Germik, a mature heavy oil field in Southeast Turkey, has been producing for more than 60 years with a significant decline in pressure and oil production. To predict future performance of this reservoir and explore possible enhanced oil recovery (EOR) scenarios for a better pressure maintenance and improved recovery, generation of a representative dynamic model is required. To address this need, an integrated approach is presented herein for characterization, modeling and history matching of the highly heterogeneous, naturally fractured carbonate reservoir spanning a long production history. Hydraulic flow unit (HFU) determination is adopted instead of the lithofacies model, not only to introduce more complexity for representing the variances among flow units, but also to establish a higher correlation between porosity and permeability. By means of artificial intelligence (AI), existing wireline logs are used to delineate HFUs in uncored intervals and wells, which is then distributed to the model through stochastic geostatistical methods. A permeability model is subsequently built based on the spatial distribution of HFUs, and different sets of capillary pressures and relative permeability curves are incorporated for each rock type. The dynamic model is calibrated against the historical production and pressure data through assisted history matching. Uncertain parameters that have the largest impact on the quality of the history match are oil-water contact, aquifer size and strength, horizontal permeability, ratio of vertical to horizontal permeability, capillary pressure and relative permeability curves, which are efficiently and systematically optimized through evolution strategy. Identification and distribution of the hydraulic units complemented with artificial neural networks (ANN) provide a better description of flow zones and a higher confidence permeability model. This reduces uncertainties associated with reservoir characterization and facilitates calibration of the dynamic model. Results obtained from the study show that the history matched simulation model may be used with confidence for testing and optimizing future EOR schemes. This paper brings a novel approach to permeability and HFU determination based on artificial intelligence, which is especially helpful for addressing uncertainties inherent in highly complex, heterogeneous carbonate reservoirs with limited data. The adopted technique facilitates the calibration of the dynamic model and improves the quality of the history match by providing a better reservoir description through flow unit distinction.

Dynamic saturation distribution of fluids in oil reservoirs is arguably the most important piece of information petroleum engineers and geophysicists need. It allows them to better characterize oil fields, choose right enhanced oil recovery techniques and make accurate recovery forecasts. The main objective of the present paper is to develop and test a novel non-intrusive technology that enables real time in-situ monitoring of fluid saturations in porous media during immiscible floods. To achieve this goal we designed, constructed and commissioned a high pressure (up to 25MPa) and temperature (up to 200°C) core-holder with an antenna that allows for low power electromagnetic sweeps in the radio frequency range. A novel inversion algorithm was created and incorporated with our core-holder-pump system that enables dynamic acquisition of the oil and water saturations. Experiments were conducted through sand packs saturated with water and then displaced with oils of varying viscosity (drainage) followed by water flooding (imbibition). Reflection and transmission coefficients in the frequency domain were measured while flooding using a commercial vector network analyzer connected to the core holder. Recorded frequency data was processed with the novel high-resolution inversion technique to obtain impulse reflection and transmission responses in the time domain. These responses were further normalized to dynamically track the water-oil volumetric saturations within the porous media. Every displacement experiment has been performed in both vertical and horizontal positions to emulate water-oil override and underride scenarios. Material balance calculations were performed to validate fluid saturation profiles for all imbibition and drainage experiments every 5 % of the pore volume of the fluids injected. Frequency domain reflection and transmission electromagnetic responses were measured every 1 % of the fluid injected. Material balance was used to validate the measured saturation profiles. The goodness of fit was calculated between these two independent measurements for every flood experiment performed. The mean-square error was calculated to be around 1.26% of the total pore volume on average. Late breakthroughs and piston-like displacement were observed in the floods with favorable mobility ratios. In contrast, much earlier breakthroughs have been registered in all the experiments with unfavorable mobility ratios due to fingering. All our observations are in agreement with the current theory of immiscible displacement in porous media. The novel automated system paired with the inversion algorithm were developed to allow for virtually real time monitoring of the fluid saturations during imbibition and drainage displacement cycles. Our technology is shown to be a promising candidate to compliment resistive logging measurements in the field.

