APPLICATION OF RESISTIVITY INVERSION MODELLING TO ENHANCE WATER SATURATION CALCULATIONS FROM WIRELINE LOGS

2000 ◽  
Vol 40 (1) ◽  
pp. 355
Author(s):  
C.J. Shield
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Strong Relationship ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Resistivity Logs ◽  
Resistivity Inversion ◽  
Induction Logs

Water saturation (Sw) values calculated from resistivity or induction logs are often higher than those measured from core-derived capillary pressure (Pc) measurements. The core-derived Sw measurements are commonly applied for reservoir simulation in preference to the log-derived Sw calculations. As it is economically and logistically impractical to core every hydrocarbon reservoir, a method of correlating the core-derived Sw to resistivity/induction logs is required. Two-dimensional resistivity modelling is applied to dual laterolog data to ascertain the applicability of this technique.The Griffin and Scindian/Chinook Fields, offshore Western Australia, have been producing hydrocarbons since 1994 from two early-to-middle Cretaceous reservoirs, the clean quartzose sandstones of the Zeepaard Formation and the overlying glauconitic, quartzose sandstones of the Birdrong Formation. Routine and special core analysis of cores recovered from wells intersecting these two reservoirs creates an excellent data set with which to correlate the good quality wireline log data.A strong relationship is noted between the modelled water saturation from resistivity logs, and the irreducible water saturation measured from core capillary pressure data. Correlation between the core-derived permeability and the invasion diameter calculated from the modelled laterolog data is shown to produce a locally applicable means of estimating permeability from the resistivity modelling results.The evaluation of these data from the Griffin and Scindian/Chinook Fields provides a method for reducing appraisal and development well analysis costs, through the closer integration of core and wireline log data at an earlier stage of the field appraisal phase.

scholarly journals A CUSTOMIZED QUASI THREE-PHASE DRAINAGE RELATIVE PERMEABILITY MODEL FOR SOME INDONESIAN WATER-WET SANDSTONES

2018 ◽  
Vol 41 (1) ◽  
pp. 1-15
Author(s):  
Prof. Dr. Ir. Bambang Widarsono, M.Sc.
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Measurement Data ◽  
Production Performance ◽  
Permeability Model ◽  
Reservoir Rocks ◽  
Hydrocarbon Reservoir ◽  
Three Phase ◽  
Irreducible Water Saturation ◽  
Phase Saturation

Information about drainage effective two-phase i.e. quasi three-phase relative permeability characteristics of reservoir rocks is regarded as very important in hydrocarbon reservoir modeling. The data governs various processes in reservoir such as gas cap expansion, solution gas expansion, and immiscible gas drive in enhanced oil recovery (EOR). The processes are mechanisms in reservoir that in the end determines reserves and resevoir production performance. Nevertheless, the required information is often unavailable for various reasons. This study attempts to provide solution through customizing an existing drainage relative permeability model enabling it to work for Indonesian reservoir rocks. The standard and simple Corey et al. relative permeability model is used to model 32 water-wet sandstones taken from 5 oil wells. The sandstones represent three groups of conglomeratic sandstones, micaceous-argillaceous sandstones, and hard sandstones. Special correlations of permeability irreducible water saturation and permeability ratio irreducible water saturation have also been established. Model applications on the 32 sandstones have yielded specific pore size distribution index (?) and wetting phase saturation parameter (Sm) values for the three sandstone groups, and established a practical procedure for generating drainage quasi three-phase relative permeability curves in absence of laboratory direct measurement data. Other findings such as relations between ? and permeability and influence of sample size in the modeling are also made.

