Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa

Abstract The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.

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Pressure and fluid saturation prediction in a multicomponent reservoir using combined seismic and electromagnetic imaging

Geophysics ◽

10.1190/1.1620632 ◽

2003 ◽

Vol 68 (5) ◽

pp. 1580-1591 ◽

Cited By ~ 58

Author(s):

G. Michael Hoversten ◽

Roland Gritto ◽

John Washbourne ◽

Tom Daley

Keyword(s):

Electrical Conductivity ◽

Water Saturation ◽

Saturation Pressure ◽

Shear Velocity ◽

Velocity Shear ◽

Rock Properties ◽

Velocity Change ◽

Archie’S Law ◽

Fluid Saturation ◽

Compressional Velocity

This paper presents a method for combining seismic and electromagnetic (EM) measurements to predict changes in water saturation, pressure, and CO2 gas/oil ratio in a reservoir undergoing CO2 flood. Crosswell seismic and EM data sets taken before and during CO2 flooding of an oil reservoir are inverted to produce crosswell images of the change in compressional velocity, shear velocity, and electrical conductivity during a CO2 injection pilot study. A rock‐properties model is developed using measured log porosity, fluid saturations, pressure, temperature, bulk density, sonic velocity, and electrical conductivity. The parameters of the rock‐properties model are found by an L1‐norm simplex minimization of predicted and observed differences in compressional velocity and density. A separate minimization, using Archie's law, provides parameters for modeling the relations between water saturation, porosity, and electrical conductivity. The rock‐properties model is used to generate relationships between changes in geophysical parameters and changes in reservoir parameters. Electrical conductivity changes are directly mapped to changes in water saturation; estimated changes in water saturation are used along with the observed changes in shear‐wave velocity to predict changes in reservoir pressure. The estimation of the spatial extent and amount of CO2 relies on first removing the effects of the water saturation and pressure changes from the observed compressional velocity changes, producing a residual compressional velocity change. This velocity change is then interpreted in terms of increases in the CO2/oil ratio. Resulting images of the CO2/oil ratio show CO2‐rich zones that are well correlated to the location of injection perforations, with the size of these zones also correlating to the amount of injected CO2. The images produced by this process are better correlated to the location and amount of injected CO2 than are any of the individual images of change in geophysical parameters.

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Direct reservoir parameter estimation using joint inversion of marine seismic AVA and CSEM data

Geophysics ◽

10.1190/1.2194510 ◽

2006 ◽

Vol 71 (3) ◽

pp. C1-C13 ◽

Cited By ~ 109

Author(s):

G. Michael Hoversten ◽

Florence Cassassuce ◽

Erika Gasperikova ◽

Gregory A. Newman ◽

Jinsong Chen ◽

...

Keyword(s):

Water Saturation ◽

Joint Inversion ◽

Hydrocarbon Exploration ◽

Rock Properties ◽

Parameter Estimates ◽

Angle Of Incidence ◽

Model Errors ◽

Inversion Algorithm ◽

Fluid Saturation ◽

Reservoir Parameter

Accurately estimating reservoir parameters from geophysical data is vitally important in hydrocarbon exploration and production. We have developed a new joint-inversion algorithm to estimate reservoir parameters directly, using both seismic amplitude variation with angle of incidence (AVA) data and marine controlled-source electromagnetic (CSEM) data. Reservoir parameters are linked to geophysical parameters through a rock-properties model. Errors in the parameters of the rock-properties model introduce errors of comparable size in the reservoir-parameter estimates produced by joint inversion. Tests of joint inversion on synthetic 1D models demonstrate improved fluid saturation and porosity estimates for joint AVA-CSEM data inversion (compared with estimates from AVA or CSEM inversion alone). A comparison of inversions of AVA data, CSEM data, and joint AVA-CSEM data over the North Sea Troll field, at a location for which we have well control, shows that the joint inversion produces estimates of gas saturation, oil saturation, and porosity that are closest (as measured by the rms difference, the [Formula: see text] norm of the difference, and net values over the interval) to the logged values. However, CSEM-only inversion provides the closest estimates of water saturation.

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DETERMINATION CONVENTIONAL ROCK PROPERTIES FROM LOG DATA & CORE DATA FOR UPPER NUBIAN SANDSTONE FORMATION OF ABU ATTIFEL FIELD

Scientific Journal of Applied Sciences of Sabratha University ◽

10.47891/sabujas.v2i1.29-37 ◽

2019 ◽

Vol 2 (1) ◽

pp. 29-37

Author(s):

Adel Alabeed ◽

Zeyad Ibrahim ◽

Emhemed Alfandi

Keyword(s):

