bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Modeling of a Structurally Complex Deepwater Field: A Gulf of Mexico Case History
Authors: Fontana S. , Atmajasetiadi N. A. , Brega F. , Villacres J. , Aliyev K. , Catalani C. 
Published: September 2015

Abstract
Reservoir modeling of structurally complex fields is particularly challenging when dealing with reverse or Y-shaped faults. In such cases, the modeling approaches usually tend to incorrectly reproduce or to simplify the actual geological situation. The scope of this contribution is to describe a case history where reservoir modeling activities are effectively performed for a field having high structural complexity, including Y faults.
The novel structural modeling approach has been applied for a deepwater oilfield located in the Gulf of Mexico. The Miocene-Pliocene reservoir consists of a series of stacked turbidite sandstone layers, which were deposited in a small basin against a salt ridge. A main set of WNW-ESE trending normal faults, as well as the allochtonous salt presence in the southwestern part, are responsible for the high compartmentalization of the field. Because of the complex fault framework, especially the Y faults geometry, a particular type of stair-step grid was adopted for the static modeling.
In presence of complex geological structures, such as reverse faults and/or Y faults, the use of the common pillar gridding modeling approach would lead to difficulties to build an effective geological model and, consequently, reliable dynamic reservoir simulations. In the current case, the adopted approach allowed building a static reservoir model accounting for its high structural complexity. The resulting grid (structural grid) is a corner point grid having specific characteristics that differentiate it from a conventional pillar grid. The main difference is the existence of apparent duplicated i, j, k indices in the structural grid. The apparent layer index (Geological Layer) property correctly reproduces the geological situation from a reservoir static standpoint. However, the flow simulators use the real grid layer index (Grid Layer), which may not correspond to the Geological Layer property, especially for complex fault patterns. Then, if such situation is well-known and handled with a proper strategy, the dynamic model will run effectively.
The positive results achieved with the described approach, despite the complicated nature of the studied field, must be highlighted. In fact, in the previous 3D grid models the field history match was never achieved, while the current structural reconstruction allowed a successful reproduction of the field history and, consequently, a more robust definition of the future activities to optimize the field production.
A CFD Compositional Wellbore Model for Thermal Reservoir Simulators
Authors: Shahamiri A. , Heidari M. , Buchanan W. L. , Nghiem L. X. 
Published: September 2015

Abstract
A robust, fast, and accurate wellbore model is essential for a reliable reservoir simulation. There has been significant interest to improve the wellbore models as the operations and behavior of advanced wells have become more complicated, in particular for thermal Steam-Assisted Gravity Drainage (SAGD) process. The non-linear and dynamic nature of the processes involved, as well as the necessity for prediction and control of such wells under rigorous operating conditions, makes the development of such a model complicated. The majority of current models use simplifying assumptions, especially with respect to the fluid dynamics involved. This work uses CFD techniques to solve the complete form of Navier-Stokes equation along with the mass and energy conservation equations. The objective is to develop a robust and efficient CFD numerical procedure for flow in wellbores where the slippage between phases, phase change, and radial mass/heat transfer between the wellbore and reservoir, are taken into account. A finite volume approach is employed to discretize the conservative form of the balance equations using a staggered grid arrangement. A Drift Flux model estimates the physical phase velocities, and the modified Beggs and Brill pressure-drop model is used to estimate the frictional pressure term in the momentum equation. Both of these models are valid for all multiphase flow regimes, at upward and downward flow conditions with different inclination angles from -90ᵒ to 90ᵒ. The phase fractions, component mole fractions, and temperature distribution are obtained using isenthalpic flash calculations. The system of equations is solved implicitly using Newton's method. The model was validated for a wide range of operating conditions against available data for different single and multi-phase flow conditions. The results of CFD wellbore model is also compared with the current thermal wellbore model FlexWell of CMG's STARS™ reservoir simulator.
Model for a Shale Gas Formation with Salt-Sealed Natural Fractures
Authors: Merry Hoagie , Ehlig-Economides C. A. , Wei Pang 
Published: September 2015

Abstract
Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.
Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.
This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.
Pore Connectivity and Permeability Assessment in Carbonate Formations using NMR Log-Inject-Log Method
Authors: Cheng Kai , Heidari Zoya 
Published: September 2015