A Comprehensive Approach for Assessing the Impacts of Wettability on Oil Production in Carbonate Reservoirs

2012 ◽  
Author(s):  
Marcos Faerstein ◽  
Paulo Couto ◽  
José Alves
Keyword(s):  
Capillary Pressure ◽  
Case Studies ◽  
Water Saturation ◽  
Oil Production ◽  
Comprehensive Approach ◽  
Carbonate Reservoirs ◽  
Irreducible Water Saturation ◽  
Reservoir Simulator ◽  
Correct Understanding ◽  
The Impact

This paper discusses the impacts that rock wettability may have upon the production and recovery of oil with waterflooding in carbonate reservoirs and how it should be modeled. A broad review of the state of the art has been conducted surveying existing disagreements and knowledge gaps, basic definitions, as well as the correct understanding of the physical phenomena and identification of the characteristics of the various wettability scenarios. Case studies conducted with a black oil reservoir simulator evaluated the impact of different wettability scenarios on oil production and recovery. A comprehensive approach considering all the parameters involved in the wettability modeling was applied to the case studies, showing how the behavior of the reservoir varies as a function of their wettability. This paper shows how relative permeability and capillary pressure should be varied to correctly represent different wettability scenarios and consequently assess its impacts on oil production and recovery. The case studies show that the evaluation of the volume of oil in the reservoir is impacted by wettability through the irreducible water saturation and primary drainage capillary pressure and must be considered in the analyses. In long term analyses, mixed-wet scenarios have a higher oil production and recovery. In medium and short term, the water-wet scenarios have the higher recovery, but in relation to oil production, these scenarios are negatively influenced by the smaller volume of oil in place. The main contribution of this paper is the simultaneous analyses of all the parameters involved in the modeling of wettability showing how they impact the behavior of a reservoir. It shows how the parameters must be varied in a heterogeneous reservoir and how heterogeneity impacts the relevance of wettability in the studies.

Technique Proves Effective in Remediation of Phase-Trapping Damage in Tight Reservoirs

2021 ◽  
Vol 73 (07) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Chemical Treatment ◽  
Water Saturation ◽  
Gas Permeability ◽  
Abu Dhabi ◽  
Absolute Permeability ◽  
Treatment Technique ◽  
The Core ◽  
Carbonate Formation ◽  
Irreducible Water Saturation ◽  
Damaged Zone

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202996, “An Efficient Treatment Technique for Remediation of Phase-Trapping Damage in Tight Carbonate Gas Reservoirs,” by Rasoul Nazari Moghaddam, SPE, Marcel Van Doorn, and Auribel Dos Santos, SPE, Nouryon, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Aqueous- and hydrocarbon-phase trapping are among the few formation-damage mechanisms capable of significant reduction in effective permeability (sometimes near 100%). In this study, a new chemical treatment is proposed for efficient remediation of water- or hydrocarbon-phase-trapping damage in low-permeability porous media. The method proposed here is cost-effective and experimentally proved to be efficient and long-lasting. Such a chemical treatment is recommended to alleviate gas flow in tight gas with aqueous-trapping-damaged zones or in gas condensate reservoirs with condensate-banking challenges. Introduction Remediation techniques for existing aqueous- or hydrocarbon-phase-trapping damage can be categorized into two approaches: bypassing the damaged region by direct penetration techniques and trapping-phase removal. In the former category, the damaged zone is bypassed by creation of high-conductance flow paths through hydraulic fracturing or acidizing. However, for tight and ultratight formations, conventional acidizing may not be feasible (mostly because of injectivity difficulties). In the second category, direct removal and indirect removal have been used, but usually are seen as short-term solutions. The fluid used in the proposed treatment is comprised of a nonacidic chelating agent. The treatment fluid can be injected safely into the damaged region, while a slow reaction rate allows it to penetrate deep into the formation. In the proposed treatment, the mechanism is the permanent enlargement of pore throats where the nonwetting phase has the most restriction (to overcome the capillary forces) to pass through. In fact, phase trapping or capillary trapping occurs inside the pore structure when viscous forces are not strong enough to overcome the capillary pressure. The experimental setup and method are detailed in the complete paper. Results and Discussion Treatment of Outcrop Samples: Lueder Carbonate. The performance of the proposed treatment fluid initially was investigated on two outcrop core samples from the Lueder carbonate formation. The first treatment was conducted on the Le1 core sample with an absolute permeability of 1.46 md. To establish trapped water in the core, 10 pore volumes (PV) of 5 wt% potassium chloride brine were injected followed by nitrogen (N2) gas displacement. Then, to achieve irreducible water saturation, N2 was injected at a rate of 2 cm3/min for at least 100 PVs until no further water was produced. Next, the effective gas permeability was measured while N2 was injected at approximately 0.2 cm3/min. The effective gas permeability was obtained as 0.042 md. The trapped water saturation was also calculated (from the core weight) as 77.7%. After all pretreatment measurements, the core was loaded into the core holder for the treatment. The treatment injections with preflush and post-flush were performed at 130°C. In this test, 0.5 PV of treatment fluid was injected.

