Fluid substitution in sandstone: Effective porosity or total porosity

2015 ◽  
Author(s):  
Morten Kanne Soerensen* ◽  
Ida Lykke Fabricius
Keyword(s):  
Total Porosity ◽  
Effective Porosity ◽  
Fluid Substitution

scholarly journals Fluid substitution in shaley sediment using effective porosity

Geophysics ◽  
2007 ◽  
Vol 72 (3) ◽  
pp. O1-O8 ◽  
Author(s):  
Jack Dvorkin ◽  
Gary Mavko ◽  
Boris Gurevich
Keyword(s):  
Elastic Modulus ◽  
Pore Space ◽  
Total Porosity ◽  
Effective Porosity ◽  
Fluid Substitution ◽  
Mineral Phase ◽  
Hydrocarbon Production ◽  
System A ◽  
Alternative Method ◽  
Water Saturated

The traditional method of fluid substitution in porous rock requires the total porosity and the elastic modulus of the mineral phase as input and assumes that the fluid reaches instantaneous hydraulic equilibrium throughout the pore space. This assumption may not be appropriate for shaley sediment because of the low permeability of shale and the resulting immobility of the water in it. To address this problem, we propose an alternative method that uses effective porosity instead of total porosity. Effective porosity is lower than total porosity if porous shale is present in the system. A new, composite mineral phase is introduced, which includes the porous water-saturated shale together with the nonporous minerals and whose elastic modulus is an average of those of its components, including the porous shale. This alternative method increases the sensitivity of the elastic properties of sediment-to-pore-fluid changes and therefore may be used as a physics-based theoretical tool to better explain and interpret seismic data during exploration as well as variations in seismic response as hydrocarbon production progresses.

THE STAG OILFIELD

1996 ◽  
Vol 36 (1) ◽  
pp. 130 ◽  
Author(s):  
J. Crowley ◽  
E.S. Collins
Keyword(s):  
Water Saturation ◽  
Vertical Section ◽  
Far East ◽  
Total Porosity ◽  
Analysis Data ◽  
Effective Porosity ◽  
Seismic Survey ◽  
North West ◽  
The North ◽  
Southeastern Margin

The Stag Oilfield is located approximately 65 km northwest of Dampier and 25 km southwest of the Wandoo Oilfield near the southeastern margin of the Dampier Sub-basin, on the North West Shelf of Western Australia,.The Stag-1 discovery well was funded by Apache Energy Ltd (formerly Hadson Energy Ltd), Santos Ltd and Globex Far East in June 1993 under a farmin agreement with BHP Petroleum Pty Ltd, Norcen International Ltd and Phillips Australian Oil Co. The well intersected a gross oil column of 15.5 m within the Lower Cretaceous M. australis Sandstone. The oil column intersected at Stag-1 was thicker than the pre-drill mapped structural closure.A 3D seismic survey was acquired over the Stag area in November 1993 to define the size and extent of the accumulation. Following processing and interpretation of the data, an exploration and appraisal program was undertaken. The appraisal wells confirmed that the oil column exceeds mapped structural closure and that there is a stratigraphic component to the trapping mechanism. Two of the appraisal wells were tested; Stag-2 flowed 1050 BOPD from a 5 m vertical section and Stag-6 flowed at 6300 BOPD on pump from a 1030 m horizontal section.Evaluation of the well data indicates the M. australis Sandstone at the Stag Oilfield is genetically related to the reservoir section at the Wandoo Oilfield. The reservoir consists of bioturbated glauconitic subarkose and is interpreted to represent deposition that occurred on a quiescent broad marine shelf. Quantitative evaluation of the oil-in-place has been hampered by the effects of glauconite on wireline log, routine and special core analysis data. Petrophysical evaluation indicates that core porosities and water saturations derived from capillary pressure measurements more closely match total porosity and total water saturation than effective porosity and effective water saturation.A development plan is currently being prepared and additional appraisal drilling in the field is expected.

scholarly journals Characterization of Mishrif Formation Reservoir in Amara Oil Field, Southeast Iraq, Using Geophysical Well-logging

