Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi

2021 ◽  
Author(s):  
Catherine Breislin ◽  
Laura Galluccio ◽  
Kate Al Tameemi ◽  
Riaz Khan ◽  
Atef Abdelaal
Keyword(s):  
Depositional Environment ◽  
Middle Miocene ◽  
Quality Analysis ◽  
Reservoir Quality ◽  
Carbonate Facies ◽  
Pore System ◽  
Thin Sections ◽  
Reservoir Architecture ◽  
Porosity And Permeability ◽  
Permeability Anisotropy

Abstract Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.

scholarly journals Integrated reservoir characterization and quality analysis of the carbonate rock types, case study, southern Iraq

2020 ◽  
Vol 10 (8) ◽  
pp. 3157-3177 ◽  
Author(s):  
Sameer Noori Ali Al-Jawad ◽  
Muhammad Abd Ahmed ◽  
Afrah Hassan Saleh
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Rock Type ◽  
High Water ◽  
Quality Analysis ◽  
Reservoir Quality ◽  
High Porosity ◽  
Rock Types ◽  
Porosity And Permeability ◽  
Medium Porosity

Abstract The reservoir characterization and rock typing is a significant tool in performance and prediction of the reservoirs and understanding reservoir architecture, the present work is reservoir characterization and quality Analysis of Carbonate Rock-Types, Yamama carbonate reservoir within southern Iraq has been chosen. Yamama Formation has been affected by different digenesis processes, which impacted on the reservoir quality, where high positively affected were: dissolution and fractures have been improving porosity and permeability, and destructive affected were cementation and compaction, destroyed the porosity and permeability. Depositional reservoir rock types characterization has been identified depended on thin section analysis, where six main types of microfacies have been recognized were: packstone-grainstone, packstone, wackestone-packstone, wackestone, mudstone-wackestone, and mudstone. By using flow zone indicator, four groups have been defined within Yamama Formation, where the first type (FZI-1) represents the bad quality of the reservoir, the second type (FZI-2) is characterized by the intermediate quality of the reservoir, third type (FZI-3) is characterized by good reservoir quality, and the fourth type (FZI-4) is characterized by good reservoir quality. Six different rock types were identified by using cluster analysis technique, Rock type-1 represents the very good type and characterized by low water Saturation and high porosity, Rock type-2 represents the good rock type and characterized by low water saturation and medium–high porosity, Rock type-3 represents intermediate to good rock type and characterized by low-medium water saturation and medium porosity, Rock type-4 represents the intermediate rock type and characterized by medium water saturation and low–medium porosity, Rock type-5 represents intermediate to bad rock type and characterized by medium–high water saturation and medium–low porosity, and Rock type-6 represents bad rock type and characterized by high water saturation and low porosity. By using Lucia Rock class typing method, three types of rock type classes have been recognized, the first group is Grain-dominated Fabrics—grainstone, which represents a very good rock quality corresponds with (FZI-4) and classified as packstone-grainstone, the second group is Grain-dominated Fabrics—packstone, which corresponds with (FZI-3) and classified as packstone microfacies, the third group is Mud-dominated Fabrics—packstone, packstone, correspond with (FZI-1 and FZI-2) and classified as wackestone, mudstone-wackestone, and mudstone microfacies.

Redefining Reservoir Architecture of Hydrocarbon-Bearing Ngrayong Formation in Banyu Urip Area:New Insights to Unravel Hidden Potential in East Java Basin

2021 ◽  
Author(s):  
L. O Ahdyar
Keyword(s):  
Deep Water ◽  
Energy Demand ◽  
Carbonate Reservoir ◽  
Reservoir Quality ◽  
New Paradigm ◽  
Thin Sections ◽  
Carbonate Cement ◽  
Reservoir Architecture ◽  
Wide Range ◽  
Clastic Reservoir

