The Experts below are selected from a list of 6798 Experts worldwide ranked by ideXlab platform

Mayank Malik - One of the best experts on this subject based on the ideXlab platform.

  • 2007, “Influence of petrophysical and fluid properties on array-induction measurements acquired in the presence of oil-Base Mud-filtrate invasion,” paper AAA presented at the 48 th Annual Logging Symposium: Society of Petrophysicist and Well Log Analysts
    2015
    Co-Authors: Mayank Malik, Gong Li Wang, Carlos Torres-verdín, Jesús M. Salazar, Hee Jae Lee, Kamy Sepehrnoori
    Abstract:

    This paper quantifies the influence of petrophysical and fluid properties on array-induction resistivity measurements acquired in the presence of oil-Base Mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on componen

  • numerical investigation of oil Base Mud contamination in condensates from cleanup to sample quality
    Journal of Natural Gas Science and Engineering, 2010
    Co-Authors: Mayank Malik, Birol Dindoruk, Hani Elshahawi, Carlos Torresverdin
    Abstract:

    Abstract Formation Testers are widely used to determine pore pressure, estimate formation permeability, and detect reservoir connectivity through pressure transient testing after the onset of invasion. Mud filtrate invasion takes place in reservoirs penetrated by a well that is hydraulically overbalanced by Mud circulation, or due to capillary forces. In water-Base Muds (WBM), the invading Mud is immiscible with respect to the formation hydrocarbons. Therefore, water can be physically separated from the in-situ hydrocarbons leading to the best estimates of the in-situ PVT properties and thereby formation properties. Oil-Base Muds (OBM) are partially to completely miscible with the reservoir hydrocarbons, and so OBM contamination causes alteration of fluid properties which becomes even more critical for condensates when changes in fluid viscosity, density, and relative permeability occur. Due to the complexity of partial miscibility with gases and gas condensates, limited work has been done to simulate invasion by OBM. The goals of our work were to: 1. Determine conditions to obtain better samples. 2. Quantify the errors in numerical cleaning methods necessary for obtaining in-situ fluid compositions and properties. 3. Investigate the physics of the clean-up process. 4. Investigate the feasibility of tracers for monitoring contamination. Our results show that for condensates and lean gases, quantifying OBM contamination in terms of the live/bulk fluid alone can be misleading. For such fluids, contamination in the stock tank oil is just as critical as that of the bulk fluid because only the former predicts the errors in saturation pressures and CGR numbers observed in laboratory analyses. Lean fluids can take extremely long times to completely clean up during a formation test or even during a well test. For those fluids, it is more essential than ever to clearly define the primary objectives of the sampling program and to decide which answers are most critical.

  • Comparison of Wireline Formation-Tester Sampling with Focused and Conventional Probes in the Presence of Oil-Base Mud-Filtrate Invasion
    2009
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torres-verdín, Richard Jackson, Peter Weinheber, Oliver C. Mullins, Mohamed Hashem
    Abstract:

    In the course of fluid sampling, varying concentrations of oil Base Mud (OBM) will lead to variations of fluid properties such as viscosity, density, and gas-oil ratio (GOR). A focused probe can be useful in reducing OBM contamination by diverting flow into different channels without compromising fluid pumpout time. However, it is important to properly quantify the relative performance of focused and conventional probes for a wide range of field conditions. The objective of this paper is to appraise the performance of different probes under the same simulated field conditions and for a comprehensive set of petrophysical and fluid properties. Results indicate that sample quality generally improves when the flow is split between the guard and sample probes, but the specific amount of improvement depends on probe geometry, fluid composition, and formation properties. Permeability anisotropy, presence of a flow boundary, and lack of Mud-filtrate invasion can help to improve sample quality. In addition, fluid cleanup can be accelerated by altering both the probe design and the flow-rate ratio between the sample and guard fluid streams, thereby leading to increased pressure differential between the sample and guard areas and enhancing the "coning" of the Mud-filtrate invasion front.

  • Effects of Petrophysical Properties on Array-Induction Measurements Acquired in the Presence of Oil-Base Mud-Filtrate Invasion
    Petrophysics, 2008
    Co-Authors: Mayank Malik, Gong Li Wang, Carlos Torres-verdín, Jesús M. Salazar, Hee Jae Lee, Kamy Sepehrnoori
    Abstract:

    We quantify the influence of petrophysical properties on array-induction resistivity measurements acquired in the presence of oil-Base Mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility ofthe oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on component concentrations. This behavior in turn conditions the spatial distribution of electrical resistivity and, consequently, the borehole array-induction measurements. We use an implicit pressure, explicit concentration (IMPEC) reservoir simulator with a two-component formulation to reproduce the invasion process in axial-symmetric rock formations penetrated by a vertical well. Simulations of the process of OBM-filtrate invasion yield two-dimensional spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity using Waxman-Smits' saturation-resistivity equations. Subsequently, we simulate array-induction measurements with a numerical mode-matching method. Simulation of induction measurements in the presence of OBM are compared against the corresponding measurements acquired in the presence of water-Base Mud (WBM) using field measurements from a deepwater Gulf-of-Mexico reservoir. Sensitivity analyses are conducted to quantify the effect of OBM-filtrate invasion on array-induction logs, including different values of formation porosity-permeability, movable water zone, capillary pressure, relative permeability, Mud-filtrate invasion rates, and fluid viscosity. In addition, we quantify the effect of changes of rock wettability due to OBM invasion on field measurements. Our study indicates that relative permeability, capillary pressure, and flow rate of invasion control the radial length of invasion of OBM and, consequently, the values and relative separation of apparent resistivity curves. Porous rock formations saturated with movable water entail smooth radial distributions of water saturation which, in turn, result in deep (1.5 ft - 2 ft) radial invasion profiles and relatively large separation of apparent resistivity curves. By contrast, null or marginal separation of apparent resistivity curves occurs when the invaded rock is at irreducible water saturation.

