Variations In Petrophysical Properties Research Articles

Effect of Stress and Thermal Deformation Modes on Correlation of Permeability of Naturally Fractured Sandstone and Shale Formations

Summary Proper correlations of the variations of petrophysical properties like the permeability of naturally fractured porous subsurface formations are developed under different effective stress and thermal deformation modes. The threshold or critical stress and temperature conditions splitting the different deformation modes are determined by analyzing the experimental data. The stress and thermal deformation mode changes occurring at the critical stress and temperature are referred to as the stress and thermal shock phenomena. The improved correlations are developed using the experimental permeability data of the naturally fractured porous sandstone and shale formations based on the theoretically sound modified power-law equation. The critical effective stress and temperature values are determined at the slope discontinuity observed in the variation of the parameters of the modified power-law equation. The parameters of the modified power-law correlations are also correlated as functions of the effective stress and temperature. It is demonstrated that correlating the data separately over the different portions of the full data set divided by the critical stress and temperature values yields more accurate and representative correlations of the naturally fractured porous formations than the correlations obtained using the full-range data. The improved analytical and theoretically sound methodology and approaches presented in this paper can be applied effectively for the development of the improved correlations of the permeability of subsurface porous rock formations deforming by variation of the effective stress and temperature conditions, such as in geothermal and thermally stimulated petroleum reservoirs, and the subsurface storage processes considered for energy transition.

Assessment of the deep oil and gas bearing potential onshore in the west of Azerbaijan (Tarsdallar area)


 
 
 The Tarsdeller oil and gas field, which has a brachyoanthicline structure, is the most promising area of the oil-gas region (OGR) in the Kura-Gabirri interfluve. Goal: Based on the reservoir characteristics of rock samples obtained from exploration wells drilled in the area adjacent to the field, petrophysical models have been compiled, reflecting the spatial variation in porosity and permeability of oil-containing reservoirs. Objects: Consideration of the petrophysical properties of core samples taken in the study area made it possible to confirm the oil and gas potential of deep-seated reservoirs. Methods: This analyzed the values and variation of petrophysical properties by depth, age and various physical factors. The observed wide range of changes in the reservoir properties of rocks in the study area is mainly due to tectonic changes, lithological heterogeneity of the sedimentary complex, differences in the depth of bedrocks, as well as the complexity of tectonic conditions. As a result, to predict the oil and gas content in deep reservoirs of the same structures, it is advisable to use the methods of exploration geophysics, as well as the results of changes inthe reservoir characteristics of rocks, determined by petrophysical data. At the same time, it is most expedient to focus on the study of Paleogene-Cretaceous tectonics for the search for oil and gas objects using prospecting and exploration (preferably aerial-photo-space) works at the field. Results: Models made in 3D format illustrate the predicted oil and gas potential and patterns of distribution of productive horizons involved in the geological structure of oil and gas deposits, along the depths and stratigraphic units. It is shown that although the permeability of the rocks in the area is low, the porosity values are favorable for the industrial accumulation of hydro-carbons. Fractured carbonate reservoirs of the Upper Cretaceous are the most promising among the Mesozoic sediments in the OGRbetween the Kura and Gabirri rivers. Deep-seated structural uplifts complicated by large-amplitude fractures are recommended as the priority targets for further geological exploration. However, the real potential of the Eocene deposits, which are widespread in the NGR between the Kura and Gabirri rivers, remains unexplored by deep drilling. This is due, on the one hand, to the incomplete opening of the Eocene section in the structures prepared for deep drilling, structural-tectonic and lithofacies features, as well as insufficient knowledge of drilling for oil and gas, and on the other hand, poor development of promising intervals of the section.
 
 

3D Geological Model for Zubair Reservoir in Abu-Amood Oil Field

The Zubair reservoir in the Abu-Amood field is considered a shaly sand reservoir in the south of Iraq. The geological model is created for identifying the facies, distributing the petrophysical properties and estimating the volume of hydrocarbon in place. When the data processing by Interactive Petrophysics (IP) software is completed and estimated the permeability reservoir by using the hydraulic unit method then, three main steps are applied to build the geological model, begins with creating a structural, facies and property models. five zones the reservoirs were divided (three reservoir units and two cap rocks) depending on the variation of petrophysical properties (porosity and permeability) that results from IP software interpretation. Five wells that penetrate the lower Cretaceous Formation (Zubair reservoir) are used to construct the geological model. ZUB-1 unit considered as the most important zone which have a good petrophysical parameters about 24% for porosity, 800 md permeability, 38% water saturation and 85% net to gross. The initial oil in place is estimated to be about 1.7898*109 STB. Finally, 3D geological model support in improving and estimates the hydrocarbon potentialities in oil field and enhances the production of the field.