Results of Banyu Urip (BU) carbonate exploration, appraisal and development drillings revealed the existence of hydrocarbon-contained in Serravallian deep-water clastic reservoir on top of the primary BU carbonate reservoir. This clastic reservoir is equivalent to the Ngrayong Formation in East Java Basin which is widely known as a mature exploration target and consists of a wide range of depositional environment from fluvio-deltaic (northern part of the Basin) to basin floor (southern part of the basin) with various reservoir quality. However, after a century of exploration activities in East Java Basin, commercial discoveries in the Ngrayong Formation are still considered insignificant (approximately 330 MMboe) (Mazied et al. 2016). This probably due to complex reservoir architecture posted high uncertainty of its reservoir presence, distribution, and quality as well challenging on their dynamic aspects such as un-known hydrocarbon connectivity, un-even contacts and low-deliverability. This paper will present new insights and the potential of Ngrayong clastic opportunity in BU area based on static and dynamic data including BU wells, newly reprocessed 3D seismic data, conventional core and thin sections, as well as integrated geologic and geophysical analyses. Integration of the available dataset suggest the presence of stacked deep water channels and deep water lobes systems. The distribution of stacked channels and lobes seem to be more predictive and widespread, hence providing a better understanding of its reservoir distribution. Furthermore, well data indicates approximately total of 100m net stacked clastic reservoirs consist of mixed carbonate-clastic materials, and have good reservoir pressure connectivity with the carbonate reservoir underneath. This mixed clastic-carbonate system in Ngrayong Formation is diagenetically-altered, and this diagenesis process plays as an important roles in modifying reservoir quality. Although carbonate cement and diagenetic overprint impose challenging reservoir quality prediction, a dissolution creates better reservoir quality, generates excess permeability and produces high flow reservoir. Detail study of reservoir architecture and diagenesis process are critical to better assess volumetric and development opportunity. These key components will open up new paradigm and essential for successful of Ngrayong Formation exploration in East Java Basin in order to contribute to the country’s energy demand.

Reservoir Quality and Flow Unit Characterization of a Reservoir in X Field, Baram Delta

2020 ◽  
Vol 17 (2) ◽  
pp. 1447-1459
Author(s):  
Najmuddin Abdul Rahim ◽  
Wan Ismail Wan Yusoff
Keyword(s):  
Fluid Flow ◽  
Depositional Environment ◽  
Flow Unit ◽  
Reservoir Quality ◽  
Facies Distribution ◽  
Flow Capacity ◽  
Porosity And Permeability ◽  
Core Descriptions ◽  
Reservoir Facies ◽  
Permeability Data

Reservoir stratigraphic continuity are uncertainties that may be due to lack of facies association definition in reservoirs. These uncertainties come into play where proper porosity–permeability (poroperm) evaluation is misrepresented, leading to volumetric estimation uncertainties. Most oil fields in the Baram Delta have been previously studied with the development of static models. The lack of sequence stratigraphic input in the study was due to constraints including fault shadowing and gas chimney presence which deterred the volume estimations. Earlier interpretation of facies distribution and depositional environment of a field, named X, was achieved mainly by using core descriptions and interpretations. In this study, a reinterpretation of the depositional environment and facies distribution were carried out in the R1 and R2 reservoirs. The analysis was done by incorporating the depositional environment and facies with newly interpreted facies comprising of sand, silty sand, sandy shale and shale facies, created using neural network programme. Utilising newly set facies definitions with additional inputs including porosity and permeability data, a better facies distribution for the reservoir is emplaced. With the facies definitions set for 3 wells, the reservoir quality was investigated through poroperm relationship, reservoir quality index (RQI) and fluid flow unit interpretation. The new definitions for reservoir facies consequently matched well to the core descriptions. The R1 reservoir facies-poroperm relationship were clustered well with respect to each facies type. The RQI was then evaluated from the permeability and porosity values for all the selected wells. The fluid flow units were estimated using depth interval difference, effective porosity and permeability data. The fluid flow regimes are different for all the wells, where the updip Well B displayed significantly better flow capacity than both Well C and Well A. However, Well C also displayed good fluid flow capability, indicated by high gradient flow capacity over storage capacity, although with presence of some layers of poor flow quality. Good communication for the downdip wells provides a potential for lateral fluid flow component which can influence the storage and flow capacity of fluid in the updip Well A, and thus creating an overall control and validation of fluid capacity in the reservoir.

