scholarly journals The Influence of Magmatic Intrusions on Diagenetic Processes and Stress Accumulation

Geosciences ◽  
2019 ◽  
Vol 9 (11) ◽  
pp. 477 ◽  
Author(s):  
Magnhild Sydnes ◽  
Willy Fjeldskaar ◽  
Ivar Grunnaleite ◽  
Ingrid Fjeldskaar Løtveit ◽  
Rolf Mjelde
Keyword(s):  
Numerical Study ◽  
Sedimentary Basins ◽  
Reservoir Quality ◽  
Hydrocarbon Migration ◽  
Hydrocarbon Reservoir ◽  
Hydrocarbon Traps ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Magmatic Intrusions ◽  
Stress Accumulation

Diagenetic changes in sedimentary basins may alter hydrocarbon reservoir quality with respect to porosity and permeability. Basins with magmatic intrusions have specific thermal histories that at time of emplacement and in the aftermath have the ability to enhance diagenetic processes. Through diagenesis the thermal conductivity of rocks may change significantly, and the transformations are able to create hydrocarbon traps. The present numerical study quantified the effect of magmatic intrusions on the transitions of opal A to opal CT to quartz, smectite to illite and quartz diagenesis. We also studied how these chemical alterations and the sills themselves have affected the way the subsurface responds to stresses. The modeling shows that the area in the vicinity of magmatic sills has enhanced porosity loss caused by diagenesis compared to remote areas not intruded. Particularly areas located between clusters of sills are prone to increased diagenetic changes. Furthermore, areas influenced by diagenesis have, due to altered physical properties, increased stress accumulations, which might lead to opening of fractures and activation/reactivation of faults, thus influencing the permeability and possible hydrocarbon migration in the subsurface. This study emphasizes the influence magmatic intrusions may have on the reservoir quality and illustrates how magmatic intrusions and diagenetic changes and their thermal and stress consequences can be included in basin models.

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

Minerals ◽  
2020 ◽  
Vol 10 (9) ◽  
pp. 757
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Christopher Baiyegunhi
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Reservoir Quality ◽  
Reservoir Properties ◽  
Oil And Gas Production ◽  
Thin Sections ◽  
Hydrocarbon Reservoir ◽  
Porosity And Permeability ◽  
The Impact

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

scholarly journals Diagenesis Processes Impact on Reservoir Quality in Carbonate Yamama Formation /Faihaa Oil Field

2020 ◽  
pp. 92-102
Author(s):  
Mohammed A. Ahmed ◽  
Madhat E. Nasser ◽  
Sameer N. AL Jawad
Keyword(s):  
Oil Field ◽  
Reservoir Quality ◽  
Genetic Classification ◽  
Thin Sections ◽  
Positive Effects ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Cretaceous Period ◽  
The Impact

The Yamama Formation is a significant reservoir in the southern part of Iraq. This formation consists of limestone deposited throughout the Lower Cretaceous period within main retrogressive depositional series. This study aims to identify the impact of the diagenesis processes on the reservoir’s characteristics (porosity and permeability). Diagenesis processes’ analysis and the identification of Yamama Formation depended on the examination of more than 250 thin sections of the core samples from two wells that were used to determine different diagenetic environments and processes. The three identified diagenetic environments that affected Yamama reservoir were the marine, meteoric and burial environments. Eight diagenetic processes were recognized in Yamama Formation and showed positive and destructive effects on the reservoir quality; Dissolution and fracture had highly positive effects through creating and improving porosity and permeability that led to improving reservoir quality. Cementation and compaction had destructive effects, through reducing porosity and permeability, that led to reducing reservoir quality. Other processes such micritization, dolomitization, bioturbation and neomorphism did not have strong effects on reservoir quality. Based on genetic classification of porosity, most of porosity within Yamama Formation in this field was formed by diagenesis processes, implying that Yamama reservoir is a type of diagenetic reservoir.

