bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study of Confinement Effect on Hydrocarbon Phase Behavior in Nano-Scale Porous Media Using Differential Scanning Calorimetry
Authors: Luo Sheng , Lutkenhaus Jodie L. , Nasrabadi Hadi 
Published: September 2015

Abstract
Phase behavior in shale remains a challenging problem in petroleum industry due to many complexities. One complexity arises from strong surface-fluid interactions in shale nano-scale pores. These interactions can lead to a heterogeneous distribution of molecules, which conventional bulk-phase thermodynamics fails to describe. Phase behavior in shale is altered from that characterized in PVT cells. The majority of current models are based on bulk-phase thermodynamics and efforts have been made using molecular simulation to gain insight into the nano-structure of confined fluids. However, to our best knowledge, the experimental data for hydrocarbon phase behavior in shale systems is severely absent.
In this work, we investigated the phase change in nano-scale capillaries using experiments. The controlled pore glasses (CPGs) were applied to model the nano-porous structure of shale reservoirs. CPGs (pore diameters 4.3 and 38.1 nm) infiltrated with hydrocarbons (octane, decane, and the binary mixture) are subject to differential scanning calorimetric (DSC) analysis. It's observed that the bubble point is affected by pore size dramatically: at 38.1 nm the confinement effect is insignificant, but at 4.3 nm two distinct bubble points appear with deviations as great as ±15 K relative to the bulk, suggesting two populations of evaporating fluid. Based on experiments and simulations, a two-state model for the nanoconfined hydrocarbons is proposed.
The bubble point is modeled using Peng-Robinson equation of state (PR-EOS) with the capillary pressure considered. The flash calculation is based on isofugacity and an interfacial tension model is accommodated. The modeling shows a general trend of increasing bubble point temperature with decreasing pore diameter, inconsistent with the experimental results. Besides, the “dual bubble points” behavior observed at 4.3 nm is not predicted by the model. This indicates the incapabilty of the bulk-phase thermodynamics in describing the behavior of nanoconfined fluids and the needs for molecule-scale simulation.
Unified Finite Difference Modeling of Transient Flow in Naturally Fractured Carbonate Karst Reservoirs - A 3D Case Study
Authors: He Jie , Killough John E. , Fadlelmula F. Mohamed M. , Fraim Michael 
Published: September 2015

Abstract
The modeling and numerical simulation of fluid flow in naturally fractured carbonate karst reservoirs are extremely challenging due to non-Darcy flow in vugs and caves connected by fracture networks. The momentum balance of such flow has been shown to be better described by the Brinkman equation both physically and mathematically, and many methods have been proposed in the literature dealing with the steady-state Brinkman model. We carry Brinkman's idea one step further and propose a transient flow model which consists of the Brinkman equation and a generalized material balance equation, and the latter has proven to be exact in the fractured carbonate karst reservoir. Finite differences are implemented for the solution of the proposed transient flow model. This solution method is more straightforward, easier to derive and implement, and more apt to generalization from 2D to 3D cases than alternative techniques.
Numerical simulation of the transient Brinkman model requires explicit solution of not only pressure at the center of each grid block, but also velocities at the interfaces between the blocks, which exaggerates the computational cost and makes the computational process more difficult and less stable. In this paper, we propose a simplified finite difference formulation of the transient Brinkman model, which significantly reduces the computational time of the simulation process, and improves accuracy and stability of the simulation results. We update our reservoir simulator with this new formulation and illustrate it with a complex 3D naturally fractured carbonate karst reservoir model. The results of this study form the foundation for future 3D multi-phase reservoir cases.
Map-Based Estimation of Reservoir Pressure and Saturation from 4D Seismic with a Data-Driven Procedure
Authors: Landa Jorge , Meadows Mark , Thacher Catherine , Waddle Robert , Williams Nneka 
Published: September 2015

Abstract
In this work we describe a mathematical procedure and associated data-driven workflow for map-based estimation of reservoir pressure and saturation changes using 4D seismic and well production/injection data. The practicality of the approach is illustrated with a field application from an offshore clastic reservoir under waterflood production. The application of the procedure results in maps of estimated reservoir pressure and saturation changes that can be used directly in field reservoir management and history matching of flow simulation models.
The outstanding feature of this data-driven approach is the reliance on field-observed data rather than on complex modeling and compute-intensive schemes typically found in classical mathematical inversion approaches. The focus is on joint use of acquired time-lapse (4D) seismic and measured well production/injection data.
Simple mathematical functions are used to model the correlation between 4D seismic and pressure-saturation information. The correlation models are calibrated with well data. Multiple seismic attributes are then used to infer map-based pressure-saturation change information.
Use of flow simulation, forward seismic modeling, and rock-physics models is limited to the feasibility analysis stage of the inversion process, where such information is needed to generate synthetic test data.
Uncertainty/probabilistic analysis in the map-based estimation of reservoir pressure and saturation changes is performed using the well-known Bayesian framework for inverse problems.
The paper adds a new case study to the relatively limited existing body of literature on data-driven methods for pressure-saturation inversion from 4D seismic, where very few such field examples have been published to date. The innovative component in this work consists of a novel application of a data-driven inversion approach that improves the usefulness of the technology in real-data environments.
A New Salinity-Independent Cased Hole Water Saturation Method Using Pulsed Neutron Oxygen Activation Logging: Physics, Modeling and Interpretation
Authors: Chace David , Inanc Feyzi , Zhang Qiong , Gade Sandeep 
Published: September 2015

