Article

Kinetic Modeling of Quartz Cementation and Porosity Loss in Deeply Buried Sandstone Reservoirs

May 1996
AAPG Bulletin 80(5):731-745

DOI:10.1306/64ED88A4-1724-11D7-8645000102C1865D

Authors:

A mathematically simple kinetic model simulates quartz cementation and the resulting porosity loss in quartzose sandstones as a function of temperature history. Dissolved silica is considered to be sourced from quartz dissolution at stylotites or individual quartz grain contacts containing clay or mica, and diffuses short distances to sites of precipitation on clean quartz surfaces. The modeled sandstone volume is located between stylolites, and no quartz dissolution or grain interpenetration takes place within this volume. After quartz cementation starts, compactional porosity loss is typically minor, and porosity loss within the modeled sandstone volume is therefore considered to be equal to the volume of precipitated quartz cement. The quartz cementation process is modeled as a precipitation rate-controlled reaction where quartz precipitation rate per unit time and surface area can be expressed by an empirically determined logarithmic function of temperature. When the sandstone`s temperature history is known, precipitation rate per unit time and surface area can be expressed as a function of time, and the amount of quartz cement precipitated within a certain time interval can be calculated by multiplying the precipitation rate function with the surface area available for quartz precipitation and integrating with respect to time. Because quartz surface area will change as quartz cement precipitation proceeds, the calculations are performed for short time steps, and quartz surface area is adjusted after each time step. The total amount of quartz cement precipitated during a sandstone`s burial history and the corresponding porosity loss are found by taking the sum of the increments of quartz cement precipitated during each time step.

Evaluating the Influence of Grain-Coating Chlorite on Quartz Cements and Sandstone Porosity: A Review

Article

Mar 2025
J EARTH SCI-CHINA

Chlorite coats are believed to inhibit quartz cementation and preserve deeply-buried sandstone porosity. However, geologists face numerous challenges in evaluating the influences of chlorite coats in real cases. To tackle these challenges, this work reviewed a large number of case studies to discuss the proper way to evaluate their role using petrography. The following five main conclusions were drawn: (1) Compared to other coat parameters, coat coverage is more reliable in evaluating the influence of chlorite coats on quartz cements; (2) In addition to chlorite coats, quartz growth is influenced by multiple factors such as temperature, while sandstone porosity is affected by various factors including mechanical compaction; therefore, when evaluating the influence of chlorite coats, geologists should take these factors into account; (3) Even if no negative correlation exists between chlorite coats and quartz cements, and no positive correlation is observed between chlorite coats and sandstone porosity, one cannot simply conclude that chlorite coats do not inhibit quartz cements and protect sandstone porosity; (4) Chlorite coats can significantly occupy pore space, leading to a net porosity decrease; (5) Chlorite coats can undergo significantly dissolution, while whether this phenomenon is ubiquitous remains underexplored.

Simulating Compaction and Cementation of Clay Grain Coated Sands in a Modern Marginal Marine Sedimentary System

Article

Full-text available

Oct 2024

Reservoir quality prediction in deeply buried reservoirs represents a complex challenge to geoscientists. In sandstones, reservoir quality is determined by the extent of compaction and cementation during burial. During compaction, porosity is lost through the rearrangement and fracture of rigid grains and the deformation of ductile grains. During cementation, porosity is predominantly lost through the growth of quartz cement, although carbonate and clay mineral growth can be locally important. The degree of quartz cementation is influenced by the surface area of quartz available for overgrowth nucleation and thermal history. Clay grain coats can significantly reduce the surface area of quartz available for overgrowth nucleation, preventing extensive cementation. Using a coupled-effect compaction and cementation model, we have forward-modelled porosity evolution of surface sediments from the modern Ravenglass Estuary under different maximum burial conditions, between 2000 and 5000 m depth, to aid the understanding of reservoir quality distribution in a marginal marine setting. Seven sand-dominated sub-depositional environments were subject to five burial models to assess porosity-preservation in sedimentary facies. Under relatively shallow burial conditions (<3000 m), modelled porosity is highest (34 to 36%) in medium to coarse-grained outer-estuary sediments due to moderate sorting and minimal fine-grained matrix material. Fine-grained tidal flat sediments (mixed flats) experience a higher degree of porosity loss due to elevated matrix volumes (20 to 31%). Sediments subjected to deep burial (>4000 m) experience a significant reduction in porosity due to extensive quartz cementation. Porosity is reduced to 1% in outer estuary sediments that lack grain-coating clays. However, in tidal flat sediments with continuous clay grain coats, porosity values of up to 30% are maintained due to quartz cement inhibition. The modelling approach powerfully emphasises the value of collecting quantitative data from modern analogue sedimentary environments to reveal how optimum reservoir quality is not always in the coarsest or cleanest clastic sediments.

Understanding the synergistic impact of stress release and cementation on sandstone using sound waves — Implications for exhumation estimation

Article

Full-text available

Aug 2023

Exhumation is the process that encompasses both uplift and erosion, leading to the removal of overburden and the release of effective stress exerted on rocks. When estimating exhumation magnitude using the compaction trend method, it is commonly assumed that the physical properties of rocks are insensitive to stress reduction. However, recent laboratory evidence has shown that porosity exhibits weaker sensitivity to stress release compared to velocity that can be significantly affected by stress release. This raises uncertainties regarding the assumption of irreversible compaction. It remains unclear whether the impact of stress release can be observed in real rocks in exhumed areas, as there is a lack of methods to directly measure the impact of stress release on field data. Additionally, studying real rocks is further complicated by the presence of rock diagenesis and its interaction with stress release. To address these knowledge gaps, this study employs stress-dependent burial and uplift modeling and interprets an extensive well log dataset using the modeling-derived evaluation metrics. We discover that the disparity between porosity sensitivity and velocity sensitivity to stress release can be leveraged to derive a metric “porosity inconsistency” which can serve as both a qualitative and quantitative measure for identifying and evaluating stress release in sandstone using geophysical field measurements. We have gathered a significant amount of sonic velocity and porosity data from normally compacted and uplifted clean sandstones in the Norwegian Sea and the Barents Sea. Notably, we observe significant porosity inconsistency in the exhumed well 6510/2-1 in the Norwegian Sea. In the Barents Sea, well data reveals a varying pattern of porosity inconsistency that not only aligns with the spatial variation of exhumation reported in various studies but also exhibits a positive correlation with the magnitude of exhumation. These observations provide support for the predictions made by the conceptual modeling.

The importance of facies, grain size, and clay content in controlling fluvial reservoir quality – An example from the Triassic Skagerrak Formation, Central North Sea, UK

Article

Full-text available

Feb 2023

Clay-coated grains play an important role in preserving reservoir quality in high-pressure high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high energy channel sandstones have higher permeabilities (100-1150 mD) than low energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay coat coverage correlating with grain size, clay coat volume and quartz cement. Higher coverage (70-98%) occurs in finer-grained, low energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration. Supplementary material: of data and technique used in this study are available at https://doi.org/10.6084/m9.figshare.c.6438450.v1

Low volumes of quartz cement in deeply buried Fulmar Formation sandstones explained by a low effective stress burial history

Article

Dec 2022

Upper Jurassic Fulmar Formation sandstones from the Fulmar Field in the Central North Sea are buried to 3.2 km and 128 °C but contain only 3.7 ± 1.7% (1σ) quartz cement, substantially less than volumes predicted by models based on temperature-related quartz precipitation kinetics. Oxygen isotope microanalysis of quartz overgrowths suggests that only limited cementation occurred at temperatures above 110 °C. We suggest that the anomalously low volumes of quartz cement are most readily explained by the effective stress history of the Fulmar Formation. Regional pore pressure analysis strongly suggests that pore fluid pressures in the Fulmar Formation decreased substantially in the last <0.5 Ma as a result of lateral seal failure, increasing effective stress from ca. 10 MPa to the current 31 MPa. A recent increase in effective stress is supported by the common occurrence of grains that are both fractured and unhealed by quartz cement. Intergranular pressure dissolution can account for around one third of the observed quartz cement, with the remainder from deep burial feldspar dissolution. We argue that the continuous history of low effective stress, until the very recent geological past, limited the rate of silica supply by intergranular pressure dissolution, and thus the rate of quartz cementation. Effective stress histories should be incorporated into predictive models of quartz cementation of sandstones.

