Utilization of Spectral Gamma Ray Logs to Ascertain Stratigraphic Surfaces in Carbonate Reservoir and Integration with Seismic Interpretation: An Integrated Case Study from Eocene-Oligocene Carbonate Reservoirs, D31 Cluster, Mumbai Offshore Basin, India

2021 ◽  
Author(s):  
Manabesh Chowdhury ◽  
Arun Babu Nalamara ◽  
VR Sunder ◽  
Pankaj Kumar ◽  
Pinakadhar Mohapatra ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Middle Eocene ◽  
Seismic Interpretation ◽  
Depositional Environments ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Commercial Development ◽  
Early Oligocene ◽  
Porosity Development

Abstract D31 cluster is located in the prolific Mumbai Offshore Basin, Western part of India. B-192Afield is part of this cluster, where Bassein (Middle Eocene),Mukta and Panvel (Early Oligocene)Formations are the main reservoirs. The reservoirs are complex in terms of reservoir heterogeneity. They were deposited in a shallow marine carbonate platform.Sea level fluctuations andchange in depositional environment impacted the porosity development. The main objective of this study was to integrate spectral gamma ray signatures with seismic interpretation for demarcating significant stratigraphic surfaces and differentiating depositional environments for robust reservoir characterization. Regionally, Bassein Formation (Middle Eocene) is characterized by thick foraminiferal and algal wackestone, packstone and occasional grainstone facies.The Mukta Formation (Early Oligocene),which unconformably overlies the Bassein Formation, is characterized by presence of fossiliferous limestone with shale intercalations. In the present study, data from four exploration wells data have been analyzed, where spectral gamma ray log patterns in carbonate reservoirs appear to have a distinctive relationship to depositional facies and stratigraphic surfaces in the Bassein and Mukta Formations. Different cross plots have also been utilized for analyzing the depositional conditions (i.e. oxic or anoxic).Later, the spectral log interpretations have been integrated with seismic interpretation. This study is part of a larger effort for reservoir characterization, as a basis for seismic interpretation and integrated reservoir modelling. The spectral gamma ray signatures demarcated significant stratigraphic surfaces. In BasseinFormation, three different units have been marked as Upper, Middle and Lower Bassein. The major lithological boundary between the Bassein and Mukta Formation is also well demarcated with spectral GR signature. The carbonate strata of Bassein & Mukta Formation have also been subdivided with U-Th-K abundance.The "Low Th-Low U" units indicative of pure carbonate and deposition in oxidizing environment whereas "Low Th-High U"is indicative ofreducing environment, which gave a relative sea level fluctuation in the area.The major stratigraphic boundaries identified from these spectral GR logs has been incorporated in the seismicinterpretation and used for regional seismic mapping.As porosity development is governed by thesea level fluctuations,this study also gave an indication of the possibility of porous zonein the reservoir section. These results can be useful as a basis for applying spectral GR signature as a tool for stratigraphic interpretation in un-cored heterogenous carbonate sections. Along with the petrophysical interpretation, integration of core analysis, biostratigraphy and seismic attribute are critical for detailed carbonate reservoir characterization incorporating depositional environment.This approach can be applied to support commercial development of the complex carbonate reservoirs.

Carbonate Reservoir Characterization with High-Resolution Logging-While-Drilling Dual-Images in Oil-Based Mud

2021 ◽  
Author(s):  
Shiduo Yang ◽  
Thilo M. Brill ◽  
Alexandre Abellan ◽  
Chandramani Shrivastava ◽  
Sudipan Shasmal
Keyword(s):  
High Resolution ◽  
Reservoir Characterization ◽  
Early Stage ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Secondary Porosity ◽  
Rock Typing ◽  
Logging While Drilling ◽  
Dual Images ◽  
Ultrasonic Images

