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Moharana, Abhishek (Schlumberger) | Mahapatra, Mahabir Prasad (Schlumberger) | Chakraborty, Subrata (Schlumberger) | Biswal, Debakanta (Adani Welspun Exploration Limited) | Havelia, Khushboo (Schlumberger)
Petroleum Geologists typically study hydrocarbon bearing reservoirs, understand the geology, and build numerical models to help better produce hydrocarbon. On the other hand, conventional sedimentologists try to simulate the natural process of sedimentation in laboratory through miniature sand box models to better understand such processes. But a proper integration of the laboratory-based techniques in developing subsurface reservoirs models was always lacking in the industry.
Petroleum geologists developed computer based geostatistical techniques based quantitative statistics like variograms, histograms to develop stochastic models of reservoirs which could be used to put a number and range on the geological uncertainty. However, geostatistics deals more with regularly sampled data, describing their spatial variability and directionality. In development oil fields with many wells sampling the reservoir, geostatistics helps us to create a more predictive subsurface reservoir model. However, in the exploratory state of a field with few drilled wells, the data for geostatistical analysis reduces and a robust conceptual geological is needed to build a predictive subsurface geological model where a proper integration of sedimentology and petroleum geology is required.
Different approaches like conceptual block diagrams of depositional models, average sand distribution maps, training images from present day analogs were tried. However, these were less than optimal, deterministic with a long turnaround time for any robust subsurface reservoir model.
A relatively recent addition to the geologist's set of quantitative tools has been Geologic Process Modeling (GPM), also known as Forward Stratigraphic Modeling (FSM) technique. This technique aims to digitally model the natural processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution based on quantitative deterministic physical principles (
Eni started production from the Perla giant gas field located in the Gulf of Venezuela, 50 km offshore. Consisting of Mio-Oligocene carbonates with excellent characteristics, the reservoir is approximately 3000 m below sea level and lies at a water depth of 60 m. The best wells are estimated to produce more than 150 MMscf/D of gas each. The development plan includes 21 producing wells and four light offshore platforms linked by a 30-in. Two treatment trains have been installed at the facility, each capable of handling 150 Mscf/D and 300 Mscf/D of natural gas.
This case study describes the successful outcomes and learnings from a brownfield tie-back project in offshore Trinidad. The greater Angostura Asset consists of multiple Oligocene-age turbidite sandstone reservoirs with complex geology and compartmentalization. The Asset has produced oil since 2005 from thin oil rims overlaid by large gas caps. This has been supported by significant gas reinjection and constrained by gas coning. Commencement of gas sales added value but also increased gas cap blowdown in the oilfields. The Angostura Phase 3 project was conceptualized to enable gas production from an adjacent gas discovery and extend the overall productive life of the existing oil fields.
Key subsurface uncertainties and operational constraints were identified early in the project. Historically, drilling in the Angostura field has been challenging due to the complex geology and compartmentalization. Poor seismic data in the Phase 3 area added complexity to optimal well placement. Ensuring high deliverability was another critical project requirement. The main reservoir management challenge in the existing fields was optimizing both oil and gas sales while managing voidage and coning. Limited topside facilities and space constrained addition of new gas at flowing at higher pressures.
To address these challenges, a multi-disciplinary project team was formed to plan and execute the project. Material balance, detailed geological modeling and numerical simulation were used to understand the impact of key uncertainties on recovery. The integrated evaluation resulted in an optimized development plan with three subsea gas wells tied back to existing facilities. Production performance of existing wells helped highlight critical performance drivers for Phase 3 wells. Modified completion designs along with a flow back and stimulation program during completion helped to maximize productivity.
Phase 3 wells have performed at the high levels expected during project design and sanction. Detailed surveillance (including pressure transient analysis (PTA) and interference testing during completion, start-up and production phases) has continuously helped to optimize production. Oil production in the existing fields has also been improved by better balancing gas sales and injection. The project added significant value from the increased gas sales and oil production.
