Quantitative comparison of processes of oil- and water-based mud-filtrate invasion and corresponding effects on borehole resistivity measurements

Geophysics ◽  
2009 ◽  
Vol 74 (1) ◽  
pp. E57-E73 ◽  
Author(s):  
Jesús M. Salazar ◽  
Carlos Torres-Verdín
Keyword(s):  
Electrical Resistivity ◽  
Flow Rate ◽  
Water Saturation ◽  
Base Case ◽  
Petrophysical Properties ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Mud Cake ◽  
Water Based ◽  
Mud Filtrate

Some laboratory and qualitative studies have documented the influence of water-based mud(WBM)-filtrate invasion on borehole resistivity measurements. Negligible work, however, has been devoted to studying the effects of oil-based mud(OBM)-filtrate invasion on well logs and the corresponding impact on the estimation of petrophysical properties. We quantitatively compare the effects of WBM- and OBM-filtrate invasion on borehole resistivity measurements. We simulate the process of mud-filtrate invasion into a porous and permeable rock formation assuming 1D radial distributions of fluid saturation and fluid properties while other petrophysical properties remain constant. To simulate the process of mud-filtrate invasion, we calculate a time-dependent flow rate of OBM-filtrate invasion by adapting the available formulation of the physics of WBM-filtrate invasion. This approach includes the dynamically coupled effects of mud-cake growth and multiphase filtrate invasion. Simulations are performed with a commercial adaptive-implicit compositional formulation that enables the quantification of effects caused by additional components of mud-filtrate and native fluids. The formation under analysis is 100% water saturated (base case) andis invaded with a single-component OBM. Subsequently, we perform simulations of WBM filtrate invading the same formation assuming that it is hydrocarbon bearing, and compare the results to those obtained in the presence of OBM. At the end of this process, we invoke Archie’s equation to calculate the radial distribution of electrical resistivity from the simulated radial distributions of water saturation and salt concentration and compare the effects of invasion on borehole resistivity measurements acquired in the presence of OBM and WBM. Simulations confirm that the flow rate of OBM-filtrate invasion remains controlled by the initial mud-cake permeability and formation petrophysical properties, specifically capillary pressure and relative permeability. Moreover, WBM causes radial lengths of invasion 15%–40% larger than those associated with OBM as observed on the radial distributions of electrical resistivity. It is found also that, in general, flow rates of WBM-filtrate invasion are higher than those of OBM-filtrate invasion caused by viscosity contrasts between OBM filtrate and native fluids, which slow down the process of invasion. Such a conclusion is validated by the marginal variability of array-induction resistivity measurements observed in simulations of OBM invasion compared with those of WBM invasion.

Effects of Surfactant-Emulsified Oil-Based Mud on Borehole Resistivity Measurements

SPE Journal ◽  
2011 ◽  
Vol 16 (03) ◽  
pp. 608-624 ◽  
Author(s):  
Jesús M. Salazar ◽  
Carlos Torres-Verdín ◽  
Gong Li Wang
Keyword(s):  
Electrical Resistivity ◽  
Spatial Distribution ◽  
Sensitivity Analyses ◽  
High Resistivity ◽  
Reliable Estimate ◽  
Spatial Distributions ◽  
Oil Viscosity ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Mud Filtrate

Summary We quantify the influence of oil-based mud (OBM)-filtrate invasion and formation-fluid properties on the spatial distribution of fluid saturation and electrical resistivity in the near-wellbore region. The objective is to appraise the sensitivity of borehole resistivity measurements to the spatial distribution of fluid saturation resulting from the compositional mixing of OBM and in-situ hydrocarbons. First, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. A second approach consists of adding water and surfactant to a multicomponent OBM invading a formation saturated with multiple hydrocarbon components. Simulations also include presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion because oil viscosity and oil density are both dependent on component concentrations. Presence of surfactants in the OBM is simulated with a commercial adaptive implicit compositional formulation that models the flow of three-phase multicomponent fluids in porous media. Simulations of the process of OBM invasion yield 2D spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity. Subsequently, we simulate the corresponding array-induction measurements assuming axial-symmetric variations of electrical resistivity. We perform sensitivity analyses on field measurements acquired in a well that penetrates a clastic formation and that includes different values of density and viscosity for mud filtrate and formation hydrocarbon. These analyses provide evidence of the presence of a high-resistivity region near the borehole wall followed by a low-resistivity annulus close to the noninvaded resistivity region. Such an abnormal resistivity annulus is predominantly caused by high viscosity contrasts between mud filtrate and formation oil. The combined simulation of invasion and array-induction logs in the presence of OBM invasion provides a more reliable estimate of water saturation, which improves the assessment of in-place hydrocarbon reserves.