Pore throat characterization of bioturbated heterogeneous sandstone, Bhuj Formation, Kachchh India: An integrated analysis using NMR and HPMI studies

Nuclear magnetic resonance (NMR) relaxometry and high-pressure mercury intrusion (HPMI) are substantially utilized techniques to characterize the inherent heterogeneity of reservoirs. Bioturbation is one such type of microscale heterogeneity that provides challenges to optimal recovery planning and volumetric estimation of hydrocarbon reserves. A comprehensive approach is determined by acknowledging the applicability and limitation of each method. Due to the wide variation in petrophysical properties resulting from the effect of bioturbation, the sample size ranges from mm to cm; hence, a proper methodology needs to be formulated. The present study extends the available method of generating pseudo Pc curves from NMR studies to analyze the effect of multiscale bioturbation heterogeneity. The samples were chosen from two different classes on a bioturbation scale referred to as the bioturbation index (BI) ranging from 0 to 6, 0 being 0% bioturbation and 6 meaning 100% bioturbation. The results indicate that lower BI samples had unimodal behavior, while the higher BI sample had bimodal characteristics in pore network distribution. Increased anisotropy was evident in the higher BI samples, and the HPMI study revealed a contrasting nature of pore throat connectivity with a lower threshold and displacement pressure and an increased median throat diameter in the bioturbated part compared with the nonbioturbated. The bioturbated volume essentially had better and less tortuous pore throat connectivity. The effects of bioturbation were identifiable in a core-scale study using NMR. The bimodal characteristic behavior with two distinct pore throat classes with the larger throat class as dominant claims the bioturbation-assisted pore throat connectivity established in them. The purpose of the paper is to investigate pore throat distribution in bioturbated or heterogeneous reservoirs by integrating NMR and HPMI methods. This study proposes a method that can correlate NMR responses from logging into pore throat distribution in bioturbated zones of the reservoir.

Petrophysics and sediment variability in a mixed alluvial to lacustrine carbonate system (Miocene, Madrid Basin, Central Spain)

AbstractThis study evaluates variations in petrophysical properties within a mixed alluvial to lacustrine carbonate system (Miocene, Madrid Basin, Central Spain). The transition from alluvial environments to lake margins settings displays a shift from alluvial, siliciclastic red sandstones and mudstones to palustrine–lacustrine mudstones to packstones. Fluctuations in lake‐water level enabled land plants to occupy the lake margins during periods of low lake levels. The palustrine carbonates include features like pseudo‐microkarst, nodular and mottled limestones; the lacustrine deposits include enlarged root cavities, desiccation cracks and channel bodies. Scarce fresh water biota comprises charophytes, gastropods and ostracods. The sediments possess high natural, irregular varying, gamma‐ray values at the alluvial–lacustrine transition, and low, but constant values at full lacustrine sites. Acoustic properties agree with lithological variations within individual facies. Porosity is the most important parameter influencing P‐wave and S‐wave velocities. The scatter in the velocity–porosity relationship links to the porosity type; macro‐porosity or microporosity. The wide range of pore types and pore sizes results in a weak porosity to permeability relationship for the carbonate‐dominated rocks with low permeability for microporous and high permeability for macro‐porous carbonates. The sandstones (probably only inhibiting interparticle porosity), and to a lesser extent the sandy wackestones to packstones, show quite a strong relationship between porosity and permeability. Elastic properties of mixed alluvial–lacustrine deposits (this study) and marine deposits (literature data) overlap as variations in pore structures and porosity values are similar. Only 16% of the marine and lacustrine carbonate sediments display Equivalent Pore Aspect Ratio values above 0.2. In travertine deposits, 83% of the samples exceed Equivalent Pore Aspect Ratio values above 0.2, which highlights that travertine deposits are dominated by larger Equivalent Pore Aspect Ratios compared to lacustrine and marine carbonate deposits. Travertines display other rock frameworks with different pore types, pore distribution and amount of porosity.

Geological Model for Mauddud Reservoir Khabaz Oil Field

The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.