2021 ◽  
pp. 4702-4711
Author(s):  
Asmaa Talal Fadel ◽  
Madhat E. Nasser
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Reservoir Water ◽  
Resistivity Logs ◽  
Reliable Knowledge

     Reservoir characterization requires reliable knowledge of certain fundamental properties of the reservoir. These properties can be defined or at least inferred by log measurements, including porosity, resistivity, volume of shale, lithology, water saturation, and permeability of oil or gas. The current research is an estimate of the reservoir characteristics of Mishrif Formation in Amara Oil Field, particularly well AM-1, in south eastern Iraq. Mishrif Formation (Cenomanin-Early Touronin) is considered as the prime reservoir in Amara Oil Field. The Formation is divided into three reservoir units (MA, MB, MC). The unit MB is divided into two secondary units (MB1, MB2) while the unit MC is also divided into two secondary units (MC1, MC2). Using Geoframe software, the available well log images (sonic, density, neutron, gamma ray, spontaneous potential, and resistivity logs) were digitized and updated. Petrophysical properties, such as porosity, saturation of water, saturation of hydrocarbon, etc. were calculated and explained. The total porosity was measured using the density and neutron log, and then corrected to measure the effective porosity by the volume content of clay. Neutron -density cross-plot showed that Mishrif Formation lithology consists predominantly of limestone. The reservoir water resistivity (Rw) values of the Formation were calculated using Pickett-Plot method.   

scholarly journals Petrophysical Properties and Well Log Interpretations of Tertiary Reservoir in Khabaz Oil Field / Northern Iraq

2020 ◽  
Vol 26 (6) ◽  
pp. 18-34
Author(s):  
Yousif Najeeb Abdul-majeed ◽  
Ahmad Abdullah Ramadhan ◽  
Ahmed Jubiar Mahmood
Keyword(s):  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Petrophysical Properties ◽  
Secondary Porosity ◽  
Northern Iraq ◽  
Sonic Log ◽  
Oil Concentration

The aim of this study is interpretation well logs to determine Petrophysical properties of tertiary reservoir in Khabaz oil field using IP software (V.3.5). The study consisted of seven wells which distributed in Khabaz oilfield. Tertiary reservoir composed from mainly several reservoir units. These units are : Jeribe, Unit (A), Unit (A'), Unit (B), Unit (BE), Unit (E),the Unit (B) considers best reservoir unit because it has good Petrophysical properties (low water saturation and high porous media ) with high existence of hydrocarbon in this unit. Several well logging tools such as Neutron, Density, and Sonic log were used to identify total porosity, secondary porosity, and effective porosity in tertiary reservoir. For Lithological identification for tertiary reservoir units using (NPHI-RHOB) cross plot composed of dolomitic-limestone and mineralogical identification using (M/N) cross plot consist of calcite and dolomite. Shale content was estimated less than (8%) for all wells in Khabaz field. CPI results were applied for all wells in Khabaz field which be clarified movable oil concentration in specific units are: Unit (B), Unit (A') , small interval of Jeribe formation , and upper part of Unit (EB).

scholarly journals Evaluation of Mishrif Reservoir in Abu Amood Oil Field, Southern Iraq

2021 ◽  
pp. 4758-4768
Author(s):  
Ahmed Hussain ◽  
Medhat E. Nasser ◽  
Ghazi Hassan
Keyword(s):  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Well Logs ◽  
Neutron Density ◽  
High Porosity ◽  
Petrophysical Properties ◽  
Density Method ◽  
Southern Iraq

     The main goal of this study is to evaluate Mishrif Reservoir in Abu Amood oil field, southern Iraq, using the available well logs. The sets of logs were acquired for wells AAm-1, AAm-2, AAm-3, AAm-4, and AAm-5. The evaluation included the identification of the reservoir units and the calculation of their petrophysical properties using the Techlog software. Total porosity was calculated using the neutron-density method and the values were corrected from the volume of shale in order to calculate the effective porosity. Computer processed interpretation (CPI) was accomplished for the five wells. The results show that Mishrif Formation in Abu Amood field consists of three reservoir units with various percentages of hydrocarbons that were concentrated in all of the three units, but in different wells. All of the units have high porosity, especially unit two, although it is saturated with water.