Abstract Fracture evaluation and vuggy feature understanding are of prime importance in carbonate reservoirs. Commonly the related features are extracted from high resolution borehole images in water-based mud environments. To reduce the formation damage from drilling fluids, many wells are drilled with oil-based muds (OBM) in carbonate reservoirs. There are no appropriate measurements to resolve the reservoir characterization in OBM with the existing technologies in horizontal wells—especially in real-time—to make decisions at an early stage. In this paper, we would like to introduce a workflow for geological characterization using a new dual-images logging while drilling tool in oil-based mud. This new tool provides high resolution resistivity and ultrasonic images at the same time. Structural features, such as bedding boundaries, faults, fractures can be identified efficiently from resistivity images; while detailed sedimentary features, for example, cross beddings, vugs, stylolite are easily characterized using ultrasonic images. Benefiting from the dual images, an innovative workflow was proposed to estimate the vug feature more accurately; and the fractures can be identified from images and classified based on tool measurement principles. One case study from the Middle East demonstrated the benefits of this new measurement. A near well structure model was constructed from bed boundaries picked from borehole images. The fractures were picked and classified confidently using the dual images. Additionally, fracture density statistics are available along the well trajectory. The vug features were extracted efficiently, which indicates the secondary porosity development information. Rock typing is achieved by combining fracture and vug analysis to provide zonation for completion and production stimulation. The dual-images provide the capability for geological characterization in carbonate reservoir in an oil-based mud environment. The image-based rock typing helps segment the drain-hole for completion and production stimulation. The reservoir mapping with rock typing provides detailed information for in-filling well design.

scholarly journals Seismic expression of miocene carbonate platform and reservoir characterization through geophysical approach: application in central Luconia, offshore Malaysia

2021 ◽  
Vol 11 (4) ◽  
pp. 1533-1544
Author(s):  
Yasir Bashir ◽  
Muhammad Amir Faisal ◽  
Ajay Biswas ◽  
Amir abbas Babasafari ◽  
Syed Haroon Ali ◽  
...  
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Carbonate Platform ◽  
Petroleum Industry ◽  
Seismic Inversion ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Fluid Distribution ◽  
Central Luconia

AbstractA substantial proportion of proven oil and gas reserves of the world is contained in the carbonate reservoir. It is estimated that about 60% of the world’s oil and 40% of gas reserves are confined in carbonate reservoirs. Exploration and development of hydrocarbons in carbonate reservoirs are much more challenging due to poor seismic imaging and reservoir heterogeneity caused by diagenetic changes. Evaluation of carbonate reservoirs has been a high priority for researchers and geoscientists working in the petroleum industry mainly due to the challenges presented by these highly heterogeneous reservoir rocks. It is essential for geoscientists, petrophysicists, and engineers to work together from initial phases of exploration and delineation of the pool through mature stages of production, to extract as much information as possible to produce maximum hydrocarbons from the field for the commercial viability of the project. In the absence of the well-log data, the properties are inferred from the inversion of seismic data alone. In oil and gas exploration and production industries, seismic inversion is proven as a tool for tracing the subsurface reservoir facies and their fluid contents. In this paper, seismic inversion demonstrates the understanding of lithology and includes the full band of frequency in our initial model to incorporate the detailed study about the basin for prospect evaluation. 3D seismic data along with the geological & petrophysical information and electrologs acquired from drilled wells are used for interpretation and inversion of seismic data to understand the reservoir geometry and facies variation including the distribution of intervening tight layers within the Miocene carbonate reservoir in the study area of Central Luconia. The out-come of the seismic post-stack inversion technique shows a better subsurface lithofacies and fluid distribution for delineation and detailed study of the reservoir.

Reservoir Characterization of the Pennsylvanian (Desmoinesian) Lower Bartlesville Sandstone in Big Sandy and Clinesmith Fields, Southeast Kansas

2019 ◽  
Vol 56 (2) ◽  
pp. 185-226
Author(s):  
James P Rogers ◽  
Mark W Longman
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Total Porosity ◽  
Fine Sand ◽  
Depositional Environments ◽  
Width Ratio ◽  
Fluvial Systems ◽  
Rock Fragments ◽  
Coastal Marine ◽  
Estuarine Coastal

