively closed diagenetic system; and (3) the clay minerals produced by feldspar dissolution in different diagenetic environments and diagenetic stages have different effects on the reservoir. When the kaolinite content is less than 3%, the illite content is less than 4%, and the chlorite content is less than 12%, the clay minerals have a positive effect on the porosity. These clay minerals can reduce porosity and block pore throats when their contents are larger than these values.

Characteristics of the Russian shelf seas in the Arctic Ocean regarding the content of heavy minerals in surface sediments: new data

2021 ◽  
Author(s):  
Elena Popova
Keyword(s):  
Arctic Ocean ◽  
Environmental Science ◽  
Barents Sea ◽  
Source Rocks ◽  
Heavy Minerals ◽  
The Arctic ◽  
Arctic Seas ◽  
Riverine Input ◽  
The Arctic Ocean ◽  
Shelf Seas

<p>Such factors as climate, currents, morphology, riverine input, and the source rocks influence the composition of the sediments in the Arctic Ocean. Heavy minerals being quite inert in terms of transport can reflect the geology of the source rock clearly and indicate the riverine input. There is a long history of studying the heavy mineral composition of the sediments in the Arctic Ocean. The works by Vogt (1997), Kosheleva (1999), Stein (2008), and others study the distribution of the minerals both on a sea scale and oceanwide. The current study covers Russian shelf seas: Barents, Kara, Laptev, East Siberian, and Chukchi Seas. To collect the material several data sources were used: data collected by the institute VNIIOkeangeologia during numerous expeditions since 2000 for mapping the shelf, data from the old expedition reports (earlier than 2000) taken from the geological funds, and datasets from PANGAEA (www.pangaea.de). About 82 minerals and groups of minerals were included in the joint dataset. The density of the sample points varied significantly in all seas: 1394 data points in the Barents Sea, 713 in the Kara Sea, 487 in the Laptev Sea, 196 in the East Siberian Sea, and 245 in the Chukchi Sea. These data allowed comparing the areas in terms of major minerals and associations. Maps of prevailing and significant components were created in ODV (Schlitzer, 2020) to demonstrate the differences between the seas and indicate the sites of remarkable changes in the source rocks. Additionally, the standardized ratio was calculated to perform quantitative comparison: the sea average was divided by the weighted sea average and then the ratio of that number to the mineral average was found. Only the minerals present in at least four seas and amounting to at least 20 points per sea were considered. As a result, water areas with the highest content of particular minerals were detected. The ratio varied from 0 to 3,4. Combining the ratio data for various minerals allowed mapping specific groups or provinces for every sea and within the seas.</p><p> </p><p>Kosheleva, V.A., & Yashin, D.S. (1999). Bottom Sediments of the Arctic Seas. St. Petersburg: VNIIOkeangeologia, 286pp. (in Russian).</p><p>PANGAEA. Data Publisher for Earth & Environmental Science https://www.pangaea.de/</p><p>Schlitzer, R. (2020). Ocean Data View, Retrieved from https://odv.awi.de.</p><p>Stein, R. (2008). Arctic Ocean Sediments: Processes, Proxies, and Paleoenvironment. Oxford: Elsevier, 602pp.</p><p>Vogt, C. (1997). Regional and temporal variations of mineral assemblages in Arctic Ocean sediments as a climatic indicator during glacial/interglacial changes. Berichte Zur Polarforschung, 251, 309pp.</p>

The Uniqueness of Heterogeneous Globigerina Limestone Reservoir and The Importance of Integrated Rock Type Definition for Field Development Plan: Case Study in Madura Strait, East Java

2021 ◽  
Author(s):  
E. P. Putra
Keyword(s):  
Water Saturation ◽  
Rock Type ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
Secondary Porosity ◽  
Field Development ◽  
Core Data ◽  
Type Definition ◽  
Volume Porosity ◽  
Porosity And Permeability

The Globigerina Limestone (GL) is the main reservoir of the seven gas fields that will be developed in the Madura Strait Block. The GL is a heterogeneous and unique clastic carbonate. However, the understanding of reservoir rock type of this reservoir are quite limited. Rock type definition in heterogeneous GL is very important aspect for reservoir modeling and will influences field development strategy. Rock type analysis in this study is using integration of core data, wireline logs and formation test data. Rock type determination applies porosity and permeability relationship approach from core data, which related to pore size distribution, lithofacies, and diagenesis. The analysis resulted eight rock types in the Globigerina Limestone reservoir. Result suggests that rock type definition is strongly influenced by lithofacies, which is dominated by packstone and wackestone - packstone. The diagenetic process in the deep burial environment causes decreasing of reservoir quality. Then the diagenesis process turns to be shallower in marine phreatic zone and causes dissolution which increasing the reservoir quality. Moreover, the analysis of rock type properties consist of clay volume, porosity, permeability, and water saturation. The good quality of a rock type will have the higher the porosity and permeability. The dominant rock type in this study area is RT4, which is identical to packstone lithofasies that has 0.40 v/v porosity and 5.2 mD as average permeability. The packstone litofacies could be found in RT 5, 6, 7, even 8 due to the increased of secondary porosity. It could also be found at a lower RT which is caused by intensive cementation.