This paper discusses the planning, successful execution and impact on the overall value of the Angostura Asset from the Phase 3 project. Optimized completions along with an improved approach for evaluating stimulation options during completion (detailed near well-bore modelling, real-time PTA and simulation) enabled strong well performance. We highlight some of the critical factors for achieving success in brownfield tie-back projects including having (right from project inception): multi-disciplinary project teams, tight coordination with existing operations and a focus on key uncertainties and constraints. Building optionality and flexibility into development plans and being prepared for contingencies have been the other critical learnings from this project
Wang, Wenguang (School of Geosciences, China University of Petroleum) | Lin, Chengyan (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Lin, Jianli (School of Geosciences, China University of Petroleum) | Zhang, Xianguo (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Dong, Chunmei (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Ren, Lihua (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum)
The purpose of this paper is to use 3D compaction numerical simulation method to study the sandstone porosity evolution and high-value porosity area in the few well areas of offshore oilfields. These sandstones are located in the central inversion structural belt of the Xihu sag, East China Sea Basin. Based on geological data, seismic data, log data, thin section, scanning electron microscopy, cathode luminescence, bulk X-ray diffraction analysis, powder particle size analysis and routine core analysis, this study used compaction numerical simulation method to reconstruct the porosity evolution of different grain size sandstones in the fourth (H4) and fifth (H5) members of the Oligocene E3h Formation in the study area. Three aspects of research were carried out, including the distribution model of 3D grain size sandstones, mechanical compaction and chemical compaction parameters, 3D porosity evolution and high-value porosity areas. It was determined that there was no correlation between the porosity compaction loss and quartz cement content in different grain size sandstones in the H4 and H5 members, indicating that chemical compaction did not inhibit mechanical compaction. The mechanical compaction and chemical compaction were simulated separately. Different grain sizes sandstones had different mechanical compaction and chemical compaction porosity reductions. The porosity reductions of medium sandstone, sandy conglomerate and fine sandstone by mechanical compaction were 25.3%, 21.81% and 25.97%, and those by chemical compaction were 0.82%, 1.08% and 0.42%, respectively. The sandstone compaction stages of the H4 and H5 members under different tectonic stages were investigated. In the first phase of the slow subsidence stage, the reservoir temperature of the H4 and H5 members were less than 70°C, and these sandstones were in the stage of mechanical compaction. In the second phase of the slow subsidence stage, the reservoir temperature range of the H4 and H5 members were 70°C–114.63°C and 70°C–120.47°C, respectively; these sandstones entered the coexistence stage of mechanical compaction and chemical compaction. From the rapid subsidence stage to regional steady subsidence stage, the reservoirs temperature ranges of the H4 and H5 members were 114.63°C–159.7°C and 120.47°C–167.05°C, respectively; these sandstones were in the stage of chemical compaction dominated- mechanical compaction supplemented. Finally, the differences of sandstone compaction and porosity between the H4b-6 and H5-6 submembers and in the same layers were analyzed. By integrating sedimentary lithologies, porosity evolution, and reservoir "sweet spot" evaluation criteria, the spatial distribution of favorable areas in the H4b-6 and H5-6 submembers were determined. This study is of theoretical significance to elucidate the compaction characteristics, porosity evolution and high-value porosity area distribution in deep and ultra-deep clastic rocks, and also has reference value for the optimization of the tight sandstone favorable areas.
Recently many engineering objects have been built on Devolli valley. These objects include hydropower plants such as Banja HPP, Moglica HPP, Grabova HPP, new roads such as the main road from Banja-Gramshi-Moglica up to Maliq in Korça county. All these engineering objects have required detailed geological and geotechnical studies.
The rock formations, which give shape to the slopes of the canyon, are very weathered. During the construction phases different kind of geological phenomena were faced, which threatened the overall stability such as: rolling rock masses, superficial sliding, detaching of rock blocks etc…
In this paper, we would like to present our investigation study with the intention of characterizing the rock mass, which manifested problems regarding the stability and ensuring its safety. We aim to localize the different kind of instabilities and in conformity with them, give the recommendations regarding the necessary engineering protection measures. Also, we would like to present our arguments why these protective engineering measures are necessary and why are they vary in function of the kind of instability of the rock mass encountered in a few road's kilometres.