scholarly journals Properties of Mortar with Recycled Aggregates, and Polyacrylonitrile Microfibers Synthesized by Electrospinning

Materials ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 3849 ◽  
Author(s):  
Manuel J. Chinchillas-Chinchillas ◽  
Manuel J. Pellegrini-Cervantes ◽  
Andrés Castro-Beltrán ◽  
Margarita Rodríguez-Rodríguez ◽  
Víctor M. Orozco-Carmona ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Compressive Strength ◽  
Flexural Strength ◽  
Total Porosity ◽  
Cementitious Materials ◽  
Effective Porosity ◽  
Recycled Aggregates ◽  
Capillary Absorption ◽  
Fine Aggregate ◽  
Water Penetration

Currently it is necessary to find alternatives towards a sustainable construction, in order to optimize the management of natural resources. Thus, using recycled fine aggregate (RFA) is a viable recycling option for the production of new cementitious materials. In addition, the use of polymeric microfibers would cause an increase in the properties of these materials. In this work, mortars were studied with 25% of RFA and an addition of polyacrylonitrile PAN microfibers of 0.05% in cement weight. The microfibers were obtained by the electrospinning method, which had an average diameter of 1.024 µm and were separated by means of a homogenizer to be added to the mortar. Cementing materials under study were evaluated for compressive strength, flexural strength, total porosity, effective porosity and capillary absorption, resistance to water penetration, sorptivity and carbonation. The results showed that using 25% of RFA causes decreases mechanical properties and durability, but adding PAN microfibers in 0.05% caused an increase of 2.9% and 30.8% of compressive strength and flexural strength respectively (with respect to the reference sample); a decrease in total porosity of 5.8% and effective porosity of 7.4%; and significant decreases in capillary absorption (approximately 23.3%), resistance to water penetration (25%) and carbonation (14.3% after 28 days of exposure). The results showed that the use of PAN microfibers in recycled mortars allowed it to increase the mechanical properties (because they increase the tensile strength), helped to fill pores or cavities and this causes them to be mortars with greater durability. Therefore, the use of PAN microfibers as a reinforcement in recycled cementitious materials would be a viable option to increase their applications.

scholarly journals Comparative Porosity and Pore Structure Assessment in Shales: Measurement Techniques, Influencing Factors and Implications for Reservoir Characterization

Energies ◽  
2019 ◽  
Vol 12 (11) ◽  
pp. 2094 ◽  
Author(s):  
Yujie Yuan ◽  
Reza Rezaee
Keyword(s):  
Pore Structure ◽  
Gas Adsorption ◽  
Measurement Techniques ◽  
Bound Water ◽  
Total Porosity ◽  
Low Pressure ◽  
Effective Porosity ◽  
Shale Formations ◽  
Helium Expansion ◽  
The Impact

Porosity and pore size distribution (PSD) are essential petrophysical parameters controlling permeability and storage capacity in shale gas reservoirs. Various techniques to assess pore structure have been introduced; nevertheless, discrepancies and inconsistencies exist between each of them. This study compares the porosity and PSD in two different shale formations, i.e., the clay-rich Permian Carynginia Formation in the Perth Basin, Western Australia, and the clay-poor Monterey Formation in San Joaquin Basin, USA. Porosity and PSD have been interpreted based on nuclear magnetic resonance (NMR), low-pressure N2 gas adsorption (LP-N2-GA), mercury intrusion capillary pressure (MICP) and helium expansion porosimetry. The results highlight NMR with the advantage of detecting the full-scaled size of pores that are not accessible by MICP, and the ineffective/closed pores occupied by clay bound water (CBW) that are not approachable by other penetration techniques (e.g., helium expansion, low-pressure gas adsorption and MICP). The NMR porosity is largely discrepant with the helium porosity and the MICP porosity in clay-rich Carynginia shales, but a high consistency is displayed in clay-poor Monterey shales, implying the impact of clay contents on the distinction of shale pore structure interpretations between different measurements. Further, the CBW, which is calculated by subtracting the measured effective porosity from total porosity, presents a good linear correlation with the clay content (R2 = 0.76), implying that our correlated equation is adaptable to estimate the CBW in shale formations with the dominant clay type of illite.