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. D209-D227 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Radial Distribution ◽  
Apparent Resistivity ◽  
Water Saturation ◽  
Estimation Method ◽  
Petrophysical Properties ◽  
Fluid Saturation ◽  
Irreducible Water Saturation ◽  
Geophysical Measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

Enhanced Assessment of Fluid Saturation in the Wolfcamp Formation of the Permian Basin

2021 ◽  
Vol 62 (6) ◽  
pp. 737-751
Author(s):  
Sabyasachi Dash ◽  
◽  
Zoya Heidari ◽  
Keyword(s):  
Spatial Distribution ◽  
Water Saturation ◽  
Geometric Model ◽  
New Method ◽  
Model Parameters ◽  
Unique Contribution ◽  
Permian Basin ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Resistivity Model

Conventional resistivity models often overestimate water saturation in organic-rich mudrocks and require extensive calibration efforts. Conventional resistivity-porosity-saturation models assume brine in the formation as the only conductive component contributing to resistivity measurements. They also do not reliably assimilate the spatial distribution of the clay network and pore structure. Moreover, they do not incorporate other conductive minerals and organic matter, impacting the resistivity measurements and leading to uncertainty in water saturation assessment. We recently introduced a resistivity-based model that quantitatively assimilates the type and spatial distribution of all rock constituents to improve reserves evaluation in organic-rich mudrocks using electrical resistivity measurements. This paper aims to expand the application of this model for well-log-based assessment of water/hydrocarbon saturation and to verify the reliability of the introduced method in the Wolfcamp Formation of the Permian Basin. Our recently introduced resistivity model uses pore combination modeling to incorporate conductive (clay, pyrite, kerogen, brine) and nonconductive (grains, hydrocarbon) components in estimating effective resistivity. The inputs to the model are volumetric concentrations of minerals, conductivity of rock components, and porosity obtained from laboratory measurements or interpretation of well logs. Geometric model parameters are also critical inputs to the model. To simultaneously estimate the geometric model parameters and water saturation, we developed an inversion algorithm with two objectives: (a) to estimate the geometric model parameters as inputs to the new resistivity model and (b) to estimate the water saturation. The geometric model parameters are determined for each rock type or formation by minimizing the difference between the measured resistivity and the resistivity estimated from pore combination modeling. We applied the new method to two wells drilled in the Wolfcamp Formation of the Permian Basin. The formation-based inversion showed variation in geometric model parameters, which improved the assessment of water saturation. Results demonstrated that the new method improved water saturation estimates by 24.1% and 32.4% compared to Archie’s and Waxman-Smits models, respectively, in the Wolfcamp Formation. The most considerable improvement was observed in the Middle and the Lower Wolfcamp Formations, where the average clay concentration was relatively higher than the other zones. There was an additional 70,000 bbl/acre of hydrocarbon reserve using the proposed method compared to when water saturation was quantified using Archie’s model in the Permian Basin, which is a 33% relative improvement. It should be highlighted that the new method did not require any calibration effort using core water saturation measurements, which is a unique contribution of this rock-physics-based workflow.

Electrical resistivity and chemical properties of kerogen isolated from organic-rich mudrocks

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. D643-D655 ◽  
Author(s):  
Anqi Yang ◽  
Gama Firdaus ◽  
Zoya Heidari
Keyword(s):  
Electrical Resistivity ◽  
Water Saturation ◽  
Resonance Spectroscopy ◽  
Chemical Transformations ◽  
Thermal Maturity ◽  
Microscopy Imaging ◽  
Eagle Ford ◽  
Resistivity Measurements ◽  
Low Resistivity ◽  
Geochemical Properties

Low electrical resistivity measurements in organic-rich mudrocks are commonplace in highly mature zones. These low resistivity values are usually difficult to justify and lead to overestimation of water saturation when using conventional resistivity-porosity-saturation models (e.g., dual water and Waxman-Smits). Previous publications suggest that the electrical conductivity of kerogen increases when it thermally matures. This increase in thermal maturity of kerogen might contribute to low resistivity measurements in organic-rich mudrocks. However, electrical properties of kerogen within these rocks have not yet been quantified experimentally. We have introduced a technique to quantify electrical resistivity of kerogen through combined experimental and numerical approaches and quantified electrical resistivity of kerogen samples from the Haynesville and Eagle Ford Formations. We first isolated kerogen from mudrock samples using physical and chemical treatments. The isolated kerogen powder was then compressed into a homogeneous disk. Then, we synthetically matured mudrock and kerogen samples to controlled maturity levels and measured the electrical resistivity and geochemical properties of each sample. The true electrical resistivity of kerogen was then estimated by minimizing the difference between the numerically simulated and measured electrical resistivity of the molded kerogen samples. We have observed a significant decrease in the electrical resistivity of kerogen isolated from the Haynesville (i.e., up to four orders of magnitude) and Eagle Ford (i.e., up to nine orders of magnitude) Formations upon heat treatment from 300°C to 800°C. The decrease in resistivity can be reasoned by the chemical transformations of organic matter through thermal maturation. The results of solid-state [Formula: see text] nuclear magnetic resonance spectroscopy and transmission electron microscopy imaging confirmed increase in graphitization and aromaticity in the kerogen samples as thermal maturity increases. Our outcomes can potentially improve interpretation of electrical resistivity logs in organic-rich mudrocks, such as enhancing well-log-based assessment of in situ hydrocarbon saturation.

scholarly journals Petrophysical Properties of an Iraqi Carbonate Reservoir Using Well Log Evaluation

