Modelling the impact of depositional and diagenetic processes on reservoir properties of the crystal-shrub limestones in the ‘Pre-Salt’ Barra Velha Formation, Santos Basin, Brazil

A common problem in dolomite reservoirs is the heterogeneous distribution of porosity-reducing diagenetic phases. The intrasalt carbonates of the Ediacaran-Early Cambrian Ara Group in the South Oman Salt Basin represent a self-sourcing petroleum system. Depositional facies and carbonate/evaporite platform architecture are well understood, but original reservoir properties have been modified by diagenesis. Some of the carbonate reservoirs failed to produce hydrocarbons at acceptable rates, which triggered this study. The extent of primary porosity reduction by diagenetic phases was quantified using point counting. To visualize the distribution of diagenetic phases on a field scale, we constructed 2D interpolation diagenesis maps to identify patterns in cementation. The relative timing of diagenetic events was constrained based on thin-section observations and stable isotope analyses. Near-surface diagenesis is dominated by reflux-related processes, leading to porosity inversion in initial highly porous facies and a patchy distribution of early cements. This strong diagenetic overprint of primary and early diagenetic porosity by reflux-related cements leads to a reduction of stratigraphic and facies control on porosity. Calcite was identified as a burial-related cement phase that leads to an almost complete loss of intercrystalline porosity and permeability. Bitumen is an important pore-occluding phase and time marker of the deep-burial realm. The stratigraphic position of the dolomite reservoirs embedded at the base of a salt diapir had a strong impact on its diagenetic development. The salt isolated the dolomites from external fluids, leading to a closed system diagenesis and the buildup of near lithostatic fluid pressures. In combination, these processes decreased the impact of further burial diagenetic processes. The study highlights that cement distribution in salt-encased carbonate reservoirs is mainly related to early diagenetic processes but can be very heterogeneous on a field scale. Further work is needed to implement these heterogeneities in an integrated numerical reservoir model.

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Testing geologic assumptions and scenarios in carbonate exploration: Insights from integrated stratigraphic, diagenetic, and seismic forward modeling

The Leading Edge ◽

10.1190/tle37090672.1 ◽

2018 ◽

Vol 37 (9) ◽

pp. 672-680 ◽

Cited By ~ 7

Author(s):

Cyprien Lanteaume ◽

François Fournier ◽

Matthieu Pellerin ◽

Jean Borgomano

Keyword(s):

Spatial Distribution ◽

Forward Modeling ◽

Reservoir Properties ◽

Modeling Approaches ◽

Diagenetic Processes ◽

Stratigraphic Architecture ◽

Carbonate Deposition ◽

Seismic Models ◽

Seismic Reflectors ◽

The Impact

Carbonates are considered complex, heterogeneous at all scales, and unfortunately often poorly seismically imaged. We propose a methodology based on forward-modeling approaches to test the validity of common exploration assumptions (e.g., chronostratigraphic value of seismic reflectors) and of geologic interpretations (e.g., stratigraphic correlations and depositional and diagenetic architecture) that are determined from a limited amount of data. The proposed workflow includes four main steps: (1) identification and quantification of the primary controls on carbonate deposition and the prediction of the carbonate stratigraphic architecture (through stratigraphic forward modeling); (2) identification of diagenetic processes and prediction of the spatial distribution of diagenetic products (diagenetic forward modeling); (3) quantification of the impact of diagenesis on acoustic and reservoir properties; and (4) computation of synthetic seismic models based on various scenarios of stratigraphic and diagenetic architectures and comparison with actual seismic. The likelihood of a given scenario is tested by quantifying the misfit between the modeled versus the real seismic. This workflow illustrates the relevance of forward-modeling approaches for building realistic models that can be shared by the various disciplines of carbonate exploration (sedimentology, stratigraphy, diagenesis, seismic, geomodeling, and reservoir).

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The impact of diagenesis on the reservoir quality of the early Cretaceous Lower Goru sandstones in the Lower Indus Basin, Pakistan

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01415-8 ◽

2021 ◽

Author(s):

Qamar UZ Zaman Dar ◽

Renhai Pu ◽

Christopher Baiyegunhi ◽

Ghulam Shabeer ◽

Rana Imran Ali ◽

...

