Peciko Geological Modeling: Optimizing Fluid Distribution & Model Resolution of a Giant Gas Field in a Shale Dominated Deltaic Environment

2005 ◽  
Author(s):  
Philippe Marc Samson ◽  
Tantri Dewi-Rochette ◽  
Maurice Lescoeur
Keyword(s):  
Distribution Model ◽  
Fluid Distribution ◽  
Geological Modeling ◽  
Model Resolution ◽  
Gas Field

Experimental Study on the Saturation Model of Volcanic Rock Based on Fluid Distribution

2021 ◽  
Vol 62 (4) ◽  
pp. 422-433
Author(s):  
Baozhi Pan ◽  
◽  
Weiyi Zhou ◽  
Yuhang Guo ◽  
Zhaowei Si ◽  
...  
Keyword(s):  
Volcanic Rock ◽  
Oil And Gas ◽  
Water Saturation ◽  
Early Stage ◽  
Evaluation Model ◽  
Acoustic Velocity ◽  
Distribution Model ◽  
Fluid Distribution ◽  
Water Drainage ◽  
Gas Reservoirs

A saturation evaluation model suitable for Nanpu volcanic rock formation is established based on the experiment of acoustic velocity changing with saturation during the water drainage process of volcanic rock in the Nanpu area. The experimental data show that in the early stage of water drainage, the fluid distribution in the pores of rock samples satisfies the patchy formula. With the decrease of the sample saturation, the fluid distribution in the pores is more similar to the uniform fluid distribution model. In this paper, combined with the Gassmann-Brie and patchy formula, the calculation equation of Gassmann-Brie-Patchy (G-B-P) saturation is established, and the effect of contact softening is considered. The model can be used to calculate water saturation based on acoustic velocity, which provides a new idea for the quantitative evaluation of volcanic oil and gas reservoirs using seismic and acoustic logging data.

Pore-scale fluid distributions determined by nuclear magnetic resonance spectra of partially saturated sandstones

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. MR107-MR114 ◽  
Author(s):  
Chunhui Fang ◽  
Baozhi Pan ◽  
Yanghua Wang ◽  
Ying Rao ◽  
Yuhang Guo ◽  
...  
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Water Saturation ◽  
Acoustic Property ◽  
P Wave ◽  
Distribution Model ◽  
Fluid Distribution ◽  
Pore Scale ◽  
Saturation Model ◽  
Partially Saturated ◽  
P Wave Velocity

The acoustic property and the P-wave velocity of partially saturated rocks depend not only on the water saturation but also on the pore-scale fluid distribution. Here, we analyzed the pore-scale fluid distribution using nuclear magnetic resonance (NMR) [Formula: see text] spectra, which present the variation of porosity components associated with NMR transverse relaxation time [Formula: see text]. Based on the [Formula: see text] spectra, we classified the pore-scale fluid distribution during water imbibition and drainage into three models: a low-saturation model, a patchy distribution model, and a uniform distribution model. We specifically assigned the low-saturation model to deal with the acoustic property of the rocks at the imbibition starting stage and the drainage final stage because cement softening has a nonnegligible effect. We studied the acoustic properties of sandstone rocks with various pore-scale fluid distributions, at the imbibition process and the drainage process. We confirmed that, once the variations in water saturation and pore-scale fluid distribution are taken into account, the P-wave velocity prediction matches well with the laboratory measurement of samples, representing nearly tight sandstone rocks that are partially saturated with distilled water.