Abstract
Nuclear magnetic resonance (NMR) logging is a well-established technology for estimating porosity, pore-size distribution, and permeability in conventional reservoirs. However, the uncertainty associated with these estimates can be significant in complex heterogeneous carbonate reservoirs, such as those with variable pore size and pore network connectivity. In such cases, distinguishing isolated pore space is often impossible using well-log measurements and conventional well-log interpretation methods, which makes permeability evaluation unreliable. This paper proposes a new application of the NMR log-inject-log method to improve assessment of permeability and to distinguish isolated pores from connected pores. We propose injecting manganese-bearing solution in the rock samples and simultaneously analyze NMR measurements before and after injection of the contrast solution. We introduced a method to eliminate the impact of isolated pore space from the NMR T2 distribution, which is then used for improved permeability assessment.
To confirm the feasibility of the proposed method for field applications, we conducted NMR laboratory measurements in two carbonate rock types. We injected manganese-bearing solution into rock samples using a coreflood experimental procedure and measured NMR T2 distributions before and after injection. We then estimated isolated porosity and interconnected porosity by taking into account the difference between the NMR T2 distributions acquired before and after the injection of the contrast solution. We introduced a method to calculate geometric mean of T2 distribution for interconnected pores, and also to obtain effective free fluid volume and bound fluid volume. Finally, we used the T2 distribution corrected for the impact of isolated pores in conventional NMR-based permeability models to improve permeability assessment. We cross-validated the NMR-based permeability estimates against Kinkenberg permeability measured by an unsteady-state gas permeameter. The results confirmed that the proposed method enables quantifying the isolated and connected pore volume, and finally improves NMR-based permeability assessment. The new method provided estimates of permeability with approximately 10% average error in eight carbonate rock samples, which was a significant improvement compared to the errors observed before correcting T2 distribution for the impact of isolated pores.
Description of In-situ Oil Upgrading Mechanism for In-situ Combustion Based on a Reductionist Chemical Model
Authors: Hascakir B. 
Published: September 2015

Abstract
Oil recovery following in-situ combustion (ISC) is highly dependent on initial oil saturation. The mechanisms leading to this dependence are not well understood due to the complexity of the reaction pathways leading to oil upgrading. We hypothesize that this dependence can be explained through a reductionist chemical model based on Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractionation. We then substantiate this model with five combustion tube experiments, and by performing SARA fractionation on produced oils. The combustion tube experiments are conducted at identical experimental conditions but varying initial oil saturations of 13%, 26%, 34%, 42%, and 53%. The produced oil samples are examined with viscosity and API gravity measurements and weight of SARA fractions. Analysis of SARA fractions is performed with Fourier Transform InfraRed Spectroscopy (FTIR). The oil recovery and the produced gas and temperature profiles are used to define the dominant reaction type that occurred throughout the experiments, namely High Temperature Oxidation (HTO) or Low Temperature Oxidation (LTO) reactions. Metal content of the produced water samples are determined with Inductive Coupled Plasma-Mass Spectroscopy (ICP-MS). The highest temperature, with greatest oil recovery and the highest carbon dioxide concentration are observed in the experiment conducted with 42% initial oil saturation in which the HTO reactions dominate the reaction path. However, the higher oxygen and lower carbon dioxide yields observed during the experiments with 13% and 26% initial oil saturations indicate that those experiments are controlled mainly by the LTO reactions. The experiments which show dominance in HTO reactions produce low density but higher viscosity oil. On the other hand, a reverse relationship is observed for cases with LTO reaction dominance. The analysis of SARA fractions with FTIR displays significant variations in molecular structure of aromatic fractions only. A quantitative analysis of resins to aromatics ratio strongly correlates with the viscosity of the samples. Hence, we conclude that resins to aromatics ratio governs the viscosity reduction and the molecular structure of the aromatic fraction seems to be the leading factor of density improvement. ICP- MS analysis on produced water show that the dominance of the HTO reactions reduces the water-oil interaction, which leads to the production of more neutral pH water. ISC is one of the most efficient thermal enhanced oil recovery methods in which maximum oil recovery can be attained. However, the complexity of the chemical reactions taking place during the process make this process difficult to understand and control. In this study, we provide a reductionist chemical model based on SARA fractionation to explain the reaction pathways describing the in-situ oil upgrading mechanisms and the dependence of oil recovery on initial oil saturation.
Discrete Fracture-Vug Network Modeling in Naturally Fractured Vuggy Reservoirs Using Multiple-Point Geostatistics: A Micro-Scale Case
Authors: Fadlelmula F. Mohamed M. , Fraim Michael , He Jie , Killough John E. 
Published: September 2015