To unlock unconventional reservoirs for optimum production, maximum contact with the reservoir is required; however, excessively dense well placement and hydraulic fractures interconnection is a source of well-to-well interaction which impairs production significantly. The first step to have successful and effective well completion is to understand the characteristics of the hydraulic fractures and how they propagate in reservoir. This paper demonstrates an integrated approach with a field example in the Montney formation for how modern modeling techniques were used to understand and optimize hydraulic fracture parameters in unconventional reservoir. Advanced logs from vertical wells and 3D-seismic were used to build an integrated geological model. Lamination index analysis was performed, using borehole imagery data to account for interaction of hydraulic fracture with vertically segregated rock fabric and to provide additional control on hydraulic fracture height growth during modeling process. A non-uniform Discrete-Fracture-Network (DFN) model was constructed. 3D-geo-mechanical model was built and initialized, using sonic log and seismic data. Fluid friction and leak-off was calibrated, using treatment pressure and DFIT data. Hydraulic fracture modeling was done for pad consists of 6 horizontal wells with multi-stage fracturing treatments, by utilizing actual pumped schedules and calibrating it against microseismic data. High-stress anisotropy led to planar hydraulic fractures despite presence of natural fractures in area. Fracturing sequence, i.e., effect of stress shadow, is seen to have major impact on hydraulic fracture geometry and propped surface area. Heatmaps were generated to estimate average stimulated and propped rock volume in section. It was also observed that rock fabrics, i.e., natural fracture and lamination has considerable impact on propagation of hydraulic fracture. Multiple realizations of natural fracture and lamination distribution were generated and used as an input in modeling process. High resolution unstructured simulation grids were generated to capture fracture dimensions and conductivities, as well as track propped and unpropped regions in stimulation network. Dynamic model was constructed and calibrated against historical production data. History matched model was then used as predictive tool for pad development optimization and to evaluate parent-child interaction in depleted environment.

Much work has been done on hydraulic-fracturing as a well stimulation technique but our understanding of formation damage due to fracturing is limited. This is due to inherent complexity of shale-water interactions under subsurface conditions. Damage is triggered by cold and low-salinity water invasion into the formation. Here, we introduce the formation damage mechanisms as a multi-physics/chemistry problem developing in a region near the fracture-matrix interface. Using high-resolution flow simulation models, we investigate the mechanisms and their impact on natural gas production. The simulation model includes geo-mechanically fully coupled non-isothermal multi-component two-phase flow equations that are developed for a multi-scale porous medium representative of the shale formations. We consider the occurrence of formation damage during two consecutive periods: well shut-in period which is considered to begin with the completion of fracturing and extending 1-2 days; followed by water flow-back and gas production period which takes months. During the early shut-in period, cold water invasion leads to thermal contraction of the matrix and reduces the normal mean stress. These changes improve the formation permeability temporarily, they may create secondary fractures, and modify the capillary pressure and saturations in the water invaded zone. These thermal effects are reduced rapidly, however, due to heat supplied by the reservoir. Osmosis pressure and the associated clay swelling cause the formation matrix to absorb fracturing water, reduce the matrix permeability, and amplify the capillary pressure/saturations. In summary, the well goes to the flowback and production with modified near-fracture conditions. During the water flowback the water saturation near the fracture-matrix interface increases; hence, liquid blockage effect on the gas flow becomes larger than that predicted based on the water imbibition during the shut-in only. This is due to capillary-end-effect developing near the interface during the water flow-back, when the fracturing water is displaced by the gas, i.e., drainage. Clay swelling and stress change continue during the withdrawal of the fluids. Consequently, we observe significant impairment in gas production rates. Only a fraction (<20%) of the injected water is ultimately produced back from the shale gas wells; the rest stays in the fractures and invades into the formation. Our simulation work shows that it is mainly the water in the fractures that are produced. The rest stays in the fractures due to relative permeability effects therein, and in the matrix as capillary-bound water due capillary end effect and to clay-swelling.