Application of Geological Modeling Technique Based on Seismic Frequency Division Processing and Fluids Substitution Forward Modeling in Lithologic Gas Reservoir Risk Assessment

2021 ◽  
Author(s):  
Zongbin Liu ◽  
Zuobin Lv ◽  
Jiatao Wen ◽  
Hao Yan ◽  
Zhicheng Yang
Keyword(s):  
Forward Modeling ◽  
Modeling Method ◽  
Geological Model ◽  
Geological Modeling ◽  
Frequency Division ◽  
Gas Reservoir ◽  
Gas Field ◽  
Sand Body ◽  
Distribution Ranges ◽  
Sand Bodies

Abstract JZ Gasfield is an offshore sublacustrine fan lithologic gas field located in Bohai Bay Basin, in China, with a buried depth of about 1750m. It is currently in the stage of overall development plan preparation. Two exploration wells have been drilled. They show that the gas field has characteristics of rapid lateral change in reservoir, complex distribution range and connectivity of sand bodies. In addition, the few drilling data, large well spacing and low resolution of seismic data in the evaluation stage make it extremely challenging to establish an accurate geological model of gas reservoir. In order to solve the above problems, in this paper, an integrated geological modeling method based on seismic frequency division processing and fluid substitution forward modeling is proposed. There are four key aspects to this method. (1) Using seismic sedimentology, the lateral distribution ranges of sublacustrine fan sand bodies are described by seismic frequency division processing and interpretation technique and seismic variance attribute. (2) Based on markers of single-well, logging and seismic faceis, the average instantaneous frequency attribute is selected by optimizing the seismic attributes in the dominant frequency band, and then the distribution ranges of three subfacies including inner fan, middle fan and outer fan of the sublacustrine fan are characterized, and the fine sedimentary pattern of the sublacustrine fan is established. (3) Based on an understanding of the sedimentary pattern, fluid substitution forward modeling is carried out, and the superposition and connectivity of the sublacustrine fan sand body are described. (4) A 3D geological model of the sublacustrine fan sand body is established by using a new four-step modeling method including the concept of facies-in-facies modeling: 1) A model of the distribution of the sand body is established through a deterministic modeling method; 2) Within the sand body, according to the division results of subfacies, the distribution model of sub-facies is established; 3) A fine lithofacies model is established by combining stochastic simulation with deterministic modeling and hierarchical modeling from rough to fine under the constraint of a seismic attribute; 4) Petrophysical models are established by lithofacies control, which provide a more accurate geological model for preparation of the gas field development plan. Based on this comprehensive study, it is concluded that there is a great possibility of reservoir disconnection between the inner fan and the middle fan, where the gas reservoir is located, and the inner fan in the updip position of the structure has the risk of no gas accumulation, and the drilling risk in the development stage is greater than the potential. Based on this geological understanding, the available reserves of the gas field are reduced by nearly 40%.

3D Microfacies Modeling of Tight Gas Reservoir: A Case from Changling Block, Jilin Oilfield

2014 ◽  
Vol 915-916 ◽  
pp. 1124-1127
Author(s):  
Guo Yi Zhang ◽  
Xue Li ◽  
Xiao Yu Yu ◽  
Xiao Song Li
Keyword(s):  
Tight Gas ◽  
Geological Modeling ◽  
Gas Reservoir ◽  
Gas Field ◽  
Sedimentary Characteristics ◽  
Modeling Methods ◽  
The Core ◽  
Geological Characteristics ◽  
Well Pattern ◽  
Tight Gas Reservoir

Reservoir geological model is actually used to characterize the reservoir structure and the spatial distribution of reservoir parameters and variations, thus, the prediction of reservoir parameters between wells is the core of geological modeling. In order to improve the accuracy of geological modeling, traditional cycle correlation and sequence stratigraphy method are combined to classfy the sub zones into single sand sections according to the sedimentary characteristics of Changling gas field. The study area has experienced many years of development. On one hand, researchers has a certain understanding of its underground geological characteristics. On the other hand, the well pattern is almost perfect, only the edge of study area needs a certain prediction. Therefore, deterministic and stochastic modeling methods are combined in microfacies modeling and a 3D regional microfacies model of Changling gas field is established finally.

scholarly journals Distribution Model of Fluid Components and Quantitative Calculation of Movable Oil in Inter-Salt Shale Using 2D NMR

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2447
Author(s):  
Weichao Yan ◽  
Fujing Sun ◽  
Jianmeng Sun ◽  
Naser Golsanami
Keyword(s):  
2D Nmr ◽  
Distribution Model ◽  
Fluid Distribution ◽  
Fluid Composition ◽  
Distribution Analysis ◽  
Oil Saturation ◽  
Experimental Scheme ◽  
Quantitative Calculation ◽  
Fluid Saturation ◽  
Shale Reservoirs

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T1-T2 maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices.