Burial of a sand sea: Heterogeneous compaction and cementation of the Jurassic Etjo Formation, Namibia and what it tells

Article

Full-text available

Aug 2024
MAR PETROL GEOL

Alteration of chlorite coats and sandstone porosity reduction: Insights from reactive transport modeling

Article

Dec 2023
MAR PETROL GEOL

Chlorite coats are widely recognized as a key element in preserving sandstone porosity because it can inhibit the growth of quartz cements. However, the alteration of chlorite coats and its potential influences on sandstone porosity are rarely discussed. Therefore, this work used reactive transport models under different petrographic and geochemical conditions to investigate the influence of chlorite coats on sandstone porosity in a major dissolution window (100 °C). The HCO3-rich (CO2-charged) and HCO3-depleted (organic acids-charged) waters were injected to induce mineral dissolution and precipitation. The results indicate that the alteration of chlorite coats may result in sandstone porosity reduction. The HCO3-rich water leads to a porosity decrease mainly through the precipitation of magnesite and siderite resulting from chlorite dissolution. In contrast, the HCO3-depleted water causes a porosity decrease mainly through the redistribution of kaolinite and quartz cements. Factors, including pCO2, organic acid concentration, coat coverage, coat thickness, and grain size, have secondary influences on net porosity change. In comparison, factors, including chlorite mineralogy, detrital lithology, and the reduction of K-feldspar dissolution rate caused by chlorite coat, have negligible influences. The alteration of chlorite coats may introduce significant mis-interpretation to the analysis of the relationship between chlorite coats and sedimentary facies. Moreover, the actual impact of pore-filling chlorite on porosity reduction may be either underestimated or overestimated. Therefore, the alteration of chlorite coats should be taken into consideration in future studies.

Reservoir characteristics and diagenesis of the Buntsandstein sandstones in the Campine Basin (NE Belgium)

Article

Full-text available

Dec 2022

The red beds of the Buntsandstein (Early Triassic) in the Campine Basin (NE Belgium) display porosities between 5.3–20.2% (average 13.7%) and permeabilities varying between 0.02–296.4 mD (average 38.7 mD). Knowledge of their reservoir controlling properties, which today are missing, is important in view of potential geological storage of CO2 or natural gas and geothermal reservoir potential within these sandstones. Therefore the effects of diagenesis were assessed based on petrography, stable isotope analyses, fluid inclusion microthermometry, X-ray diffraction, electron microprobe and porosity-permeability core analyses. These sandstones were deposited by a dryland river system, in a warm, mostly arid climate with episodic rainfall and high evaporation rates. During wetter periods especially feldspars were dissolved. Strong evaporation during dry periods led to reprecipitation of the dissolved species as K-feldspar and quartz overgrowths, smectite and calcite/dolomite. Sediment reworking resulted in framework grains becoming clay coated. The clay coats are better developed in finer than in coarser grained sediments. The original smectite composing the rims converted to illite during burial. The tangential orientation of the clay platelets in the rims led to illite-mica-induced dissolution of quartz during burial/compaction, which is manifested as bedding parallel dissolution seams that are filled with clays and micas, especially in the fine-grained sandstone/siltstone/claystone. These constitute important barriers to the vertical flow within the reservoir. The released silica did not really affect the red sandstones but was exported (often on mm to cm scale) to nearby bleached horizons, where nucleation inhibiting clay rims are less well developed. The red colour of the sandstones arises from the presence of small amounts of Fe-oxides in the inherited clay rims. Migration of fluids enriched in organic acids, expelled from underlying Carboniferous coal-bearing strata, resulted in local bleaching of coarser grained horizons. In the finer grained sediments, the red colour was mostly preserved, which suggests that the reductive capacity of the fluid was limited.

Imaging and interpretation: Seismic, rock physics and image log analysis workflows for deepwater systems

Chapter

Sep 2022

Seismic and well log imaging are among the most important tools for subsurface characterization and reservoir delineation. The significance of these two tools has further increased as we have started exploring unexplored deepwater reservoirs. Seismic attributes help identify different geological features by revealing geomorphology, whereas the amplitude vs offset (AVO) can differentiate between the lithology and fluid effects. Different seismic attributes can highlight different characteristics of the seismic data, which can relate to different geological features. The case study of the Cretaceous Nanushuk-Torok sequence on the North Slope, Alaska, utilizes multiple seismic attributes as inputs to unsupervised machine learning (ML) for seismic facies classification. Two ML algorithms, such as self-organizing map (SOM) and generative topographic map (GTM) are used for seismic facies classification. GTM provides more details in different geomorphological features compared to SOM. However, reservoir identification and mapping solely based on seismic amplitude and other attributes, such as bright or dim spots, as direct hydrocarbon indicators can often be misleading. Rock physics and AVO feasibility modeling can provide a better understanding of the reservoir. In the case study from the Glitne Field, North Sea, Norway, we study seismic amplitude and AVO to characterize the Glitne submarine fan system. AVO feasibility modeling should be utilized in improved reservoir mapping and prospect derisking. Borehole images provide higher resolution than seismic and conventional wireline logs and can be correlated to core and outcrops. Borehole images can be used to identify lithologies, thin beds and fractures. An integrated analysis of all seismic attributes, rock physics and borehole imaging analysis results can provide a detailed subsurface characterization for deepwater reservoirs.

A giant sand injection complex: Processes and implications for basin evolution and subsurface fluid flow

Article

Jun 2022

Giant sand injection complexes form, intricate, basin-scale fluid plumbing systems and document the remobilisation and intrusion of several tens of cubic kilometres of sand within the shallow crust in stratigraphic units 100's metres thick. This is the first detailed and extensive account of the Panoche Giant Injection Complex (PGIG), a regionally significant outcrop (>300 km2) and part of a larger subsurface development (>4000 km2) identified in boreholes and on seismic reflection data. Magnificent exposure of the PGIC occurs along the north western margin of the San Joaquin Valley and presents the opportunity to examine the regional geological significance of a giant sand injection complex and its origin in the context of a late Cretaceous – early Paleocene forearc basin. Between 25 and 49 km3 of sand were remobilised and injected, at least 0.35 km3 of which extruded onto the paleo-seafloor. Large sandstone intrusions often >10 m thick and laterally extensive on a kilometer scale formed saucer-shaped intrusions, wing-like intrusions and a variety of sill geometries along with volumetrically smaller randomly oriented dikes in a 200–300 m thick interval. Dikes prevail below and above this interval, some reaching the paleo seafloor and extruding sand. Networks of propagating hydrofractures form intensely brecciated host strata, some of which were intruded by sand. All intrusions formed in a single pulsed event in which the most intense hydrofracturing caused by supra-lithostatic fluid pressure occurred approximately 600 to 800 m below the paleo seafloor. A crudely orthogonal arrangement of dikes is preserved with most oriented normal, and less commonly oriented parallel to the oceanic trench associated with the late Mesozoic to early Tertiary North Pacific subduction. Dikes orthogonal to the trench opened against the minimum horizontal stress, which was parallel to the trench. Dikes parallel to the trench opened against the regional maximum horizontal stress along minor faults formed in extension caused by shallow crustal deformation. There is no evidence that compressional tectonics influenced the onset of elevated pore fluid pressure necessary to promote sand injection. However, tectonic compression was responsible for creating the basin physiography that locally increased subsidence and accelerated chemical diagenesis in the basin centre. PGIC outcrop, located along the basin margins, was unlikely to have experienced heating above 70 °C, equivalent about 2 km burial, so the effects of chemical diagenesis in the host strata of the injection complex had negligible potential to evolve significant pore water volume. In a deeper part of the basin approximately 150 km to the south, lateral equivalents of the host strata were subjected to heating >100 °C and would expel significant volumes of water displaced by quartz cementation and clay dehydration that caused lateral pressure transfer to the north and western margin of the basin where the PGIC formed. Estimates of the total volume of water expelled from the deep basin suggest that a fluid volume equivalent to a gross rock volume reduction <1% would have provided a fluid budget sufficient to fluidise and inject the sand that forms the PGIC. In terms of areal and vertical extent, volume and architecture the PGIC shares strong similarity with the regionally developed giant injectite systems of Tertiary age in the North Sea basin. In both cases regional sand injection is genetically linked to pressure transfer toward the basin margin from more rapidly subsiding basin centres. Aqueous fluid is derived from thermally driven chemical diagenesis of thick deep water clastic sandstone and smectitic mudstone or from deeper, stratigraphically older, aquifers.

