Island-arc augite-bytownite-labradoritic dacites of the Kara-Dag, Crimea

2019 ◽  
pp. 53-61
Author(s):  
E. M. Spiridonov ◽  
N. N. Korotayeva ◽  
N. N. Krivitskaya ◽  
V. M. Ladygin ◽  
G. N. Ovsyannikov ◽  
...  
Keyword(s):  
Crystallization Temperature ◽  
Water Saturation ◽  
Central Zone ◽  
Island Arc ◽  
The Core ◽  
Subvolcanic Body ◽  
Logarithmic Unit ◽  
Late Origin ◽  
Early Origin

Island-arc calc-alcaline dacites (66,7% of SiO2, 3,4% of Na2O, 1,9% of K2O) compose a subvolcanic body among tuffs, andesites and trachyandesites in the east of the Kara-Dag volcanic massif of the Rocky Crimea. The unique features of dacites is abundance of plagioclase phenocrysts (the central zone is bytownite Ca75–72Na24–27K0,5–1; the intermediate and external zones is labradorite Ca67–52Na32–47K1) and low-Ti augite (augite Ca43–41Mg41–38Fe16–21 with 1–2% of Al2O3 composes the core; the intermediate and external zones is augite Ca43–41Mg41–38Fe16–21 with 1–2% Al2O3). Titanomagnetite, ilmenite and apatite form intergrowths with augite. Lowmagnesian titanomagnetite is enriched with manganese (up to 4,5 wt.% MnO) and zinc (up to 1,6% of ZnO); it contains from 39 to 28% of ulvospinel minal. Ilmenite, poor in Mn, contains from 10 to 25 mol.% of hematite minal that demonstrates the crystallization with the raised fO2, in other words, the water saturation of fusion. Apatite is poor in Sr, Ce and S. The trend with standard accumulation of fluorine from chlorine-hydroxyl-fluorapatite up to fluorapatite is shown. Plagioclase microlites — labradorite Ca52–50Na46–48K2–3 composes the cementing mass of rhyolitic composition (77,3% SiO2, 3,3% Na2O, 2,5% K2O) with quartz, small amounts of andesine Ca49–46Na49–52K2–3, oligoclase Ca27Na68K5 and anorthoclase in interstitions. The speciality of the described dacites is plagioclase wealth in anorthite component, what is typical for island-arc volcanites. The crystallization temperature of augite is ~1050–950 ᵒC. The crystallization temperature of associated titanomagnetite and ilmenite of early origin is ~900 ᵒC, fO2 exceed by 1 logarithmic unit the QFM buffer, their late origin crystallization temperature is ~880 ᵒC, fO2 exceed by 2 logarithmic units the QFM buffer.

Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SPE Journal ◽  
2020 ◽  
pp. 1-26
Author(s):  
Sajjaat Muhemmed ◽  
Harish Kumar ◽  
Nicklaus Cairns ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Dioxide ◽  
Water Saturation ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Carbonate Mineral ◽  
Carbonate Minerals ◽  
Oil Saturation ◽  
The Core ◽  
Three Phase ◽  
Water Saturated

Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study

scholarly journals Depositional facies model and reservoir characterization of USANI field 1, Niger delta basin, Nigeria

2017 ◽  
Vol 5 (2) ◽  
pp. 57 ◽  
Author(s):  
Godwin Aigbadon ◽  
A.U Okoro ◽  
Chuku Una ◽  
Ocheli Azuka
Keyword(s):  
Tidal Flat ◽  
Water Saturation ◽  
Well Logs ◽  
Physical Analysis ◽  
Well Log ◽  
Delta Front ◽  
Depositional Facies ◽  
Facies Model ◽  
Core Data ◽  
The Core

The 3-D depositional environment was built using seismic data. The depositional facies was used to locate channels with highly theif zones and distribution of various sedimentary facies. The integration core data and the gamma ray log trend from the wells within the studied interval with right boxcar/right bow-shape indicate muddy tidal flat to mixed tidal flat environments. The bell–shaped from the well logs with the core data indicate delta front with mouth bar, the blocky box- car trend from the well logs with the core data indicate tidal point bar with tidal channel fill. The integration of seismic to well log tie display a good tie in the wells across the field. The attribute map from velocity analysis revealed the presence of hydrocarbons in the identified sands (A, B, C, D1, D2, D4, D5). The major faults F1, F2, F3 and F4 with good sealing capacity are responsible for hydrocarbon accumulation in the field. Detailed petro physical analysis of well log data showed that the studied interval are characterized by sand-shale inter-beds. Eight reservoirs were mapped at depth intervals of 2886m to 3533m with their thicknesses ranging from 12m to 407m. Also the Analysis of the petrophysical results showed that porosity of the reservoirs range from 14% to 28 %; permeability range from 245.70 md to 454.7md; water saturation values from 21.65% to 54.50% and hydrocarbon saturation values from 45.50% to 78.50 %. The by-passed hydrocarbons were identified and estimated in low resistivity pay sands D1, D2 at depth of 2884m – 2940m, sand D5 at depth of 3114m – 3126m respectively. The model serve as a basis for establishing facies model in the field.

