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.

scholarly journals Photon-magnon response to fluid variability and saturation levels in sandstone reservoirs

2020 ◽  
Vol 17 (6) ◽  
pp. 1065-1074
Author(s):  
Abdullah Musa Ali ◽  
Amir Rostami ◽  
Noorhana Yahya
Keyword(s):  
Oil Recovery ◽  
Relative Permittivity ◽  
Wave Interaction ◽  
Heterogeneous Porous Media ◽  
Injection System ◽  
Bragg Grating ◽  
Fibre Bragg Grating ◽  
Core Flooding ◽  
Oil Saturation ◽  
Fluid Saturation

Abstract The need to recover high viscosity heavy oil from the residual phase of reservoirs has raised interest in the use of electromagnetics (EM) for enhanced oil recovery. However, the transformation of EM wave properties must be taken into consideration with respect to the dynamic interaction between fluid and solid phases. Consequently, this study discretises EM wave interaction with heterogeneous porous media (sandstones) under different fluid saturations (oil and water) to aid the monitoring of fluid mobility and activation of magnetic nanofluid in the reservoir. To achieve this aim, this study defined the various EM responses and signatures for brine and oil saturation and fluid saturation levels. A Nanofluid Electromagnetic Injection System (NES) was deployed for a fluid injection/core-flooding experiment. Inductance, resistance and capacitance (LRC) were recorded as the different fluids were injected into a 1.0-m long Berea core, starting from brine imbibition to oil saturation, brine flooding and eventually magnetite nanofluid flooding. The fluid mobility was monitored using a fibre Bragg grating sensor. The experimental measurements of the relative permittivity of the Berea sandstone core (with embedded detectors) saturated with brine, oil and magnetite nanofluid were given in the frequency band of 200 kHz. The behaviour of relative permittivity and attenuation of the EM wave was observed to be convolutedly dependent on the sandstone saturation history. The fibre Bragg Grating (FBG) sensor was able to detect the interaction of the Fe3O4 nanofluid with the magnetic field, which underpins the fluid mobility fundamentals that resulted in an anomalous response.

Capillary Equilibrium in Porous Materials

1965 ◽  
Vol 5 (01) ◽  
pp. 15-24 ◽  
Author(s):  
Norman R. Morrow ◽  
Colin C. Harris
Keyword(s):  
Mass Transfer ◽  
Fluid Flow ◽  
Porous Materials ◽  
Capillary Pressure ◽  
Chemical Engineering ◽  
Fluid Distribution ◽  
Bulk Fluid ◽  
Fluid Saturation ◽  
Capillary Pressure Curves ◽  
The Relationship

Abstract The experimental points which describe capillary pressure curves are determined at apparent equilibria which are observed after hydrodynamic flow has ceased. For most systems, the time required to obtain equalization of pressure throughout the discontinuous part of a phase is prohibitive. To permit experimental points to be described as equilibria, a model of capillary behavior is proposed where mass transfer is restricted to bulk fluid flow. Model capillary pressure curves follow if the path described by such points is independent of the rate at which the saturation was changed to attain a capillary pressure point. A modified suction potential technique is used to study cyclic relationships between capillary pressure and moisture content for a porous mass. The time taken to complete an experiment was greatly reduced by using small samples. Introduction Capillary retention of liquid by porous materials has been investigated in the fields of hydrology, soil science, oil reservoir engineering, chemical engineering, soil mechanics, textiles, paper making and building materials. In studies of the immiscible displacement of one fluid by another within a porous bed, drainage columns and suction potential techniques have been used to obtain relationships between pressure deficiency and saturation (Fig. 1). Except where there is no hysteresis of contact angle and the solid is of simple geometry, such as a tube of uniform cross section, there is hysteresis in the relationship between capillary pressure and saturation. The relationship which has received most attention is displacement of fluid from an initially saturated bed (Fig. 1, Curve Ro), the final condition being an irreducible minimum fluid saturation Swr. Imbibition (Fig. 1, Curve A), further desaturation (Fig. 1, Curve R), and intermediate scanning curves have been studied to a lesser but increasing extent. This paper first considers the nature of the experimental points tracing the capillary pressure curves with respect to the modes and rates of mass transfer which are operative during the course of measurement. There are clear indications that the experimental points which describe these curves are obtained at apparent equilibria which are observed when viscous fluid flow has ceased; and any further changes in the fluid distribution are the result of much slower mass transfer processes, such as diffusion. Unless stated otherwise, this discussion applies to a stable packing of equal, smooth, hydrophilic spheres supported by a suction plate with water as the wetting phase and air as the nonwetting phase. SPEJ P. 15ˆ

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.