  • comparison of wireline formation tester sampling with focused and conventional probes in the presence of oil Base Mud filtrate invasion
    Petrophysics, 2008
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torresverdin, Richard Jackson, Peter Weinheber, Oliver C. Mullins, Mohamed Hashem
    Abstract:

    Acquisition of fluid samples is challenging in the presence of oil-Base Mud (OBM) filtrate invasion due to its partial or full miscibility with reservoir hydrocarbons. In the course of fluid sampling, varying concentrations of OBM will lead to variations of fluid properties such as viscosity, density, and gas-oil ratio (GOR). Contamination of OBM filtrate in the sampled fluid can drastically affect sample quality and lead to non-representative fluid properties. Fluid pumpout time can be extended to reduce filtrate contamination, although at the expense of increasing overall rig cost. A focused probe can be useful in reducing OBM contamination by diverting flow into different channels without compromising fluid pumpout time. However, it is important to properly quantify the relative performance of focused and conventional probes for a wide range of field conditions.

Carlos Torresverdin - One of the best experts on this subject based on the ideXlab platform.

  • sampling with new focused oval and conventional probe type formation tester in the presence of water and oil Base Mud filtrate invasion for vertical and high angle wells
    Journal of Petroleum Science and Engineering, 2014
    Co-Authors: Hamid Hadibeik, Kamy Sepehrnoori, Carlos Torresverdin, Mark A Proett, Renzo Angeles
    Abstract:

    Abstract Speculation about the potential of developing new fluid and pressure sampling methods with probe-type formation testers has existed since the introduction of formation pressure testing while drilling technology was introduced to the industry nearly a decade ago. To replace the existing wireline technology, a new pumping system is required to remove invasion fluids and then to fill single-phase sample chambers. To make this commercially possible, several technology enhancements are necessary in advance. Although wireline pumpout tools may require hours to retrieve representative fluid samples, it is not a practical alternative to spend hours obtaining samples in the drilling environment. Most simulations of wireline formation-tester measurements assumed that invasion ended at the time when fluid pumpout began. Additionally, previous studies assumed a time-constant rate of invasion that was the time average of invasion rate. Both of these assumptions are optimistic for a drilling tool. The objective of this study is to quantify the viability of sampling in the drilling environment by way of numerical simulations. The study considers the dynamic nature of invasion while drilling when using both new and conventional probe configurations to retrieve fluid samples. With the realistic Mudcake model, there are higher rates of invasion soon after drilling. Therefore, to simulate the invasion during drilling, a Mudcake model is used that continues to grow in thickness and sealing effectiveness during invasion and throughout the sampling process. Simulation results focus on scenarios in which water-Base Mud (WBM) and oil-Base Mud (OBM) invade an oil-bearing zone. Furthermore, it studied the accuracy of functions used to estimate contamination in an OBM environment. The Base model consists of a typical probe-type tool in a vertical well wherein fluid samples are retrieved using a time-constant flow rate. Invasion time is varied from 1 to 48 h to compare drilling and wireline sampling tools. Simulations of fluid cleanup times for a variety of rock types and wellbore deviation angles indicate that the oval focused probe retrieves the cleanest fluid sample in the least amount of time. This study also quantifies Mudcake sealing effectiveness, as well as the effect of borehole deviation. Oval (elongated) and focusing guard-style probes are compared to standard probe configurations in various petrophysical rock types.

  • fluid substitution analysis to correct borehole geophysical measurements acquired in gas bearing formations invaded by oil Base Mud
    Seg Technical Program Expanded Abstracts, 2012
    Co-Authors: Carlos Torresverdin
    Abstract:

    Summary Borehole geophysical measurements acquired in gas-bearing formations can be significantly influenced by oil-Base Mud (OBM) invasion. Fluid substitution of density and sonic logs in OBM-invaded gas-bearing formations is necessary but difficult because resistivity logs cannot differentiate the saturations of OBM filtrate and gas. Numerical simulations indicate that invasion of OBM filtrate into gas-bearing formations is typically shallower than 30 cm and exhibits a sharp saturation front. The radial invasion profile is largely controlled by the rock’s petrophysical properties under relatively stable drilling conditions. On the other hand, density and neutron logs are mainly sensitive to invasion shallower than 18 cm while slowness/velocity processed from sonic waveforms is only affected by invasion deeper than 18 cm. Therefore, accurate fluid substitution in OBM invaded gas-bearing formations requires pre-assessment of the radial invasion profile which is governed by pore geometry, i.e., petrophysical rock type. We introduce a new method to address this technical challenge by integrating fast numerical simulation of well logs under Mud-filtrate invasion and well-log Based petrophysical rock classification. A field example from Trinidad onshore deltaic gas reservoirs is used to validate the proposed method.