This work presents a new open access carbonate reservoir case study that uniquely considers the major uncertainties inherent to carbonate reservoirs using one of the most prolific aggradational parasequence carbonate formation sets in the U.A.E., the Upper Kharaib Member (Early Cretaceous), as an analogue. The ensemble considers a range of interpretational scenarios and geomodelling techniques to capture the main components of its reservoir architecture, stratal geometries, facies, pore systems, diagenetic overprints and wettability variations across its shelf-to-basin profile. Fully anonymized data from 43 wells across 22 fields in the Bab Basin in the U.A.E from different geo-depositional settings and height above the free water level (FWL) was used. The data comprises of a full suite of open-hole logs and core data which has been anonymized, rescaled, repositioned and structurally deformed; FWLs were normalized and the entire model was placed in a unique coordinate system. The resultant static and dynamic models(s) capture the geological setting and reservoir heterogeneities of selected fields but now at a manageable scale. Synthetic production data has been generated by adding wells to an undisclosed ‘truth case’ model to obtain field-wide and well-by-well production data (oil, gas, and water rates, bottom-hole pressures etc.) from simulation runs. The original oil in place (OOIP) and reserves that have been computed from these models are synthetic and unique. Here we present an initial field development plan and corresponding reservoir simulations that showcase the heterogeneity inherent to the model and demonstrate the variability of the flow and storage capacity of the different reservoir architectures found in and around the Bab Basin. This is an example application of how we can use synthetic production data to improve our understanding of flow behaviours in carbonates. The novelty of our work is the provision of a unique open access dataset which enables reproducible science in the field of reservoir characterisation and simulation, and helps training new generations of geoscientists and reservoir engineers in the art of characterising, simulating and predicting the reservoir performance of carbonate reservoirs under different recovery processes.

Many oil reservoirs worldwide have cycle dependent oil recovery either by design (e.g. WAG injection) or unintended (e.g. repeated expansion/shrinkage of gas cap). However, to reliably predict oil recovery involving three-phase flow process, a transformational shift in the procedure to model such complex recovery method is needed. Therefore, this study focused on identifying the shortcomings of the current reservoir simulators to improve the simulation formulation of the cycle-dependent three-phase relative- permeability hysteresis. To achieve this objective, several core-scale water-alternating-gas (WAG) injection experiments were analysed to identify the trends and behaviours of oil recovery by the different WAG cycles. Furthermore, these experiments were simulated to identify the limitations of the current commercial simulators available in the industry. Based on the simulation efforts to match the observed experimental results, a new methodology to improve the modelling process of WAG injection using the current simulation capabilities was suggested. Then the WAG injection core-flood experiments utilized in this study were simulated to validate the new approach. The results of unsteady-state WAG injection experiments performed at different conditions were used in this simulation study. The simulation of the WAG injection experiments confirmed the positive impact of updating the three-phase relative-permeability hysteresis parameters in the later WAG injection cycles. This change significantly improved the match between simulation and WAG experimental results. Therefore, a systematic workflow for acquiring and analyzing the relevant data to generate the input parameters required for WAG injection simulation is presented. In addition, a logical procedure is suggested to update the simulation model after the third injection cycle as a workaround to overcome the limitation in the current commercial simulators. This guideline can be incorporated in the numerical simulators to improve the accuracy of oil recovery prediction by any cycle-dependent three-phase process using the current simulation capabilities.

One way of obtaining water-oil relative permeability curves is from co-injection (of water and oil) experiments at steady-state (SS) condition. The two-phase Darcy Law can be used to calculate the relative permeability directly only when water saturation is constant along the core. However, the capillary end effect (CEE) causes water accumulation or depletion at the end of the core depending upon the wettability. This work describes an improved method for correcting for this effect by modifying the "intercept method" initially proposed by Gupta and Maloney (2014) . Similar to their work, we again envisage carrying out a steady-state co-injection experiment. For each ratio of water to oil flowrate ( F = q w q o ), we require experiments at several different total flowrates to be carried out. From each run, we obtain pressure drop across the core and average water saturation inside the core. We demonstrate mathematically that a plot of pressure difference vs. oil flowrate yields a straight line whose slope gives the oil relative permeability which can be used to calculate water relative permeability. A plot of average water saturation vs. reciprocal of oil flowrate gives a straight line whose intercept is the water saturation associated with the oil/water relative permeability values just obtained. It is necessary to perform the same experiment for at least two values of water and oil flowrates while the ratio is constant since we require at least two points to construct a straight line. The same procedure is used for other values of F to obtain more data points to construct the relative permeability curves. We have also mathematically corrected Gupta and Maloney’s work and other works after them and arrived at a simpler and more rigorous method. The details of how our method builds upon and improves their work will be published in due course ( Goodarzian and Sorbie, 2020 ).