Risk Planning with Discrete Distribution Analysis Applied to Petroleum Spills

2013 ◽  
Vol 2 (4) ◽  
pp. 61-78 ◽  
Author(s):  
Roy L. Nersesian ◽  
Kenneth David Strang
Keyword(s):  
Probability Distribution ◽  
Probability Distributions ◽  
Low Cost ◽  
Discrete Distribution ◽  
Distribution Model ◽  
Distribution Analysis ◽  
Distribution Models ◽  
Discrete Probability ◽  
Nonparametric Statistical ◽  
Spreadsheet Software

This study discussed the theoretical literature related to developing and probability distributions for estimating uncertainty. A theoretically selected ten-year empirical sample was collected and evaluated for the Albany NY area (N=942). A discrete probability distribution model was developed and applied for part of the sample, to illustrate the likelihood of petroleum spills by industry and day of week. The benefit of this paper for the community of practice was to demonstrate how to select, develop, test and apply a probability distribution to analyze the patterns in disaster events, using inferential parametric and nonparametric statistical techniques. The method, not the model, was intended to be generalized to other researchers and populations. An interesting side benefit from this study was that it revealed significant findings about where and when most of the human-attributed petroleum leaks had occurred in the Albany NY area over the last ten years (ending in 2013). The researchers demonstrated how to develop and apply distribution models in low cost spreadsheet software (Excel).

Oil content prediction of lacustrine organic-rich shale from wireline logs: A case study of intersalt reservoirs in the Qianjiang Sag, Jianghan Basin, China

2020 ◽  
Vol 8 (3) ◽  
pp. SL79-SL88
Author(s):  
Xin Nie ◽  
Jing Lu ◽  
Roufida Rana Djaroun ◽  
Peilin Wang ◽  
Jun Li ◽  
...  
Keyword(s):  
Experimental Data ◽  
Oil Content ◽  
Pore Space ◽  
Oil Reservoirs ◽  
Fluid Distribution ◽  
Shale Oil ◽  
Oil Saturation ◽  
Archie’S Law ◽  
The Core ◽  
Shale Oil Reservoirs

Shale oil is an unconventional oil resource with great potential. Oil saturation ([Formula: see text]) is an essential parameter for formation evaluation. However, due to the complexity of matrix mineral components and pore structure, Archie’s law cannot be used directly to calculate [Formula: see text] in shale oil reservoirs. We have developed a new saturation model for shale oil reservoirs. This model allows us to separate the organic from the inorganic pores, eliminate the background conductivity mainly caused by the borehole fluid or conductive minerals and determine the effective conductive porosity, which rules out nonconductive porosity, including isolated pores and the pore space affected by the fluid distribution. By analyzing the logging and core experimental data from the Qianjiang Sag, Jianghan Oilfield, we found that the T2 cutoff porosities of nuclear magnetic resonance logging are strongly related to the nonconductive porosities. After we determine the T2 cutoff value using the core experimental data, we can use it to obtain nonconductive porosity fraction in each depth point, which allows us to efficiently calculate [Formula: see text]. We calculate oil saturation values and use them to estimate the oil content. The results are coherent with the core experimental data, which indicates the efficiency of this model.

Fluid distribution effect on sonic attenuation in partially saturated limestones

Geophysics ◽  
1998 ◽  
Vol 63 (1) ◽  
pp. 154-160 ◽  
Author(s):  
Thierry Cadoret ◽  
Gary Mavko ◽  
Bernard Zinszner
Keyword(s):  
Wave Attenuation ◽  
Water Saturation ◽  
High Water ◽  
Fluid Distribution ◽  
Computer Assisted ◽  
Fluid Content ◽  
Partially Saturated ◽  
Fluid Saturation ◽  
Distribution Effect ◽  
Saturation Method

