Better Understanding on Diagenetic Processes in the Low Productivity Reservoirs: An Opener Approach for Further Tambora G Zone Development Strategy

2020 ◽  
Author(s):  
D., K. Said
Keyword(s):  
Development Strategy ◽  
Depositional Environment ◽  
Burial Depth ◽  
Well Placement ◽  
Reservoir Characteristics ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Zone Development ◽  
Diagenetic Minerals ◽  
Iron Bearing

Tambora Field reservoir zone is sub-divided into D, E, F and G. Of the four zonation, Tambora G Zone has the lowest recovery factor. Based on this, the current study was intended to have better understanding of the diagenetic processes in low productivity reservoirs and its development strategy in that zone. Reduction of porosity and permeability due to different diagenetic intensity and causes are possible reasons for this condition. A new-improved petrology study was performed to understand the effects of diagenesis and the contribution of clay minerals which has led to worsening reservoir characteristics. In order to achieve better understanding of reservoir characteristics, integrated petrology analysis of petrography, XRD, SEM and CEC were performed. The results of detailed lithofacies analyses show that low productivity related to poor porosity and permeability is primarily caused by mechanical compaction and are worsened by chemical diagenesis related to isolated pore spaces, unconnected pore throats and depositional environment. Those affects the increase of diagenetic quartz-overgrowths, ferroan/iron-bearing and calcareous minerals. The occurrence of these minerals act as a pore-filling cement and are more developed in clean rather than shaly Sandstones. The most dominant diagenetic clay mineral in all lithofacies is recorded as kaolinite, followed by illite, chlorite and illite-smectite with this trend varying relative to depth and lithofacies. The effect of these factors is more intense when burial depth increases, and the depositional environment is increasingly distal as in the G Zone’s northeast area. Referring to this, and in order to minimize the risks of diagenetic minerals causing low productivity, the well placement strategy is addressed to the south and northwest compared to the northeast area. The proven result of applying this approach is the success story of drilling the TM-132 northwest well in 2019 that reached an initial gas rate production of around 3 MMscfd.

scholarly journals REE and Sr–Nd Isotope Characteristics of Cambrian–Ordovician Carbonate in Taebaek and Jeongseon Area, Korea

Minerals ◽  
2021 ◽  
Vol 11 (3) ◽  
pp. 326
Author(s):  
Tae-Hyeon Kim ◽  
Seung-Gu Lee ◽  
Jae-Young Yu
Keyword(s):  
Depositional Environment ◽  
Sea Water ◽  
Geological Time ◽  
Nd Isotope ◽  
Diagenetic Processes ◽  
Platform Margin ◽  
Carbonate Formations ◽  
Diagenetic History ◽  
Cretaceous Period ◽  
Ree Patterns

Carbonate formations of the Cambro-Ordovician Period occur in the Taebaek and Jeongseon areas, located in the central–eastern part of the Korean Peninsula. This study analyzed the rare earth element (REE) contents and Sr–Nd isotope ratios in these carbonates to elucidate their depositional environment and diagenetic history. The CI chondrite-normalized REE patterns of the carbonates showed negative Eu anomalies (EuN/(SmN × GdN)1/2 = 0.50 to 0.81), but no Ce anomaly (Ce/Ce* = CeN/(LaN2 × NdN)1/3 = 1.01 ± 0.06). The plot of log (Ce/Ce*) against sea water depth indicates that the carbonates were deposited in a shallow-marine environment such as a platform margin. The 87Sr/86Sr ratios in both Taebaek and Jeongseon carbonates were higher than those in the seawater at the corresponding geological time. The 87Sr/86Sr ratios and the values of (La/Yb)N and (La/Sm)N suggest that the carbonates in the areas experienced diagenetic processes several times. Their 143Nd/144Nd ratios varied from 0.511841 to 0.511980. The low εNd values and high 87Sr/86Sr ratios in the carbonates may have resulted from the interaction with the hydrothermal fluid derived from the intrusive granite during the Cretaceous Period.

scholarly journals Spatial variation in porosity and permeability of the Rupel Clay Member in the Netherlands