The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multi-phase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which impact relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modelling. Therefore, the saturation height model (SHM) should not only capture an average hydrocarbon pore volume (HCPV), but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work defines a new terminology, "excess water", for more precise classification of SHM-scenarios in reservoirs where multiple mechanisms have interacted and caused a complex water saturation distribution. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modelling of oil migration over millions of years. High permeable reservoirs are more likely to have locally trapped water due to lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high and low permeability reservoirs may have significant excess water due to still ongoing dynamical effects. In both cases, long distances for water to drain laterally to a regional aquifer enhances the possibility for a dynamic excess water situation. The impact of excess water on well test results are demonstrated with focus on calculation of the product of permeability and sand thickness.

Saturation Height Model (SHM) definition is a primary activity for estimating volume of hydrocarbon initially in place. SHM describes the variation of the water saturation (S W ) as a function of the main rock properties (porosity and permeability), the fluid properties (density and interfacial tension), the rock-fluid interaction (wettability) and the distance from free water level. Algorithms defining these models can be directly implemented into 3D reservoir modelling for continuous SW profile calculation, once the input properties have been propagated. The computed SW honors the saturation profiles at wells and its variation in the inter-wells space is driven by the distribution of input properties. Conversely, most used commercial platforms for dynamic simulation do not accept equations for saturation calculation. We propose a method to initialize a 3D dynamic model in a way consistent with the 3D static one. Consistency of the defined reservoir model, and relevant estimate of volume in place, can be verified after field production start-up through the behavior of production wells. A workflow was implemented to define a discrete number of reservoir S W classes (SatClass) with homogeneous behavior as a reference for volume calculations. The workflow consists of the following steps: 1) Definition of a number of SatClasses corresponding to the most frequent permeability values (modes) in a permeability distribution. Each SatClass represents a reservoir facies described by a range of Rock Quality Index (RQI) values. 2) Characterization of SatClasses with permeability and porosity values, from relevant modes, and a synthetic capillary pressure (P C ) curve, calculated for the previous properties using the SHM algorithm. 3) Calculation of SatClass-based permeability and porosity discrete profiles at wells. 4) Calculation of SatClass-based Saturation Height Discrete Model at wells (SHDM). 5) Satclass- based comparison of SHDM and SHM at wells. If the single value from SHDM and the most frequent value (the mode) from SHM distribution are close, the comparison can be considered acceptable and the SatClass correctly characterized; if not, properties are revised and verified iteratively. Defined SatClasses are used to initialize the 3D dynamic model through the PC curves most representative of the reservoir behavior. Main achievements of proposed method are: 1) Defining an initial dynamic hydrocarbon volume consistent with the one from 3D static model. 2) Validating the reservoir properties distribution in inter-wells space through the consistency between the dynamic model simulation and the observed dynamic response (history match). To assess the workflow, it was applied to an oil field in the Norwegian offshore. SHM was built on core P C data from appraisal wells and propagated to horizontal producer wells targeting heterogeneous fluvial deposits. Approaching 3D dynamic model initialization with the proposed method makes more robust the choice of P C behaviors as input for reservoir characterization.

An important aspect of reservoir management process is monitoring and revising plans and an essential component of reservoir management strategy is integration of technologies ( Satter et al. 1994 ). In revisions of reservoir management plans, very rarely do operators incorporate any other data than the data from newly drilled wells and the field production in between the revisions. Any inference in the inter-well space is an interpolation between the well data, as surface seismic is limited by its resolution, as the calibration data is available only at well level. For an effective reservoir management, especially in the decline phase of the field, a logical integration of technologies to capture maximum heterogeneity in the interwell space can be very advantageous. Crosswell technologies, that provide high resolution data between a set of wells, but if used individually, are essentially limited to a very small part of the field having multiple wells. Therefore, in order to monitor and revise reservoir management plans, it is important that such technologies are integrated with full-field solutions. This paper describes a methodology that aims to better manage reservoir by logically integration the 3D reservoir model- a full-field solution- and crosswell electromagnetics/crosswell seismic- an interwell solution.