Extensional and torsional wave‐attenuation measurements are obtained at a sonic frequency around 1 kHz on partially saturated limestones using large resonant bars, 1 m long. To study the influence of the fluid distribution, we use two different saturation methods: drying and depressurization. When water saturation (Sw) is higher than 70%, the extensional wave attenuation is found to depend on whether the resonant bar is jacketed. This can be interpreted as the Biot‐Gardner‐White effect. The experimental results obtained on jacketed samples show that, during a drying experiment, extensional wave attenuation is influenced strongly by the fluid content when Sw is between approximately 60% and 100%. This sensitivity to fluid saturation vanishes when saturation is obtained through depressurization. Using a computer‐assisted tomographic (CT) scan, we found that, during depressurization, the fluid distribution is homogeneous at the millimetric scale at all saturations. In contrast, during drying, heterogeneous saturation was observed at high water‐saturation levels. Thus, we interpret the dependence of the extensional wave attenuation upon the saturation method as principally caused by a fluid distribution effect. Torsional attenuation shows no sensitivity to fluid saturation for Sw between 5% and 100%.

Application of Air-Mercury and Oil-Air Capillary Pressure Data In the Study of Pore Structure and Fluid Distribution

1966 ◽  
Vol 6 (01) ◽  
pp. 55-61 ◽  
Author(s):  
J.J. Pickell ◽  
B.F. Swanson ◽  
W.B. Hickman
Keyword(s):  
Interfacial Tension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Fluid Distribution ◽  
Pore Geometry ◽  
Residual Oil ◽  
Pressure Data ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Phase Saturation

Abstract Many physical properties of the porous media-immiscible liquid system are dependent upon the distribution of fluids within the pores; this in turn, is primarily a function of pore structure, liquid-liquid interfacial tension and liquid-solid wetting conditions. The capillary pressure hysteresis process provides a means of investigating the influence of pore structure upon fluid distribution for consistent surface conditions. Investigations indicate that residual non-wetting-phase saturations following the imbibition process (i.e., wetting phase displacing non-wetting phase) are dependent upon both pore structure and initial non-wetting phase saturation and suggest that residual fluid is distributed to discontinuous globules, one to a few pore sizes in dimension, through the entire range of pore sizes originally occupied. It appears that air-mercury capillary pressure data adequately reflect the distribution of fluids in a water-oil system when strong wetting conditions prevail. An oil-air counter-current imbibition technique has also been found to provide a rapid means of obtaining residual-initial saturation data. In a majority of cases, residual saturations determined from the oil-air or air-mercury process reasonably approximate residual oil and saturation following water drive of a strongly water-wet medium. Introduction A reliable estimate of recoverable reserves depends not only on the amount of original oil-in-place but also on pore geometry and distribution of fluids within the pores. A critical parameter determining the recovery from a reservoir under waterflood, for example, is the amount and distribution of residual oil within the various rock types present. The purpose of this paper is to investigate the mechanism of capillary trapping and assess its importance in laboratory measurements of residual oil saturation. The degree of wettability of a reservoir rock is recognized as an important factor in waterflood or imbibition experiments. In this paper, however, only the water-wet case has been considered. Considerable experimental evidence1 suggests that for water-wet rocks, capillary forces predominate in the distribution of fluids and that viscous forces in the range normally of interest in the reservoir have a minimum influence on residual oil saturation. It follows that if the ultimate recovery is controlled by pore geometry, a unique residual non-wetting phase saturation should exist for a given set of initial conditions. Two laboratory procedures found to be extremely useful in the study of pore structure and degree of fluid interconnection at various saturations are described. Although air-mercury capillary injection curves have been used2 previously to characterize the drainage case, the withdrawal or imbibition case can provide valuable supplementary data. The air-mercury process, however, has several disadvantages; it is difficult to run in a sufficiently accurate manner, mercury does not always act as a strongly non-wetting liquid and in the air-mercury process the sample is rendered unsuitable for future analyses. An alternative process is described in which air is the non-wetting phase and naptha, heptane, octane or toluene is the wetting phase. Interfacial Tension and Capillary Pressure Interfacial tension between immiscible fluids is due to the difference in attraction of like molecules as compared with their attraction to molecules of the neighboring fluid. This net attraction results in a tension at the interface. To extend the interface; thus, interfacial tension s can also be thought of as free surface energy. Interfacial tension is normally expressed as dynes/cm, and interfacial energy is measured in ergs/cm2 hence, both have dimensions mLt-2 and are numerically equal.