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.

A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Artur Posenato Garcia ◽  
Zoya Heidari
Keyword(s):  
Pore Structure ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Water Saturation ◽  
Rock Physics ◽  
Rock Fabric ◽  
The Core ◽  
Directional Permeability ◽  
Water Saturated ◽  
Pore Body

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

SATURATION EXPONENT AS A FUNCTION OF RESERVOIR HETEROGENEITY AND WETTABILITY IN THE TAMBAREDJO OIL FIELD, SURINAME

2021 ◽  
Author(s):  
Elias R. Acosta ◽  
◽  
Bhagwanpersad Nandlal ◽  
Ryan Harripersad ◽  
◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Variable Parameter ◽  
Oil Field ◽  
High Resistivity ◽  
Reservoir Properties ◽  
Core Data ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Saturation Exponent

This research proposed an alternative method for determining the saturation exponent (n) by finding the best correlations for the heterogeneity index using available core data and considering wettability changes. The log curves of the variable n were estimated, and the effect on the water saturation (Sw) calculations and the Stock Tank Oil Initially In Place (STOIIP) in the Tambaredjo (TAM) oil field was analyzed. Core data were employed to obtain the relationship between n and heterogeneity using cross-plots against several heterogeneity indices, reservoir properties, and pore throat size. After filtering the data, the clay volume (Vcl), shale volume, silt volume, basic petrophysical property index (BPPI), net reservoir index, pore grain volume ratio, and rock texture were defined as the best matches. Their modified/improved equations were applied to the log data and evaluated. The n related to Vcl was the best selection based on the criteria of depth variations and logical responses to the lithology. The Sw model in this field showed certain log readings (high resistivity [Rt] reading ≥ 500 ohm.m) that infer these intervals to be probable inverse-wet (oil-wet). The cross-plots (Rt vs. Vcl; Rt vs. density [RHOB]; Rt vs. total porosity [PHIT]) were used to discard the lithologies related to a high Rt (e.g., lignites and calcareous rocks) and to correct Sw when these resulted in values below the estimated irreducible water saturation (Swir). The Sw calculations using the Indonesian equation were updated to incorporate n as a variable (log curves), comparing it with Sw from the core data and previous calculations using a fixed average value (n = 1.82) from the core data. An integrated approach was used to determine n, which is related to the reservoir’s heterogeneity and wettability changes. The values of n for high Rt (n > 2) intervals ranged from 2.3 to 8.5, which is not close to the field average n value (1.82). Specific correlations were found by discriminating Swir (Swir < 15%), (Swir 15%–19%), and Swir (> 19%). The results showed that using n as a variable parameter improved Sw from 39.5% to 36.5% average in the T1 and T2 sands, showing a better fit than the core data average and increasing the STOIIP estimations by 6.81%. This represents now a primary oil recovery of 12.1%, closer to the expected value for these reservoirs. Although many studies have been done on n determination and its effect on Sw calculations, using average values over a whole field is still a common practice regardless of heterogeneity and wettability considerations. This study proposed a method to include the formation of heterogeneity and wettability changes in n determination, allowing a more reliable Sw determination as demonstrated in the TAM oil field in Suriname.