2016 ◽  
Vol 95 (3) ◽  
pp. 253-268 ◽  
Author(s):  
Hanneke Verweij ◽  
Geert-Jan Vis ◽  
Elke Imberechts
Keyword(s):  
The Netherlands ◽  
Spatial Variation ◽  
Clay Content ◽  
Burial Depth ◽  
Southeastern Part ◽  
Boom Clay ◽  
The North ◽  
Sealing Capacity ◽  
Porosity And Permeability ◽  
Permeability Data

AbstractThe spatial distribution of porosity and permeability of the Rupel Clay Member is of key importance to evaluate the spatial variation of its sealing capacity and groundwater flow condition. There are only a limited number of measured porosity and permeability data of the Rupel Clay Member in the onshore Netherlands and these data are restricted to shallow depths in the order of tens of metres below surface. Grain sizes measured by laser diffraction and SediGraph® in samples of the Rupel Clay Member taken from boreholes spread across the country were used to generate new porosity and permeability data for the Rupel Clay Member located at greater burial depth. Effective stress and clay content are important parameters in the applied grain-size based calculations of porosity and permeability.The calculation method was first tested on measured data of the Belgian Boom Clay. The test results showed good agreement between calculated permeability and measured hydraulic conductivity for depths exceeding 200m.The spatial variation in lithology, heterogeneity and also burial depth of the Rupel Clay Member in the Netherlands are apparent in the variation of the calculated permeability. The samples from the north of the country consist almost entirely of muds and as a consequence show little lithology-related variation in permeability. The vertical variation in permeability in the more heterogeneous Rupel Clay Member in the southern and east-southeastern part of the country can reach several orders of magnitude due to increased permeability of the coarser-grained layers.

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 GEOCHEMISTRY AND MICROFACIES OF THE RUTEH FORMATION IN THE RUTEH AREA, CENTRAL ALBORZ, IRAN

2019 ◽  
Vol 16 (32) ◽  
pp. 930-944
Author(s):  
G. BABAEE KHOU ◽  
M. H. ADABI ◽  
D. JAHANI ◽  
S. H. VAZIRI
Keyword(s):  
Depositional Environment ◽  
Facies Analysis ◽  
Minor Element ◽  
Upper Permian ◽  
Diagenetic Processes ◽  
Geochemical Study ◽  
Alborz Region ◽  
Dolomite Cement ◽  
East West

To understand microfacies, depositional environment and geochemistry of Upper Permian rocks in Alborz region, the type sections of Ruteh Formation were studied. During the Permian, the Alborz region was a part of the east-west trending Paleotethys sea. Stratigraphic studies indicate that the Ruteh Formation in Ruteh section is composed of thin to massive limestone, argillaceous limestone interbedded with shale, is overlain by distinct laterite horizon of the Elika Formation and is underlain by the disconformity by the Dorud Formation. Facies analysis and petrographic studies led to the recognition of 11 microfacies in Ruteh section. These facies were deposited in 4 facies belts such as tidal flat, lagoon, shoal and open marine sub-environment. The Permian calcareous algae in the Ruteh Formation are widespread and well documented to determine the environment and microfacies of Permian deposits. Cementation and dolomitization are the main diagenetic processes in Ruteh Formation. Based on petrographic (size and fabric) studies, 4 dolomite types such as dolomicrite, dolomicrospar, dolospar, and dolomite cement were recognized. Seawater was the main source of Mg for early diagenetic dolomite (type 1), while Mg for late diagenetic dolomite (types 2,3,4) probably were sourced by shale pressing processes and pressure solution. Major and minor element studies led to there cognition of aragonite mineralogy. The geochemical study illustrates that these carbonates were affected mostly by meteoric diagenesis, which is occurred in a semi-close to open diagenetic system.

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 Key controls on the hydraulic properties of fault rocks in carbonates

2020 ◽  
pp. petgeo2020-034
Author(s):  
E. A. H. Michie ◽  
A. P. Cooke ◽  
I. Kaminskaite ◽  
J. C. Stead ◽  
G. E. Plenderleith ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
Rock Properties ◽  
Burial Depth ◽  
Extrinsic Factors ◽  
Fault Rock ◽  
Fault Rocks ◽  
Content Type ◽  
Intrinsic Factors ◽  
Hydraulic Behaviour ◽  
Porosity And Permeability

A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from seven countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c. 400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, and maximum burial depth, as well as the depth at the time of faulting. The results indicate which factors may have had the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes.Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

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