Keyword(s):

Early Cretaceous ◽

Pore Space ◽

Hydrocarbon Exploration ◽

Indus Basin ◽

Coarse Grained ◽

Rock Properties ◽

Reservoir Properties ◽

Diagenetic Processes ◽

Lower Indus Basin ◽

The Impact

AbstractThe sandstone units of the Early Cretaceous Lower Goru Formation are significant reservoir for gas, oil, and condensates in the Lower Indus Basin of Pakistan. Even though these sandstones are significant reservoir rocks for hydrocarbon exploration, the diagenetic controls on the reservoir properties of the sandstones are poorly documented. For effective exploration, production, and appraisal of a promising reservoir, the diagenesis and reservoir properties must be comprehensively analyzed first. For this study, core samples from depths of more than 3100 m from the KD-01 well within the central division of the basin have been studied. These sandstones were analyzed using petrographic, X-ray diffraction, and scanning electron microscopic analyses to unravel diagenetic impacts on reservoir properties of the sandstone. Medium to coarse-grained and well-sorted sandstone have been identified during petrographic study. The sandstone are categorized as arkose and lithic arkose. Principal diagenetic events which have resulted in changing the primary characters of the sandstones are compaction, cementation, dissolution, and mineral replacement. The observed diagenetic processes can be grouped into early, burial, and late diagenesis. Chlorite is the dominant diagenetic constituent that occurs as rims, coatings, and replacing grains. The early phase of coating of authigenic chlorite has preserved the primary porosity. The recrystallization of chlorite into chamosite has massively reduced the original pore space because of its bridging structure. The current study reveals that diagenetic processes have altered the original rock properties and reservoir characteristics of the Lower Goru sandstone. These preliminary outcomes of this study have great potential to improve the understanding of diagenetic process and their impact on reservoir properties of the Lower Goru sandstone in the Lower Indus Basin and adjoining areas.

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Geostatistical Inversion in Carbonate Reservoirs to Map Reservoir Quality With High Predictability – A Case Study From Onshore Abu Dhabi

10.2118/207583-ms ◽

2021 ◽

Author(s):

S Al Naqbi ◽

J Ahmed ◽

J Vargas Rios ◽

Y Utami ◽

A Elila ◽

...

Keyword(s):

High Resolution ◽

Seismic Data ◽

Pore Volume ◽

Rock Physics ◽

Static Model ◽

Reservoir Quality ◽

Reservoir Properties ◽

Geostatistical Inversion ◽

High Predictability ◽

The Impact

Abstract The Thamama group of reservoirs consist of porous carbonates laminated with tight carbonates, with pronounced lateral heterogeneities in porosity, permeability, and reservoir thickness. The main objective of our study was mapping variations and reservoir quality prediction away from well control. As the reservoirs were thin and beyond seismic resolution, it was vital that the facies and porosity be mapped in high resolution, with a high predictability, for successful placement of horizontal wells for future development of the field. We established a unified workflow of geostatistical inversion and rock physics to characterize the reservoirs. Geostatistical inversion was run in static models that were converted from depth to time domain. A robust two-way velocity model was built to map the depth grid and its zones on the time seismic data. This ensured correct placement of the predicted high-resolution elastic attributes in the depth static model. Rock physics modeling and Bayesian classification were used to convert the elastic properties into porosity and lithology (static rock-type (SRT)), which were validated in blind wells and used to rank the multiple realizations. In the geostatistical pre-stack inversion, the elastic property prediction was constrained by the seismic data and controlled by variograms, probability distributions and a guide model. The deterministic inversion was used as a guide or prior model and served as a laterally varying mean. Initially, unconstrained inversion was tested by keeping all wells as blind and the predictions were optimized by updating the input parameters. The stochastic inversion results were also frequency filtered in several frequency bands, to understand the impact of seismic data and variograms on the prediction. Finally, 30 wells were used as input, to generate 80 realizations of P-impedance, S-impedance, Vp/Vs, and density. After converting back to depth, 30 additional blind wells were used to validate the predicted porosity, with a high correlation of more than 0.8. The realizations were ranked based on the porosity predictability in blind wells combined with the pore volume histograms. Realizations with high predictability and close to the P10, P50 and P90 cases (of pore volume) were selected for further use. Based on the rock physics analysis, the predicted lithology classes were associated with the geological rock-types (SRT) for incorporation in the static model. The study presents an innovative approach to successfully integrate geostatistical inversion and rock physics with static modeling. This workflow will generate seismically constrained high-resolution reservoir properties for thin reservoirs, such as porosity and lithology, which are seamlessly mapped in the depth domain for optimized development of the field. It will also account for the uncertainties in the reservoir model through the generation of multiple equiprobable realizations or scenarios.