Carbonate Pore System Characterization, a Study Case from Drowning Cap Sequence in VITA Field, ExxonMobil Block Cepu Limited (EMCL)

2021 ◽  
Author(s):  
V.T Dewi
Keyword(s):  
Reservoir Simulation ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
High Porosity ◽  
Pore System ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Study Case ◽  
Low Porosity

Carbonate rocks are known as one of the principal reservoir rocks in the world due to their good porosity and permeability. However, the heterogeneity of carbonate reservoir quality is difficult to predict. Variability of diagenetic processes overprinting carbonate depositional texture has resulted in a complex carbonate pore system. As a consequence, this complexity results in a harder reservoir characterization and also a discrepancy between actual and model properties, that leads to a harder history match in reservoir simulation. By presenting a study case from the Drowning Cap Sequence in the VITA Reservoir Block Cepu, this paper will present a comprehensive approach which focusing on characterization of a carbonate pore system for optimum geomodel, simulation and surveillance. This approach utilized static data of 100 ft total of cores, ±500 thin sections, well, and image logs. The study has resulted in definition of four Carbonate Reservoir Rock Types (RRT) which were clustered using the analysis of carbonate dominant pore types and the porosity-permeability relationship. Results revealed that there are 4 RRTs observed as follows: (1) RRT 1 – Touching Vugs-dominated, with high porosity and permeability, (2) RRT 2 – Interparticle- and Moldic-dominated, with moderate to high porosity value and lower permeability than RRT 1, (3) RRT 3 – Microfracture-dominated, with very low porosity value and low to moderate permeability, and (4) RRT 4 – Minimum Dissolution, with very low porosity and permeability value, lower than RRT 3. Each RRT was integrated with well and image logs to understand its characteristics and behavior. Ultimately, all data were integrated, analyzed and successfully captured carbonate reservoir quality variation, distribution and depositional evolution along with overprinted diagenetic processes vertically and laterally. This approach successfully captured carbonate heterogeneity which ultimately will be useful to develop better geological and reservoir simulation models after being integrated with dynamic data and observations.

Carbonate Diagenesis in a Sequence Stratigraphic Framework; Case study from Miocene Dam Formation, Eastern Saudi Arabia

2020 ◽  
Author(s):  
Moaz Salih ◽  
Osman Abdullatif ◽  
Khalid Al-Ramadan ◽  
Mazin Bashri
Keyword(s):  
Saudi Arabia ◽  
Arabian Plate ◽  
Sequence Stratigraphic ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Thin Section Petrography ◽  
Calcite Cement ◽  
Sequence Boundaries ◽  
Analytical Tools

<p>The Miocene Dam Formation in the Al-Lidam area of Eastern Saudi Arabia consists of a succession </p><p>of mixed siliciclastic-carbonate sequences that were deposited during Miocene (Burdigalian) </p><p>times. Stratigraphic equivalents of the Dam Formation occur as hydrocarbon reservoir intervals in </p><p>the Arabian Plate. Reservoir quality of carbonate rocks is controlled by a combination of </p><p>depositional setting and post-depositional diagenetic factors. </p><p>In this study, fifteen lithofacies were identified as they were deposited on a low angle dipping </p><p>carbonate ramp, under supratidal, beach, intertidal and shallow subtidal conditions. Carbonate </p><p>diagenesis has been examined using: thin-section petrography, SEM, XRD and </p><p>cathodoluminescence. These analytical tools have shown that the intertidal lithofacies are </p><p>influenced by extensive meteoric dissolution and minor cementation. Marine diagenesis was </p><p>restricted to beach grainstone and subtidal lithofacies, in the form of aragonite and high magnesium </p><p>calcite cement. Shallow burial conditions were inferred by grain contacts represented by point, </p><p>suture and concavo-convex contacts. Mimetic dolomitization for the whole succession was also </p><p>observed. Three fourth - order, shallowing upward sequences were identified in the study area, and </p><p>they are separated by two sequence boundaries. A clear relation between sequence surfaces and </p><p>diagenetic processes was observed; meteoric diagenesis and dolomitization increases upwards in </p><p>each sequence. Porosity and permeability measurements have shown that the highest values are </p><p>associated with the HST of each sequence, followed by the TST and the LST. The results of this </p><p>study can help in understanding of diagenetic processes, and consequently in developing better </p><p>and more accurate predictions of the porosity and permeability distribution within hydrocarbon </p><p>reservoirs.</p><p> </p>