Big Sandy and Clinesmith oil fields are located about five miles apart along the boundary between Woodson and Wilson counties in southeast Kansas. They are located on the Pennsylvanian Cherokee Platform and were discovered almost 60 years apart in 1923 and 1982 respectively. Both fields produce from Desmoinesian lower Bartlesville sandstone reservoirs at shallow depths (1,100 to 1,200 ft) from reservoirs that have been interpreted as “shoestring sandstones.” However, if Big Sandy is restricted just to the area of Section 23 and the southeast quarter of Section 22, T26S, R14E where it offers the best wireline log control, the two fields have different orientations. Big Sandy has a southwest/northeast trend almost perpendicular to Clinesmith Field, which trends from north-northwest to southward. Big Sandy Field has a more elliptical shape with a length-to-width ratio of 3:1, vs. 10:1 for the very linear Clinesmith Field. Another major difference between the two fields is that the gamma-ray logs in and along the Clinesmith reservoir trend generally have a fairly well-defined fining-upward trend characteristic of a fluvial channel system. Big Sandy logs, in contrast, show much more variability from well to well. Petrographically the two fields have characteristics that are both consistent and strikingly different. Both reservoirs have a consistent very-fine to fine sand grain size with fair to well-sorted grains. Both also have texturally immature grains that are angular to subrounded with nearly identical compositions of abundant quartz, and associated plagioclase, biotite, muscovite, plant debris, and metamorphic rock fragments. Thus, the Bartlesville Sandstone in both fields had the same nearby sediment source terrain comprised mainly of granites and metamorphic rocks. Each field also produces mainly from primary interparticle porosity in sandstones with loosely packed grains where total porosity locally exceeds 20%. A difference is that, although both fields contain common shale clasts, those in Big Sandy Field tend to be much larger and occur with common siderite (iron carbonate) nodules. Siderite is rare in Clinesmith Field although a few small nodules occur in the associated floodplain shales, along with carbonaceous partings. Also present in Big Sandy’s reservoir are other iron-bearing minerals such as glauconite, pyrite, and chlorite, although all of these are far less common than the siderite. Such an abundance of iron-rich minerals can occur in marginal marine environments such as estuaries where a reducing diagenetic environment forms just below the sediment/water interface. In contrast, well-oxygenated fluvial systems generally contain any iron in highly oxidized forms such as hematite and limonite. From these observations, it appears that Big Sandy’s reservoir interval was deposited in an estuarine (coastal marine) setting with diverse localized depositional environments whereas the Clinesmith reservoir represents a nearly straight, south-flowing fluvial channel and adjacent floodplain, with no marine influence on deposition.

scholarly journals Hydrocarbon Reservoir Characterization of ‘Khume’ Field, Offshore Niger Delta, Nigeria

2021 ◽  
pp. 47-60
Author(s):  
K. A. Obakhume ◽  
O. M. Ekeng ◽  
C. Atuanya
Keyword(s):  
Niger Delta ◽  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Seismic Interpretation ◽  
Effective Porosity ◽  
Well Logs ◽  
Integrative Approach ◽  
Neutron Density ◽  
Hydrocarbon Reservoir

The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 19-26% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes

scholarly journals GEOPHYSICAL CHARACTERIZATION OF ALBIAN CARBONATES RESERVOIRS IN BRAZILIAN BASINS: THE SWEETNESS AS A TOOL FOR CARBONATE RESERVOIRS DEFINITION

2014 ◽  
Vol 32 (4) ◽  
pp. 695 ◽  
Author(s):  
Maria Gabriela Castillo Vincentelli ◽  
Sergio Antonio Caceres Contreras ◽  
Michelle Uchoa Chaves
Keyword(s):  
Seismic Interpretation ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Seismic Attribute ◽  
Espírito Santo ◽  
Short Period ◽  
Seismic Characterization ◽  
Attribute Extraction ◽  
Espirito Santo