Diagenetic controls on the elastic velocity of the early Triassic Upper Khartam Member (Khuff Formation, central Saudi Arabia)

The Permo-Triassic intervals of the Arabian Plate host the most important gas reservoirs in the world, the Khuff Formation and its equivalents. Understanding the main controls on the elastic properties of the Khuff carbonates is crucial for hydrocarbon exploration and quantitative interpretation of sonic and seismic data. In total, 88 samples were collected from the Upper Khartam Member of the Khuff Formation (central Saudi Arabia) to investigate the controls and variations in petrophysical properties and the associated acoustic velocities. Samples were analyzed using optical microscopy, XRD, and SEM to identify their texture, mineralogy and pore types. Porosity, permeability, and compressional and shear wave velocities were measured for all samples. A significant scatter is observed in the velocity-porosity relationship of the studied samples. Depositional environment, lithofacies and minerology show no clear impact on such observed scatter. Our results show that variations in pore types, predominantly of diagenetic origin, are the main factor controlling variations of velocity at any given porosity. Samples characterized by vuggy and non-cemented moldic porosity have a higher velocity when compared to samples characterized by infilled molds, interparticle and microporosity. The impact of pore types on velocity is investigated by means of velocity-porosity trajectories obtained by the differential effective medium (DEM) modeling, which incorporates variable equivalent pore aspect ratio (EPAR) values. Three main diagenetic processes, all being non-EPAR-preserving, contribute to the evolution of velocity and porosity: 1) dolomitization creating connected pore system between the euhedral dolomite rhombs which increases permeability (best reservoir unit) but decreases pore aspect ratio and thus velocity; 2) dissolution of microporous ooids and skeletal grains creating high EPAR molds and vugs at the expense of low EPAR micropores, 3) blocky calcite cementation that does not preserve the rounded shape of open oomolds reducing EPAR from more than 0.4 to less than 0.1 for extensively infilled molds. The established impedance-porosity trajectories in this study suggest that elastic properties can provide important insights about diagenetic overprints, pore types and reservoir quality in Khuff carbonates.

Experimental Investigation of the Effects of Water and Polymer Flooding on Geometric and Multifractal Characteristics of Pore Structures

During water and polymer flooding for enhanced oil recovery, pore structures may vary because of the fluid–rock interactions, which can lead to variations in petrophysical properties and affect oil field production. To investigate the effects of fluid flooding on pore structures, six samples were subjected to brine water, dual-system, and alkaline–surfactant–polymer (ASP) polymer displacement experiments. Before and after experiments, samples were scanned by X-ray CT. Thin sections, X-ray diffraction, and high pressure mercury injection tests were also carried out to characterize mineralogy and fractal dimension of pore systems before experiments. Experiment results show that water flooding with low injection pore volume ratio (IPVR) can improve reservoir quality since total porosity and connected porosity of samples rise after the flooding and the proportion of large pores also increases and heterogeneity of pore structure decreases. However, water flooding with high IPVR has reverse effects on pore structures. Polymer flooding reduces the total porosity, connected porosity, the percentage of small pores and enhances the heterogeneity of pore structures. It can be found that pore structures will change in fluid flooding and appropriate water injection can improve reservoir quality while excessive water injection may destroy the reservoir. Meanwhile, injected polymer may block throats and destroy reservoirs. The experimental results can be used as the basis for oil field development.

Petrophysical properties variation of bitumen-bearing carbonates at increasing temperatures from laboratory to model

Variations in reservoir seismic properties can be correlated to changes in saturated-fluid properties. Thus, the determination of variation in petrophysical properties of carbonate-bearing rocks is of interest to the oil exploration industry because unconventional oils, such as bitumen (HHC), are emerging as an alternative hydrocarbon reserve. We have investigated the temperature effects on laboratory seismic wave velocities of HHC-bearing carbonate rocks belonging to the Bolognano Formation (Majella Mountain, central Italy), which can be defined as a natural laboratory to study carbonate reservoir properties. We conduct an initial characterization in terms of porosity and density for the carbonate-bearing samples and then density and viscosity measurements for the residual HHC, extracted by HCl dissolution of the hosting rock. Acoustic wave velocities are recorded from ambient temperature to 90°C. Our acoustic velocity data point out an inverse relationship with temperature, and compressional (P) and shear (S) wave velocities show a distinct trend with increasing temperature depending on the amount of HHC content. Indeed, samples with the highest HHC content show a larger gradient of velocity changes in the temperature range of approximately 50°C–60°C, suggesting that the bitumen can be in a fluid state. Conversely, below approximately 50°C, the velocity gradient is lower because, at this temperature, bitumen can change its phase in a solid state. We also propose a theoretical model to predict the P-wave velocity change at different initial porosities for HHC-saturated samples suggesting that the velocity change mainly is related to the absolute volume of HHC.