Abstract
Most of the world's massive fields produce from naturally fractured vuggy carbonate reservoirs. However, modeling such reservoirs is a challenging task due to the co-existence of porous and free-flow domains over a wide range of scales. Realistic characterization of fractured vuggy reservoirs requires preservation of the geological structure and reproduction of patterns. In this study, we model a discrete fracture-vug network using microtomography and multiple-point geostatistics (MPG) modeling technique. For this purpose, one micro-CT scan image of a real core is used to generate a micro-scale geological model (the reference model and the first training image) having three structures; matrix, fractures, and vugs.
The structures in the reference model are also separated into matrix-fracture and matrix-vug to construct two other training images. The three training images are then used in MPG to generate multiple equiprobable models that mimic the original networks of the fractures and vugs. The models created using matrix-fracture and matrix-vug training images are combined into fracture-vug-matrix models by superimposing the fracture networks from the matrix-fracture models on their corresponding matrix-vug models. The spatial continuity, patterns reproduction, and flow performance of the generated models are compared with those of the reference model. The results show that, although the fracture patterns are not well reproduced, all the generated realizations preserved the structures and reproduced the spatial continuity of the reference model. In addition, the study revealed that the flow curves of the models generated with the introduced combined MPG method bracket better with the curve of the reference model than those of the direct MPG method. These results lay the foundation for future application of the presented method to field-scale modeling of naturally fractured vuggy reservoirs.
Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives
Authors: Liang Tianbo , Longoria Rafael A. , Lu Jun , Nguyen Quoc P. , DiCarlo David A. 
Published: September 2015

Abstract
Fracturing fluid loss into the formation can potentially damage the hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field as a way to dissipate the trapped water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants can be potentially used to reduce the impact of fracturing fluid loss on hydrocarbon permeability in the matrix as well. Unconventional tight reservoirs can differ significant from one another, which could potentially make the use of these techniques effective in some cases while not in others. We present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically-fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants on hydrocarbon permeability for different initial reservoir conditions. From this work, we identify the mechanism responsible for the permeability damage in matrix and we then suggest criteria that can be used to optimize the fracturing fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.
Reservoir Flow Geometry from Primary Production: F-F Curves
Authors: Dean R. M. 
Published: September 2015

Abstract
A major challenge while implementing waterfloods is estimating flow heterogeneity and potential water cycling issues. Core data, being static, does not accurately represent flow in a reservoir. Isolated zones may only contribute near wellbore, and cross-flow may make reservoirs act more homogeneously than estimated by core data. A new method is proposed that can estimate flow heterogeneity in reservoirs from primary production.
This method has potential application in a wide area of study such as high-grading waterflood candidates, building accurate reservoir models to aid in rapid history matches, building reasonable models for pressure transient analysis, identifying potential thief zones, and potentially analyzing flow back distribution of fractured unconventional wells.
The method relates hyperbolic decline rate to a flow geometry, specifically flow paths with both a fraction of the total flow capacity and storage capacity. The rate at which decline occurs is related to the size of the flow path and ability to cross flow fluid from other flow paths. Hyperbolic exponents and initial declines are fit to historical decline then a solver function is used to manipulate two separate F-Φ curves, one a purely exponential fit and another fit which has the ability to match a reservoir with a thief zone. Both F-Φ functions can be adjusted by one heterogeneity fitting parameter “n”.
Matching the F-Φ curve gives the ability to estimate heterogeneity factors explicitly such as the Lorenz coefficient and Dykstra-Parsons coefficient by defined mathematical functions. The match also provides the weighted average decline exponent which is a function of pore volume, productivity index, and total compressibility. Therefore if a curve is fit, pore volume can be inferred. For water drive reservoirs, aquifer size can be calculated if oil pore volume is known, and similarly oil pore volume can be solved if total reservoir volume is known.
Synthetic data sets have been used to confirm the equation produces correct results. Several fields have been analyzed and a good relationship is shown between the F-Φ curve match and core data or tracer data depending on the application.
Direct Observation of the Impact of Nanopore Confinement on Petroleum Gas Condensation
Authors: Parsa E. , Yin X. , Ozkan E. 
Published: September 2015