Water Saturation ◽

Rock Properties ◽

Well Log ◽

Log Data ◽

Nubian Sandstone ◽

Core Data ◽

Hydrocarbon Reservoir ◽

Fluid Saturation ◽

Volume Porosity ◽

Sandstone Formation

A reservoir is a subsurface rock that has effective porosity and permeability which usually contains commercially exploitable quantity of hydrocarbon. Reservoir characterization is undertaken to determine its capability to both store and transmit fluid. Petrophysical well log and core data, in this paper, were integrated in an analysis of the reservoir characteristics by selecting of three productive wells. The selected wells are located at Abu Attifel field in Libya for Upper Nubian Sandstone formation at depth varied form 12921 to14330 ft. The main aim of this study is to compare the laboratory measurement of core data with that obtained from well log data in order to determine reservoir properties such as shale volume, porosity (Φ), permeability (K), fluid saturation, net pay thickness. The plots of porosity logs and core porosity versus depth for the three wells revealed significant similarity in the porosity values. The average volume of shale for the reservoir was determined to be 22.5%, and average permeability values of the three wells are above 150 md, while porosity values ranged from 9 to 11%. Low water saturation 13 to 22% in the three wells indicates the wettability of the reservoir is water-wet.

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Digital Rock Typing DRT Algorithm Formulation with Optimal Supervised Semantic Segmentation

10.36227/techrxiv.17876570 ◽

2022 ◽

Author(s):

Omar Alfarisi ◽

Djamel Ouzzane ◽

Mohamed Sassi ◽

TieJun Zhang

Keyword(s):

Carbonate Rock ◽

Chemical Properties ◽

Rock Physics ◽

Semantic Segmentation ◽

Rock Properties ◽

Digital Rock Physics ◽

Digital Rock ◽

Rock Types ◽

Fluid Saturation ◽

Rock Typing

<p><a></a>Each grid block in a 3D geological model requires a rock type that represents all physical and chemical properties of that block. The properties that classify rock types are lithology, permeability, and capillary pressure. Scientists and engineers determined these properties using conventional laboratory measurements, which embedded destructive methods to the sample or altered some of its properties (i.e., wettability, permeability, and porosity) because the measurements process includes sample crushing, fluid flow, or fluid saturation. Lately, Digital Rock Physics (DRT) has emerged to quantify these properties from micro-Computerized Tomography (uCT) and Magnetic Resonance Imaging (MRI) images. However, the literature did not attempt rock typing in a wholly digital context. We propose performing Digital Rock Typing (DRT) by: (1) integrating the latest DRP advances in a novel process that honors digital rock properties determination, while; (2) digitalizing the latest rock typing approaches in carbonate, and (3) introducing a novel carbonate rock typing process that utilizes computer vision capabilities to provide more insight about the heterogeneous carbonate rock texture.<br></p>

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Relating Acoustic Anisotropy to Kerogen Content in Unconventional Formations - A Case Study in A Kerogen-Rich Unconventional Carbonate

10.2118/205912-ms ◽

2021 ◽

Author(s):

Yair Gordin ◽

Thomas Bradley ◽

Yoav O. Rosenberg ◽

Anat Canning ◽

Yossef H. Hatzor ◽

...

Keyword(s):

Wave Velocity ◽

Water Saturation ◽

Well Logs ◽

Rock Properties ◽

Thermal Maturity ◽

Burial Diagenesis ◽

S Wave ◽

Velocity Anisotropy ◽

Thermal Maturation ◽

Wide Range

Abstract The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements. In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data. Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.

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Duration of water saturation in selected soils of Weatherley, South Africa

South African Journal of Plant and Soil ◽

10.1080/02571862.2007.10634799 ◽

2007 ◽

Vol 24 (3) ◽

pp. 152-160 ◽

Cited By ~ 6

Author(s):

C. W. van Huyssteen ◽

P. A.L. le Roux ◽

M. Hensley ◽

T. B. Zere

Keyword(s):

South Africa ◽

Water Saturation

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Residual Water Saturation of Source Rocks of the Bazhenov Formation Western Siberia, Russia

10.2118/206586-ms ◽

2021 ◽

Author(s):

Anton Vasilievich Glotov ◽

Anton Gennadyevich Skripkin ◽

Petr Borisovich Molokov ◽

Nikolay Nilovich Mikhailov

Keyword(s):

Western Siberia ◽

Water Saturation ◽

Source Rocks ◽

Rock Properties ◽

Low Permeability ◽

Residual Water ◽

Bazhenov Formation ◽

Rock Formation ◽

Low Permeability Reservoirs ◽

Significant Underestimation

Abstract The article presents a new method of determining the residual water saturation of the Bazhenov Rock Formation using synchronous thermal analysis which is combined with gas IR and MS spectroscopy. The efficiency of the extraction-distillation method of determining open porous and residual saturation in comparison with the developed method which are considered in detail. Based on the results of studies in the properties of the Bazhenov Rock Formation, a significant underestimation of the residual water saturation in the existing guidelines for calculating reserves was found, and the structure of the saturation of rocks occurred to be typical for traditional low-permeability reservoirs. The values of open porous and residual water saturation along the section of the Bazhenov Formation vary greatly, which also contradicts the well-established opinion about the weak variability of the rock properties with depth.

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