The Finite Element Analysis of Coupling Law of Stress Field / Seepage Field in Impermeable Stratum Medium

2011 ◽  
Vol 250-253 ◽  
pp. 298-304
Author(s):  
Jing Yan Li
Keyword(s):  
Finite Element ◽  
Porous Medium ◽  
Stress Field ◽  
Fluid Distribution ◽  
Oil Well ◽  
Distribution Law ◽  
Seepage Field ◽  
Flow Process ◽  
Gas Field ◽  
Element Analysis

In order to forecast the mining process of oil and gas field rightly, simulate the flow process of reservoir fluid accurately and reveal the fluid distribution law, it must be considered that multiphase fluid seepage caused by water injection and exploitation, the change of stress state and the coupling between the reservoir deformations. According to the basic theory of rock mechanics, fluid mechanics in porous medium, geologic mechanics, calculated mechanics and fluid-solid coupling seepage, a mathematical and numerical model of seepage field and stress field coupling is developed in porous medium and a computer program is designed with the method of finite element technique. The Coupling Law of depressurizing exploitation Seepage field /Stress field in porous medium is studied. By the method of numerical simulation the variation law of stress-strain with time and space around borehole of impermeable rock medium, variety law of rock physical properties parameters is studied. Results show that the quantity of change nearby oil well and the change gradient is bigger, so it reduces very quickly to the oil deposit boundary,the stress and the strain are also biger in the oil well control area's influence area.

De-Risking Fluid Compartmentalization of the Barik Reservoir in the Khazzan Field, Oman - An Integrated Approach

2021 ◽  
Author(s):  
Abdullah Al Anboori ◽  
Stephen Dee ◽  
Khalil Al Rashdi ◽  
Herbert Volk
Keyword(s):  
Oil And Gas ◽  
Water Pressure ◽  
Integrated Approach ◽  
Fluid Distribution ◽  
Geological Time ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Development Costs ◽  
Potential Reservoir ◽  
Reservoir Compartmentalization

Abstract The degree of fluid compartmentalization has direct implications on the development costs of oil and gas reservoirs, since it may negatively impact gas water contacts (GWC) and fluid condensate gas ratios (CGR). In this case study on the Barik Formation in the giant Khazzan gas field in Block 61 in Oman we demonstrate how integrating independent approaches for assessing potential reservoir compartmentalization can be used to assess compartmentalization risk. The three disciplines that were integrated are structural geology (fault seal analysis, movement and stress stages of faults and fractures, traps geometry over geological time), petroleum systems (fluid chemistry and pressure, charge history) and sedimentology-stratigraphy including diagenesis (sedimentological and diagenetic controls on vertical and lateral facies and reservoir quality variation). Dynamic data from production tests were also analyzed and integrated with the observations above. Based on this work, Combined Common Risk Segment (CCRS) maps with a most likely and alternative scenarios for reservoir compartmentalization were constructed. While pressure data carry significant uncertainty due to the tight nature of the deeply buried rocks, it is clear pressures in gas-bearing sections fall onto a single pressure gradient across Block 61, while water pressures indicate variable GWCs. Overall, the GWCs appear to shallow across the field towards the NW, while water pressure appears to increase in that direction. The "apparent" gas communication with separate aquifers is difficult to explain conventionally. A range of scenarios for fluid distribution and reservoir connectivity are discussed. Fault seal compartmentalization and different trap spill points were found to be the most likely mechanism explaining fluid distribution and likely reservoir compartmentalization. Perched water may be another factor explaining variable GWCs. Hydrodynamic tilting due to the flow of formation water was deemed an unlikely scenario, and the risk of reservoir compartmentalization due to sedimentological and diagenetic flow barriers was deemed to be low.

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