Abstract
The carbon/oxygen (C/O) method of pulsed neutron logging has been widely used since the mid-1970s for saturation monitoring in cased hole wells. C/O logging measures the ratio of gamma rays created by inelastic neutron scattering by carbon and oxygen to determine formation water and oil saturation. A key benefit of C/O logging is that it provides a salinity-independent measurement. However, very slow logging speeds are required to achieve the necessary statistical accuracy. This paper introduces a faster salinity-independent water saturation method based on oxygen activation (OA) logging, including the physical principles, modeling and interpretation of laboratory test pit data.
Oxygen activation can be induced when fast neutrons with an energy greater than 10 MeV interact with isotope O-16, resulting in the creation of radioactive N-16 and subsequent generation of gamma rays with a predominant energy of 6.13 MeV. These detected activation gamma rays are directly indicative of the amount of oxygen in the vicinity of the neutron source. Modeling of the oxygen activation response accounts for formation lithology, porosity, borehole fluid, wellbore geometry and logging speed. Formation water saturation is determined by comparing the measured oxygen activation gamma rays to the modeled activation response envelope.
A custom-designed test pit was fabricated to evaluate OA water saturation feasibility. Comparison of C/O and OA measurements obtained over a range of logging speeds, and with different wellbore fluids, has confirmed that OA measurements can be successfully used to determine formation water saturation. In addition, the OA water saturation measurement is feasible at much faster logging speeds than C/O logging and can significantly reduce operation time. Indeed, the maximum practical logging speed in the test facility was 16 ft/min, and the upper speed limit of OA logging remains to be determined. This will best be evaluated through field testing in actual well conditions.
OA logging is a new alternative to C/O logging for through-casing salinity-independent water and oil saturation measurement. With the ability to log at much faster speeds, OA logging can provide significantly improved performance considering the operational limitations of C/O logging.
This paper presents the laboratory experiments, modeling and interpretation that confirm the viability of the OA water saturation measurement. In continuation of this work, the OA method is being applied to acquire and interpret field data from different wells globally. Various logging scenarios will be evaluated, including mixed lithology formations, flowing wells, and openhole completions. This will be presented in a separate publication.
Permeability Measurement of Organic-Rich Shale - Comparison of Various Unsteady-State Methods
Authors: Jin Guodong , Pérez Héctor Gonzàlez , Al Dhamen Ali Abdullah , Ali Syed Shujath , Nair Asok , Agrawal Gaurav , Khodja Mohamed R. , Hussaini Syed Rizwanullah , Jangda Zaid Zaffar , Ali Abdulwahab Zaki 
Published: September 2015

Abstract
Accurate determination of organic-rich shale permeability is still a major challenge. Various methods have been proposed to measure the permeability on core plugs or crushed samples under various stress conditions using different fluids. Permeability obtained from core plugs and their crushed samples could differ by two orders of magnitude, potentially painting very different views of the reservoirs and resulting in differences in asset development workflows. This situation only reinforces the need for considerable additional focused work to quantify tight rock permeability and better understand the measurement method dependence.
This paper presents the experimental comparison of three different unsteady-state transient methods for measuring the permeability of organic-rich shale plugs: pressure build-up, pulse-decay and oscillating pulse techniques. Permeability measurements are conducted isothermally using nitrogen gas on core plugs from the Barnett, Eagle Ford, Marcellus and Mancos formations at the same confining pressure and pore pressure. These plugs differ in mineralogy, total organic carbon (TOC), nuclear magnetic resonance (NMR) and helium porosity. Fractures are observed through the horizontal samples along the gas flow direction, while vertical samples do not have fractures. For each plug, the permeability tests begin with the pressure build-up measurement, and are followed sequentially by the pulse-decay and oscillating pulse methods whenever applicable. The plugs are then cut into smaller sizes for continuation of permeability tests and investigation of the permeability dependence on the plug size.
For the samples analyzed, the permeability measured from the pulse-decay method is essentially identical to that from the oscillating pulse method. Compared to these two methods, the pressure build­up test generally gives a relatively higher value when requiring an independent porosity measurement to compute the permeability, while it gives a relatively lower value when no porosity is needed. However, the permeability difference among these methods is generally small. This indicates that the pressure build-up test can be used to perform permeability measurement on large core plugs that cannot be tested using the pulse-decay or oscillating pulse methods. There is no trend observed on the permeability dependence on the plug sizes used. Depending on fracture distribution and connectivity, the measured permeability of horizontal samples is randomly affected by the sample sizes, indicating multiple samples with various sizes may be required to obtain a representative permeability value for horizontal plugs. Vertical plugs show little permeability dependence on the sample sizes. Consequently, a small vertical plug can be used for very tight rocks enabling quicker matrix permeability measurements.
Fracture Detection Using the Conductivity Triaxiality Index
Authors: Wang Gong Li , Abubakar Aria , Barber Tom , Alatrach Samer 
Published: September 2015