The reliable prediction of reservoir performance requires the cost effective implementation of oil recovery systems, and it is necessary to simulate the fluid flow processes in the reservoir and to measure the rock and fluid properties that determine reservoir behaviour. However, a good prediction relies on accurate values of reservoir physical properties. Carbonates rocks in Brazilian Pre-salt are known for their heterogeneity. Characterizing their physical represents a great challenge and the combination of experimental and computational techniques lead to a more comprehensive understanding of the reservoir behavior. In the present work, the relative permeability curves of a carbonate core sample with respect to oil and water are calculated by matching the data obtained in a labscale unsteady-state core flood experiment carried out at high pressure high temperature characteristics of Brazilian Pre-salt reservoirs. Corey-type equations were used to model the relative permeability due to its simplicity and having fewer parameters involved. The Monte Carlo Markov chain (MCMC) method was used as optimization tool, taking the fluid production and pressure drop measurements collected during the core flood experiment as input data. An alalysis of the sensitivity cofficients was carried out in order to deal with eventual linear dependences among the terms to be estimated. The Markov chain was generated and its convergence observed. The posterior distributions of the constant terms in the Corey equations were calculated and their mean values applied in order to calculate the relative permeability curves for the oil and water phases. The range of water saturation in which the relative permeability curves describe the core conditions after the breakthrough time, due to the occurrence of capillary end-effects, was calculated. The history match of fluid production and pressure drop was carried out, showing a good fit between the pressure curves. A gap was observed between the production curves due to the fact that the experimental measurements accounted the cumulative volume of oil and water, while the theoretical curve accounted the oil volume only.

Conventional drilling design tends to inaccurately predict the mud density needed for borehole stability because it assumes that the porous medium is fully saturated with a single fluid while in actuality it may have two or more fluids. This paper provides a new semi-analytical poroelastic solution for the case of an inclined borehole subjected to non-hydrostatic stresses in a porous medium saturated with two immiscible fluids, namely, water and gas. The new solution is obtained under plane strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. Based on the expansion of Laplace transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. The model is verified by analytical solutions for the limiting case of a formation saturated with a single fluid. The impact of the unsaturated poroelastic effect on pore pressure, stresses and borehole stability is investigated. Our results show that the excess pore pressure due to the poroelastic effect is generally higher for the saturated case (water) than the unsaturated case due to the large difference between the compressibility of fluid phases (water and gas). The time-dependency of the poroelastic effect causes the safe mud pressure window of both the unsaturated and saturated cases to narrow and approach the long-time poroelastic one with increasing time. The safe mud pressure window narrows with increasing initial gas saturation. The commonly used assumption that the formation is fully saturated by one fluid (such as water) tends to be conservative in predicting the mud density required for borehole stability. This new semi-analytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing him to design the mud weight to ensure borehole stability.

The wettability of reservoir rocks impacts many aspects of well planning and production, from estimating hydrocarbon saturation to enhanced oil recovery. Wettability is often experimentally quantified through laboratory measurements; however, in-situ wettability assessment is challenging. In this work, we introduce a new method to quantify wettability using resistivity measurements obtained from either well logs or core measurements. The objectives of this paper are (i) to introduce a resistivity-based wettability index from our recent analytically-derived resistivity model that takes into account wettability and (ii) to verify the reliability of the new resistivity-based wettability index using Amott Index, U.S. Bureau of Mines (USBM), and/or contact angle wettability measurements as reference. We quantify the resistivity-based wettability index using our new analytically-derived resistivity model which requires as inputs the resistivity of the rock-fluid system and brine, water saturation, porosity, and pore-geometry-related parameters. Water saturation and porosity can be estimated from the interpretation of borehole geophysical or core measurements. The pore-geometry-related parameters can be estimated from image analysis performed on three-dimensional pore-scale images (e.g. micro-computed tomography) or through a physics-based calibration method. Next, we calculate the resistivity-based wettability index by minimizing the error between the measured and predicted resistivity of the rock-fluid system. To verify this method, we prepare core samples covering a wide range of wettability states and saturation levels. We vary the wettability of the samples by injecting brine, an anionic surfactant solution, or a naphthenic acid and decane solution to make the core samples water-, mixed-, or oil-wet, respectively. Finally, we obtain the resistivity-based wettability index in the core samples and verify its reliability by comparing the estimates against the Amott Index and the contact angle measurements. We also used previously documented data in Berea sandstone for further verification of the new method. We successfully demonstrated the reliability of the introduced resistivity-based wettability index for limestone and sandstone core samples. The resistivity-based wettability indices were in agreement with both Amott and USBM Indices for the limestone and sandstone samples, respectively. The average absolute difference between the resistivity-based wettability index and the Amott and USBM Indices was less than 0.4 for all the core samples documented in this paper. The outcomes of this work can potentially be used for assessment of wettability from borehole geophysical measurements, to deliver in-situ properties of rocks in real-time. Additionally, the new resistivity model consists only of physically meaningful parameters and minimizes calibration efforts. Furthermore, if the wettability, porosity, and pore-geometry-related parameters are known, then we can use this resistivity model to obtain water saturation without the need for calibration.