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

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.  

scholarly journals Reservoir quality and its controlling diagenetic factors in the Bentiu Formation, Northeastern Muglad Basin, Sudan

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Yousif M. Makeen ◽  
Xuanlong Shan ◽  
Mutari Lawal ◽  
Habeeb A. Ayinla ◽  
Siyuan Su ◽  
...  
Keyword(s):  
Clay Content ◽  
Petroleum Exploration ◽  
Reservoir Quality ◽  
Burial Depth ◽  
Petroleum Reservoir ◽  
Fine Grained ◽  
Porosity And Permeability ◽  
Negative Role ◽  
Crevasse Splay ◽  
Channel Deposits

AbstractThe Abu Gabra and Bentiu formations are widely distributed within the interior Muglad Basin. Recently, much attention has been paid to study, evaluate and characterize the Abu Gabra Formation as a proven reservoir in Muglad Basin. However, few studies have been documented on the Bentiu Formation which is the main oil/gas reservoir within the basin. Therefore, 33 core samples of the Great Moga and Keyi oilfields (NE Muglad Basin) were selected to characterize the Bentiu Formation reservoir using sedimentological and petrophysical analyses. The aim of the study is to de-risk exploration activities and improve success rate. Compositional and textural analyses revealed two main facies groups: coarse to-medium grained sandstone (braided channel deposits) and fine grained sandstone (floodplain and crevasse splay channel deposits). The coarse to-medium grained sandstone has porosity and permeability values within the range of 19.6% to 32.0% and 1825.6 mD to 8358.0 mD respectively. On the other hand, the fine grained clay-rich facies displays poor reservoir quality as indicated by porosity and permeability ranging from 1.0 to 6.0% and 2.5 to 10.0 mD respectively. A number of varied processes were identified controlling the reservoir quality of the studies samples. Porosity and permeability were enhanced by the dissolution of feldspars and micas, while presence of detrital clays, kaolinite precipitation, iron oxides precipitation, siderite, quartz overgrowths and pyrite cement played negative role on the reservoir quality. Intensity of the observed quartz overgrowth increases with burial depth. At great depths, a variability in grain contact types are recorded suggesting conditions of moderate to-high compactions. Furthermore, scanning electron microscopy revealed presence of micropores which have the tendency of affecting the fluid flow properties in the Bentiu Formation sandstone. These evidences indicate that the Bentiu Formation petroleum reservoir quality is primarily inhibited by grain size, total clay content, compaction and cementation. Thus, special attention should be paid to these inhibiting factors to reduce risk in petroleum exploration within the area.

scholarly journals Studies on the onshore hydrocarbon potential in East Greenland 1986-87: field work from 72° to 74°N

1987 ◽  
Vol 135 ◽  
pp. 72-81
Author(s):  
C Marcussen ◽  
F.G Christiansen ◽  
P.-H Larsen ◽  
H Olsen ◽  
S Piasecki ◽  
...  
Keyword(s):  
Thermal History ◽  
Sedimentary Basins ◽  
Field Work ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
East Greenland ◽  
The North ◽  
Hydrocarbon Traps ◽  
Subsidence History ◽  
Tectonic Study

A study of the onshore hydrocarbon potential of central and northem East Greenland was initiated in 1986. Field work was carried out from early July to mid August covering the region between Kong Oscar Fjord and Kejser Franz Joseph Fjord (fig. 1). In 1987 field activities will continue further to the north, eventually reaching Danmarkshavn (77°N). The programme is a continuation of the 1982-83 investigations in Jameson Land (Surlyk, 1983; Surlyk et al., 1984a) and is part of a regional programme comprising petroleum geological studies of all sedimentary basins in Greenland (Larsen & Marcussen, 1985; Larsen, 1986). The aim of the two-year field study followed by laboratory analyses is: (1) to study the presence and distribution of potential hydrocarbon source rocks in the region; (2) to evaluate the thermal history and maturity pattern of the region including the thermal effect of Tertiary intrusions and volcanics; (3) to make a stratigraphic, sedimentological and tectonic study of the region with special emphasis on subsidence history, reservoir formation and potential hydrocarbon traps.

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