bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Corrections to Buckley-Leverett Flow
Authors: Deng Lichi , King Michael J. 
Published: September 2015

Abstract
At the reservoir scale, multiphase fluid flow is well characterized by the Buckley-Leverett flow equations, neglecting capillarity. However, as we extend our studies in higher resolution using multiscale calculations, or evaluate tighter or higher contrast heterogeneous or fractured reservoirs, capillarity becomes increasingly important. To improve the understanding of these situations, we have extended the analytic solution of the Buckley-Leverett equations to include capillarity. Specifically we have solved the incompressible waterflood flow equations along a streamtube or streamline with arbitrary cross-section for a heterogeneous porous media with variable injection water rate, including capillarity. The methodology is an application of a singular perturbation expansion with matched asymptotic solutions. The outer solution is identical to the continuous portion of the Buckley-Leverett saturation profile while the inner solution is the steady state solution first noted by Terwilliger experimentally. The two solutions match at the Buckley-Leverett shock saturation and all solutions can be expressed in closed form. The result of this analytical solution is tested against high resolution flow simulation to verify its validity. This analysis is also applied to the calculation of capillary end effects in laboratory core floods, where the length scale of the saturation correction can be predicted. We also demonstrate, as the shape of the saturation profile near the front depends upon the capillary pressure function, that this analytical solution can used to interpret experimental data and derive and calibrate the capillary pressure function.
Advances in Flowback Chemical Analysis of Gas Shales
Authors: Zolfaghari Ashkan , Tang Yingzhe , Holyk Jordan , Binazadeh Mojtaba , Dehghanpour Hassan , Bearinger Doug 
Published: September 2015

Abstract
Recently, flowback chemical analysis has been considered as a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging due to the complexity of shale-water interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water.
The water samples at different flowback times and the shale samples are collected from three wells completed in the Muskwa, Otter-Park, and Evie members of the Horn River Basin. The water samples consist of aqueous solution and precipitated salts. The water samples are digested in nitric acid to dissolve the precipitated salts, and are analyzed at both intact and acid-digested conditions using ICP-MS. The flowback salts are weighted and analyzed using XRD and SEM-EDXS. A sequential ion-extraction is performed on the shale samples; and the extracted ions are categorized into three tiers of loosely-, moderately-, and strongly-attached ions.
The concentration of monovalent cations in both intact and acid-digested samples is higher than that of divalent cations. Also, the concentration of all cations is higher in the acid-digested samples compared with that in the intact samples. The ratio of divalent cations concentration in the acid-digested samples to that in the intact samples is higher than that for the monovalent cations. This ratio increases for the divalent cations over time, while it remains constant for the monovalent cations. Additionally, for the acid-digested samples the monovalent cations concentration has an initial sharp increase followed by a slower increase at later flowback stages; while the divalent cations concentration increases continuously over time. These results suggest that the majority of the ions in the early flowback water are loosely-attached monovalent ions. These ions can be originated from the mixing with in-situ formation brine, dissolution of soluble precipitated salts, or leaching of exchangeable cations from the clay minerals. Similarly, the role of relatively slow water-rock interactions (such as leaching of divalent exchangeable cations, e.g. Ca2+,) increases at the later flowback stages. XRD and SEM-EDXS analyzes of the flowback salts indicate that sodium chloride, potassium chloride, and calcium carbonate are the major salts. The sequential ion-extraction reveals that the majority of the monovalent cations are in the loosely-attached tier. However, majority of the divalent cations are moderately- /strongly-attached to the rock. The strongly-attached portion of the ions is determined by acid digestion of the rock sample at the final stage of sequential extraction process. These strongly-attached ions cannot be easily released by hydraulic fracturing and therefore, has small effect on the flowback water chemistry.
Pore Size Distribution from Water Adsorption Isotherm
Authors: Zolfaghari Ashkan , Dehghanpour Hassan 
Published: September 2015