Uncertainty Quantification of geochemical and mechanical compaction in layered sedimentary basins

Preprint

Mar 2017

In this work we propose an Uncertainty Quantification methodology for sedimentary basins evolution under mechanical and geochemical compaction processes, which we model as a coupled, time-dependent, non-linear, monodimensional (depth-only) system of PDEs with uncertain parameters. While in previous works (Formaggia et al. 2013, Porta et al., 2014) we assumed a simplified depositional history with only one material, in this work we consider multi-layered basins, in which each layer is characterized by a different material, and hence by different properties. This setting requires several improvements with respect to our earlier works, both concerning the deterministic solver and the stochastic discretization. On the deterministic side, we replace the previous fixed-point iterative solver with a more efficient Newton solver at each step of the time-discretization. On the stochastic side, the multi-layered structure gives rise to discontinuities in the dependence of the state variables on the uncertain parameters, that need an appropriate treatment for surrogate modeling techniques, such as sparse grids, to be effective. We propose an innovative methodology to this end which relies on a change of coordinate system to align the discontinuities of the target function within the random parameter space. The reference coordinate system is built upon exploiting physical features of the problem at hand. We employ the locations of material interfaces, which display a smooth dependence on the random parameters and are therefore amenable to sparse grid polynomial approximations. We showcase the capabilities of our numerical methodologies through two synthetic test cases. In particular, we show that our methodology reproduces with high accuracy multi-modal probability density functions displayed by target state variables (e.g., porosity).

The Golden Zone temperature distribution of petroleum: Part 2

Article

Sep 2024

Our previous publication examined the estimated ultimate recovery (EUR) of conventionally recoverable oil, gas and condensate in 1175 of the Earth's largest reservoirs in relation to reservoir temperature and showed that 74% occurs within the "Golden Zone" (GZ) temperature range of 60 to 120 ± 2°C, with only 6% at higher temperatures. The present article examines the temperature distribution of EUR in 18 geographic regions not covered earlier, including six with EUR distributions skewed toward low temperature and three with distributions skewed toward high temperature. A fuller explanation is provided here as to why diagenetic processes are thought to be the main causes of overpressure in deeply buried reservoirs, and a new model is proposed for how opening of the Arctic and North Atlantic oceans led to uplift of Arctic continental margins, with possible negative consequences for Arctic exploration potential. Particular attention is given to examples of large reservoirs at temperatures outside the GZ in order to examine the possible factors favoring these occurrences. Most low-temperature cases can be ascribed to tectonic uplift and cooling subsequent to petroleum accumulation, whereas most of the high-temperature reservoirs have low to moderate fluid pressure consistent with preservation of hydrocarbon columns due to open lateral drainage. It is clear that reservoir temperature is a useful parameter for exploration risk analysis, but one that should be calibrated using available analogs relevant for each area of interest.

Application of the EBSD Technique in the Study of Porosity and Permeability in Deformation Bands in Sandstone

Article

Aug 2024
MICROSC MICROANAL

Deformation bands are common constituents of porous clastic fluid reservoirs. Various techniques have been used to study deformation band structure and the associated changes in porosity and permeability. However, the use of electron backscatter diffraction technique is limited. Thus, more information is needed regarding the crystallographic relationships between detrital crystals, which can significantly impact reservoir rock quality. We employ microscopic and microstructural investigation techniques to analyze the influence of cataclastic deformation bands on pore space. Porosity measurements of the Cretaceous Ilhas Group sandstone in NE Brazil, obtained through computerized microtomography, indicate that the undeformed domains exhibit a total porosity of up to 13%. In contrast, this porosity is slightly over 1% in the deformation bands. Scanning electron microscopy analyses revealed the presence of grain fragmentation and dissolution microstructures, along with cement-filling pre-existing pores. The electron backscatter diffraction analyses indicated extensive grain fragmentation and minimal contribution from intracrystalline plasticity as a deformation mechanism. However, the c axes of quartz crystals roughly align parallel to the orientation of the deformation band. In summary, we have confirmed and quantified the internal changes in a deformation band cluster, with grain size reduction and associated compaction as the main mechanism supported by quartz cementation.

Improved reservoir quality assessment by evaluating illite grain coatings, quartz cementation, and compaction – Case study from the Buntsandstein, Upper Rhine Graben, Germany

Article

Jul 2024

Diving-wave time-lapse delay for CO2 thin layer detection

Article

Full-text available

Jan 2024

We have derived an analytical approximate expression to estimate the delay in diving seismic waves due to thin layers of CO2. The expression is valid for high frequencies and can be used to estimate the delay in diving waves at seismic frequencies for large separations between the source and receiver (offset). The approximation may be used to assess CO2 detection limits using diving waves and to support survey planning for CO2 monitoring and full-waveform inversion (FWI) cycle skipping analysis. In this study, we analyze the diving-wave response to a thin layer of CO2 for band-limited data using acoustic finite-difference modeling, and compare the results against the analytical calculations. We find that the responses are offset-dependent and related to double- and single-leg interactions between the diving waves and the CO2. To test the methods, we created a synthetic representation of the 2010 subsurface conditions for the top CO2 layer at the Sleipner storage complex in the North Sea, by combining base and monitor post-stack seismic data with field velocity trends. Using the acoustic finite-difference method, we model pre-stack data that captures the complexity of field data and demonstrate the use of the diving-wave delay for CO2 migration monitoring and CO2 thin layer detection.

The influence of sedimentary facies, mineralogy, and diagenesis on reservoir properties of the coal-bearing Upper Carboniferous of NW Germany

Article

Jan 2024

Former coal mines hosted in Upper Carboniferous silt- and sandstones in the Ruhr Basin, NW Germany, are currently examined for post-mining applications (e.g., geothermal energy) and are also important tight-gas reservoir analogs. Core material from well Pelkum-1, comprising Westphalian A (Bashkirian) delta deposits, was studied. The sandstones and siltstones are generally tight (mean porosity 5.5 %; mean permeability 0.26 mD). Poor reservoir properties primarily result from pronounced mechanical compaction (mean COPL 38.8 %) due to deep burial and high contents of ductile rock fragments. Better reservoir properties in sandstones (> 8 %; > 0.01 mD) are due to (1) lower volumes of ductile grains (< 38 %) that deform during mechanical compaction and (2) higher volumes in feldspar and unstable rock fragments. During burial these form secondary porosity (> 1.5 %) resulting from acidic pore water from organic matter maturation. Still, sandstones with enhanced porosities only show a small increase in permeability since authigenic clays (i.e., kaolinite and illite) or late diagenetic carbonates (i.e., siderite and ferroan dolomite/ankerite) clog secondary porosity. Quartz cementation has a minor impact on reservoir properties. Evaluating the Si/Al ratio can be a suitable proxy to assess grain sizes and may be a convenient tool for further exploration. Supplementary material: https://doi.org/10.6084/m9.figshare.c.7003156

Influence of Mineral Composition on Rock Mechanics Properties and Brittleness Evaluation of Surrounding Rocks in Soft Coal Seams

Article

Full-text available

Dec 2023

The structural fracture of the coal seam with its low permeability is the dominant reason for the “difficult gas out” of the broken soft coal seam. The brittleness of the roof and floor rock stratum of the broken soft coal seam has a significant effect on the fracture extension pressure of the surrounding rock after casing perforation and hydraulic fracturing of the horizontal well for coalbed methane (CBM). In this paper, 15 rock samples were scientifically collected from the roof and floor of the main mining coal seam of the Early Permian coal-bearing series in the Xinxie-1 well of the Huainan Coalfield in Anhui Province, China. On the basis of mineral composition analysis of these samples, the influence of mineral composition on the mechanics properties of the rock at the roof and floor of the coal seam was investigated. The correlation analysis and gray correlation analysis were adopted to construct an evaluation method for the brittleness of the rock at the roof and floor of the coal seam based on the mineral content. The results indicated that the most significant compositions of the minerals in the rock at the roof and floor of the broken soft coal seam were quartz and clay minerals. The most significant types of rock cementation are quartz agglomeration and rhodochrosite cementation. Pore destruction as a result of cementation was much greater than that of compaction. In comparison to clay minerals, the variation in the content of brittle minerals such as quartz, plagioclase, and siderite in the rock showed more sensitivity to the mechanics properties of the rock. The more sensitive minerals for compressive strength (CS), shear strength (SS), modulus of elasticity (E), softening coefficient (K), and Poisson’s ratio (μ) are quartz, those for tensile strength (TS) are plagioclase and siderite, and those for Poisson’s ratio are clay minerals. Based on the established mineral content weighting analysis method, it was calculated that the brittleness index (BI) of the rocks at the roof of the 13-1, 11-2, 9-2, and 4-2 coal seams was larger, which was advantageous for the formation of longer fracturing crack networks. This is theoretical guidance for the optimization of horizontal well fracturing design in the deep coal beds of the Huainan Coalfield.