The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir. Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other. The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments. It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing. Therefore the use of AICDs is a real option for horizontal well completion. This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.

Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) reckons 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 and hydrocarbon saturation still rely on model calibration using core measurements. Furthermore, 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 (a) developing a new multiphysics workflow to simultaneously quantify rock fabric features (e.g., porosity, tortuosity, and effective throat size) and hydrocarbon saturation from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements, (b) 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 (c) validating the reliability of the new workflow in pore- and core-scale domains. 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 T 2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T 2 -distribution for assessment of porosity, pore-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 interpretation of resistivity measurements. 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 core- and pore-scale domains on rock samples at different water saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure and fluid distribution 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. Finally, since the new workflow relies on fundamental rock physics principles, hydrocarbon saturation, permeability, and saturation-dependent capillary pressure can be estimated from well-logs with minimum calibration efforts, which is another unique contribution of this work.

This paper presents an investigation on the effect of foaming agents perpropeties in tetms of surfactant concentration, interfacial tension (IFT) and foam strength during foam flooding in porous media in the absence of oleic phase. The experiments consisted of the co-injection of gas and various surfactant solutions with three different formulation properties in terms of IFT reduction and foaming strength capability into Bentheimer sandstone samples initially saturated with the surfactant solution. Experiments were performed using Bentheimer sandstone cores during, where X-ray CT images were taken during foam generation to find out the stability of advancing front of foam propagation and to map the gas saturation for both the transient and steady-state flow regimes. Then, a series of numerical simulation was conducted to investigate the effect of surfactant concentration on pressure drop across the core for the foam flooding in the absence of oil. The foam model implemented is based on a local equilibrium and describes dependency of foam mobility reduction factor using several independent functions, such as liquid saturation, foam velocity, oil saturation and capillary number. To this end, the dry-out and gas velocity functions in the foam model were determined from the experimental data obtained at low and high-quality regimes of foam flow at a constant injection velocity. Next, pressure drop profiles of foam flooding at two different surfactant concentrations were modelled to determine the parameters of the surfactant-dependent function in the foam model. The simulation results fit the experimental data of pressure drops very well.

An experimental study of polymer flooding is here presented focusing on the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Experiments were carried out using homogeneous Bentheimer sandstones of similar properties. The cores were oil flooded using mineral oil for water wet conditions, and with crude oil (after an ageing period) for intermediate wet conditions keeping constant in all experiments the viscosity ratio between oil and polymer solution. Polymer, which is a partially hydrolysed polyacrylamide (HPAM) was used at a concentration of 2500ppm in a moderate salinity brine. The polymer solution was injected in the core at different maturity times (0PV, Breakthrough, 1PV, 1.75PV, 2.5PV, 4PV and 6.5PV). Coreflood results show that the maturity of polymer injection plays an important role on final oil recovery regardless wettability. The 0PV maturity (secondary polymer flooding) leads to the best sweep efficiency while final oil production decreases when the polymer flood maturity is high (late polymer injection after waterflooding). A difference of 15% in recovery is observed between secondary polymer flooding and late maturity (6.5 PV). Concerning the effect of wettability, the recovery factor obtained with water wet cores is always lower (from 10% to 20% depending on maturity) than the values obtained with intermediate wet cores, raising the importance of correctly restoring core wettability to obtain representative values of polymer incremental recovery. The influence of wettability can be explained by the oil phase distribution at the pore scale. Considering that the waterflooding period leads to different values of the oil saturation at which polymer flooding starts, we measured the core dispersivity using a tracer method at different states. The two-phase dispersivity decreases when water saturation increases which is favourable for polymer sweep. This study shows that in addition to wettability, maturity of polymer flooding plays a dominant role in oil displacement efficiency. Final recovery is correlated to the dispersion value at which polymer flooding starts. The highest oil recovery is obtained when the polymer is injected early.