Effective equation to assess solute transport in two-lithology reservoirs

Understanding solute transport in heterogeneous porous media is a challenging problem due to the degree of complexities coming from the spatial variations of petrophysical properties. The developments of theoretical formulations are powerful tools used to obtain insights regarding the phenomenology involved in the transport process when analyzing large-scale systems. In this context and within the framework of the volume averaging method, in this work we present an effective one-equation model and its validity conditions for the solute transport in heterogeneous reservoirs characterized by two-lithology arrangements. For this purpose, the hypothesis of local mass equilibrium was assumed valid and what follows included the determination of physical constraints supporting such a hypothesis. In a previous work (Aguilar-Madera et al., 2019), the closure problems to calculate the effective coefficients of the two-equation model were presented, and with this base we present here the numerical estimation of the effective velocity vector and the mass dispersion tensor included in the one-equation model. As one application, the numerical solution of the one-equation model was carried out for different lithology arrangements and the breakthrough curves for two permeability ratio scenarios were analyzed. The results confirm that the permeability ratio dramatically impact not only the tracer dispersion but also the arrival time at observation points, which is strongly correlated to the velocity vector field and its spatial deviations. We found that the local mass equilibrium is met more easily in lenticular reservoirs provided that the boundary and initial conditions have no long-term effects. Finally, the dispersion coefficient was compared against reported reservoir field data, finding similarities in the orders of magnitude for certain geologies.

Experimental investigation on precipitation damage during water alternating flue gas injection

Water Alternating Gas (WAG) approach can improve the efficiency of gas flooding. However, the precipitation damage that is induced by the gas injection may be inevitable. The precipitation pressure point test of gas injection, and the WAG parallel double-tube long-core flooding experiment under different injection conditions were systematically performed to obtain the optimum injection parameters. The variations of petrophysical properties were caused by precipitation, and its morphology was also determined by centrifugal capillary force and environmental scanning electron microscope. The precipitation pressure rised with the increase of the amount of gas injection, generally 2.0 MPa ~ 3.0 MPa higher than the bubble point pressure (Pb), and it was confirmed by X-ray energy spectrum and scanning electron microscope that the precipitation was mainly asphaltene. The optimum injection parameters for WAG were Gas–Water Ratio (GWR) of 1:1 and slug size of 0.1 HydroCarbon Pore Volume (HCPV), which benefited the recovery of low-permeability and high-permeability pipe by additional recovery of 28.5% and 17.4% respectively, while WAG process enhanced the total oil recovery by 23.4%. The pore volume and median radius of capillary pressure of all cores were both reduced with more obvious effects on conglomerate. Combined with the results of sediment saturation, it also showed the poorer the physical properties of the cores, the severer the influence of the precipitation. Overall, the WAG could greatly improve the recovery but the influence of precipitation must be considered.

Reservoir evaluation within the sequence stratigraphic framework of the Upper Cretaceous Anambra Basin, Nigeria

The Anambra Basin has become a subject of interest in recent years, following renewed search for hydrocarbon in Nigeria's inland sedimentary basins to increase its reserve base. Although there are extensive studies on different hydrocarbon aspects of the basin, there are currently no published studies on the assessment of potential subsurface reservoirs. This study evaluates the reservoir properties of the Upper Cretaceous (Campanian to Maastrichtian) Anambra Basin, within a sequence stratigraphic framework, using wireline-log data. Four depositional sequences (SEQ-1, SEQ-2, SEQ-3, and SEQ-4, from oldest to youngest) were interpreted, each bounded by two sequence boundaries. They span in age from 83 Ma to 63 Ma (20 Myr duration), and overall record an initial transgression, then subsequent regression, aggradation, and final transgression. The cross-plots and computed petrophysical properties suggest that there are significant spatial and temporal variations in reservoir parameters in the basin, with some predictable trends, as shown by generated isoparametric maps. Preliminary assessment further suggests that the main controls on reservoir property variations are the depositional facies, burial depth, and diagenetic processes (compaction and cementation). A new method of ranking the reservoir potential of interpreted depositional sequences showed that the best ranked sequence is SEQ-4 (chance of success, CoS = 0.73/0.9), while the least ranked sequence is SEQ-1 (CoS = 0.45/0.9). This study therefore provides a framework within which additional well data should be made available, to allow a robust assessment of the trends of and controls on the spatio-temporal variations in petrophysical properties, in order to better predict reservoir quality distribution, and guide future exploration in this frontier basin.