The “Golden Zone” temperature distribution of oil and gas occurrence examined using a global empirical database

Article

Full-text available

Dec 2023
MAR PETROL GEOL

We present a straightforward empirical correlation between petroleum occurrence in sedimentary basins and reservoir temperature that can be integrated with other methods of analysis to reduce exploration risk. Global amounts of recoverable oil, gas, and gas-condensate in 1175 well characterized reservoirs from 954 of the world’s largest fields, constituting 54% of the world’s documented recoverable conventional oil and 50% of gas, are examined in terms of present-day reservoir temperature. Most volumes (74%) occur within the range of 60–120 ± 2 ◦ C (140–248 ±4 ◦F), corresponding with the isotherm-bounded depth interval in petroliferous basins previously defined as the “Golden Zone” for exploration. Only 6% of the global total occurs at higher temperatures and 20% at lower temperatures.

Periods and Processes of Oil and Gas Accumulation in the HZ-A Structure Double Paleogene Field, Pearl River Mouth Basin

Article

Full-text available

Oct 2023

The source of oil and gas and the stages of oil and gas accumulation in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin are analyzed, and the spatiotemporal coupling relationship of the key conditions of oil and gas accumulation are discussed to reconstruct the process of oil and gas accumulation. Based on previous research results, which are based the characteristics of biomarker compounds, the oil and gas in the HZ-A structure double Paleogene field came from the Paleogene Wenchang Formation hydrocarbon source rocks in the HZ26 sub-sag. By means of the casting thin section identification and inclusion homogenization temperature measurement, this paper reveals the three major hydrocarbon accumulation periods and corresponding fluid charging types in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin. The results show that 13.8–10 Ma is the charging period of low mature crude oil, 10–5.3 Ma is the charging period of mature crude oil, and from 5.3 Ma is the natural gas charging period. Based on actual geological, drilling, logging, and seismic data, the key conditions for hydrocarbon accumulation in the HZ-A structure “double-Paleo” field are sorted out; that is, the source conditions are characterized by high-quality lacustrine source rocks generating early oil and late gas and a near-source continuous hydrocarbon supply. The reservoir conditions are characterized by weathering and superposition of a fracture zone that transforms into a reservoir, and a large-scale sandstone rock mass that transforms into a reservoir. The caprock conditions are characterized by the stacking of several thin mudstones that form a seal and the combination of multiple lithologies that block hydrocarbon migration. The trap conditions are characterized by multistage uplift structure traps and fracture-lithology combination control traps. The transport conditions are characterized by multi-stage cross-bed transport of source-connected faults and lateral differential transport of shallow sand in deep fractures. Finally, oil and gas accumulation models of the HZ-A structure double Paleogene field were established, and the accumulation process was reconstructed. The overall process involved three stages, with the first stage being the localized oil-displacing-water mode, the second being the large-scale oil-displacing-water mode, and the third being the late progressive gas-displacing-oil mode.

Sediment texture and geochemistry as predictors of sub-depositional environment in a modern estuary using machine learning: A framework for investigating clay-coated sand grains

Article

Full-text available

Oct 2023
SEDIMENT GEOL

Sedimentary cores from the Ravenglass Estuary lack some of the sedimentary structures which can be seen in other estuarine sands due to their unconsolidated nature, making it difficult to meaningfully interpret depositional environments using standard sedimentological facies analysis. Here we explore how sediment texture, obtained from laser particle size analysis, and geochemistry, obtained from portable X-ray fluorescence, can be used independently, or in combination, to automatically classify sub-depositional environment and estuarine zone in a modern estuary. We have adapted an established Extreme Gradient Boosting workflow to select the most informative geochemical elements to be included in a training set to automatically classify sub-depositional environment at the surface of the Ravenglass Estuary, NW England, UK. Models that are trained exclusively on textural data significantly outperform those that use geochemical data when classifying sub-depositional environment but are comparable when classifying estuarine zone. However, the combination of textural and geochemical data in training sets improves model performance in all but one class when compared to separate textural and geochemical models. We have applied surface-calibrated combined textural and geochemical models to classify palaeo sub-depositional environment in three cores obtained from a tidal flat in the Ravenglass Estuary that are interpreted to record initial outer estuary deposition which transitioned to an inner estuary setting dominated by deposition from suspension. The subsurface classifications provide a framework to investigate the occurrence of reservoir quality-preserving detrital grain coats which vary in abundance as a function of sub-depositional environment at the surface. A review of literature suggests that the mixed flat sub-depositional environment is an ideal target for optimum clay grain coat occurrence, and we show that this sub-depositional environment is reliably identified by all models. We also discuss the implications of the modelling, how it compares to other machine learning approaches to understand reservoir quality in ancient systems, and how the workflow may be adapted for application to reservoir core. This study demonstrates value in utilising textural and geochemical data in conjunction with machine learning methods to help reveal the environmental evolution of marginal marine sands.

The effects of uplift and erosion on the petroleum systems in the southwestern Barents Sea: Insights from seismic data and 2D petroleum systems modelling

Article

Oct 2023
MAR PETROL GEOL

Simulations of the effect of smectite-to-illite transition in shales on permeability and overpressures using a stochastic approach, a Norwegian margin case study

Article

Full-text available

Oct 2023
BASIN RES

The smectite-illite transition in shales due to subsidence, temperature changes and diagenesis influences many processes in a sedimentary basin that can contribute to overpressure build up like reducing the shale permeability. The smectite-rich layers can form sealing barriers to fluid flows that will influence pore pressure prognosis for drilling campaigns, contribute to sealing caprocks for possible CO 2 storage and to sealing of plugging and abandonment wells. In this work, we have included the diagenetic smectite-illite transition into a three-dimensional pressure simulation model to simulate its effect on pressure build-up due to reduced shale permeabilities over geological time scale. We have also tested effect of thermal history and potassium concentration on the process of smectite-illite transition and the associated smectite-illite correction on perme-ability. A new smectite-illite correction has been introduced, to mimic how shale permeability will vary dependent on the smectite-illite transition. Stochastic Monte Carlo simulations have been carried out to test the sensitivity of the new correction parameters. Finally, a 3D Monte Carlo pore pressure simulation with 1000 drawings has been carried out on a case study covering Skarv Field, and Dønna Terrace offshore Mid-Norway. The simulated mean overpressures are in range with observed overpressures from exploration wells in the area for the Cretaceous sandy Lysing Formation and for the two Cretaceous Intra Lange Formation sandstones. The simulated smectite content versus depth is in line with published XRD dataset from wells. The corresponding modelled present-day permeabilities for the shales including the smectite-illite transition are two magnitudes higher than measured permeabilities on small samples in the laboratory using transient decay method. The measured permeabilities are in the range of 2.66·10 −18 to 3.94·10 −22 m 2 (2695 to 0.39 nD) for the North Sea database and represent the end members for shales-permeabilities with the lowest values, since the small samples are selected with no or minor natural fractures. This work

Quantitative Study of the Lateral Sealing Ability of Faults Considering the Diagenesis Degree of the Fault Rock: An Example from the Nantun Formation in the Wuerxun-Beier Sag in the Hailar Basin, China