  • estimation of dynamic petrophysical properties of water bearing sands invaded with oil Base Mud from the interpretation of multiple borehole geophysical measurements
    Geophysics, 2012
    Co-Authors: Zoya Heidari, Carlos Torresverdin
    Abstract:

    ABSTRACTNonmiscible 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...

  • numerical investigation of oil Base Mud contamination in condensates from cleanup to sample quality
    Journal of Natural Gas Science and Engineering, 2010
    Co-Authors: Mayank Malik, Birol Dindoruk, Hani Elshahawi, Carlos Torresverdin
    Abstract:

    Abstract Formation Testers are widely used to determine pore pressure, estimate formation permeability, and detect reservoir connectivity through pressure transient testing after the onset of invasion. Mud filtrate invasion takes place in reservoirs penetrated by a well that is hydraulically overbalanced by Mud circulation, or due to capillary forces. In water-Base Muds (WBM), the invading Mud is immiscible with respect to the formation hydrocarbons. Therefore, water can be physically separated from the in-situ hydrocarbons leading to the best estimates of the in-situ PVT properties and thereby formation properties. Oil-Base Muds (OBM) are partially to completely miscible with the reservoir hydrocarbons, and so OBM contamination causes alteration of fluid properties which becomes even more critical for condensates when changes in fluid viscosity, density, and relative permeability occur. Due to the complexity of partial miscibility with gases and gas condensates, limited work has been done to simulate invasion by OBM. The goals of our work were to: 1. Determine conditions to obtain better samples. 2. Quantify the errors in numerical cleaning methods necessary for obtaining in-situ fluid compositions and properties. 3. Investigate the physics of the clean-up process. 4. Investigate the feasibility of tracers for monitoring contamination. Our results show that for condensates and lean gases, quantifying OBM contamination in terms of the live/bulk fluid alone can be misleading. For such fluids, contamination in the stock tank oil is just as critical as that of the bulk fluid because only the former predicts the errors in saturation pressures and CGR numbers observed in laboratory analyses. Lean fluids can take extremely long times to completely clean up during a formation test or even during a well test. For those fluids, it is more essential than ever to clearly define the primary objectives of the sampling program and to decide which answers are most critical.

  • estimation of dynamic petrophysical properties of water bearing sands invaded with oil Base Mud from multi physics borehole geophysical measurements
    Seg Technical Program Expanded Abstracts, 2010
    Co-Authors: Zoya Heidari, Carlos Torresverdin
    Abstract:

    Summary We develop and successfully test a new method to estimate permeability, capillary pressure, and relative permeability of water-bearing sands invaded with oil-Base Mud (OBM) from multi-physics borehole geophysical measurements. The inferred petrophysical properties of water-saturated sands are used for calibration of equivalent properties in hydrocarbon-bearing sands within the same sedimentary sequence. Our estimation method simulates the process of invasion between OBM and water. We iteratively adjust porosity, permeability (mobility), capillary pressure, and relative permeability in the simulation of invasion until density, PEF, neutron, and resistivity logs are accurately reproduced with numerical simulations from post-invasion radial distributions of water saturation. Examples of application include the cases of oil- and gasbearing 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 waterbearing portion of the reservoirs are in agreement with the vertical variations of water saturation above the free waterhydrocarbon contact, thereby valid ating our estimation method. Furthermore, we show that the radial distribution of water saturation inferred from resistivity and nuclear logs can be used for fluid-substitution analysis of sonic compressional and shear logs.

Kamy Sepehrnoori - One of the best experts on this subject based on the ideXlab platform.

  • Depth variation of wettability alteration during oil-Base Mud-filtrate invasion and corresponding effects on resistivity logs
    Journal of Petroleum Science and Engineering, 2016
    Co-Authors: Rohollah Abdollah-pour, Kamy Sepehrnoori, Carlos Torres-verdín, Zoha Nasizadeh
    Abstract:

    Abstract Resistivity logs acquired in hydrocarbon-bearing formations invaded by oil-Base Mud (OBM) often indicate abnormally high values of mobile water saturation. It is not possible to explain such abnormally high values of water saturation with saturation-height analysis. The common explanation invokes rock wettability alterations due to surfactants included in oil-Base Mud-filtrate (OBMF). A quantitative study is needed to explain whether the interaction of OBMF surfactants with water-wetted grains can cause a sufficiently large increase in mobile water saturation in the near-wellbore region to affect resistivity logs. In this paper, we use a near wellbore simulator to model the processes of Mud-filtrate invasion and ensuing wettability alteration once emulsifiers included in OBMF make contact with grain surfaces. We assume a wettability alteration model in which the degree and type of alteration are governed by the pore-volume concentration of emulsifier in OBMF within the invaded formation. Results indicate surfactants included in OBMF may change the rock's surface wettability from a water-wet to a neutral or oil-wet condition. This behavior causes a fraction of the originally residual pore volume of connate water to become moveable. The radial displacement of movable water by OBMF can give rise to an annulus of water bank, which in turn causes the resistivity annulus. We perform simulations of OBMF invasion into oil and gas saturated formations. Simulated apparent resistivity logs across layers which exhibited shallow invasion showed a reverse OBM effect where deep resistivity was larger than shallow resistivity.