Effective Correlation of Stress and Thermal Effects on Porosity and Permeability of Naturally Fractured Formations by a Modified Power Law

SummaryEffective theory and methodology are proposed and validated for accurate correlation of stress–dependent petrophysical properties of naturally fractured or induced–fractured reservoir formations by means of a matrix/fracture dual–compressibility treatment. Inspection of various experimental data indicates a sudden change in trends at a certain critical net effective stress in the stress dependence of petrophysical properties of porous rocks as a result of a stress shock caused by the opening or closing of fractures. The variation of petrophysical properties in fractured–rock formations subjected to stress loading/unloading and thermally induced stress occurs mainly by deformation of the fractures below the critical effective stress and the deformation of the matrix above the critical effective stress. The alteration of petrophysical properties and a slope discontinuity might also be experienced when the stress exceeds the onset of other rock–alteration/damaging processes, such as pore collapsing and grain crushing. Proper formulations of the relevant processes and special correlation methods are presented in a manner to capture this nature of the petrophysical experimental data obtained by testing of cores extracted from naturally fractured or induced–fractured reservoir–rock formations. The dependency of porosity and permeability of fractured–rock samples under stress because of thermal, hydraulic, and mechanical effects is represented accurately by a modified–power–law equation derived from a kinetics model as confirmed by effective correlations of various experimental data. It is shown that this new model represents the thermal effect better than the frequently used Arrhenius (1889) equation and Vogel–Tammann–Fulcher (VTF) equation (Vogel 1921; Fulcher 1925; Tammann and Hesse 1926).

ПЕТРОФІЗИЧНІ МОДЕЛІ ТЕРИГЕННИХ КОЛЕКТОРІВ КАМ’ЯНОВУГІЛЬНИХ ВІДКЛАДІВ ЦЕНТРАЛЬНОЇ ЧАСТИНИ ДНІПРОВСЬКО-ДОНЕЦЬКОЇ ЗАПАДИНИ

The purpose of the work was to construct petrophysical models of reservoir rocks of different rank: typical and unified. Typical models describe connections between the parameters of individual rocks lithotypes occurring in definite geological conditions and serving as the basis for the development of petrophysical classification of reservoir rocks in the oil geology. The principle of unification provides for creation of the models structure for different reservoir lithotypes both in the geological section and in the area. We have studied petrophysical properties of reservoir rocks of Carboniferous deposits in the central part of the Dnieper-Donets depression. Petrophysical properties of rocks in conditions close to the formational ones and relations between them were studied on a number of samples formed by the core samples of different age. Main geological factors that have an influence on reservoir properties of rocks were taken into consideration. While constructing and analysing of petrophysical models we have used a probable-statistic approach with the use of the correlative-regressive analysis. Result of the work is contained in typical petrophysical models for individual areas and in unified models obtained on consolidated samples for Lower Carboniferous deposits of this region. Characteristic features in variations of petrophysical properties of reservoir rocks of Carboniferous deposits and their models have been ascertained. A conclusion has been made that multidimensional models, in which the depth of occurrence of deposits is one of the parameters that are necessary to consider while constructing petrophysical models, are the most informative for determination of petrophysical properties of the studied deposits, and the models obtained by us are known to be a petrophysical basis for quantitative interpretation of data from geophysical studies in the boreholes of the given region.