Laboratory and Field Evaluation of an Inelastic Neutron Scattering and Capture Gamma Ray Spectrometry Tool

1980 ◽  
Vol 20 (05) ◽  
pp. 327-340 ◽  
Author(s):  
R.C. Hertzog
Keyword(s):  
Gamma Ray ◽  
Inelastic Neutron Scattering ◽  
Relative Number ◽  
Experimental System ◽  
Water Salinity ◽  
Gamma Ray Spectrometry ◽  
Fluid Composition ◽  
Atomic Carbon ◽  
Oil Saturation ◽  
Oxygen Ratio

Abstract An experimental system for gamma ray spectroscopy logging has been developed which uses prompt and capture gamma radiation induced in formations by 14-MeV neutrons from a pulsed-neutron generator to determine relative concentrations of various elements in the formation. The logging system uses computer-processing techniques based on spectral modeling that has been developed to analyze the inelastic and capture gamma ray data obtained with a borehole spectrometer. The physics of the production of gamma rays from fast-neutron interactions with elemental nuclei in formations is discussed, leading to a simple but realistic interpretation model for the tool's response. This model is confirmed by laboratory and field tests. The relative spectroscopic contributions from carbon, oxygen, silicon, calcium, iron, chlorine, and hydrogen are used for various cased-hole and openhole logging applications. Particular emphasis is placed on the carbon/oxygen ratio used to obtain oil saturation independent of formation-water salinity. Carbon/oxygen ratio determinations made in the laboratory are compared with values predicted on the basis of known lithologies, porosities, and oil-saturation changes. In addition, the spectral contributions from iron, silicon, and calcium are used to interpret lithology; hydrogen, silicon, and calcium contributions are used to determine the effects of porosity; and chlorine and hydrogen contributions are used to investigate salinity changes. Field-test log examples of these elemental determinations are shown. Introduction A principal objective of the induced gamma ray tool (IGT™) is to make a more direct measurement of oil saturation So in cased-hole formations where conditions are not favorable for the use of the thermal neutron decay time (TDT™) log. These include formations with low water salinity (less than 50,000 ppm NaCl) and formations where the producing zone is being flooded with water of unknown or variable salinity. Any measurement of the relative number of carbon and oxygen atoms in the formation will be sensitive to the changing formation-fluid composition. Fig. 1 shows the calculated carbon/oxygen atomic-abundance ratio vs. porosity f for various oil saturations in limestone, dolomite, and sandstone formations and provides a picture of the expected changes in this ratio for typical clean formations. For example, in moderate to high porosities (0.20 < f < 0.30), the atomic carbon/oxygen ratio in limestone changes by about a factor of two as the oil saturation changes from 0 to 1000/0. In sandstone the atomic carbon/oxygen ratio starts from zero and increases with oil saturation by about the same amount. However, since there is considerable carbon in the matrix of a limestone or dolomite formation, an elemental analysis for carbon and oxygen by itself is not sufficient to interpret unambiguously oil saturation using a crossplot such as Fig. 1. An independent knowledge of lithology and porosity is required.

Three-Dimensional Modeling of Mineral/Elemental Compositions for Shale Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 2067-2078
Author(s):  
Y. Z. Ma
Keyword(s):  
Elemental Composition ◽  
Three Dimensional ◽  
Compositional Analysis ◽  
Physical Constraint ◽  
Modeling Methods ◽  
Three Dimensional Modeling ◽  
Fluid Saturation ◽  
Mineral Compositions ◽  
Shale Reservoirs ◽  
Log Ratio

Summary Mineral compositional analysis of rocks is important for developing shale resources because the relationships between mineral compositions and petrophysical properties are critical for resource evaluation and completion optimization. Elementary properties are now routinely analyzed at wells in evaluating shale reservoirs. However, these properties have not been modeled in the three-dimensional (3D) reservoir. This is because an elemental composition has a physical constraint that is relatively easily adhered to in data analysis for wells but not in 3D modeling of reservoirs. A critical condition of elemental composition is that the sum of its components is equal to 100% to honor the mass-preservation principle. Traditional modeling methods do not satisfy this physical condition, sometimes producing nonphysical values, such as negative porosity values and fluid-saturation values greater than 100%. To date, only the compositional-modeling methods using a log-ratio transform can consistently satisfy this physical constraint. This paper presents modeling methods using additive log-ratio transform for modeling mineral compositions.

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