Interpretation of hydraulic rock types with resistivity logs in Tertiary deepwater turbidite reservoirs: Pore-scale modeling verified with field observations in the Gulf of Mexico, USA

2013 ◽  
Vol 1 (2) ◽  
pp. T177-T185 ◽  
Author(s):  
Chicheng Xu ◽  
Carlos Torres-Verdín ◽  
Shuang Gao
Keyword(s):  
Hydraulic Conductivity ◽  
Gulf Of Mexico ◽  
Pore Size ◽  
Water Saturation ◽  
Size Distributions ◽  
Clastic Rocks ◽  
Rock Types ◽  
Rock Typing ◽  
Irreducible Water Saturation ◽  
Resistivity Logs

Well-log-based hydraulic rock typing is critical in deepwater reservoir description and modeling. Resistivity logs are often used for hydraulic rock typing due to their high sensitivity to rock textural attributes such as porosity and tortuosity. However, resistivity logs measured at different water saturation conditions need to be cautiously used for hydraulic rock typing because, by definition, the properties of hydraulic rock types (HRT) are independent of fluid saturation. We compare theoretical models of electrical and hydraulic conductivity of clastic rocks exhibiting different pore-size distributions and originating from different sedimentary grain sizes. When rocks exhibiting similar porosity ranges are fully saturated with high-salinity water, hydraulic conductivity is dominantly controlled by characteristic pore size while electrical conductivity is only marginally affected by the characteristic pore size. As a result, rock types with similar porosity but different characteristic pore sizes cannot be effectively differentiated with resistivity logs in a water-bearing zone. In a hydrocarbon-bearing zone at irreducible water saturation, capillary pressure gives rise to specific desaturation behaviors in different rock types during hydrocarbon migration, thereby causing differentiable resistivity log attributes that are suitable for classifying HRT. Core data and well logs acquired from a deep-drilling exploration well penetrating Tertiary turbidite oil reservoirs in the Gulf of Mexico, verify that inclusion of resistivity logs in the rock classification workflow can significantly improve the accuracy of hydraulic rock typing in zones at irreducible water saturation. Classification results exhibit a good agreement with those obtained from nuclear magnetic resonance logs, but have relatively lower vertical resolution. The detected and ranked HRT exhibit different grain-size distributions, which provide useful information for sedimentary facies analysis.

scholarly journals Analysis of the efficiency of models of transition zones to determine oil-saturation factors and position of contact of hydrocarbons with water

2020 ◽  
pp. 67-76
Author(s):  
G. E. Stroyanetskaya
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Water Saturation ◽  
Residual Water ◽  
Oil Saturation ◽  
Transition Zones ◽  
The Core ◽  
Geophysical Parameter ◽  
Saturation Factor ◽  
Geophysical Information

The article is devoted to the usage of models of transition zones in the interpretation of geological and geophysical information. These models are graphs of the dependences of oil-saturation factors of the collectors on their height above the level with zero capillary pressure, taking into account the geological and geophysical parameter. These models are not recommended for estimating oilsaturation factors of collectors in the transition zone. The height of occurrence of the collector above the level of zero capillary pressure can be estimated from model of the transition zone that take into account the values of the coefficients of residual water saturation factor of the collectors, but only when the model of the transition zone is confirmed by data capillarimetry studies on the core.

EXPERIENCE WITH DETERMINATION OF WATER SATURATION FROM CORE IN THE COSSACK FIELD

1993 ◽  
Vol 33 (1) ◽  
pp. 39
Author(s):  
D. Lasserre & C.F. Choo
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pressure Data ◽  
Reservoir Rocks ◽  
Saturation Parameter ◽  
The Core ◽  
Sandstone Reservoir

Water saturation measurements were made on core in two Cossack field appraisal wells to investigate the discrepancy between the water saturation calculated from logs and that observed from the capillary pressure data in the Cossack-1 discovery well. The core measurements resulted in a more accurate water saturation parameter which was then used to estimate the volume of hydrocarbons in place. The core measurements also provided valuable information about the wettability of the reservoir rocks. The results of this exercise also highlighted the uncertainty attached to the water saturation determination from logs in what was an apparently simple case of a thick, clean sandstone reservoir.

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