  • 2007, “Influence of petrophysical and fluid properties on array-induction measurements acquired in the presence of oil-Base Mud-filtrate invasion,” paper AAA presented at the 48 th Annual Logging Symposium: Society of Petrophysicist and Well Log Analysts
    2015
    Co-Authors: Mayank Malik, Gong Li Wang, Carlos Torres-verdín, Jesús M. Salazar, Hee Jae Lee, Kamy Sepehrnoori
    Abstract:

    This paper quantifies the influence of petrophysical and fluid properties on array-induction resistivity measurements acquired in the presence of oil-Base Mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on componen

  • sampling with new focused oval and conventional probe type formation tester in the presence of water and oil Base Mud filtrate invasion for vertical and high angle wells
    Journal of Petroleum Science and Engineering, 2014
    Co-Authors: Hamid Hadibeik, Kamy Sepehrnoori, Carlos Torresverdin, Mark A Proett, Renzo Angeles
    Abstract:

    Abstract Speculation about the potential of developing new fluid and pressure sampling methods with probe-type formation testers has existed since the introduction of formation pressure testing while drilling technology was introduced to the industry nearly a decade ago. To replace the existing wireline technology, a new pumping system is required to remove invasion fluids and then to fill single-phase sample chambers. To make this commercially possible, several technology enhancements are necessary in advance. Although wireline pumpout tools may require hours to retrieve representative fluid samples, it is not a practical alternative to spend hours obtaining samples in the drilling environment. Most simulations of wireline formation-tester measurements assumed that invasion ended at the time when fluid pumpout began. Additionally, previous studies assumed a time-constant rate of invasion that was the time average of invasion rate. Both of these assumptions are optimistic for a drilling tool. The objective of this study is to quantify the viability of sampling in the drilling environment by way of numerical simulations. The study considers the dynamic nature of invasion while drilling when using both new and conventional probe configurations to retrieve fluid samples. With the realistic Mudcake model, there are higher rates of invasion soon after drilling. Therefore, to simulate the invasion during drilling, a Mudcake model is used that continues to grow in thickness and sealing effectiveness during invasion and throughout the sampling process. Simulation results focus on scenarios in which water-Base Mud (WBM) and oil-Base Mud (OBM) invade an oil-bearing zone. Furthermore, it studied the accuracy of functions used to estimate contamination in an OBM environment. The Base model consists of a typical probe-type tool in a vertical well wherein fluid samples are retrieved using a time-constant flow rate. Invasion time is varied from 1 to 48 h to compare drilling and wireline sampling tools. Simulations of fluid cleanup times for a variety of rock types and wellbore deviation angles indicate that the oval focused probe retrieves the cleanest fluid sample in the least amount of time. This study also quantifies Mudcake sealing effectiveness, as well as the effect of borehole deviation. Oval (elongated) and focusing guard-style probes are compared to standard probe configurations in various petrophysical rock types.

  • Miscibility Effects of Oil-Base Mud and In-Situ Gas on Conventional Well Logs
    2013
    Co-Authors: Hamid Hadibeik, Carlos Torres-verdín, Essi Kwabi, Kamy Sepehrnoori
    Abstract:

    Oil-Base Muds (OBMs) are often preferred over water-Base Muds for many applications, including hostile environments such as high-temperature, high-pressure drilling. However, because the Base fluid in OBM is oil, OBM filtrate tends to mix readily with reservoir hydrocarbon during invasion. When reservoir hydrocarbon and OBM filtrate properties are not similar, as is in the case of gas-bearing formations, near wellbore fluid properties can be greatly affected by invasion. Consequently, wireline logs such as neutron, density, sonic, and nuclear magnetic resonance (NMR) can be affected by compositional fluid mixing. Recent field data collected in deepwater plays show that fluid miscibility effects could explain questionable nuclear-log readings across gas reservoirs. This study investigates and quantifies thermodynamic reservoir conditions that facilitate reservoir gas dissolution into OBM filtrate during invasion and the consequent effect on neutron-density logs. Phase behavior of hydrocarbon fluids indicates that any multi-component system, under given temperature and pressure conditions, would exist either in a single phase (liquid or gas) or in multiple phases (liquid and gas). During invasion, formation gas and OBM filtrate form a multi-component system which, under favorable conditions, can exist as a single liquid phase due to the dissolution of formation gas into OBM filtrate. As a result, the large cross-over between neutron-density logs, normally observed within a gas-bearing formation, is significantly reduced by gas-OBM miscibility. Other dynamic reservoir properties, such as wettability, have a less intuitive, yet significant effect on neutron-density logs, thereby requiring a more challenging petrophysical interpretation of well logs. This abnormal gas- OBM miscibility effect could have a measurable impact on formation-tester, NMR, and sonic measurements. We use the University of Texas at Austin’s Petrophysical and Well-Log Simulator (UTAPWeLS) to construct synthetic models to study OBM-gas miscibility effects under various reservoir conditions. The roles of pressure, temperature, overbalance pressure and invasion time, and wettability on OBM-gas miscibility are quantified to identify conditions that enable fluid miscibility. Results indicate that high reservoir pressure, low temperature, high overbalance pressure, and increased invasion time facilitate gas dissolution into OBM filtrate, hence a reduction in neutron-density cross-over. Water-wet systems also provide a favorable condition for the same phenomenon. It is therefore imperative to consider invasion and fluid miscibility during petrophysical interpretations of logs acquired in OBM-drilled wells. The integration of dynamic and static measurements prevents bypassing and/or misidentification of gas-bearing reservoirs for oil- or even water-bearing reservoirs.