Abstract
Over the years, triaxial induction tools have found applications in not only determining formation resistivity, anisotropy, and dip, but also in detecting fractures. Fracture detection techniques provide useful information in identifying fractured reservoirs because fractures provide both space for hydrocarbon storage and also the channel for fluid flow. When fractures are developed in a formation, the formation can exhibit triaxially anisotropic conductivity if the fractures are filled with a fluid with a significantly different conductivity than that of the formation. This is particularly true for transversely isotropic formations. In an isotropic sedimentary formation, fractures can also cause the formation to be triaxially anisotropic if the geometric properties, orientation and porosity of fractures are varied from place to place in the fractured zone.
In this paper, we present a new method that uses the information of the conductivity tensor to detect fractures. The new method indicates the presence of contrasting fluid-filled fractures by the difference in three conductivity components of the tensor. This difference is called triaxiality in the paper. The conductivity tensor is found using an inversion approach. In addition to three conductivity components σx, σy, and σz, the inversion also provides three Euler angles γ, α, and β. Multiple initials for Euler angles are used to ensure that a global minimum is obtained. The inversion is followed by a rotation operation on the inverted conductivity tensor to eliminate the ambiguity effect of the principal coordinate system. The new Euler angles are found by solving a minimization problem.
We have applied the new method to both synthetic and field examples. Synthetic examples show that the rotation operation is indispensable to remove the ambiguity effect of the principal coordinate system. Furthermore, it is shown that the triaxiality is indeed responsive to the presence of fracture. Previous processing of the field example has showed that fractures exist in many zones. The triaxiality index derived from the new method is found in a fairly good agreement with the fracture index from a previous method.
Physics-Based Approach for Shale Gas Numerical Simulation: Quintuple Porosity and Gas Diffusion from Solid Kerogen
Authors: Lopez Bruno , Aguilera Roberto 
Published: September 2015

Abstract
The objective of this study is to provide a detailed physics-based explanation of production behavior of shales through the construction of a fully implicit finite difference numerical model that includes five storage mechanisms as well as the gas dissolved in solid kerogen. Shale gas reservoirs are characterized by multiple porosities such as inorganic matrix porosity, organic matrix porosity, microfracture and slot porosity, hydraulic fracture porosity created during the stimulation of the shale reservoir, and adsorbed porosity. In addition to this complex system, natural gas is trapped and stored in shales as free, adsorbed and dissolved gas.
Simulation of shale gas reservoirs is conducted by the introduction of a quintuple porosity approach in which the aforementioned storage mechanisms, the dominant nano-scale structure of shales and the presence of viscous flow, slip flow and Knudsen diffusion are honored in order to rigorously represent the physics associated with gas flow in these types of reservoirs.
Simulated results are presented as cross-plots of P/Z vs. Gp, which are used to show the effects of the quintuple storage formulation on the behavior of shale gas reservoirs. The gas contributions due to free gas, adsorbed gas and dissolved gas are highlighted as part of the numerical modeling results. The numerical model is also compared against real data from Devonian gas shales. The characteristic signature of actual data is reproduced by the numerical simulator developed in this work.
This paper presents a comprehensive methodology, which efficiently handles all the storage mechanisms present in shale gas reservoirs in such a way that better estimates of original gas in place (OGIP) and recoveries can be performed. This work also helps to reduce the uncertainty related to shale gas production forecasts since the current available simulators do not efficiently represent the physics of these unconventional reservoirs. Therefore, it is crucial to consider all the factors addressed in this paper. Ignoring one of these elements will lead to underestimation of gas production from shale gas reservoirs.
It is concluded that the simulation approach proposed in this study provides a more accurate reservoir model for shale gas representation and a better understanding of the flow mechanisms occurring in these reservoirs.
Effective Method for Monitoring Oil Based Mud Contamination in Wireline Formation Testers Sampling
Authors: Pineda W. , Gozalpour F. , Hagshenas Mehdi 
Published: September 2015