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.

scholarly journals ONSHORE-OFFSHORE FACIES CHANGE OF NGRAYONG SANDSTONE IN MADURA AREAINDONESIA

2018 ◽  
Vol 8 (2) ◽  
pp. 1-15
Author(s):  
Sugeng Sapto Surjono ◽  
Mustafid Gunawan
Keyword(s):  
Late Miocene ◽  
Depositional Environment ◽  
Middle Miocene ◽  
Field Work ◽  
Carbonate Facies ◽  
North East ◽  
Facies Change ◽  
Well Correlation ◽  
Well Data ◽  
Clastic Reservoir

Ngrayong sandstone composes a siliciclastic reservoir that produces oil for more than a century in North East Java Basin of Indonesia. Clean sand facies makes the best reservoir in western part of the basin, onshore East Java Island. Meanwhile, sand quality decreases eastward to Madura Island. In Madura, rock gradually changes to be more calcareous and shaly, due to the change of depositional environment. In offshore of Madura, the depositional environment is still questionable. This study is aimed to reveal differences between onshore and offshore facies of Ngrayong sandstone in Madura as their distribution is not well known and oil potential of Madura Strait is not well identified. Study methods consisted of geological field work, well correlation, and petrophysical analysis from several well data. The results show that Ngrayong sandstone was deposited during Middle Miocene, composed by interbedding of thickly bedded sandstone and alternating thinly bedded sandstoneshale. The succession is commonly intercalated by mudstone and thinly bedded limestone. At Madura Island, Ngrayong sandstone overlies the Early-Middle Miocene Tawun Formation, which both represent the Megasequence (MS) 3 interval. Due to regional subsidence and transgression during Late Miocene, Ngrayong sandstone and other equivalent rocks were overlain by monotonous mudstone and calcareous sandstone of Wonocolo Formation. The Ngrayong sandstone is evenly distributed in whole surface area of Madura Island and it spreads further 25-50 Km to the south and 100-125 Km to eastern part of offshore Madura Strait. Sandstone distribution is roughly depleted from the gross thickness hundreds of meters in northern part to only few centimeters in southeast part of study area. The facies changes to be more calcareous to the east, while the southward facies is shaly due to a deeper depositional environment. Despite of facies changing into shales or carbonate facies, Ngrayong sandstone potential in offshore Madura Strait needs to be considered as upside potential due to its distribution is wider than initial estimation, and its petrology and petrophysic data support it as a clastic 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.

scholarly journals Small-Scale Diagenetic Heterogeneity Effects on Reservoir Quality of Deep Sandstones: A Case Study from the Lower Jurassic Ahe Formation, Eastern Kuqa Depression

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-25
Author(s):  
LiKuan Zhang ◽  
Xiaorong Luo ◽  
Mingze Ye ◽  
Baoshou Zhang ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Effective Properties ◽  
Lower Jurassic ◽  
Coarse Grained ◽  
Small Scale ◽  
Reservoir Quality ◽  
Thin Sections ◽  
Kuqa Depression ◽  
Porosity Evolution ◽  
Reservoir Rocks ◽  
Porosity And Permeability