  • QUANTIFYING WETTABILITY ALTERATION DURING OIL-Base Mud-FILTRATE INVASION AND CORRESPONDING EFFECTS ON RESISTIVITY LOGS
    2011
    Co-Authors: Rohollah A. Pour, Carlos Torres-verdín, Kamy Sepehrnoori
    Abstract:

    Resistivity logs acquired in hydrocarbon-bearing formations invaded by oil-Base Mud (OBM) often indicate abnormally high values of mobile water saturation. It is not possible to explain such abnormally high values of water saturation with saturation-height analysis. The common explanation invokes rock wettability alterations due to surfactants included in oilBase Mud-filtrate (OBMF). A quantitative study is needed to explain whether interaction of OBMF surfactants with water-wetted grains can cause a sufficiently large increase in mobile water saturation in the near-wellbore region. We develop a new equation-of-state compositional simulator for near-wellbore applications. The simulator models the processes of Mud-filtrate invasion and ensuing wettability alterations once emulsifiers included in OBMF make contact with grain surfaces. We assume a wettability alteration model in which the degree and type of alteration are governed by the porevolume concentration of emulsifier in OBMF within the invaded formation. Sensitivity analyses on different Mudcake properties quantify the effect of each Mudcake property on the radial distributions of water saturation and electrical resistivity resulting from invasion. Simulation results confirm that irreducible water saturation decreases as grain surfaces make contact with OBMF emulsifiers. The reduction of irreducible water saturation causes a portion of connate water to become mobile, with the percentage of additional movable water depending on both type of Mud-filtrate and degree of wettability alteration. It is found that additional movable water saturation released by wettability alteration can give rise to a radial annulus of abnormally low electrical resistivity. This behavior is consistent with observations made of apparent resistivity logs acquired in OBMF invaded formations. Numerically simulated radial distributions of electrical resistivity also explain the separation of apparent resistivity logs often observed in hydrocarbon-saturated formations invaded with OBM. Comparison of radial profiles of electrical resistivity simulated for various rock types confirms that dynamic petrophysical properties of invaded formations can have a significant effect on the degree of wettability alteration due to OBMF.

Carlos Torres-verdín - One of the best experts on this subject based on the ideXlab platform.

  • Depth variation of wettability alteration during oil-Base Mud-filtrate invasion and corresponding effects on resistivity logs
    Journal of Petroleum Science and Engineering, 2016
    Co-Authors: Rohollah Abdollah-pour, Kamy Sepehrnoori, Carlos Torres-verdín, Zoha Nasizadeh
    Abstract:

    Abstract Resistivity logs acquired in hydrocarbon-bearing formations invaded by oil-Base Mud (OBM) often indicate abnormally high values of mobile water saturation. It is not possible to explain such abnormally high values of water saturation with saturation-height analysis. The common explanation invokes rock wettability alterations due to surfactants included in oil-Base Mud-filtrate (OBMF). A quantitative study is needed to explain whether the interaction of OBMF surfactants with water-wetted grains can cause a sufficiently large increase in mobile water saturation in the near-wellbore region to affect resistivity logs. In this paper, we use a near wellbore simulator to model the processes of Mud-filtrate invasion and ensuing wettability alteration once emulsifiers included in OBMF make contact with grain surfaces. We assume a wettability alteration model in which the degree and type of alteration are governed by the pore-volume concentration of emulsifier in OBMF within the invaded formation. Results indicate surfactants included in OBMF may change the rock's surface wettability from a water-wet to a neutral or oil-wet condition. This behavior causes a fraction of the originally residual pore volume of connate water to become moveable. The radial displacement of movable water by OBMF can give rise to an annulus of water bank, which in turn causes the resistivity annulus. We perform simulations of OBMF invasion into oil and gas saturated formations. Simulated apparent resistivity logs across layers which exhibited shallow invasion showed a reverse OBM effect where deep resistivity was larger than shallow resistivity.

  • 2007, “Influence of petrophysical and fluid properties on array-induction measurements acquired in the presence of oil-Base Mud-filtrate invasion,” paper AAA presented at the 48 th Annual Logging Symposium: Society of Petrophysicist and Well Log Analysts
    2015
    Co-Authors: Mayank Malik, Gong Li Wang, Carlos Torres-verdín, Jesús M. Salazar, Hee Jae Lee, Kamy Sepehrnoori
    Abstract:

    This paper quantifies the influence of petrophysical and fluid properties on array-induction resistivity measurements acquired in the presence of oil-Base Mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on componen

  • Miscibility Effects of Oil-Base Mud and In-Situ Gas on Conventional Well Logs
    2013
    Co-Authors: Hamid Hadibeik, Carlos Torres-verdín, Essi Kwabi, Kamy Sepehrnoori
    Abstract:

    Oil-Base Muds (OBMs) are often preferred over water-Base Muds for many applications, including hostile environments such as high-temperature, high-pressure drilling. However, because the Base fluid in OBM is oil, OBM filtrate tends to mix readily with reservoir hydrocarbon during invasion. When reservoir hydrocarbon and OBM filtrate properties are not similar, as is in the case of gas-bearing formations, near wellbore fluid properties can be greatly affected by invasion. Consequently, wireline logs such as neutron, density, sonic, and nuclear magnetic resonance (NMR) can be affected by compositional fluid mixing. Recent field data collected in deepwater plays show that fluid miscibility effects could explain questionable nuclear-log readings across gas reservoirs. This study investigates and quantifies thermodynamic reservoir conditions that facilitate reservoir gas dissolution into OBM filtrate during invasion and the consequent effect on neutron-density logs. Phase behavior of hydrocarbon fluids indicates that any multi-component system, under given temperature and pressure conditions, would exist either in a single phase (liquid or gas) or in multiple phases (liquid and gas). During invasion, formation gas and OBM filtrate form a multi-component system which, under favorable conditions, can exist as a single liquid phase due to the dissolution of formation gas into OBM filtrate. As a result, the large cross-over between neutron-density logs, normally observed within a gas-bearing formation, is significantly reduced by gas-OBM miscibility. Other dynamic reservoir properties, such as wettability, have a less intuitive, yet significant effect on neutron-density logs, thereby requiring a more challenging petrophysical interpretation of well logs. This abnormal gas- OBM miscibility effect could have a measurable impact on formation-tester, NMR, and sonic measurements. We use the University of Texas at Austin’s Petrophysical and Well-Log Simulator (UTAPWeLS) to construct synthetic models to study OBM-gas miscibility effects under various reservoir conditions. The roles of pressure, temperature, overbalance pressure and invasion time, and wettability on OBM-gas miscibility are quantified to identify conditions that enable fluid miscibility. Results indicate that high reservoir pressure, low temperature, high overbalance pressure, and increased invasion time facilitate gas dissolution into OBM filtrate, hence a reduction in neutron-density cross-over. Water-wet systems also provide a favorable condition for the same phenomenon. It is therefore imperative to consider invasion and fluid miscibility during petrophysical interpretations of logs acquired in OBM-drilled wells. The integration of dynamic and static measurements prevents bypassing and/or misidentification of gas-bearing reservoirs for oil- or even water-bearing reservoirs.

  • Assessment of Residual Hydrocarbon Saturation with the Combined Quantitative Interpretation of Resistivity and Nuclear Logs
    Petrophysics, 2011
    Co-Authors: Zoya Heidari, Alberto Mendoza, Carlos Torres-verdín, Gong Li Wang
    Abstract:

    Estimation of residual hydrocarbon saturation remains an outstanding challenge in formation evaluation and core analysis. Standard interpretation methods for nuclear-resistivity logs cannot distinguish between mobile and residual hydrocarbon saturation. In extreme cases, fluid pumpout or production testing are the only options to ascertain whether the reservoir's in-situ hydrocarbon is mobile. We develop a new method to distinguish mobile from residual hydrocarbon and to quantify residual hydrocarbon saturation. The method combines modeling of resistivity and nuclear logs with the physics of Mud-filtrate invasion to quantify the effect of residual hydrocarbon saturation on both nuclear and resistivity logs. This strategy explicitly takes into account the different volumes of investigation of resistivity and nuclear measurements and does not assume that the near-borehole region is flushed to the level of residual hydrocarbon saturation. The method begins with an initial multi-layer petrophysical model which is constructed via standard procedures of well-log interpretation and core measurements. Thereafter, we simulate the physics of Mud-filtrate invasion and the corresponding resistivity, density, and neutron logs. Initial estimates of residual hydrocarbon saturation and parametric relative permeability are refined until achieving a good agreement between simulated and measured neutron and density logs. Next, we refine initial estimates of water saturation, porosity, and permeability until securing a good match between numerically simulated and measured resistivity logs. The method of interpretation considers two specific options for implementation: (1) quantification of the influence of residual hydrocarbon saturation on the radial distribution of fluid saturation due to invasion, and (2) appraisal of invasion effects on the vertical distribution of fluid saturation within a flow unit that exhibits both hydrocarbon and water saturation in capillary equilibrium. Application examples are described for the cases of tight-gas sand reservoirs invaded with water-Base Mud (WBM) and oil-bearing reservoirs invaded with oil-Base Mud (OBM). In the case of tight-gas sands, our method explains the marginal productivity of deeply invaded beds that exhibit cross-over between density and neutron logs. For a 15-porosity unit formation, when the residual gas saturation increases by 10 saturation units, the cross-over between neutron and density logs increases by 2.4 porosity units. Interpretation results indicate measurable sensitivity of nuclear logs to residual hydrocarbon saturation in cases of deep WBM invasion due to immiscibility between invaded and in-situ fluids. However, the accuracy of the method decreases with increasing values of both hydrocarbon pore volume and hydrocarbon density. In the case of OBM invasion, reliable estimations of residual hydrocarbon saturation are possible with relative density differences above 15 percent between Mud filtrate and in-situ hydrocarbon.