Abstract
Condensation of petroleum retrograde gas and especially that around a wellbore can decrease the deliverability of the well significantly. Better estimation of the point of phase transition is the key for reservoir engineers to devise management strategies to reduce condensate dropout and improve production and ultimate recovery. It has been established theoretically that the point of phase transition obtained from bulk PVT experiments does not represent the phase behavior of hydrocarbon fluids confined in nano-pores. However, very few experimental data are available. In this study, we measured the impact of nano-confinement on the phase behavior of propane using nano-fluidic devices. Direct observations of phase changes show that nano-confinement led to reductions in the vapor pressure that are consistent with the theory of capillary condensation. The shifts in the vapor pressure, however, were not always in good agreement with the Kelvin equation.
Modeling of Low-Tension Surfactant-Gas Flooding Process in a Four-Phase Flow Simulator
Authors: Lashgari Hamid R. , Sepehrnoori Kamy , Delshad Mojdeh 
Published: September 2015

Abstract
This paper presents modeling of a novel tertiary enhanced oil recovery (EOR) method. In this process, slugs of gas and surfactant solution are injected (coinjection or alternate injection) to mobilize and then displace the residual oil saturation. The objective of this paper is to model the mechanisms behind the process through history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a recently published coreflooding experiment and simulate the field-scale reservoir. The results from the history matching and reservoir simulation revealed that interfacial tension (IFT) reduction between oil and water by the surfactant, displacement of oil by gas, and mobility control of gas are believed to be the main contributors to increase oil production. Based on these key findings, modeling of low-tension surfactant-gas flooding achieves a recovery of 91% of initial oil (Sio=0.56) in laboratory coreflood and a wide range of recovery factors between 65–88% of residual oil trapped by water in the numerical models in reservoir scale.
Numerical Study of Production Mechanisms and Gas-Oil Ratio Behavior of Liquid-Rich Shale Oil Reservoirs
Authors: Khoshghadam M. , Khanal A. , Lee W. J. 
Published: September 2015

Abstract
This paper summarizes our investigation of production mechanisms and well production performance in liquid-rich shale (LRS) oil wells and introduces a new methodology for modeling LRS oil well performance. It discusses the impact of nanopore confinement on PVT properties, transport properties, rock compaction, how these phenomena affect produced GOR of LRS oil wells, and how to incorporate these phenomena into reservoir modeling studies.
The proposed methodology has been applied to construct a compositional simulation model using a hydraulic fracture reservoir model with logarithmically-spaced local grid refinement (LS-LGR grids). We incorporated the impact of nanopore confinement on phase behavior by using new correlations for modifying PVT properties in nanopores. The model was divided into three zones, hydraulic fracture, nanopores, and micro pores; each zone had different PVT, rock compaction and relative permeability properties. Production data from several LRS oil wells in the Eagle Ford shale were used for history matching and model calibration.
Our numerical model is able to simulate producing GOR behavior of LRS oil wells accurately. The “flat” GOR's in early stages of production are caused by delayed development of two-phase flow as a result of reduction of the bubble point pressure in nanopores. Enhancement of critical gas saturation delays mobilization of gas molecules in nanopores and could extend non-intuitive GOR behavior further when reservoir pressure drops below the bubble point. We found that the impact of permeability reduction due to compaction on ultimate oil recovery could be more than 20%. The study reveals that the period of constant produced GOR depends on the volatility of the reservoir fluid and on the pore size distribution in the reservoir. For moderate-GOR oil reservoirs, the constant GOR duration is greater than for highly volatile oil reservoirs.
Several unique phenomena in LRS oil reservoirs were explored in this study. As a result, we were able to introduce new correlations for modifying bulk PVT properties under confinement. These new correlations and the effects of nanopores can be combined with numerical models to simulate the performance of LRS oil reservoirs and to estimate EUR more accurately.
We concluded that numerical models with PVT model based on fluid bulk properties are not able to accurately simulate unconventional LRS oil reservoir fluid flow. Confinement impact on PVT and rock-fluid property of nanopores play key roles in complex production behavior of these resources. We also concluded that, for numerical models to capture accurately fluid distribution and compositional variability in nano Darcy LRS oil reservoirs, it is necessary to have correct knowledge of pore/pore throat size distributions in the reservoir.