ABSTRACT. The current research is based on volumetric seismic interpretation with the aim to visualize the main Albian carbonate reservoirs in shallow, deepand ultra-deep water of the continental Brazilian basins (Santos, Campos and Espírito Santo). It is expected that the method assists geoscientists in order to definecarbonate reservoirs with less geological uncertainty, when compared with the response obtained from the traditional seismic interpretation. The objective proposesa quickly, but confident, methodology to better define Albian carbonates using seismic attribute extraction. To achieve this goal, 25 seismic volumetric and surfaceattributes were analyzed; it was observed that it is possible to visualize the reservoir in most of them, mainly when the acoustic impedance (AI) is included on the analysis. For all the considered oil fields the sweetness attribute presented the best carbonate reservoir visualization and using sweetness any previous seismic interpretation isnecessary. In conclusion, the sweetness attribute allowed the interpretation of the Albian carbonates reservoirs in the Brazilian basins in a short period of time and withless geometrical uncertainty. Due to this fact, is possible to enforce that the method can be applied for seismic characterization of any geological feature that showschanges in its density in comparison with the surrounding stratigraphic layers.Keywords: volumetric interpretation, instantaneous frequency, instantaneous amplitude, envelope, limestone reservoirs.RESUMO. A presente pesquisa é baseada na interpretação sísmica volumétrica com o intuito de visualizar os principais reservatórios de hidrocarboneto do Albianoem águas rasas, profundas e ultraprofundas das bacias da margem continental brasileira (Santos, Campos e Espírito Santo). É esperado que o resultado auxiliegeocientistas na definição de reservatórios carbonáticos com menor incerteza geológica, quando comparado com a resposta obtida numa interpretação sísmica tradicional.O objetivo propõe um método rápido e confiável que melhor defina os reservatórios carbonáticos do Albiano por meio da extração de atributos sísmicos. Para alcançar esta meta, 25 atributos sísmicos volumétricos e de superfície foram analisados, na maioria deles é possível visualizar o reservatório, principalmente quando aimpedância acústica (AI) é incluída na análise. Para todos os campos de hidrocarboneto avaliados o atributo sweetness apresentou a melhor visualização do reservatório carbonático, sendo que para aplicar sweetness não é necessária uma interpretação sísmica prévia. Em conclusão, o sweetness permitiu a interpretação de reservatórios carbonáticos albianos nas bacias brasileiras em um curto período de tempo e com menor incerteza geométrica da distribuição do mesmo. Devido a isso, o método podeser aplicado para a caracterização sísmica de feições geológicas que apresentem mudanças em sua densidade em relação às camadas estratigráficas ao redor.Palavras-chave: interpretação volumétrica, frequência instantânea, amplitude instantânea, envelope, reservatórios carbonáticos.

scholarly journals Elastic Properties Modeling for Identification of Prospective Reservoir Zones in the Carbonate Reservoir, MRD Field in the North East Java Basin

2019 ◽  
Vol 17 (1) ◽  
pp. 21
Author(s):  
Mordekhai Mordekhai ◽  
Sonny Winardhi
Keyword(s):  
Elastic Properties ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Middle Eocene ◽  
Carbonate Reservoir ◽  
Primary Data ◽  
Pore Shape ◽  
Gas Field ◽  
North East ◽  
The North

“MRD” field is an oil and gas field which located in Rembang Zone. One of the hydrocarbon zones in this fieldlies in Ngimbang Formation. Reservoir in this field has a lifespan of Middle Eocene to Early Oligocene. Reservoir of this formation is carbonate rocks and dominated by calcite and dolomite minerals. One of the uniqueness of this kind of reservoir is the pore shape which quite complex. In this study, reservoir characterization which performed on this field is based on elastic properties modelling. Elastic Properties modelling which was conducted in this field can provide an output of the pore shape, aspect ratio, and the fraction of each respective poresforms that exist in this field’s reservoir zone. Therefore the primary data such as petrophysical data, XRD (X-Ray Diffraction), and the data of other reservoir parameters are needed for more accurate resultsobtained with real conditions. The result of this modelling shows that the shape of the pores in the reservoir zone at any depth can be predicted. Distribution of pore shapes that exist in the two wells can be used as a reference for prospective determination of hydrocarbon zones in “MRD” field.  

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