scholarly journals Nano- to Millimeter Scale Morphology of Connected and Isolated Porosity in the Permo-Triassic Khuff Formation of Oman

Geosciences ◽  
2019 ◽  
Vol 10 (1) ◽  
pp. 7 ◽  
Author(s):  
Jörg Smodej ◽  
Laurent Lemmens ◽  
Lars Reuning ◽  
Thomas Hiller ◽  
Norbert Klitzsch ◽  
...  
Keyword(s):  
Pore Size ◽  
Ion Beam ◽  
Total Porosity ◽  
Oil And Gas Industry ◽  
Effective Porosity ◽  
Carbonate Reservoir ◽  
Size Spectrum ◽  
Pore Connectivity ◽  
Rock Types ◽  
Laboratory Techniques

Carbonate reservoirs form important exploration targets for the oil and gas industry in many parts of the world. This study aims to differentiate and quantify pore types and their relation to petrophysical properties in the Permo-Triassic Khuff Formation, a major carbonate reservoir in Oman. For that purpose, we have employed a number of laboratory techniques to test their applicability for the characterization of respective rock types. Consequently, a workflow has been established utilizing a combined analysis of petrographic and petrophysical methods which provide the best results for pore-system characterization. Micro-computed tomography (µCT) analysis allows a representative 3D assessment of total porosity, pore connectivity, and effective porosity of the ooid-shoal facies but it cannot resolve the full pore-size spectrum of the highly microporous mud-/wackestone facies. In order to resolve the smallest pores, combined mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and BIB (broad ion beam)-SEM analyses allow covering a large pore size range from millimeter to nanometer scale. Combining these techniques, three different rock types with clearly discernible pore networks can be defined. Moldic porosity in combination with intercrystalline porosity results in the highest effective porosities and permeabilities in shoal facies. In back-shoal facies, dolomitization leads to low total porosity but well-connected and heterogeneously distributed vuggy and intercrystalline pores which improves permeability. Micro- and nanopores are present in all analyzed samples but their contribution to effective porosity depends on the textural context. Our results confirm that each individual rock type requires the application of appropriate laboratory techniques. Additionally, we observe a strong correlation between the inverse formation resistivity factor and permeability suggesting that pore connectivity is the dominating factor for permeability but not pore size. In the future, this relationship should be further investigated as it could potentially be used to predict permeability from wireline resistivity measured in the flushed zone close to the borehole wall.

A physical model for porosity reduction in sandstones

Geophysics ◽  
1998 ◽  
Vol 63 (2) ◽  
pp. 454-459 ◽  
Author(s):  
Doron Gal ◽  
Jack Dvorkin ◽  
Amos Nur
Keyword(s):  
Elastic Moduli ◽  
Pore Space ◽  
Total Porosity ◽  
Effective Porosity ◽  
High Porosity ◽  
Formation Factor ◽  
Archie’S Law ◽  
Unconsolidated Sands ◽  
Porosity Reduction ◽  
Reduction Mechanisms

The experimental elastic moduli‐porosity trends for clean sandstones can be described by the modified upper Hashin‐Shtrikman (MUHS) bound. One geometrical (but not necessarily geological) realization is: as porosity decreases, the number of the pores stays the same and each pore shrinks while maintaining its shape. This concept of uniform porosity reduction implies that permeability is proportional to the effective porosity squared, and that formation factor is proportional to the inverse of the effective porosity. The effective porosity here refers to the part of the pore‐space that dominates fluid flow. The proposed relations for permeability and formation factor agree well with the experimentally observed values. These laws are different from the often used forms of the Kozeny‐Carman equation and Archie’s law, where permeability is proportional to the total porosity cubed and formation factor is proportional to the inverse of the total porosity squared, respectively. We suggest that the uniform porosity reduction concept be used in consolidated rocks with porosities below 0.3. The transition from high‐porosity unconsolidated sands to consolidated sandstones can be described by the cementation theory: the MUHS moduli‐porosity curves connect with those predicted by the cementation theory at the porosity of about 0.3. This scheme is not appropriate for modeling other porosity reduction mechanisms such as glass bead sintering because, during sintering, the pores do not maintain their shapes, rather they gradually evolve to rounder, stiffer pores.

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