Abstract
Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we develope a model to characterize PSD of shales using water adsorption isotherms. We apply the model on several shale samples and compare the results with the PSDs obtained from BET (Brunauer-Emmett-Teller) analysis using the N2 and CO2 adsorption isotherms.
The proposed model describes the relationship between the cumulative adsorbed water and the size of the invaded pores due to capillary condensation during the water adsorption process. A set-up is designed to obtain water adsorption isotherms. The shale samples are placed in a sealed environment with a controlled relative humidity (RH). Different saturated salt solutions are used to control RH. At the end of the adsorption process, the model is applied to calculate PSD of the shale samples using their water adsorption isotherm. In order to evaluate the model results, we used BET analysis to obtain PSD from the N2 and CO2 adsorption isotherms. Moreover, the specific surface area (SSA), pore volume (PV) and the average pore size of the shale samples are also obtained from the BET analysis to compare the proposed model and BET results. The results of both BET and the proposed model indicate that the majority of the pores are smaller than 10 nm. However, the model results from the water adsorption show a bimodal PSD, while the BET analysis shows a unimodal PSD. Also, the model calculates small pores of less than 1 nm, while BET does not detect these pores. Water adsorption by clay minerals at low RH values is a possible reason for this discrepancy. Furthermore, the sample with higher clay content shows larger hysteresis at the end of the sorption (adsorption-desorption) experiment; suggesting that the clay-bound water cannot be easily removed during the desorption process.
Advancing Multidisciplinary Training and Development for Young Professionals in the Oil and Gas Industry
Authors: Holderby Eric , Van Domelen Mark 
Published: September 2015

Abstract
Within the ever increasing collaborative environment of the oil and gas industry, there has been significant growth in the need for professionals to be able to operate across industry-standard definitions of disciplines. Influences, such as economic cycles, growth in other industries, and population growth have created a growing demand for young professionals to assume responsibilities and management duties at a rapid pace. While educational advances within the university setting are making efforts to close the gap necessary to supplement this demand, the majority of the responsibility to develop competent employees lies with the employer.
Employers within the industry are beginning to realize and act on the need for structured training and development programs to help ensure employees are adequately prepared and familiar with multiple concepts of business, even across historically set up discipline divisions. This is particularly true within technical disciplines, because there is a great demand for these technical employees to fulfill roles and responsibilities that push them beyond their technical training and typical roles. Moreover, the rapid increase in the use of technology necessary to operate in the unconventional reservoir setting has created a situation of dependency on these technical employees to take on managerial and strategic business-focused roles.
Historically, technical employees within the oil and gas industry have operated within specific niches according to their education and/or experience. However, an increase in multidisciplinary project management as it relates to asset development suggests the need for technical employees to develop themselves across discipline boundaries. Training and development programs that cover all aspects, from geology and geophysics, drilling, completions, production, and asset management, are essential to prepare these young professionals for the responsibilities within this setting. In addition to broader technical training, soft skills training to adequately prepare technical employees to express difficult concepts coherently and effectively is paramount to bridging the gap between the technical and nontechnical portions of the industry.
This paper outlines suggested advances that can be made to effectively train and develop technical employees in this evolving setting during entry level training and more specifically mid-career professional development. A description of historical training methods in the industry, current trends of training technical employees within a certain discipline, and the developing understanding of the importance of multidisciplinary technical collaboration are also discussed.
Nature friendly Application of Ionic Liquids for Dissolution Enhancement of Heavy Crude Oil
Authors: Sakthivel Sivabalan , Velusamy Sugirtha , Gardas Ramesh L. , Sangwai Jitendra S. 
Published: September 2015

Abstract
The upstream petroleum industry faces operational and technical challenges due to the production of crude oil containing waxes, asphaltenes and aromatic compounds and also due to the formation of gas hydrates resulting in their deposition in the surface and production equipments and in offshore pipelines affecting the safer operations, in turn resulting in huge production losses, and threatening the environment. It is also estimated that, all over the globe there are more than double the times of reserves of heavy and extra-heavy crude oil than the lighter one. In spite of this, the production of heavy oil is still low. As the world’s demand for light crude oil continues to increase tremendously, the supplies of these easily extractable crude oil continues to decrease although efforts have already been made to extract the heavy and extra-heavy oil that was previously considered uneconomical to produce and process. The enhancement in the solubility of heavy crude oil in solvent and ionic liquids mixture is investigated using UV-visible, FT-IR and 13C- NMR spectroscopic techniques. Ionic liquids also aid in the reduction of surface forces between oil-water systems thereby helping for the recovery of entrapped oil from exhausted reservoirs which have failed to produce the residual oil. This work also investigates the role of ionic liquids in reducing the surface forces at the interface of crude oil-water system. Synergistic effect of ionic liquids along with brine has also been tested. It is observed that, the dissolution of heavy crude oil is more in the solution with ionic liquid than with the solvent alone. Solubility of heavy crude oil in the presence of studied ionic liquids and in the studied solvents increases about 60 %, when compared with the solutions of heavy crude oil in solvents without ionic liquids. Measured interfacial tension values between solutions of ionic liquid and crude oil reveal that these ionic liquids are successful in reducing the surface tension and interfacial tension. Improved efficiency in reducing the interfacial tension using salt and ionic liquid mixture has been observed between crude oil and the aqueous solution of ionic liquid. This method also helps in minimizing the amount of organic solvents that may be used to a considerable extent. Delayed production of crude oil due to flow- assurance issues or the loss of valuable fuel which remains unrecoverable due to the huge and cumbersome technical difficulties in the prevailing enhanced oil recovery processes could be greatly reduced by employing the use of ionic liquids.
Petrophysical Evaluation and 3D Geostatistical Reservoir Modeling of Okati Field for Development, Shallow Offshore, Niger Delta
Authors: Alabrah Bibobra Michael 
Published: September 2015