Abstract
The Wireline Formation Tester (WFT) is a well-developed technology to collect representative downhole fluid samples. Collecting low contamination downhole samples in wells drilled with miscible oil-based mud (OBM) is challenging because the process must balance the need to acquire a sample with the desired level of contamination while using the minimum rig time. In addition, quantifying the level of OBM contamination is subject to vendor's experience and their software.
We introduce a simple but effective method for monitoring WFT sampling when targeting the low levels of contamination needed for asphaltene onset pressure (AOP) analysis. Accurate AOP measurement is critical to mitigate flow assurance risks and AOP accuracy is affected by the sample contamination levels.
The intent of this method is not to replace the well-established clean out monitoring techniques but rather to complement them. This approach uses gas oil ratio GOR data from downhole fluid analyser to predict the maximum GOR that would be achieved by pumping at infinite time and use this value as a reference to determine when the clean out process should stop and filling the sample bottles should begin.
Traditional contamination prediction methods are mainly developed for single probes and face limitations when applied to sampling with concentric probes. Although the examples used are based in focused type probes, this approach is independent of probe geometry and vendor technology.
Success stories of applying the method for obtaining high quality samples in nine sampling stations from three reservoirs in the Gulf of Mexico are presented. Laboratory analysis showed the highest OBM contamination from the samples collected was less than four weight percentage of stock tank oil (STO). In five stations the contamination was equal to or less than 1%. The highest difference between the contamination predicted real time and contamination measured in the laboratory was 1.8%.
Treatment of Condensate and Water Blocks in Hydraulic Fractured Shale Gas-Condensate Reservoirs
Authors: Ganjdanesh Reza , Rezaveisi Mohsen , Pope Gary A. , Sepehrnoori Kamy 
Published: September 2015

Abstract
The accumulation of condensate in fractures is one of the challenges of producing gas from gas-condensate reservoirs. When the bottomhole pressure drops below the dew point, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gas production rate. This reduction of gas productivity is in addition to the reduction due to water blocking by the fracking water. Solvents can be used to remove liquid blocks and increase gas and condensate production rates. In this paper, dimethyl ether (DME) is introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flow back after the treatment. We compare its behavior with both methanol and ethanol solvents.
An Experimental Study of the Impact of Injection Water Composition on Oil Recovery from Carbonate Rocks
Authors: Alshakhs Mohammed J , Kovscek Anthony R 
Published: September 2015

Abstract
An experimental investigation is presented that shows oil recovery and wettability changes accompanying alteration of injection water salinity. The study aims to provide a better understanding of the impact of salinity leading to greater oil recovery and the mechanisms that take place for carbonate rocks.
A series of forced imbibition experiments was conducted using crude-oil at different total salinity and ionic composition. In the first test set, three brines of different salinity were injected sequentially into reservoir cores with realistic initial oil and water saturation. Additional incremental oil recovery of 4.4-6.4% of the original oil in place (OOIP) was observed, during the tertiary stage. The injection of synthetic seawater, that has a salinity of 55 kppm, was replaced by a new brine (MgSO4) of similar total salinity (45 kppm) and rich in Mg2+ and SO42- ions. Injection of twice-diluted seawater of 27 kppm, during the tertiary stage, yielded an incremental oil recovery of 0.9%. The effect of reducing the total salinity was evaluated in a second test set using outcrop limestone cores and another crude-oil. An incremental oil recovery increase of 6.5% was observed when twice-diluted seawater (29 kppm) was injected during the tertiary stage following seawater injection.
Wettability alteration was assessed using classic crude-oil contact-angle tests on smooth calcite surfaces. Contact-angle measurements suggest that the release of oil is caused by a wettability shift toward water wetness. The static water contact-angle was reduced in first test set from 92.7° to 55.4° when the brine was switched from seawater to the magnesium-rich brine. Similar reduction was observed in the second test set. The static water contact-angle was reduced from 70.1° to 58.9° when the brine was switched from seawater to twice-diluted seawater.
The contribution of the rock/brine/oil interactions to the wettability was evaluated by measuring zeta potential of water/oil and water/solid interfaces. DLVO (Derjaguin, Landau, Verwey and Overbeek) theory of surface forces, using the measured zeta potentials rationalized observations of oil recovery in the case of low water salinity.
The finding of this work provides a new approach for utilizing salinity alteration to achieve greater oil recovery. The impact of water salinity is usually correlated with low water salinity or with increasing the concentration of the key divalent ions. This study combines both salinity modification schemes to increase tertiary oil recovery.