scholarly journals Magnetic Resonance Imaging of Methane Hydrate Formation and Dissociation in Sandstone with Dual Water Saturation

Energies ◽  
2019 ◽  
Vol 12 (17) ◽  
pp. 3231
Author(s):  
Stian Almenningen ◽  
Per Fotland ◽  
Geir Ersland
Keyword(s):  
Magnetic Resonance Imaging ◽  
Magnetic Resonance ◽  
Methane Hydrate ◽  
Water Saturation ◽  
High Water ◽  
Growth Patterns ◽  
Resonance Imaging ◽  
Initial Water ◽  
Hydrate Dissociation ◽  
The Core

This paper reports formation and dissociation patterns of methane hydrate in sandstone. Magnetic resonance imaging spatially resolved hydrate growth patterns and liberation of water during dissociation. A stacked core set-up using Bentheim sandstone with dual water saturation was designed to investigate the effect of initial water saturation on hydrate phase transitions. The growth of methane hydrate (P = 8.3 MPa, T = 1–3 °C) was more prominent in high water saturation regions and resulted in a heterogeneous hydrate saturation controlled by the initial water distribution. The change in transverse relaxation time constant, T2, was spatially mapped during growth and showed different response depending on the initial water saturation. T2 decreased significantly during growth in high water saturation regions and remained unchanged during growth in low water saturation regions. Pressure depletion from one end of the core induced a hydrate dissociation front starting at the depletion side and moving through the core as production continued. The final saturation of water after hydrate dissociation was more uniform than the initial water saturation, demonstrating the significant redistribution of water that will take place during methane gas production from a hydrate reservoir.

scholarly journals Application of Implicit Pressure-Explicit Saturation Method to Predict Filtrated Mud Saturation Impact on the Hydrocarbon Reservoirs Formation Damage

Mathematics ◽  
2020 ◽  
Vol 8 (7) ◽  
pp. 1057 ◽  
Author(s):  
Mingxuan Zhu ◽  
Li Yu ◽  
Xiong Zhang ◽  
Afshin Davarpanah
Keyword(s):  
Porous Media ◽  
Water Saturation ◽  
Drilling Fluid ◽  
Formation Damage ◽  
Drilling Mud ◽  
Oil Viscosity ◽  
The Core ◽  
Oil Flow ◽  
Lower Porosity ◽  
Saturation Method

Hydrocarbon reservoirs’ formation damage is one of the essential issues in petroleum industries that is caused by drilling and production operations and completion procedures. Ineffective implementation of drilling fluid during the drilling operations led to large volumes of filtrated mud penetrating into the reservoir formation. Therefore, pore throats and spaces would be filled, and hydrocarbon mobilization reduced due to the porosity and permeability reduction. In this paper, a developed model was proposed to predict the filtrated mud saturation impact on the formation damage. First, the physics of the fluids were examined, and the governing equations were defined by the combination of general mass transfer equations. The drilling mud penetration in the core on the one direction and the removal of oil from the core, in the other direction, requires the simultaneous dissolution of water and oil flow. As both fluids enter and exit from the same core, it is necessary to derive the equations of drilling mud and oil flow in a one-dimensional process. Finally, due to the complexity of mass balance and fluid flow equations in porous media, the implicit pressure-explicit saturation method was used to solve the equations simultaneously. Four crucial parameters of oil viscosity, water saturation, permeability, and porosity were sensitivity-analyzed in this model to predict the filtrated mud saturation. According to the results of the sensitivity analysis for the crucial parameters, at a lower porosity (porosity = 0.2), permeability (permeability = 2 mD), and water saturation (saturation = 0.1), the filtrated mud saturation had decreased. This resulted in the lower capillary forces, which were induced to penetrate the drilling fluid to the formation. Therefore, formation damage reduced at lower porosity, permeability and water saturation. Furthermore, at higher oil viscosities, due to the increased mobilization of oil through the porous media, filtrated mud saturation penetration through the core length would be increased slightly. Consequently, at the oil viscosity of 3 cP, the decrease rate of filtrated mud saturation is slower than other oil viscosities which indicated increased invasion of filtrated mud into the formation.