Article

Full-text available

Aug 2023

The goal of this study was to accurately evaluate the lateral sealing ability of a fault in siliciclastic stratum based on previous analysis of the lateral sealing of faults by a large number of scholars in the published literature and physical simulation experiments. Content of the clay mineral phase and the diagenetic degree of fault rock were investigated as the main factors to evaluate the lateral sealing of faults. Based on this theory, the configuration relationship between the clay content and burial depth of fault rock (SGR&H) threshold evaluation method for the lateral sealing of faults was established. Then, we applied these results to evaluate the lateral sealing ability of faults in the Beixi, Beier, Wuerxun, and Surennuoer areas in the Hailar Basin, China. The variation in SGR boundary values with burial depth between the lateral opening and moderate sealing area, as well as between the moderate and strong sealing area of the faults, are obtained. Compared with the previous methods, the SGR&H threshold method transforms the static SGR value of a formation or even a region into a dynamic SGR value that changes with the burial depth, which can fully characterize the differences in the conditions required for sealing faults with different internal structures at different depths. In determining the lateral sealing ability of faults by comparing the evaluation results, we discovered the following. (1) In the same area, the sealing thresholds of faults within different layers are different because the deep strata are subjected to greater pressures and longer loading times, so these faults are more likely to seal laterally. (2) In the same layer, the sealing thresholds of faults in different areas are also different. The higher the thickness ratio between the sandstone and the formation (RSF), the smaller the entry pressure of the fault rock when it has reached a critical seal state, so the SGR&H thresholds are relatively small. Compared to the previous methods, the SGR&H threshold method in this article reduces the exploration risk of faults with relatively low diagenetic degree in shallow strata, and also increases the exploration potential of faults with relatively high diagenetic degree in deep strata. The evaluation results are more consistent with the actual underground situation.

Fracture-pattern growth in the deep, chemically reactive subsurface

Article

Jul 2023
J STRUCT GEOL

Linking diagenesis and reservoir quality to depositional facies in marginal to shallow marine sequence: An example from the Campano-Maastrichtian Gombe Sandstone, Northern Benue Trough, NE Nigeria

Article

Jun 2023
MAR PETROL GEOL

Olaussen et al 2022 Svalbard Composite Tectono-Sedimentary Element, Barents Sea,

Article

Full-text available

Jun 2023

In this chapter, we present a comprehensive and up-to-date overview of the geology and petroleum geology of the Svalbard Composite Tectono-Sedimentary Element, Barents Sea; SCTSE, herein defined as the Carboniferous–Paleogene sedimentary rock succession and its associated structural elements. As such, the underlying economic basement consisting of Devonian and older sedimentary rocks, as well as Precambrian igneous and metamorphic rocks, are not considered.

The etiology of carbonate porosity

Article

Full-text available

Dec 2022
AAPG BULL

Stephen Ehrenberg

The Svalbard Carboniferous to Cenozoic Composite Tectono-Stratigraphic Element

Article

Full-text available

Aug 2022

The Svalbard Composite Tectono-Stratigraphic Element is located on the north-western corner of the Barents Shelf and comprises a Carboniferous to Pleistocene sedimentary succession. Due to Cenozoic uplift the succession is subaerially exposed in the Svalbard archipelago. The oldest parts of the succession consist of Carboniferous to Permian mixed siliciclastic, carbonate and evaporite and spiculitic sediments that developed during multiple phases of extension. The majority of the Mesozoic succession is composed of siliciclastic deposits formed in sag basins and continental platforms. Episodes of Late Jurassic and Early Cretaceous contraction are evident in the eastern part of the archipelago and in nearby offshore areas. Differential uplift related to the opening of the Amerasian Basin and the Cretaceous emplacement of the High Arctic Large Igneous Province created a major hiatus spanning from most of the Late Cretaceous and early Danian throughout the Svalbard Composite Tectono-Stratigraphic Element. The West Spitsbergen Fold and Thrust Belt and the associated foreland basin in central Spitsbergen (Central Tertiary Basin) formed as a response to the Eurekan orogeny and the progressive northward opening of the North Atlantic during the Palaeogene. This event was followed by formation of yet another major hiatus spanning the Oligocene to Pliocene. Multiple reservoir and source rock units are exposed in Svalbard providing analogues to the offshore prolific offshore acreages in southwest Barents Sea and are important for de-risking of plays and prospects. However, the archipelago itself is regarded as high-risk acreage for petroleum exploration. This is due to Palaeogene contraction and late Neogene uplift of particularly the western and central parts. In the east there is an absence of mature source rocks, and the entire region is subjected to strict environmental protection.

The "Golden Zone" temperature distribution of petroleum examined using a global empirical database

Conference Paper

Full-text available

Aug 2022

Velocity Depth Trends Prediction on the Norwegian Continental Shelf (NCS) Wells Using the Bounding Average Method

Thesis

Jul 2021

Nandito Davy

Earth consists of heterogeneous layers due to the complex sedimentation processes, in which lithifies both unconsolidated sand and siliciclastic clays into sandstone and shale. These two sedimentary rocks are the most abundant in the hydrocarbon reservoir, usually in the form of shaly sand or sandy shale mixture. As the advantage of the technology, geophysicists can distinguish these sedimentary rocks by using a seismic reflection method that relies on their elastic properties; P-wave (Vp) and S-wave (Vs) velocities along with density. One option to estimate these velocities are from both compressional and shear sonic logs since these two are reciprocal to the elastic velocities. However, sonic logs may not be available or partially available at specific depth intervals. Lack of these measurements could potentially be problematic for geophysicists that need accurate velocity estimations. Many rock-physics-based empirical approaches are available for elastic velocities estimations, relying on other parameters such as porosity, clay volume, differential stress, et cetera. However, these empirical approaches are only valid and optimum in the dataset they are using. Therefore, these empirical approaches are susceptible to the robustness issue. We propose a methodology to estimate the vertical velocity depth trends for the three wells taken from the Norwegian Continental Shelf (NCS). The proposed methodology mainly utilizes the rock-physics analysis of Voight-Reuss Bounds and the Bounding Average Method (BAM). It also implements the petrophysical analysis to estimate the lithological volume fraction of sand, clay, and silt. We designed two different models, namely the implicit and explicit clay-bound water. The challenges of this proposed methodology are to simulate the depositional variations between (1) Clean sand and clay; (2) Consolidation states as the rock changes from freshly deposited and later compacted; and (3) Velocity stress-sensitivity along with the burial depth. This proposed methodology yield correlation coefficients and error percentages, respectively between 0.7326 - 0.9521 and 7.73% - 15.07% for Vp; and respectively between 0.7495 - 0.9585 and 16.2% - 27.66% for Vs. These values show that the methodology is reliable but straightforward enough to perform robust predictions for the vertically-propagating elastic velocity depth trends.

Chapter

Jan 2005

This volume constitutes the proceedings of the AAPG Hedberg conference on seals held in Barossa Valley, South Australia, in 2002. The key driver for both the Hedberg conference and this publication was the recognition that knowledge of risk in the estimation of sealing capacity and fault-seal potential is important in making judgments at the exploration, appraisal, and development stages of the petroleum business. In addition, incorporating seal risk in the overall assessment of hydrocarbons in place can affect decisions to drill prospects and the location of appraisal and development wells, as well as reserve estimation. Improved methods to estimate seal capacity and fault integrity can lead to savings in well costs, improved recoveries through optimum placement of wells, and improved estimates of hydrocarbon in place. This volume contains 18 chapters that reflect the spectrum of presentations at the conference. The knowledge imparted by these chapters will be a window on the state of seal knowledge at this juncture of time and includes topics such as seal failure related to basin-scale processes, the role of geomechanics in seals, and the economic evaluation of prospects with a top seal risk.