Experimental investigation of changes in petrophysical properties and structural deformation of carbonate reservoirs

Abstract To examine the effect of pressure on pore structure and petrophysical properties of carbonate rock, the porosity, permeability, CT scanning, SEM and elastic wave velocity of two carbonate core plug samples from an oilfield in Southwest Iran were analyzed under cyclic pressure. One of the plugs was calcite and the other was dolomite with anhydrite nodules. The cyclic pressure exerted on the samples increased from 13.79 MPa to 27.58 MPa in six steps, and the variations in petrophysical properties of the two samples at different pressure loading and unloading steps were counted and analyzed. The results show that the calcite sample decreases in porosity and permeability with the increase of pressure, which is consistent with the results from compression and shear wave velocity tests. In the dolomite sample, the decreasing trend was not observed; fluctuations of compressive and shear velocities were observed during the loading stage, which may be due to different geometries of the pores and the porosity variation in the sample. Understanding the variation of carbonate petrophysical properties with pressure is helpful for optimizing reservoir development scheme.

Variation of Petrophysical Properties and Adsorption Capacity in Different Rank Coals: An Experimental Study of Coals from the Junggar, Ordos and Qinshui Basins in China

The petrophysical properties of coal will vary during coalification, and thus affect the methane adsorption capacity. In order to clarify the variation rule and its controlling effect on methane adsorption, various petrophysical tests including proximate analysis, moisture measurement, methane isothermal adsorption, mercury injection, etc. were carried out on 60 coal samples collected from the Junggar, Ordos and Qinshui basins in China. In this work, the boundary values of maximum vitrinite reflectance (Ro,m) for dividing low rank, medium rank and high rank coals are set as 0.65% and 2.0%. The results show that vitrinite is the most abundant maceral, but the maceral contents are controlled by sedimentation without any relation to coal rank. Both the moisture content and porosity results show higher values in the low ranks and stabilized with Ro,m beyond 1%. Ro,m and VL (daf) show quadratic correlation with the peak located in Ro,m = 4.5–5%, with the coefficient (R2) reaching 0.86. PL decrease rapidly before Ro,m = 1.5%, then increase slowly. DAP is established to quantify the inhibitory effect of moisture on methane adsorption capacity, which shows periodic relationship with Ro,m: the inhibitory effect in lignite is the weakest and increases during coalification, then remains constant at Ro,m = 1.8% to 3.5%, and finally increases again. In the high metamorphic stage, clay minerals are more moisture-absorbent than coal, and the inherent moisture negatively correlates with the ratio of vitrinite to inertinite (V/I). During coalification, micro gas pores gradually become dominant, fractures tends to be well oriented and extended, and clay filling becomes more common. These findings can help us better understand the variation of petrophysical properties and adsorption capacity in different rank coals.

Across‐axis variations in petrophysical properties of the North Porcupine Basin, offshore Ireland: New insights from long‐streamer traveltime tomography

AbstractThe Porcupine Basin is a Mesozoic failed rift located in the North Atlantic margin, SW of Ireland, in which a postrift phase of extensional faulting and reactivation of synrift faults occurred during the Mid–Late Eocene. Fault zones are known to act as either conduits or barriers for fluid flow and to contribute to overpressure. Yet, little is known about the distribution of fluids and their relation to the tectono‐stratigraphic architecture of the Porcupine Basin. One way to tackle this aspect is by assessing seismic (Vp) and petrophysical (e.g., porosity) properties of the basin stratigraphy. Here, we use for the first time in the Porcupine Basin 10‐km‐long‐streamer data to perform traveltime tomography of first arrivals and retrieve the 2D Vp structure of the postrift sequence along a ~130‐km‐long EW profile across the northern Porcupine Basin. A new Vp–density relationship is derived from the exploration wells tied to the seismic line to estimate density and bulk porosity of the Cenozoic postrift sequence from the tomographic result. The Vp model covers the shallowest 4 km of the basin and reveals a steeper vertical velocity gradient in the centre of the basin than in the flanks. This variation together with a relatively thick Neogene and Quaternary sediment accumulation in the centre of the basin suggests higher overburden pressure and compaction compared to the margins, implying fluid flow towards the edges of the basin driven by differential compaction. The Vp model also reveals two prominent subvertical low‐velocity bodies on the western margin of the basin. The tomographic model in combination with the time‐migrated seismic section shows that whereas the first anomaly spatially coincides with the western basin‐bounding fault, the second body occurs within the hangingwall of the fault, where no major faulting is observed. Porosity estimates suggest that this latter anomaly indicates pore overpressure of sandier Early–Mid Eocene units. Lithological well control together with fault displacement analysis suggests that the western basin‐bounding fault can act as a hydraulic barrier for fluids migrating from the centre of the basin towards its flanks, favouring fluid compartmentalization and overpressure of sandier units of its hangingwall.