Devoll River valley, from Banja up to Maliq, is of different geomorphology and it changes its latitude according to the geological composition. It is wider when flysch (mudstone & sandstone) rocks are present and very narrow where encountered strong limestone and ultrabasic rocks.
During the years in this valley have developed negative physical and geological phenomena such as: a) weathering; b) erosion; c) sliding and d) tectonic movements.
All these geological phenomena have created difficulties for slopes stabilization and altered the quality of the rocks in the area. A.L.T.E.A & Geostudio 2000, (2009-2019)
At Devolli valley there are present rocks of different types and ages: a) quaternary deposits, b) Oligocene's, c) limestone deposits, d) ultrabasic rock.
In this paper we will describe the kind of rocks associated with their characteristics derived from laboratory tests performed for each type of soil and rock deposits. A.L.T.E.A & Geostudio 2000, (2009-2019).
Bhardwaj, Sourav (OIL India Ltd.) | Baruah, Neelimoy (OIL India Ltd.) | Sharma, Dr. Manas Kumar (OIL India Ltd.) | Kumar, Rajeev Ranjan (Schlumberger)
High angle S-shaped and high displacement L-shaped well profiles are preferred now-a-days in Balimara field located in the northeast region of India. Main targets are the deep Clastic reservoirs of Oligocene age. Major events reported are while drilling against dipping formations with differential stuck pipe situations with variety of drilling complications in the unstable formations owing to shales in Tipam sandstone and thin sections of coal and shale alteration in oil bearing Barail sandstone formation. The substantial risk of wellbore instability in accessing the reservoirs with lateral variation in pore pressure threatened the commercial success of the project. This paper elaborates how geomechanical information along with BHA design and chemicals was integrated into the decision-making process during well design and drilling operations to avoid wellbore instability issues.
Wellbore stability analysis through Mechanical Earth Model was conducted using estimated state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from several sources including geophysical logs, leak-off tests, advanced sonic far field profile and drilling records collected from the earlier wells. Examination of the deviated well bore profiles suggested occurrence of ledges due to lower mud weight and improper drilling parameters while drilling alternate layers of sand, shale and coal in Barail formation. Horizontal stress contrast increases in Barail formation supporting the need of higher mud weight with increased well deviation towards specific azimuth.
The integrated geomechanical analysis provided key information: The 9 5/8" casing shoe should be set at shale layer of Tipam Bottom to isolate upper differential sticking prone sandstone layers with Barail Argillaceous sequence. This will help to drill 12.25-inch hole with 9.6 ppg-9.8 ppg only. Shale layers at Tipam bottom require 10.0-10.5 ppg, while Barail shale requires 10.5 ppg-11.0 ppg for vertical well. When the well deviation increases up to 30deg, mud weight requirement rises to 11.2 ppg-11.8 ppg. Based on analysis, the mud weight at the start of 8.5inch section was raised sufficiently to 10.5 ppg to avoid the hole collapse experienced in the earlier lower angle wells. Later, continuous review of torque and drag along with cutting analysis helped to raise mud weight up to 11.0 ppg till well TD. As a result, lower UCS shale and coal layers are drilled with minimal shear failure and improved hole condition. However, changes to the mud system were needed to limit fluid loss and avoid differential sticking across the sandstone. For deviated section, rotary BHA has been used to improve hole trajectory vs. planned with lesser ledges. Downhole hydraulics has been maintained with proper flow rate and rpm to main hole cleaning. The new well engineered with the integrated geomechanics information has been drilled from surface to extended TD while saving 15 rig days.
The PDF file of this paper is in Russian.