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Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

International Journal of Petroleum Technology ◽

10.15377/2409-787x.2021.08.5 ◽

2021 ◽

Vol 8 ◽

pp. 55-79

Author(s):

E. Bakhshi ◽

A. Shahrabadi ◽

N. Golsanami ◽

Sh. Seyedsajadi ◽

X. Liu ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Pore Pressure ◽

Earth Model ◽

Reservoir Properties ◽

Stress Regime ◽

Geomechanical Properties ◽

Hydrocarbon Reservoir ◽

Diagenetic Processes ◽

Mechanical Earth Model ◽

New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.

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

University of the Future: Re-Imagining Research and Higher Education ◽

10.29117/quarfe.2020.0043 ◽

2020 ◽

Author(s):

Fadhil N. Sadooni ◽

Hamad Al-Saad Al-Kuwari ◽

Ahmad Sakhaee-Pour ◽

Wael S. Matter

Keyword(s):

Depositional Environments ◽

Oil Reservoir ◽

Secondary Porosity ◽

Future Directions ◽

Thin Sections ◽

Intergranular Porosity ◽

Porosity Evolution ◽

Diagenetic Processes ◽

Exploration And Production ◽

The Impact

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

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Seismostratigraphic Interpretation of Upper Cretaceous Reservoir from the Carpathian Foreland, Southern Poland

Energies ◽

10.3390/en14227776 ◽

2021 ◽

Vol 14 (22) ◽

pp. 7776

Author(s):

Andrzej Urbaniec ◽

Anna Łaba-Biel ◽

Anna Kwietniak ◽

Imoleayo Fashagba

Keyword(s):

Late Cretaceous ◽

Upper Cretaceous ◽

Tectonic Setting ◽

Small Scale ◽

Reservoir Properties ◽

Southern Poland ◽

Seismic Sequence Stratigraphy ◽

First Results ◽

Depositional Architecture ◽

The Impact

The Upper Cretaceous complex in the central part of the Carpathian Foreland (southern Poland) is relatively poorly recognized and described. Its formations can be classified as unconventional reservoir due to poor reservoir properties as well as a low recovery factor. The main aim of the article is to expand knowledge with conclusions resulting from the analysis of the latest seismic data with the application of seismic sequence stratigraphy. Moreover, the seismic attributes analysis was utilized. The depositional architecture recognition based on both chronostratigraphic horizons and Wheeler diagram interpretations was of paramount importance. A further result was the possibility of using the chronostratigraphic image for tectonostratigraphic interpretation. Two distinguished tectonostratigraphic units corresponding to megasequences were recognized. A tectonic setting of the analyzed interval is associated with global processes noticed by other authors in other parts of the central European Late Cretaceous basin, but also locally accompanied by evidence of small-scale tectonics. This study fills the gap on the issue of paleogeography in the Late Cretaceous sedimentary basin of the Carpathian Foreland. It presents the first results of detailed reconstruction of the basin paleogeography and an attempt to determine the impact of both eustatic and tectonic factors on sedimentation processes.

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FORMATION EVALUATION AND STATIC MODELLING IN THE WHEATSTONE GAS FIELD

The APPEA Journal ◽

10.1071/aj05010 ◽

2006 ◽

Vol 46 (1) ◽

pp. 161 ◽

Cited By ~ 1

Author(s):

P. Theologou ◽

M. Whelan

Keyword(s):