Abstract
In order to ensure optimal hydrocarbon recovery and sustained production, it is imperative to carry out reservoir characterization and modeling, that is aimed at facilitating a holistic field evaluation geared towards effective development strategies and optimal field performance.
Okati field located on the continental shelf in water depths of 210-250 feet in shallow Offshore, Eastern Niger Delta, was investigated to determine the petrophysical properties of the reservoirs, and model the 3D spatial distribution of the properties of H3 reservoir using geostatistical techniques. Well logs, core, and pressure data were analyzed and interpreted in order to assess the hydrocarbon potential of these reservoirs.
The structural 3D grid surface and models were generated with inputs of the interpreted petrophysical parameters using Petrel and Interactive Petrophysics. These parameters were upscaled to provide discrete facies and continuous properties. The reservoirs (H1, H2, H3, H4, H5 and H6) have good effective porosities that range from 12 to 27%, high net-to-gross values that range from 55 to 89%. It was deduced that, the field has very good hydrocarbons saturation (range from 55 to 88%). The porosity and permeability models built indicate that, wells 2 and 3 have better storage and flow capacities relative to well 1. The fluid contact and water saturation models however, show that, well 3 is close to the oil-water-contact and has high water saturation which makes it a poor candidate for completions to avoid early water breakthrough. The volumetric assessment indicates 38.4MMBO of STOOIP.
It is concluded that, apart from H1, all the other five reservoirs have good petrophysical properties, hence, from a petrophysical standpoint; they are prospective candidates for future completions and development.
Mathematical Modeling Of Two-Phase Production From Unconventional Wells Using Analogy To Nature
Authors: Mikolajczak Edyta 
Published: September 2015

Abstract
Determining the changes of production is the key aspect of forecasting the exploitation of unconventional reservoirs. Two-phase flow and flowback after fracturing is observed in that resources. To get to know production profile is needed to find the relationship between produced water and produced gas.
This paper presents a new mathematical model for two-phase production forecasting, based on the populations dynamics model. The idea of this work is to use system of two logistic equations with additional term for modeling water and gas production declines. This paper is a continuation of my previous work connected with mathematical modeling of single phase flow in unconventional reservoirs.
The production process of unconventional wells divides it into three stages: dewatering, stabilized flow, decline. During the initial phase of exploitation, water production initially exceeds that of methane, but as production continues, the volume of gas increases steadily while the amount of water decreases. Over the stable period the gas rate slowly peaks. After that water production remains low and gas declining tendency begins.
The proposed model uses the analogy of processes of competition occurring in nature to two-phase flow phenomena in gas reservoirs. The presented model has a widespread use in modeling the populations dynamics including competition between two species. It is a set of two differential equations, which describe both interspecies and intraspecies interactions.
This paper contains two main parts. Part one presents a brief reminder of my preceding work, while part two includes description and explanation of my new model and modeling results.
The proposed model was successfully applied to extremely low permeability gas wells. The model can very accurately trend the declines behavior of these wells. The modeling results were verified by the real industrial data.
Gas Permeability Evolution with Soaking Time in Ultra Tight Shales
Authors: Chakraborty Nirjhor , Karpyn Zuleima T. 
Published: September 2015