  • QUANTIFYING WETTABILITY ALTERATION DURING OIL-Base Mud-FILTRATE INVASION AND CORRESPONDING EFFECTS ON RESISTIVITY LOGS
    2011
    Co-Authors: Rohollah A. Pour, Carlos Torres-verdín, Kamy Sepehrnoori
    Abstract:

    Resistivity logs acquired in hydrocarbon-bearing formations invaded by oil-Base Mud (OBM) often indicate abnormally high values of mobile water saturation. It is not possible to explain such abnormally high values of water saturation with saturation-height analysis. The common explanation invokes rock wettability alterations due to surfactants included in oilBase Mud-filtrate (OBMF). A quantitative study is needed to explain whether interaction of OBMF surfactants with water-wetted grains can cause a sufficiently large increase in mobile water saturation in the near-wellbore region. We develop a new equation-of-state compositional simulator for near-wellbore applications. The simulator models the processes of Mud-filtrate invasion and ensuing wettability alterations once emulsifiers included in OBMF make contact with grain surfaces. We assume a wettability alteration model in which the degree and type of alteration are governed by the porevolume concentration of emulsifier in OBMF within the invaded formation. Sensitivity analyses on different Mudcake properties quantify the effect of each Mudcake property on the radial distributions of water saturation and electrical resistivity resulting from invasion. Simulation results confirm that irreducible water saturation decreases as grain surfaces make contact with OBMF emulsifiers. The reduction of irreducible water saturation causes a portion of connate water to become mobile, with the percentage of additional movable water depending on both type of Mud-filtrate and degree of wettability alteration. It is found that additional movable water saturation released by wettability alteration can give rise to a radial annulus of abnormally low electrical resistivity. This behavior is consistent with observations made of apparent resistivity logs acquired in OBMF invaded formations. Numerically simulated radial distributions of electrical resistivity also explain the separation of apparent resistivity logs often observed in hydrocarbon-saturated formations invaded with OBM. Comparison of radial profiles of electrical resistivity simulated for various rock types confirms that dynamic petrophysical properties of invaded formations can have a significant effect on the degree of wettability alteration due to OBMF.

Birol Dindoruk - One of the best experts on this subject based on the ideXlab platform.

  • numerical investigation of oil Base Mud contamination in condensates from cleanup to sample quality
    Journal of Natural Gas Science and Engineering, 2010
    Co-Authors: Mayank Malik, Birol Dindoruk, Hani Elshahawi, Carlos Torresverdin
    Abstract:

    Abstract Formation Testers are widely used to determine pore pressure, estimate formation permeability, and detect reservoir connectivity through pressure transient testing after the onset of invasion. Mud filtrate invasion takes place in reservoirs penetrated by a well that is hydraulically overbalanced by Mud circulation, or due to capillary forces. In water-Base Muds (WBM), the invading Mud is immiscible with respect to the formation hydrocarbons. Therefore, water can be physically separated from the in-situ hydrocarbons leading to the best estimates of the in-situ PVT properties and thereby formation properties. Oil-Base Muds (OBM) are partially to completely miscible with the reservoir hydrocarbons, and so OBM contamination causes alteration of fluid properties which becomes even more critical for condensates when changes in fluid viscosity, density, and relative permeability occur. Due to the complexity of partial miscibility with gases and gas condensates, limited work has been done to simulate invasion by OBM. The goals of our work were to: 1. Determine conditions to obtain better samples. 2. Quantify the errors in numerical cleaning methods necessary for obtaining in-situ fluid compositions and properties. 3. Investigate the physics of the clean-up process. 4. Investigate the feasibility of tracers for monitoring contamination. Our results show that for condensates and lean gases, quantifying OBM contamination in terms of the live/bulk fluid alone can be misleading. For such fluids, contamination in the stock tank oil is just as critical as that of the bulk fluid because only the former predicts the errors in saturation pressures and CGR numbers observed in laboratory analyses. Lean fluids can take extremely long times to completely clean up during a formation test or even during a well test. For those fluids, it is more essential than ever to clearly define the primary objectives of the sampling program and to decide which answers are most critical.

  • Comparison of Wireline Formation-Tester Sampling with Focused and Conventional Probes in the Presence of Oil-Base Mud-Filtrate Invasion
    2009
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torres-verdín, Richard Jackson, Peter Weinheber, Oliver C. Mullins, Mohamed Hashem
    Abstract:

    In the course of fluid sampling, varying concentrations of oil Base Mud (OBM) will lead to variations of fluid properties such as viscosity, density, and gas-oil ratio (GOR). A focused probe can be useful in reducing OBM contamination by diverting flow into different channels without compromising fluid pumpout time. However, it is important to properly quantify the relative performance of focused and conventional probes for a wide range of field conditions. The objective of this paper is to appraise the performance of different probes under the same simulated field conditions and for a comprehensive set of petrophysical and fluid properties. Results indicate that sample quality generally improves when the flow is split between the guard and sample probes, but the specific amount of improvement depends on probe geometry, fluid composition, and formation properties. Permeability anisotropy, presence of a flow boundary, and lack of Mud-filtrate invasion can help to improve sample quality. In addition, fluid cleanup can be accelerated by altering both the probe design and the flow-rate ratio between the sample and guard fluid streams, thereby leading to increased pressure differential between the sample and guard areas and enhancing the "coning" of the Mud-filtrate invasion front.