Most of small oil fields in the South of Russia have complex unconventional fractured clay reservoirs in geological section. To justify the effectiveness of prospecting and exploration, it is necessary to characterize the petrophysical model of the reservoir properties in the productive Khadum-Batalpashinsk deposits. During certain processes, clay Oligocene rocks acquire effective porosity, become reservoirs with necessary filtration-capacitive properties, and are one of the reserves for expanding the mineral resource base. The study found that the thin pores of the matrix and the thin inter-plate and inter-sheet voids are filled with film, capillary and free water disconnected and immobile. Oil content in clays is in the form of films and lenses along lithogenetic cracks that develop along the planes of bedding of clays of various compositions. Oil mobility is provided by cracks with increased openness. The results of study of the paleogeographic conditions of sedimentation show that the productive stratum consists of two clay reservoir rocks different in reservoir properties. There is a tendency to form first, primarily, clay strata in the Khadum and then the Batalpashinsk strata with improved reservoir properties. A study of the lithological characteristics of Lower Maikop sediments allowed to conclude that there is a wide siderite formation of rocks, including clay, previously rated as ‘non-carbonate’. It was revealed that if the contrast of petrophysical parameters can serve as a criterion for the oil content of a section in a particular well, then the uniformity of the rocks composing it can serve as a criterion for determining the productivity of a particular interval. This feature confirms the fact of the influence of secondary physical and chemical processes, under the influence of which the leveling of the petrophysical parameters of the rocks occurs in accordance with the new thermodynamic conditions. The considered complex of geological, geophysical, and laboratory methods of searching for oil in clay deposits enables to increase the efficiency of exploration.
Большинство мелких нефтяных месторождений юга России имеет в геологическом разрезе сложные нетрадиционные трещиноватые глинистые коллекторы. Для обоснования эффективности поисково-разведочных работ рассмотрена петрофизическая модель фильтрационно-емкостных свойств (ФЕС) природного резервуара в продуктивных хадумско-баталпашинских отложениях. Глинистые породы олигоцена при определенных процессах приобретают эффективную пористость, становятся коллекторами с наличием необходимых фильтрационно-емкостных свойств и являются одним из резервов увеличенияминерально-сырьевой базы. Установлено, что тонкие поры матрицы, межплитчатые и межлистоватые пустоты заполнены пленочной, капиллярной и свободной водой, которая неподвижна. Нефть в глинах содержится в виде пленок и линз вдоль литогенетических трещин, которые развиваются по плоскостям напластования глин различного состава. Мобильность нефти обеспечивается трещинами с повышенной раскрытостью. Результаты изучения палеогеографических условий осадконакопления показывают, что продуктивная толща состоит из двух различных по ФЕС глинистых пород-коллекторов. Наблюдается тенденция формирования сначала преимущественно глинистой хадумской толщи, затем баталпашинской с улучшенными ФЕС. Изучение литологических характеристик нижнемайкопских отложений позволило сделать вывод о широкой сидеритизации пород, в том числе глинистых, ранее оцененных как «некарбонатные». Выявлено, что если контрастность петрофизических параметров может служить критерием нефтеносности разреза в конкретной скважине, то критерием продуктивности отдельного интервала может служить однородность слагающих его пород. Эта особенность подтверждает влияние вторичных физико-химических процессов на выравнивание петрофизических параметров пород в соответствии с новыми термодинамическими условиями. Рассмотренный комплекс геолого-геофизических и лабораторных методов поисков залежей нефти в глинистых отложениях позволит повысить эффективность поисково-разведочных работ.
Moharana, Abhishek (Schlumberger) | Mahapatra, Mahabir Prasad (Schlumberger) | Chakraborty, Subrata (Schlumberger) | Biswal, Debakanta (Adani Welspun Exploration Limited) | Havelia, Khushboo (Schlumberger)
Petroleum Geologists typically study hydrocarbon bearing reservoirs, understand the geology, and build numerical models to help better produce hydrocarbon. On the other hand, conventional sedimentologists try to simulate the natural process of sedimentation in laboratory through miniature sand box models to better understand such processes. But a proper integration of the laboratory-based techniques in developing subsurface reservoirs models was always lacking in the industry.
Petroleum geologists developed computer based geostatistical techniques based quantitative statistics like variograms, histograms to develop stochastic models of reservoirs which could be used to put a number and range on the geological uncertainty. However, geostatistics deals more with regularly sampled data, describing their spatial variability and directionality. In development oil fields with many wells sampling the reservoir, geostatistics helps us to create a more predictive subsurface reservoir model. However, in the exploratory state of a field with few drilled wells, the data for geostatistical analysis reduces and a robust conceptual geological is needed to build a predictive subsurface geological model where a proper integration of sedimentology and petroleum geology is required.