Abstract
The single phase matrix permeability to gas in ultra-tight rocks such as shales, are typically in the order of around 1 – 500nD. When these rocks are exposed to liquid invasion during hydraulic fracturing operations, gas permeability can become significantly lower, due to the formation of liquid blocks at the fracture-matrix interface. Post fracturing shut-in time or “soaking time” is thought to alleviate this permeability damage by allowing for liquid blocks to spontaneously dissipate into the reservoir, driven by the strong capillary forces present in tight rocks. However, this redistribution of fluid also results in the formation of a larger invaded zone which may further damage gas permeability.
This paper presents a means of analyzing the change in permeability on shale cores with soaking time and subsequent production. Key observations from this work are that the introduction of even relatively small quantities of liquids into the rock matrix can lead to a significant reduction in average permeability. Soaking time further exacerbates the situation by allowing fluid to spontaneously propagate deeper into the matrix. Effects such as clay swelling lead to irreversible impairment of base matrix permeability, and a low threshold water saturation for gas to become immobile means that any spreading of fracturing fluid with soaking time could reverse benefits accrued from lowering the fluid saturation in liquid blocks.
The experimental work done in the current study is on Marcellus and Haynesville shale samples. The results obtained on soaking time experiments are compared with similar experiments on conventional and tight sands. This comparative analysis indicates that soaking time is beneficial to rocks with relatively higher permeability and low clay content whereas it is detrimental to ultra-tight lithologies such as shales. These lab scale trends can help contextualize observed field scale production characteristics based on reservoir lithology, base matrix permeability, and duration of soaking time, and thereby, provide operators a scientific foundation for the selection of an optimum post stimulation gestation time before beginning production.
Thermodynamics of Flat Thin Wetting Films with Applications to Low- Salinity Waterflooding
Authors: Myint Philip C. , Firoozabadi Abbas 
Published: September 2015

Abstract
In the past several years, a number of papers have attempted to explain the phenomenon of improved oil recovery due to low-salinity waterflooding from the perspective of the thin brine films that wet the surfaces of the pores. Because of the complicated, multiscale nature of low- salinity waterflooding (LSW), the studies on this topic have been largely limited to phenomenological observations and explanations. Improving our understanding of thin liquid film thermodynamics is an important step towards developing our knowledge of LSW and optimizing the effect of brine chemistry on oil recovery.
In this work, we analyze two fundamental thermodynamic problems relating to flat thin liquid films. One problem concerns the expression for the Gibbs energy of the films. Thin liquid films undergo film tension work. There are conflicting results in the literature over whether to include the film tension work in the Legendre transform that relates the Gibbs energy to the internal energy of the films. We show that for the purposes of finding the equilibrium state, the Legendre transform must include the film tension term so that the chemical potentials are equivalent to the partial molar Gibbs energy. The second problem we examine involves the augmented Young equation, which is a condition for mechanical equilibrium involving the contact angle at the boundary between a thin liquid film and the bulk liquid droplet from which the film is formed. Two different expressions for the augmented Young equation have appeared in the literature. We show that under certain assumptions, the two expressions can be made equivalent.
We then briefly discuss how fundamental thermodynamic relations of thin liquid films can help explain the wettability alteration observed in LSW studies. We conclude with a summary of our main results.
A Comprehensive Model for Simulation of Gas Transport in Shale Formation with Complex Hydraulic Fracture Geometry
Authors: Yu Wei 
Published: September 2015

Abstract
A comprehensive model for simulating gas transport in shale formation with complex fracture geometry is still lacking in the petroleum industry. First, the current models are challenging to efficiently handle the complex non-planar fractures with varying fracture width and fracture permeability along fracture length due to very complicated gridding issues, an expensive computational cost, and complexities in development of computational codes. Second, conventional gas mass balance equation needs to be revised to include all important gas transport mechanisms such as gas slippage, gas diffusion, and gas desorption. Hence, the goal of this study was to develop a new model to fill this gap.
We present an efficient semi-analytical model by dividing fractures into several fracture segments to represent the complex non-planar fracture geometry and present a revised mass balance equation to consider all the important gas transport mechanisms for shale gas reservoirs. We verified this model against a numerical reservoir simulator for planar fracture by considering the effects of gas desorption, non-Darcy flow, and geomechanics separately. Transient flow behavior between planar fractures and non-planar fractures with and without considering the natural fractures was compared. Furthermore, a well with actual production data from Marcellus shale was analyzed. First, we use a three-dimensional fracture propagation model to generate more-realistic non-planar fracture geometry. Then, we apply the fracture geometry into a semi-analytical model to evaluate well performance. Contributions of each mechanism to gas recovery are then examined. Based on history matching and production forecasting, the difference of cumulative gas production between the realistic non-planar fractures and ideal planar fractures is about 20% at 30 years of production. In addition, the contribution of flow mechanisms such as gas slippage, gas diffusion, and gas desorption to gas recovery at 30 years of production compared to that without considering them is about 13%, 17%, and 22%, respectively. Totally, the contribution of all the important mechanisms is about 52%. Hence, modeling of gas production from the realistic non-planar fractures as well as modeling the important gas transport mechanisms in shale gas reservoirs is significant.
This work, for the first time, combines a complex non-planar fracture geometry with varying fracture permeability and the important gas transport mechanisms to efficiently analyze field production data from Marcellus shale. The model can provide significant insights into understanding the impacts of gas slippage, gas diffusion, gas desorption, and non-planar fracture geometry on long-term gas recovery prediction.