  • comparison of wireline formation tester sampling with focused and conventional probes in the presence of oil Base Mud filtrate invasion
    Petrophysics, 2008
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torresverdin, Richard Jackson, Peter Weinheber, Oliver C. Mullins, Mohamed Hashem
    Abstract:

    Acquisition of fluid samples is challenging in the presence of oil-Base Mud (OBM) filtrate invasion due to its partial or full miscibility with reservoir hydrocarbons. In the course of fluid sampling, varying concentrations of OBM will lead to variations of fluid properties such as viscosity, density, and gas-oil ratio (GOR). Contamination of OBM filtrate in the sampled fluid can drastically affect sample quality and lead to non-representative fluid properties. Fluid pumpout time can be extended to reduce filtrate contamination, although at the expense of increasing overall rig cost. A focused probe can be useful in reducing OBM contamination by diverting flow into different channels without compromising fluid pumpout time. However, it is important to properly quantify the relative performance of focused and conventional probes for a wide range of field conditions.

  • History matching and sensitivity analysis of probe-type formation-tester measurements acquired in the presence of oil-Base Mud-filtrate invasion
    Petrophysics, 2007
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torres-verdín, Mohamed Naguib Hashem
    Abstract:

    The acquisition of contamination-free fluid samples in hydrocarbon reservoirs drilled with oil-Base Mud (OBM) is challenging due to the presence of multiple fluid phases as well as partial-to-complete miscibility between reservoir fluids and OBM. Throughout the sampling process, varying concentrations of OBM contained in the sampled fluid will lead to changes in observed (apparent) fluid properties. Similarly, sand-face transient pressure measurements are affected by OBM invasion as the invasion process itself modifies both fluid viscosity and fluid density in the near-wellbore region due to mixing between different hydrocarbon components. We use a commercial adaptive-implicit compositional numerical simulator to model the filtrate cleanup process during fluid sampling and to compare the predicted pressure and apparent fluid properties at the sand-face against observed field measurements. A history-matching approach is used to estimate formation permeability and permeability anisotropy. We apply the proposed workflow to three sets of field measurements of sink probe pressure, observation probe pressure, gas-oil ratio (GOR), and flow rate acquired with a formation tester in light-oil formations. Since the formation is invaded with oil-Base Mud filtrate that is assumed free of gas, GOR can be used to discriminate between fluids. We use a dimensionless fluid contamination function to relate transient GOR measurements to sample fluid quality. The successful comparison of simulations to field measurements helps us to diagnose and quantify adverse data-acquisition conditions such as plugging and noisy transient data. It is found that numerical simulations are a reliable way to verify the internal consistency of the transient measurements of flow rate, pressure, and GOR in the presence of biasing acquisition problems. We perform sensitivity analyses to identify the dominant governing parameters such as formation properties, formation-tester flow rates, relative permeability, and radial extent of Mud-filtrate invasion, on transient measurements of sand-face pressure and sampled fluid contamination. Our observation is that transient pressure, GOR, and density variations are sensitive to both the radial extent of Mud-filtrate invasion and the rate of fluid cleanup. If the radial length of invasion is large, the total pumped volume must be increased in order to retrieve representative fluid samples. This can be achieved either by increasing the duration of the test, using higher rates of fluid withdrawal, or both.

  • Field Examples Of History Matching Of Formation Tester Measurements Acquired In The Presence Of OilBase Mud-Filtrate Invasion
    2007
    Co-Authors: Mayank Malik, Birol Dindoruk, Kamy Sepehrnoori, Hani Elshahawi, Carlos Torres-verdín, Mohamed Hashem
    Abstract:

    The acquisition of fluid samples in hydrocarbon reservoirs drilled with oil-Base Mud (OBM) is challenging due to both presence of multiple phases as well as partial-to-complete miscibility between reservoir fluids and OBM. Throughout the sampling process, varying concentrations of OBM will lead to changes in observed (apparent) fluid properties. Similarly, sand-face transient pressure measurements are affected by OBM as the invasion process itself modifies both fluid viscosity and fluid density in the near-wellbore region due to mixing between different hydrocarbon components. We use a commercial adaptive-implicit compositional method to simulate the filtrate cleanup process during fluid sampling and compare the predicted pressure and apparent fluid properties at the sand-face against observed field measurements. A history matching approach is used to estimate formation permeability and permeability anisotropy. We apply the proposed workflow to three sets of transient field measurements of sink probe pressure, observation probe pressure, gas-oil ratio (GOR), and flow rate acquired with a formation tester in light-oil formations. Since the formation is invaded by oil-Base Mud filtrate, GOR can be used to diagnose types of fluids. We use a dimensionless fluid contamination function to relate transient GOR measurements to sample fluid quality. The successful comparison to field measurements validates our simulation model and helps us to diagnose and quantify adverse data-acquisition conditions such as plugging and noisy data. We perform sensitivity analyses to identify the dominant governing parameters such as formation properties, formation tester flow rates, relative permeability, and radial length of Mud-filtrate invasion, on transient measurements of sand-face pressure and fluid contamination function. Our observation is that transient pressure, GOR, and density variations are sensitive to both the radial length of Mud-filtrate invasion and the rate of fluid cleanup. If the radial length of invasion is large, then the total pumped volume must be increased in order to retrieve representative fluid samples. This can de achieved either by increasing the duration of the test, using higher rates of fluid withdrawal, or both.