The Sea Lion Field is an Early Cretaceous turbidite fan complex, located in the North Falkland Basin, 220 km north of the Falkland Islands. The reservoirs are dominated by amalgamated high density turbidites (Bouma Ta and liquefied sediment gravity flows), but also contain low density turbidites, linked debrites and interdigitated lacustrine mudstones. An integrated dynamic modelling workflow which incorporates the latest understanding of the Sea Lion Field sedimentology and reservoir heterogeneities is presented. The workflow focuses on capturing and retaining reservoir heterogeneity throughout the reservoir modelling process. Coarse-scale heterogeneity is captured during the construction of the full-field geological (static) model and conserved in the dynamic model by using the same grid dimensions. Sedimentological features (fine-scale heterogeneity) below the grid resolution are captured in separate, 3D core-scale models. Through a process of k v /k h and relative permeability upscaling, the core-scale models are used to inform effective permeability in the full-field model. Detailed interpretation of the available core data enables a statistical evaluation, which underpins the construction of core-scale models for the individual rock types. The resulting 3D core-scale models are representative of the reservoir and the development concept in terms of reservoir dip, lithology, petrophysical and fluid properties and well spacing. Matching the coarse model behaviour to the core-scale model forecast is an inverse problem with multiple possible solutions; therefore, assisted history matching is a valuable tool for quickly obtaining, comparing and ranking possible upscaled relative permeability functions and k v /k h ratios. The upscaled relative permeability functions output from the assisted history matching workflow correct for numerical dispersion and reproduce the waterflood behaviour observed in the core-scale model, thus capturing the influence of small-scale heterogeneities. This integrated dynamic modelling workflow allows for the direct use of detailed geological models characterising the main heterogeneities impacting flow behaviour, while retaining the ability to investigate and capture small-scale heterogeneities below the resolution of the full-field static model, thus avoiding the cumbersome process of upscaling geological properties. Assisted history matching and optimization have been integrated into the workflow, providing a robust method to produce upscaled relative permeability functions that replicate the expected waterflood behaviour.

Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/liquid two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although it is regarded as immobile state, the impact of which on gas flow capacity should not be simply neglected. In this work, firstly, the state of sub-irreducible water saturation in unconventional reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas slip-flow model is established. Noting that the gas phase in moist conditions is mainly composed of both methane and vapor rather than single-component methane. Thus, the methane-vapor binary gas state equation has been introduced to describe the real gas effect under high pressure and temperature condition. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed. To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.

In this work, we validate experimentally a dimensionless capillary pressure function for imbibition at mixed-wet conditionsthat we developed recently based on pore-scale modeling in rock images. The difference to Leverett's traditional J -function is that our dimensionless function accounts for wettability and initial water saturation after primary drainage through area-averaged, effective contact angles that depend on the wetting property and distribution of oil- and water-wet grain surfaces. We hypothesized that describing these effective contact angles as a function of Amott wettability index relates the pore- and core-scale wettability, and that pore-scale imbibition simulations can provide these relations for specific rocks. In the present work, we adopt the dimensionless function to scale imbibition capillary pressure data measured on mixed-wet sandstone and chalk cores. The measured data practically collapse to a unique curve when subjected to the dimensionless capillary pressure function. For each rock material, we employ the average, dimensionless curve to reproduce the measured capillary pressure curves and obtain excellent agreement. We also demonstrate two approaches to generate different capillary pressure curves at other mixed-wettability states than that available from the data used to generate the dimensionless curve. The first approach changes the shape of the spontaneous- and forced-imbibition segments of the capillary pressure curve while the saturation at zero capillary pressure is constant. The second approach shifts the vertical level of the entire capillary pressure curve, such that the Amott wetting index (and the saturation at zero capillary pressure) changes accordingly. Thus, integrating these two approaches with the dimensionless function yields increased flexibility to account for different mixed-wettability states. The validated dimensionless function scales mixed-wet capillary pressure curves from core samples accurately, which demonstrates its applicability to describe variations of wettability and permeability with capillary pressure in reservoir simulation models. This allows for improved utilization of core experiments in predicting reservoir performance. Reservoir simulation models can also employ the dimensionless function together with existing capillary pressure correlations.