2020 ◽  
Vol 21 (1) ◽  
pp. 53-59
Author(s):  
Sarah S. Zughar ◽  
Ahmad A. Ramadhan ◽  
Ahmed K. Jaber
Keyword(s):  
Water Saturation ◽  
Carbonate Reservoir ◽  
Petrophysical Properties ◽  
Indicator Method ◽  
Rock Types ◽  
Fluid Saturation ◽  
Unit Thickness ◽  
Average Formation ◽  
Porous Zone ◽  
Mud Filtration

This research was aimed to determine the petrophysical properties (porosity, permeability and fluid saturation) of a reservoir. Petrophysical properties of the Shuiaba Formation at Y field are determined from the interpretation of open hole log data of six wells. Depending on these properties, it is possible to divide the Shuiaba Formation which has thickness of a proximately 180-195m, into three lithological units: A is upper unit (thickness about 8 to 15 m) involving of moderately dolomitized limestones; B is a middle unit (thickness about 52 to 56 m) which is composed of dolomitic limestone, and C is lower unit ( >110 m thick) which consists of shale-rich and dolomitic limestones. The results showed that the average formation water resistivity for the formation (Rw = 0.021), the average resistivity of the mud filtration (Rmf = 0.57), and the Archie parameters determined by the picket plot method, where m value equal to 1.94, n value equal to 2 and a value equal to 1. Porosity values and water saturation Sw were calculated along with the depth of the composition using IP V3.5 software. The interpretation of the computer process (CPI) showed that the better porous zone holds the highest amount of hydrocarbons in the second zone. From the flow zone indicator method, there are four rock types in the studied reservoir.

scholarly journals The Dependence of Electrical Resistivity-Saturation Relationships on Multiphase Flow Instability

2012 ◽  
Vol 2012 ◽  
pp. 1-10 ◽  
Author(s):  
Zoulin Liu ◽  
Stephen M. J. Moysey
Keyword(s):  
Electrical Resistivity ◽  
Multiphase Flow ◽  
Light Transmission ◽  
Flow Instability ◽  
Water Saturation ◽  
Bond Number ◽  
Smooth Transition ◽  
Transmission Method ◽  
Archie’S Law ◽  
Fluid Saturation

We investigate the relationship between apparent electrical resistivity and water saturation during unstable multiphase flow. We conducted experiments in a thin, two-dimensional tank packed with glass beads, where Nigrosine dyed water was injected uniformly along one edge to displace mineral oil. The resulting patterns of fluid saturation in the tank were captured on video using the light transmission method, while the apparent resistivity of the tank was continuously measured. Different experiments were performed by varying the water application rate and orientation of the tank to control the generalized Bond number, which describes the balance between viscous, capillary, and gravity forces that affect flow instability. We observed the resistivity index to gradually decrease as water saturation increases in the tank, but sharp drops occurred as individual fingers bridged the tank. The magnitude of this effect decreased as the displacement became increasingly unstable until a smooth transition occurred for highly unstable flows. By analyzing the dynamic data using Archie’s law, we found that the apparent saturation exponent increases linearly between approximately 1 and 2 as a function of generalized Bond number, after which it remained constant for unstable flows with a generalized Bond number less than −0.106.

Petro-electric modeling for CSEM reservoir characterization and monitoring

Geophysics ◽  
2012 ◽  
Vol 77 (1) ◽  
pp. E9-E20 ◽  
Author(s):  
Alireza Shahin ◽  
Kerry Key ◽  
Paul Stoffa ◽  
Robert Tatham
Keyword(s):  
Electrical Resistivity ◽  
Water Saturation ◽  
Fluid Pressure ◽  
Time Lapse ◽  
Petroleum Exploration ◽  
Water Flooding ◽  
Algorithm Analysis ◽  
Production Time ◽  
Data Set ◽  
Fluid Saturation

The controlled-source electromagnetic (CSEM) method has been successfully applied to petroleum exploration; however, less effort has been made to highlight the applicability of this technique for reservoir monitoring. This work appraises the ability of time-lapse CSEM data to detect the changes in fluid saturation during water flooding into an oil reservoir. We simulated a poorly consolidated shaly sandstone reservoir based on a prograding near-shore depositional environment. Starting with an effective porosity model simulated by Gaussian geostatistics, dispersed clay and dual water models were efficiently combined with other well-known theoretical and experimental petrophysical correlations to consistently simulate reservoir properties. The constructed reservoir model was subjected to numerical simulation of multiphase fluid flow to predict the spatial distributions of fluid pressure and saturation. A geologically consistent rock physics model and a modified Archie’s equation for shaly sandstones were then used to simulate the electrical resistivity, showing up to 60% decreases in electrical resistivity due to changes in water saturation during 10 years of production. Time-lapse CSEM data were simulated at three production time steps (zero, five, and ten years) using a 2.5D parallel adaptive finite element algorithm. Analysis of the time-lapse signal in the simulated multicomponent and multifrequency data set demonstrates that a detectable time-lapse signal after five years and a strong time-lapse signal after ten years of water flooding are attainable using current CSEM technology.

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