Displacement of oil by Solvent at High Water Saturation

1970 ◽  
Vol 10 (04) ◽  
pp. 337-348 ◽  
Author(s):  
F.I. Stalkup
Keyword(s):  
Mass Transfer ◽  
Pore Size Distribution ◽  
Water Saturation ◽  
High Water ◽  
Ethyl Benzene ◽  
Residual Oil ◽  
Berea Sandstone ◽  
Transfer Coefficients ◽  
The Core ◽  
Dead End

Abstract Displacements of laboratory oils by propane in long, consolidated sandstone cores in the presence of high water saturations have shown that oil recoveries approaching 100 percent may be realized by continuous water-propane injection, even for oil saturations close to residual oil. However, it was often necessary to inject many pore volumes of solvent to attain this high a recovery. Initial oil saturations were established by injecting water and oil at a constant ratio into the porous medium containing residual oil to a waterflood until a steady state was obtained. Propane and water were then injected in the same fixed ratio to displace the oil. These and other experiments indicate that in the presence of a high water saturation only part of the presence of a high water saturation only part of the oil is flowable. Part resides in locations that are blocked by water, and the oil in these stagnant locations is not flowable. This nonflowable oil, it is believed, can be recovered by molecular diffusion into the flowing propane of a water-propane displacement. Values for the saturation of hydrocarbon that is contained in the stagnant locations and values for the ratio of the longitudinal hydrodynamic-dispersion coefficient to displacement velocity were determined at various water saturations in the test sandstones. The data suggest that rock wettability may influence the stagnant saturation and that stagnant oil saturations may not be as large in reservoir rocks as they are observed to be in laboratory sandstones. Mass transfer between the flowing solvent and hydrocarbon components in the stagnant saturation was expressed by a first-order rate expression. Rough values for the mass transfer coefficients for the propane-trimethylhexane hydrocarbon pair were estimated from experiments. Computations using these values for mass transfer coefficients indicate that experiments in laboratory-size cores may show much poorer displacement efficiency than that which might actually occur in the field. Introduction Injection of water with light hydrocarbon solvents is a technique that may be used to partially control solvent mobility. The higher water saturation forced by water injection reduces the permeability to solvent flow, and the mobility of the solvent region is reduced relative to that of the oil-bank region. However, it also might be expected that this higher water saturation influences the microscopic unit displacement of oil by solvent to some degree. For example, as discussed by Thomas et al., two possible effects of high water saturation on the displacement mechanism come to mind. First, a miscible displacement in the presence of water is operating on a different pore-size distribution than if no water were present. Pore-size distribution and the dp term (product of the microscopic inhomogeneity factor and "effective" particle diameter) may considerably influence the magnitudes of transverse and longitudinal dispersion coefficients. Secondly, in a multiphase system the wetting phase may trap single pores or even isolate large fingers or dendrites of the nonwetting phase. The nonwetting phase in these dead-end pores or dendrites would be phase in these dead-end pores or dendrites would be nonflowing and might either be completely isolated by the wetting phase or might communicate with the flowing nonwetting fluid by diffusion through nonwetting fluid-filled pores. Aspects of miscible displacement in the presence of water have been investigated by a number of researchers. Fitzgerald and Nielson observed that the simultaneous injection of gasoline and water into a Berea sandstone core in a 1:2 ratio recovered only 36 percent of the Bradford crude oil left in the core after waterflooding, and that only 55 to 75 percent recoveries were obtained for simultaneous water-solvent injection into the core when it contained crude oil at connate water saturation. Moreover, these authors reported recoveries of only 60 to 80 percent when solvent alone was injected into the core to displace residual oil to a waterflood. Raimondi et al. injected ethyl benzene (oil) and water simultaneously into a Berea sandstone core to establish flowing oil and water saturations and then injected heptane (solvent) and water simultaneously into the core to miscibly displace the ethyl benzene. SPEJ p. 337

scholarly journals Petrophysical Properties Estimation of Euphrates Reservoir in Qayyarah Oil Field Using Core and Well Log Data

2021 ◽  
Vol 54 (2E) ◽  
pp. 186-197
Author(s):  
Maan Al-Majid
Keyword(s):  
Water Saturation ◽  
Oil Field ◽  
Oil Reservoirs ◽  
Coefficient Of Determination ◽  
Well Log ◽  
Secondary Porosity ◽  
Log Data ◽  
The Core ◽  
Core Samples ◽  
True Resistivity

The Early Miocene Euphrates Formation is characterized by its oil importance in the Qayyarah oil field and its neighboring fields. This study relied on the core and log data analyses of two wells in the Qayyarah oil field. According to the cross-plot’s information, the Euphrates Formation is mainly composed of dolomite with varying proportions of limestone and shale. Various measurements to calculate the porosity, permeability, and water saturation on the core samples were made at different depths in the two studied wells Qy-54 and Qy-55. A relationship between water saturation and capillary pressure has been plotted for some core samples to predict sites of normal compaction in the formation. The line regression for this relationship was considered as a function of the ratio of large voids to the total volume of voids in the sample. The coefficient of determination parameter was used in estimating the amount of homogeneity in the sizes of the voids, as it was observed to increase significantly at the sites of shale. After dividing the formation into several zones, the well log data were analyzed to predict the locations of oil presence in both wells. The significance of the negative secondary porosity in detecting the hydrocarbon sites in the Euphrates Formation was deduced by its correspondence with the large increase in the true resistivity values in both wells. More than 90% of the formation parts represent reservoir rocks in both wells, but only about 75% of them are oil reservoirs in the well Qy-54 and nearly 50% of them are oil reservoirs in the well Qy-55.

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.

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.

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.

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