Different approaches like conceptual block diagrams of depositional models, average sand distribution maps, training images from present day analogs were tried. However, these were less than optimal, deterministic with a long turnaround time for any robust subsurface reservoir model.
A relatively recent addition to the geologist's set of quantitative tools has been Geologic Process Modeling (GPM), also known as Forward Stratigraphic Modeling (FSM) technique. This technique aims to digitally model the natural processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution based on quantitative deterministic physical principles (
In the current study a 3D reservoir model for a field in Western Offshore India was built based on the results of Geological Process Model (GPM) for the thin deltaic reservoir sands as understanding reservoir continuity from seismic data was not possible. With only 4 wells available in the field, traditional geostatistics based reservoir models were inadequate in explaining the reservoir distribution. GPM based techniques helped not only in mapping the reservoir continuity but also opened up new areas for exploration in the area.
Meda, Marco (ENI) | Martinelli, Mattia (Università degli Studi diMilano - Bicocca) | Bistacchi, Andrea (Università degli Studi diMilano - Bicocca) | Mittempergher, Silvia (Università degli Studi diMilano - Bicocca) | Berio, Luigi (Università degli Studi di Parma) | Balsamo, Fabrizio (Università degli Studi di Parma) | Succo, Andrea (Università degli Studi di Parma) | Storti, Fabrizio (Università degli Studi di Parma)
To select the "best outcrop analogue" of a subsurface field/prospect is always challenging, especially when dealing with fractured carbonatic reservoirs. The candidate should match the mechanical stratigraphy, the depositional conditions, the diagenetic history, the tectonic evolution. This is almost impossible, considering that at least the exhumation phase and the associated diagenetic features will not be shared between the outcropping analogue and the buried reservoir. Nevertheless, the analysis of natural analogues can provide useful indications particularly in a complex matter as fracture distribution; in fact, large-scale outcrop analogues reveal their potential when trying to fill the gap between seismic- and borehole-scale structural characterization.
In order to start building an "Atlas of Fracturing Facies" as a digital interactive catalogue of natural fractured analogues, three main cases have been studied: Pag (Croatia) and Parmelan (France) anticlines as analogues for folded and faulted platform carbonates affected by pre-folding extensional faulting, and the Gozo Island (Maltese Archipelago) as an example of carbonatic sequences affected by extensional tectonics. An integrated multiscale approach has been applied, from thin sections to outcrop scale analysis, from drone-based surveys to satellite image interpretation. This workflow leads to the reconstruction of 3D models, and to the quantification of the main parameters characterizing the fracture pattern and its variability.
The Island of Pag, External Dinarides of Croatia, is a thrust-related anticline that involves Upper Cretaceous to Eocene shallow-water carbonate platform sequences affected by tight folding during Eocene – Oligocene times. The fold evolution is multiphase, expressed by pre-folding features developed during a layer-parallel shortening with a strong influence of structural inheritance, followed by fold- and thrust-related cataclastic flow in hinge zones.
The Parmelan Anticline, in the Bornes Massif, Western Alps, is a box-fold involving Lower Cretaceous massive platform carbonates. It is characterized by steeply-dipping limbs, separated by a wide crestal plateau, delimited by narrow hinge zones localized on inherited extensional faults. Its polyphasic tectonic history has been reconstructed by analyzing the fracture and vein pattern, which highlighted the strong influence of structural inheritance during folding.
The Gozo Island is a Late Oligocene-Late miocene carbonatic sequence, composed by platform carbonates with different facies, affected by two extensional events associated to a mult-sets fracture pattern. In Gozo, spectacular coastal outcrops allowed analyzing the structural and statistical relationships between fractures and faults, in terms of density, length, orientation, spatial distribution patterns, and topology.
The Pag, Parmelan and Gozo case studies, together with several literature case studies, are the starting point of the implementation of an Atlas of Fracturing Facies, providing a multidisciplinary knowledge management and data repository platform to improve the prediction of fracture patterns in the subsurface, and its impact on porosity and permeability in reservoirs.