Fault Healing and Fault Sealing in Impure Sandstones

Chapter

Jan 2005

Understanding the interplay of depositional rock types, mineralogy, and diagenesis on reservoir properties of the coal-bearing Langsettian and Duckmantian strata (Bashkirian, Pennsylvanian) of the Ruhr Area, NW Germany

Article

Sep 2024
INT J EARTH SCI

Deltaic siltstones and sandstones from the Pennsylvanian (Upper Carboniferous) in the Ruhr Basin are currently being examined for post-mining applications (e.g., geothermal) but are also an important tight-gas reservoir analog in NW Germany. Core material from two wells in the eastern Ruhr Basin, comprising Bashkirian delta deposits of the Langsettian and Duckmantian substages (Westphalian A and B), were studied using petrographic and petrophysical data to assess their reservoir properties and factors controlling these. The samples have low porosities and permeabilities (mean porosity 5.5% well Bork-1 and 5.1% well Haidberg-1; mean permeability 0.41 mD and 0.16 mD, respectively). Grain size and detrital mineralogy are the main factors affecting reservoir properties. The change in mineralogy from litharenites to lithic subarkoses corresponds to an increase in grain size from silt to sandstone and is associated with a general increase in porosity and permeability. Dissolution porosity largely contributes (up to 6%) to measured plug porosity. The dissolution porosity mostly is caused by the break down of detrital K-feldspar and plagioclase grains and affects low present-day feldspar contents (6.0 to 6.8%). Ductile rock fragments, such as shales and phyllites, cause porosity reduction due to facilitated mechanical compaction and are especially present in siltstones (ICOMPACT > 0.99). The study also used SiO2 and Al2O3 contents from XRF analyses as proxies for estimating reservoir properties and distinguishing between sandstones and siltstones. These findings help identify sections with better reservoir properties for potential exploration and production strategies in similar geological settings.

Depositional and diagenetic controls on the reservoir quality of marginal marine sandstones: An example from the Early Devonian Subbat Member, Jauf Formation, northwest Saudi Arabia

Article

Oct 2024
MAR PETROL GEOL

STRATIGRAPHY AND DIAGENESIS OF THE THAMAMA‐B RESERVOIR ZONE AND ITS SURROUNDING DENSE ZONES IN ABU DHABI OILFIELDS AND EQUIVALENT OMAN OUTCROPS

Article

Full-text available

Sep 2024

We review published studies characterizing the Thamama‐B reservoir zone in the upper Kharaib Formation (late Barremian) in Abu Dhabi oilfields and at outcrops in Oman. Available data for oxygen and carbon isotope compositions, fluid inclusion measurements, cement abundance and formation water composition are interpreted in terms of a paragenetic model for the Thamama‐B in field F in Abu Dhabi where the interval is deeply buried. The present synthesis provides a useful basis for understanding and predicting reservoir quality in static models and undrilled prospects, as well as for planning promising directions for further research. The goals of this study were to summarize the geologic setting and petrology of the Thamama‐B reservoir and its surrounding dense zones, and to examine how sedimentology, stratigraphy and diagenesis have interacted to control porosity and permeability. Results that may have useful applications for similar microporous limestone reservoirs in general include: the depositional environments and stratigraphy of the subject strata; a model for how porosity variations result mainly from calcite cementation sourced from stylolites, with little dependence on lithofacies other than the localization of chemical compaction by depositional clay linked to sequence stratigraphy; the use of solidity (rock thickness with porosity removed) as a check on porosity creation by burial dissolution; observations linking high‐permeability streaks with storm lag beds and fractures; the concept of strata being gradually buried through a relatively static salinity‐stratified water column; integration of conventional and clumped stable‐isotope data with petrologic observations to constrain the timing of porosity evolution.

Lithofacies assemblage and effects on diagenesis in lacustrine tight sandstone reservoirs: Samples from Upper Triassic Yanchang Formation, Ordos Basin, China

Article

Jul 2024
MAR PETROL GEOL

Fracture ellipticity as a measure of chemical reaction-controlled fracture growth

Article

Apr 2024
J STRUCT GEOL

Review of Triassic Sherwood Sandstone Group reservoirs of Ireland and Great Britain and their future role in geoenergy applications

Article

Full-text available

Mar 2024

As the world progressively shifts to a low/neutral carbon economy over the course of the 21 st Century, geoscience will continue to play a vital role in the energy sector and beyond. Static and dynamic characterisation of the subsurface, a key component of the petroleum industry for decades, will be required to evaluate and unlock a variety of different initiatives including carbon, capture and storage (CCS), hydrogen (or any other gas) storage, thermal energy storage and geothermal energy development. Onshore and offshore Ireland and Great Britain, Lower Triassic sandstones are likely to represent one of the primary geological targets for future geoenergy applications. This paper provides a review of the Triassic Sherwood Sandstone Group depositional system across the British and Irish region of NW Europe including its overall stratigraphic context, paleogeography, sediment provenance and transport directions, and present-day distribution. In addition to geological outcrop data, there is a wealth of subsurface data available from historical petroleum wells. Looking forward, one important focus of geoscience research will be to extrapolate away from these well-defined control points to predict sandstone facies distribution, diagenetic history and hence overall reservoir quality in new undrilled areas that will be of interest to the geothermal, CCS and gas storage sectors.

Silica cementation history of the Ediacara Member (Rawnsley Quartzite, South Australia): Insights from petrographic and in situ oxygen isotopic microanalyses

Article

Mar 2024
PRECAMBRIAN RES

Redbed diagenesis links district-scale mineralising fluids to Cu source rock in the Polaris Zn-Pb(-Cu) district, Arctic Canada

Article

Full-text available

Feb 2024
ORE GEOL REV

Fluid history of lower Cambrian Longwangmiao formation in the Anyue gas field (Sichuan Basin, SW China)

Article

Sep 2023

Digital Rock Advances from an Material Point Method Approach for Simulation of Frame Moduli and a Sedimentary Petrology Inspired Method for Creation of Synthetic Samples Through Simulation of Deposition and Diagenesis

Article

Sep 2023

We compare hydromechanical simulation results that use two alternative sources of 3D digital rock input: microCT analysis and synthetic rocks created using a newly developed process simulation methodology that more rigorously reflects knowledge from sedimentary petrology compared to previous efforts. We evaluate performance for these alternative representations using St. Peter Sandstone samples where dry static bulk modulus (K) and shear modulus (G) are simulated using a new extension of the Material Point Method that resolves contacts using high-resolution surface meshes and that considers three alternative contact modeling approaches: purely frictional, fully bonded, and cohesive zones. We evaluate model performance on two samples from the dataset with multiple static moduli measurements (sample 1_2: porosity 24.6 vol%: K 10.2 14.7 GPa, G 11.6 14.0 GP; sample 11_2: porosity 12.4 vol%: K 13.5 24.6 GPa, G 12.8 17.9 GPa). Purely frictional results underpredict measured modulus values whereas fully bonded results overpredict them. Measured values are most closely approximated by results with cohesive zones that consider sets of discrete spring-like features at contacts. Shear modulus results from FEM simulations on structured grids, by contrast, tend to be significantly greater than measured values, particularly for samples with lt; 18 vol% porosity. Permeability values from digital rock physics simulations for the studied samples are within factors of 2 5 of conventional core analysis measurements (2860 and 58 md for sample 1_2 and 11_2, respectively). We demonstrate that the process modeling approach (1) accurately reproduces measured rock microstructure parameters from thin section analysis, (2) leads to simulation results for dry static moduli and permeability of comparable accuracy to simulations that employ microCT samples, and (3) provides a rigorous basis for predicting diagenetically induced variations in hydromechanical properties over the range from unconsolidated sand to indurated rock.

Rock acoustics of CO2 storage in basalt

Article

Jun 2023

We simulate variations in the P- and S-wave velocities due to CO2 injection in basalt, caused by water replacement and mineralization in the form of carbonate cements. Carbonization can be monitored with seismic data on the basis of changes in velocity. We consider basalts composed of (Fe, Ca and Mg) minerals mainly, and the pore space is assumed to be initially saturated with water. The mineralization is based on a model that estimates the volume of precipitated cement and resulting porosity loss, and the velocities as a function of injection time are calculated with a patchy cement model. In the example, there are two stages: 1 week of CO2 injection and 29 weeks of frame cementation. After 1 week, water has been replaced by CO2, where density and P-wave velocity decrease, and cementation implies an increase in bulk density, P-wave velocity, whereas porosity and surface area are reduced. To our knowledge there are no models relating the effects of carbon mineralization on seismic properties. The present model can be applied to other rocks, where CO2 injection induces mineralization and storage.