scholarly journals Small-scale diagenetic facies heterogeneity controls porosity and permeability pattern in reservoir sandstones

2020 ◽  
Vol 79 (18) ◽  
Author(s):  
Matthias Heidsiek ◽  
Christoph Butscher ◽  
Philipp Blum ◽  
Cornelius Fischer
Keyword(s):  
Reservoir Rock ◽  
Rock Properties ◽  
Small Scale ◽  
Reservoir Quality ◽  
Permian Basin ◽  
Gas Reservoirs ◽  
Spatial Fluctuations ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Diagenetic Facies

Abstract The fluvial-aeolian Upper Rotliegend sandstones from the Bebertal outcrop (Flechtingen High, Germany) are the famous reservoir analog for the deeply buried Upper Rotliegend gas reservoirs of the Southern Permian Basin. While most diagenetic and reservoir quality investigations are conducted on a meter scale, there is an emerging consensus that significant reservoir heterogeneity is inherited from diagenetic complexity at smaller scales. In this study, we utilize information about diagenetic products and processes at the pore- and plug-scale and analyze their impact on the heterogeneity of porosity, permeability, and cement patterns. Eodiagenetic poikilitic calcite cements, illite/iron oxide grain coatings, and the amount of infiltrated clay are responsible for mm- to cm-scale reservoir heterogeneities in the Parchim formation of the Upper Rotliegend sandstones. Using the Petrel E&P software platform, spatial fluctuations and spatial variations of permeability, porosity, and calcite cements are modeled and compared, offering opportunities for predicting small-scale reservoir rock properties based on diagenetic constraints.

AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES

2003 ◽  
Vol 43 (1) ◽  
pp. 495 ◽  
Author(s):  
P.A. Arditto
Keyword(s):  
New South ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
South Wales ◽  
Permian Coal ◽  
Coal Measures ◽  
Reservoir Facies

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.

DOLOMITIZED SANDSTONES: A MARLIN FIELD GAS-RESERVES ASSESSMENT PROBLEM

1975 ◽  
Vol 15 (1) ◽  
pp. 111
Author(s):  
A. K. Svalbe
Keyword(s):  
X Ray Diffraction ◽  
Carbonate Cement ◽  
Reservoir Performance ◽  
Additional Control ◽  
Geological Information ◽  
Reservoir Sandstones ◽  
Porosity Logs ◽  
Gippsland Basin ◽  
Dolomite Cement ◽  
Field Area

Dolomite cement had been recognised within fluvio-deltaic facies sandstones of the Gippsland Basin Marlin field N-1 (Eocene) gas reservoir in the initial wildcat and two stepout wells. Although initially thought to be insignificant, the additional control provided by development drilling indicated that the degree and extent of dolomite cementation within the reservoir sandstones could be wide-ranging enough significantly to reduce reserves and influence reservoir performance. A study to define the area and degree of dolomite cementation within the reservoir showed that the distribution pattern within the 5 major sandstone units fell into 3 distinct groups. Whereas the 3 stratigraphically oldest (N-1.5, N-1.4 and N-1.3) units were only dolomitized within the northeastern portion of the field area, the N-1.2 unit was dolomite cemented field-wide. The youngest (N-1.1) unit, which unconformably overlies the truncated N-1.2 unit, is devoid of significant dolomite influence.Dolomitization of the N-1 sandstone units is interpreted to have occurred during a phase of estuarine-restricted marine shale deposition which followed the truncation of the N-1.2 sandstone unit. Although these estuarine dolomitic shales are absent by erosion at Marlin, they are present in the adjacent Tuna field area. Distribution of the dolomite cement within the reservoir sandstones was controlled by the subcrop pattern of the sandstone units during the deposition of the estuarine sediments.Petrological and x-ray diffraction information strongly suggest primary dolomite cementation, and not dolomitization of some pre-existing carbonate cement. The petrological, core analysis and geological information was integrated with the interpretation of wireline porosity logs to obtain reservoir unit average porosities and calculate reserves.The currently estimated initial N-1 reservoir dry gas reserves are 2.72 TSCF. If the reservoir sandstones were not dolomite cemented, reserves would be 3.15 TSCF, that is 14% greater.

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