The Lower Jurassic Ahe Formation is an important exploration target for deep clastic reservoirs in the eastern Kuqa Depression. The Ahe Formation sandstones show heterogeneous porosity and permeability petrophysical properties. These properties have been poorly understood, limiting forecast of petroleum accumulations and making it difficult to develop the reservoirs. Based on cores, thin sections, SEM, and fluid inclusions, this study examined sandstone composition and texture and diagenetic heterogeneity at the core scale. The aim was to understand the influence of variations in detrital composition and texture on diagenetic and reservoir quality evolution. The Ahe Formation sandstones are dominantly fine- to coarse-grained litharenites, with minor feldspathic litharenites. In fining-up sand beds, detrital grain size determines the degree of mechanical compaction and, consequently, the abundance of porosity through ductile grains and muddy matrix. Local complete calcite cementation is a noticeable exception to this general trend. Three sandstone petrofacies have been defined based on texture and framework composition, detrital matrix, diagenesis, and pore types: (1) ductile-lean sandstone, (2) ductile-rich sandstone, and (3) tightly calcite-cemented sandstone. Different petrofacies experienced contrasting diagenetic and porosity evolution pathways. Ductile-lean sandstones underwent lower degree of compaction relative to ductile-rich sandstones during the eodiagenesis stage, and extensive grain dissolution occurred. The petrofacies remained relatively porous and permeable before early oil arrival. With continued burial, the porosity and permeability in the sandstones were further reduced by cementation. The petrofacies still had moderate porosity and permeability and were substantially charged when late petroleum migrated into the reservoirs. Thus, ductile-lean sandstones constitute effective reservoir rocks in deep reservoirs. By translating petrofacies to signatures of well logs, the effective properties of the reservoir rocks can be forecasted at the well scale.

scholarly journals Improved imaging and analysis of chlorite in reservoirs and modern day analogues: new insights for reservoir quality and provenance

2018 ◽  
Vol 484 (1) ◽  
pp. 189-204 ◽  
Author(s):  
R. H. Worden ◽  
James E. P. Utley ◽  
Alan R. Butcher ◽  
J. Griffiths ◽  
L. J. Wooldridge ◽  
...  
Keyword(s):  
Electron Microscopy ◽  
Scanning Electron Microscopy ◽  
Analysis Data ◽  
Reservoir Quality ◽  
Phase Identification ◽  
Thin Sections ◽  
Analytical Technique ◽  
Quantitative Mineralogy ◽  
Digital Format ◽  
Scanning Electron

AbstractChlorite is a key mineral in the control of reservoir quality in many siliciclastic rocks. In deeply buried reservoirs, chlorite coats on sand grains prevent the growth of quartz cements and lead to anomalously good reservoir quality. By contrast, an excess of chlorite – for example, in clay-rich siltstone and sandstone – leads to blocked pore throats and very low permeability. Determining which compositional type is present, how it occurs spatially, and quantifying the many and varied habits of chlorite that are of commercial importance remains a challenge. With the advent of automated techniques based on scanning electron microscopy (SEM), it is possible to provide instant phase identification and mapping of entire thin sections of rock. The resulting quantitative mineralogy and rock fabric data can be compared with well logs and core analysis data. We present here a completely novel Quantitative Evaluation of Minerals by SCANning electron microscopy (QEMSCAN®) SEM–energy-dispersive spectrometry (EDS) methodology to differentiate, quantify and image 11 different compositional types of chlorite based on Fe : Mg ratios using thin sections of rocks and grain mounts of cuttings or loose sediment. No other analytical technique, or combination of techniques, is capable of easily quantifying and imaging different compositional types of chlorite. Here we present examples of chlorite from seven different geological settings analysed using QEMSCAN® SEM–EDS. By illustrating the reliability of identification under automated analysis, and the ability to capture realistic textures in a fully digital format, we can clearly visualize the various forms of chlorite. This new approach has led to the creation of a digital chlorite library, in which we have co-registered optical and SEM-based images, and validated the mineral identification with complimentary techniques such as X-ray diffraction. This new methodology will be of interest and use to all those concerned with the identification and formation of chlorite in sandstones and the effects that diagenetic chlorite growth may have had on reservoir quality. The same approach may be adopted for other minerals (e.g. carbonates) with major element compositional variability that may influence the porosity and permeability of sandstone reservoirs.

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