New direction for regional reservoir quality prediction using machine learning - Example from the Stø Formation, SW Barents Sea, Norway

Article

Oct 2022
J PETROL SCI ENG

Recently, the petroleum industry has focused on deeply buried reservoir discoveries and exploring potential CO2 storage sites close to existing infrastructure to increase the life span of already operating installations to save time and cost. It is therefore essential for the petroleum industry to find an innovative approach that exploits the existing core- and well log data to be successful in their endeavor of effectively characterizing and predicting reservoir quality. Continuous data sources (e.g. wireline logs) have a huge potential compared with expensive, time inefficient and sporadic data from cores in determining reservoir quality for use in a regional context. However, whereas core analysis offers in-depth knowledge about rock properties and diagenetic processes, continuous data sources can be difficult to interpret without a formation-specific framework. Here, we demonstrated how the pre-existing core data could be effectively used by integrating petrographic- and facies data with a pure predictive machine learning (ML) based porosity predictor. The inclusion of detailed core analysis is important for determining which reservoir parameter(s) that should be modeled and for the interpretation of model outputs. By applying this methodology, a framework for deducing lithological and diagenetic attributes can be established to aid reservoir quality delineation from wireline logs that can be used in frontier areas. With the ML porosity model, a Random Forest Regressor, the square of the correlation was 0.84 between predicted- and helium porosity test data over a large dataset consisting of 38 wells within the Stø Formation across the SW Barents Sea. By integrating the continuous ML porosity logs and core data, it was possible to differentiate three distinct bed types on wireline log responses within the Stø Formation. Particularly, the relationship between Gamma ray (GR) and porosity was effective in separating high porosity clean sand-, low porosity cemented clean sand and more clay and silt rich intervals. Additionally, in the P-wave velocity (VP) - density domain, separation of high porosity clean sand- and heavily cemented low porosity clean sand intervals were possible. The results also show that the ML derived porosity curves coincide with previously published and independent facies data from a selection of the wells included in the study. This demonstrates the applicability of the model in the region, because the Stø Formation has been described to exhibit similar lithological- and mineralogical properties over large parts of the Western Barents Sea area. Even though, continuous porosity data could be estimated from other sources like VP, neutron or density logs, this would generally require matrix and fluid information. This study demonstrated the effectiveness of the ML model in generating continuous porosity logs that are useful for characterizing and predicting reservoir properties in new wells. This methodology offers a workflow for exploiting already acquired core and well log data for frontier exploration that can be adapted to other formations and exploration scenarios worldwide.

Seismic rock physics and machine learning for deepwater stratigraphic intervals

Chapter

Sep 2022

This chapter shows how rock physics links geologic processes, rock and fluid properties and their seismic signatures. Understanding this relation helps in interpreting and diagnosing observed seismic data in terms of the underlying rock and fluid properties. Examples of rock physics templates and their applications for diagnosing reservoir properties in two turbidite systems in the North Sea are shown. However, rock physics models have their uncertainties and need to be calibrated with data. Combining physical models with data-driven statistical and machine-learning techniques helps to make better predictions and quantify the uncertainties in seismic interpretations. Some modern machine-learning algorithms and an application of deep learning for facies classification in the offshore Nile Delta are discussed. Geological understanding of the depositional systems along with rock physics models play a critical role in creating appropriate training datasets for deep learning algorithms that can be used for predicting reservoir properties.

Source rocks and petroleum systems in deepwater plays

Chapter

Sep 2022

A thermally mature source rock is the most foundational requirement for accumulations of petroleum to form. A field of study combining the assessment of source rocks and the definition of a subsurface fluid network that results in accumulations is known as petroleum systems analysis. A petroleum system has three key elements: charge, trap and reservoir. The charge element covers source rock, generation and migration to traps. The trap element includes a geological structure conducive to trapping petroleum as well as the ability of that structure’s edges to seal against further migration beyond the trap. The reservoir element requires a lithology of sufficient porosity such that petroleum can saturate the pore space and accumulate. A thorough understanding of these elements as well as processes affecting properties and quality of petroleum is critical to understand the viability of a play or prospect as well as place further scientific detail into context.

Reservoir quality and diagenesis of deepwater sandstones

Chapter

Sep 2022

Sandstones experience substantial reductions in porosity and permeability as they are buried. Such reductions occur in response to diagenesis, the suite of processes responsible for transforming sediment to rock. This chapter reviews diagenesis in deepwater sandstones associated with compaction as well as with quartz, clay mineral, zeolite and carbonate cementation. The most important factors influencing diagenesis are the composition and texture of sand at the time of deposition and the temperatures, stresses and fluid-fluxes the sand experiences over geologic time as it transforms into sandstone. The impacts that these factors can have on reservoir quality are illustrated through simulation scenarios that consider alternative framework grain compositions, facies within a local submarine fan complex and burial histories. Additionally, the chapter describes a simple flow chart that may be used for an initial assessment of reservoir quality risk factors for deepwater sandstones in unsampled portions of the subsurface.

New Direction for Regional Reservoir Quality Prediction Using Machine Learning - Example from the Stø Formation, Sw Barents Sea, Norway

Article

Jan 2022

Global distribution of the hydrocarbon Golden Zone

Article

Full-text available

Jul 2022
MAR PETROL GEOL

The presence of sedimentary sequences located at temperatures ranging between 60 and 120 °C has permitted the identification of hydrocarbon accumulation patterns of economic importance. This thermal range is identified as the “Golden Zone”, where there is a potential co-existence of the petroleum system elements that supports a minimal degree of degradation or transformation of hydrocarbons generated from source rocks, mainly in the hydrocarbon expulsion zone from approximately 120 °C–200 °C. The Golden Zone distribution can be represented on maps to help distinguish regions of relevant hydrocarbon potential. This work presents global Golden Zone distribution maps, estimated using a global geothermal gradient model obtained using the Curie Point Depth (CPD) distribution constrained with geothermal gradients from direct wells temperature measurements and a global model of sedimentary thicknesses obtained from data reported by a diverse array of institutions. The Golden Zone maps show the variations in different geotectonic environments. The depth interval for the Golden Zone varies between 500 m and 3000 m for the top and from 1000 m to 5000 m for the base, with thicknesses ranging between 5 and 3000 m. The Golden Zone distribution estimated shows that along active tectonic margins, the sedimentary sequences tend to be thin, located with abrupt contrasts of the basement, and where one or both isotherms that define the Golden Zone are below the basins, preventing its proper development. Exceptions to this trend are in the forelands and some intermountain basins. In contrast, the passive margins are characterized by Golden Zone regions in which the sedimentary sequences present a wide range of thicknesses within basins of diverse ages and extensions.

The Reservoir

Chapter

Jan 2023

The key properties of hydrocarbon reservoirs include porosity and permeability. Porosity refers to the pore spaces, or voids, within a rock, which are generally filled with connate water and may contain oil or gas within a field. Porosity is generally expressed as a percentage of the rock. The connected porosity in a reservoir constitutes the effective porosity, which is directly related to the permeability of the rock. The size and geometry of the pores and the diameter and tortuosity of the connecting throat passages affect the productivity of the reservoir. Primary pores are formed when sediment is deposited. Primary porosity and permeability are affected by grain shape, size, sorting, packing, and orientation. Secondary pores are those that developed in the rock sometime after deposition. Porosity can be measured in three ways: directly from cores, indirectly from geophysical well logs, or from seismic data. Permeability is helpful for evaluating porosity, as it is the ability of fluids to pass through a porous material, measured in Darcy units. This is defined as the permeability that allows a fluid with a viscosity of 1 cP to flow at a velocity of 1 cm/s for a pressure drop of 1 atm/s. The average permeability in reservoirs is commonly in the range of 5–500 md. Permeability can be measured using a drill stem or production test, from wireline logs (qualitatively), and by using a permeameter. The capillary pressure of a reservoir increases with decreasing pore size or, more specifically, pore throat diameter. Capillary pressure is also related to the surface tension generated by two adjacent fluids, which increases with increasing surface tension. Diagenesis affects reservoirs by reducing porosity by compaction and cementation and enhancing porosity by dissolution. Understanding reservoir continuity is a prerequisite for delineating reserves and the optimum method for recovering them. Most traps contain reservoirs that are heterogeneous to varying degrees. Depositional, diagenetic, and structural barriers impact reservoir continuity. Reservoir characterization aims to produce a geologic model that reflects available data and can be used to predict the distribution of porosity, permeability, and fluids throughout a field. Reserves of a field are calculated using volumetric or mass balance equations. Both involve the porosity of the reservoir, and drive mechanisms in reservoirs include water, gas cap, and dissolved gas drives. The recovery factors range up to 60% for water drives, 20–50% for gas cap drives, and 7–15% for dissolved gas drives. Enhanced recovery methods have been designed to improve recovery. Methods include gas injection and liquid (generally water) injection. The objective of enhanced recovery is to maintain or reestablish the original field pressure and sweep more oil to the wellbore.