Magnetism at Depth: A View from an Ancient Continental Subduction and Collision Zone

Recent sophisticated global data compilations and magnetic surveys have been used to investigate the nature of magnetization in the lower crust and upper mantle. Two approaches to constraining magnetizations are developed, providing minimum (0.01 SI) and maximum (0.04 SI) susceptibility estimates, given some assumed thickness (15+ km here). These values are higher than are found in many continental rocks. Are there rocks deeper in the crust or upper mantle that are more magnetic than expected, or are the model assumptions incomplete? What is the magnetic behavior of deep crustal and upper mantle rocks, when slightly cooler than the Curie or Néel temperatures of their magnetic minerals, after being exhumed from locations of high-grade metamorphism at greater depth? Different sets of equilibrium metamorphic minerals can be considered that would form under different conditions. Results on 1501 samples from the Western Gneiss Region (WGR) Norway, mainly from mafic and ultramafic bodies subducted to depths of 60-200 km and temperatures of 750 up to 950°C at the very highest pressures, show that rocks did not fully equilibrate to the dominant metamorphic-facies conditions. There is a large variation in petrophysical properties, oxide minerals, and mineral assemblages in WGR samples, though they cannot explain the broad high-amplitude (deep-seated) anomalies measured in this region. The presence of magnetite, and exsolved titanohematite and hemo-ilmenite in samples, shows those magnetic phases are preserved even at eclogite-facies conditions, in part because complete eclogite-facies equilibrium was rarely achieved.

Techno-economic assessment of reservoir heterogeneity and permeability variation on economic value of enhanced oil recovery by gas and foam flooding

This research introduces a detailed techno-economic model to estimate and evaluate the economics of enhanced oil recovery. The model categorizes the cost objects into three main modules: injection, production, and CO2 recycling. These modules are composed of a number of lower-level sub-modules that represent specific cost objects. The techno-economic model utilizes reservoir simulation inputs and results such as production rate and composition, injection fluid rate and composition, and bottomhole pressure to provide detailed costs and revenue of injection, production, and CO2 recycling, according to defined scenarios. Although the techno-economic model is a general model that can be applied to any EOR project, we illustrate it here to compare flooding scenarios for a modeled EOR project in Mississippi.Reservoir heterogeneity is the variation of petrophysical properties with space such as porosity, permeability, fluid saturation. This effect is explored for total of 81 cases considering different combinations of Dykstra-Parsons coefficient (VDP) and correlation length. For each case, 25 random realizations of the permeability field were generated and the results of realizations were averaged to provide a statistical representation of the cases. Simulations of three scenarios including Waterflood, Water Alternating Gas, and Surfactant Alternating Gas floods (using a foam model for SAG) were carried out for each realization. The results show that, under assumed cost structure and the selected foam model, on average, SAG is a better and more profitable injection scenario with an oil price of $40/bbl. The economic advantage of SAG, however, declines with greater permeability variation.

Emulation of reservoir production forecast considering variation in petrophysical properties

Implementation of proxy models, such as emulators might reduce the computational time required in a variety of reservoir simulation studies. By definition, an emulator uses reservoir properties as input parameters in a statistical model constructed from simulator outputs. However, incorporation of petrophysical properties distributions in all model grid-blocks implies too many input parameters for direct emulation. Currently, most employments of emulation only consider single-value parameterization of reservoir properties.In this work, we propose a methodology to consider spatially-distributed properties, such as porosity and permeability, in reservoir emulation technique. First, we present the process of finding a procedure to deal with geostatistical realizations in the emulator and then implement it in a risk quantification application. Construction of an emulator in a probabilistic approach involved: selection of a base model, definition of uncertain inputs, selection of outputs to be emulated, sampling inputs to generate scenarios, simulation of scenarios, and building the emulator. As an application, we used emulators to generate risk curves at the final production time of a synthetic reservoir model.By implementing the proposed procedure, we showed that emulators can provide reliable results during risk analysis in oilfield development. Furthermore, with emulators it is possible to generate risk curves that reproduce simulations results at a lower computational cost.It can be expected that parameterization of petrophysical properties will boost the applicability of the reservoir emulation technique. For instance, emulators can significantly reduce both the time and computational resources demanded in various reservoir studies for high heterogeneity and complex reservoir models such as found in the Brazilian pre-salt area.