Experimental Design ◽

Early Stage ◽

Potential Range ◽

Reservoir Properties ◽

Gas Field ◽

Formation Evaluation ◽

Place Assimilation ◽

Logging While Drilling ◽

Realistic Information ◽

The Impact

The Wheatstone gas discovery is located about 110 km north-northwest of Barrow Island in the Dampier Subbasin, northwest Australia. Gas was intersected within the AA sands of the Mungaroo Formation, and within a thin overlying Tithonian sand. Core was acquired through the base of the Tithonian sand and the upper section of the Mungaroo Formation.A combination of logging while drilling, wireline logging, core acquisition and special core analysis has formed the basis of an extensive formation evaluation program for Wheatstone–1. The acquisition of this dataset, and associated interpretation, has allowed Chevron to maximise its ability to characterise the reservoir early in the field’s history, and thereby has helped our understanding of the uncertainties associated with the formation evaluation and geological modelling of this fluvial system. Petrological studies indicate that reservoir properties and mineralogy are strongly correlated with the mean grain size of the formation. The mineralogy of the sands is relatively simple with minor quartz overgrowth, K-feldspar dissolution and kaolinite precipitation being the dominant diagenetic events. The better quality sands are generally devoid of significant amounts of clays such as illite-smectite. Within the Tithonian sand, more exotic mineral suites are present including glauconitic and phosphatic minerals.A comparison of resistivity data from wireline and logging while drilling (LWD) across cored and non-cored intervals through the Mungaroo Formation has revealed the impact that slow coring has had on formation filtrate invasion. It has been interpreted that the combination of slow rate of penetration, non-optimised mud properties, and coring assembly design resulted in deep invasion through cored intervals. Deep resistivity response through the invaded formation was subdued, and initially resulted in an underestimation of reserves. The incorporation of saturation information from capillary pressure data has provided for a more realistic view of gas-in-place.In this early stage of field appraisal, the generation of representative and fit-for-purpose reservoir models is somewhat difficult due to the small amount of available data existing away from the well. To provide realistic information on the potential range of gas-in-place for the field, experimental design methodology was incorporated into the modelling work-flow. Experimental design allows for rapid and comprehensive modelling of the possible range of the dependant variables, in this case GIIP (gas initially in place). Assimilation of geological analogues, formation evaluation and their inherent uncertainties has attempted to capture the range of GIIP in this world-class gas discovery.

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

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-01005-0 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3263-3279 ◽

Cited By ~ 1

Author(s):

Mohamed Ragab Shalaby ◽

Syamimi Hana Binti Sapri ◽

Md Aminul Islam

Keyword(s):

New Zealand ◽

Reservoir Characterization ◽

Flow Distribution ◽

Log Analysis ◽

Well Log ◽

Reservoir Properties ◽

Flow Units ◽

Potential Reservoir ◽

Well Log Analysis ◽

The Impact

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

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Diagenetic Evolution and Reservoir Quality of Sandstones in the North Alpine Foreland Basin: A Microscale Approach

Microscopy and Microanalysis ◽

10.1017/s1431927615014725 ◽

2015 ◽

Vol 21 (5) ◽

pp. 1123-1137 ◽

Cited By ~ 1

Author(s):

Doris Gross ◽

Marie-Louise Grundtner ◽

David Misch ◽

Martin Riedl ◽

Reinhard F. Sachsenhofer ◽

...

Keyword(s):

Foreland Basin ◽

Gas Production ◽

Coarse Grained ◽

Reservoir Quality ◽

Reservoir Properties ◽

The North ◽

North Alpine Foreland Basin ◽

Alpine Foreland ◽

Alpine Foreland Basin ◽

The Impact

AbstractSiliciclastic reservoir rocks of the North Alpine Foreland Basin were studied focusing on investigations of pore fillings. Conventional oil and gas production requires certain thresholds of porosity and permeability. These parameters are controlled by the size and shape of grains and diagenetic processes like compaction, dissolution, and precipitation of mineral phases. In an attempt to estimate the impact of these factors, conventional microscopy, high resolution scanning electron microscopy, and wavelength dispersive element mapping were applied. Rock types were established accordingly, considering Poro/Perm data. Reservoir properties in shallow marine Cenomanian sandstones are mainly controlled by the degree of diagenetic calcite precipitation, Turonian rocks are characterized by reduced permeability, even for weakly cemented layers, due to higher matrix content as a result of lower depositional energy. Eocene subarkoses tend to be coarse-grained with minor matrix content as a result of their fluvio-deltaic and coastal deposition. Reservoir quality is therefore controlled by diagenetic clay and minor calcite cementation.Although Eocene rocks are often matrix free, occasionally a clay mineral matrix may be present and influence cementation of pores during early diagenesis. Oligo-/Miocene deep marine rocks exhibit excellent quality in cases when early cement is dissolved and not replaced by secondary calcite, mainly bound to the gas–water contact within hydrocarbon reservoirs.

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