Porosity Trends of the Lower Cretaceous J Sandstone, Denver Basin, Colorado

Article

Jan 1991

Debra K. Higley James W. Schmoker

The petrographic factors that most affect J sandstone porosity variability at a given level of thermal maturity are carbonate cementation and clay content. Carbonate cement, where present, reduces porosity. If previously more widespread, carbonate cement could also introduce porosity heterogeneity by temporarily preserving the pore network relative to uncemented intervals. Abundant detrital and authigenic clay reduces porosity by occupying pores. Low clay content indirectly reduces porosity because the inhibiting effects of clay upon quartz cementation and pressure solution are largely absent. -from Authors

Clastic diagenesis and basin evolution

Article

Jan 1980

Knut Bjørlykke

Experimental Study of Sandstone Cementation

Article

Jan 1966

Porosity reduction in sandstone by quartz overgrowth

Article

Nov 1986

A mathematical model for predicting porosity histories due to quartz overgrowth in quartz-rich sandstone reservoirs has been developed. The model neglects secondary dissolution porosity and other diagenetic processes such as compaction and precipitation of carbonate and clay minerals. Nevertheless, the model is straightforward and easy to use to calculate porosity. The calculated porosity corresponds to measured porosity of simple quartz-cemented sandstones in 27 wells in North and South America. The model is based on fluid flow through initially porous, unlithified sands in which the fluid phase is saturated with Si(OH)â and is always in equilibrium with quartz. As the continuously circulating fluid migrates updip toward the basin edge, it cools, and quartz precipitates into the pore spaces causing a loss of porosity. Basinal fluid velocities may be calculated assuming (1) thermal convection and (2) hydrostatic pressure due to recharge at the edge of the basin. Porosity diagrams relating porosity to geothermal gradient, burial rate, and depth of burial are compared to thermal maturation models of source rocks, fluid flow history, and grain-size distribution. The rate of porosity reduction depends on the following variables in decreasing order of significance: burial rate, age, initial porosity, basin size (dip angle), fluid dynamics, initial permeability, and geothermal gradient. 11 figures, 2 tables.

Zur Herkunft des Quarzzements. Abschätzung der Quarzauflösung in Silt und Sandsteinen

Article

Oct 1978

Hans Füchtbauer

Zusammenfassung Die Kieselsäure des Quarzzementes von Sandsteinen stammt wahrscheinlich zum größten Teil von aufgelöstem Quarz, und zwar1. aus den benachbarten Silt- und Tonsteinen. An Sand- und Siltsteinen des Mittelrhät und des Dogger beta aus Bohrungen NE von Hannover sowie an Konkretionen devonischen bis oberkretazischen Alters wurde festgestellt, a) daß die Quarzkörner in Siltlagen flacher und dadurch um ca. 35 % reduziert sind gegenüber gleichgroßen Quarzen im begleitenden Sandstein, b) daß von dem ursprünglichen, nur in Konkretionen konservierten Quarzgehalt 10 bis 50 % in den umgebenden Silt- und Tonsteinen aufgelöst sind. 2. aus den Sandsteinen selbst, von Stylolithen. Dies konnte anhand von Glimmeranreicherungen quantifiziert werden. Die Amplitude der Stylolithen ist teufenabhängig. Es ist wahrscheinlich, daß die SiO2-Zufuhr aus tonigen Nebengesteinen in einem früheren Stadium der Diagenese geschah, als noch ein kräftiger Kompaktionsstrom für Transport und gleichmäßige Verteilung der gelösten Kieselsäure sorgte. Eine Abschätzung ergibt, daß durch Tonmineralumwandlungen nur etwa 1/10 der durch Quarzauflösung im Tongestein freigesetzten Kieselsäure bereitgestellt wurde. Die SiO2-Umlagerung im Sandstein selbst geschah später und im wesentlichen durch lokale Diffusion.

Silicate and Associated Cements in an Oxfordian Marine—Freshwater Transition, Inner Moray Firth, UK North Sea

Article

Jan 1989

Christopher Jeans

These sediments exhibit a close relationship between the pattern of mineral diagenesis and the physico-chemical conditions of the original depositional environment. Both marine and non-marine lithofacies have undergone a complex alternation of mineral cementation and grain dissolution. Prior to the entry of hydrocarbons during the Early Tertiary at a burial depth of between 6000 and 9000 ft, the sandstones experienced a major loss of pore-fluid pressure, localized collapse, and the precipitation of allochthonous baryte cement in both the marine and non-marine lithofacies. -from Authors

Secondary porosity in hydrocarbon-bearing transgressive sandstones on an unstable Lower Palaeozoic continental shelf, Welsh Borderland

Article

Jan 1987

J. Parnell

Coarse sandstones were deposited during each of four transgressions across the shelf of the Lower Palaeozoic back-arc Welsh Basin. Hydrocarbon shows record porosity in the deposits of the Cambrian, Arenig, Caradoc and Llandovery transgressions. Hydrocarbons migrated from two sources: from Lower Palaeozoic source rocks within the basin, and later from Carboniferous rocks. Diagenesis and reservoir potential is related to the mineralogy of the sandstones, which reflects a balance between reworking of shelf sediment and an input from the eroded substrate. The substrate included Precambrian volcanic and plutonic rocks formed at the southern margin of the Iapetus Ocean. Quartz arenites are quartz-cemented or exhibit thick pore-linings of clay which restrict permeability. They have only minor reservoir potential. Arkoses do not exhibit macroporosity but have effective microporosity in the immediate vicinity of source rocks. Subarkoses have optimal reservoir potential, consisting of primary porosity about non-quartz grains (feldspars, glauconite) and secondary (intragranular) porosity in feldspars and lithics. The secondary porosity formed by leaching of clay alteration products in feldspars. Subarkoses retained sufficient framework stability to preserve the secondary porosity, whereas arkoses experienced widespread alteration and framework collapse. Limited secondary porosity after calcite dissolution may be due to surficial weathering of the Lower Palaeozoic rocks during Devonian/Lower Carboniferous exposure.

Porosity prediction, prior to drilling, in sandstones of the Kekiktuk Formation (Mississippian), North Slope of Alaska

Article

Sep 1990
AAPG BULL

Porosity in sandstones of the Kekiktuk Formation was successfully estimated prior to drilling of the 1 Leffingwell wildcat well (North Slope of Alaska). The estimate was based on a calibration data set used to evaluate the effects of (1) framework grain composition, (2) depositional facies, and (3) postdepositional processes on porosity of Kekiktuk sandstones. The sandstones of the Kekiktuk Formation are chert-bearing sublitharenites and quartzarenites characterized by a homogeneous composition of the detrital framework in the study area. Thus, mineral composition is not a major factor responsible for differences in reservoir quality. Based on outcrop and available core observations, the Kekiktuk Formation was interpreted to include several wet fan-deltas. The depositional model suggested that the 1 Leffingwell well would penetrate the distal, fine-grained facies of one such system. A petrographic study indicated that in fine- and very fine-grained Kekiktuk sandstones, such as those predicted in the wildcat, porosity was reduced primarily by silica cementation. Silica cementation, in turn, is related to burial history. Because of the relationship among porosity, silica cementation, and burial history, burial history diagrams provided a measure of the effect of burial history on porosity in available calibration wells. A synthetic burial history curve was constructed prior to drilling of the 1 Leffingwell well from available seismic data. This burial history curve was then used to estimate the wells porosity based on the previously established porosity-burial history relationship. 13 figs., 4 tabs.

Cementation of sandstones - Discussion

Article

Jan 1979

Knut Bjørlykke

In discussion of papers by Land and Dutton (GeoAbstracts 79E/1052) and Boles and Franks (GeoAbstracts 79E/1980) Bj/orlykke calculates that ascending pore water derived from dewatering of shales cannot provide sufficient volumes of water in order to cement the sandstones unless they are only a few centimeters thick. He sugests that descending groundwater circulation may provide a high enough flux of water through the sandstones to supply the silica cement. -I.McTaggart

Kinetic Modeling of Quartz Cementation and Porosity Loss in Deeply Buried Sandstone Reservoirs

Abstract

No full-text available

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