bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Squeeze Placement Options in Subsea Multi-Lateral Horizontal Wells Completed With Sliding Sleeve Technology
Authors: Jordan Myles , Ishkov Oleg , Vazquez Oscar , Mackay Eric 
Published: April 2016

Abstract
The deployment of scale squeeze treatments in subsea horizontal wells has always presented a challenge in terms of understanding the location of injected fluids vs the location of the produced water where scale formation will occur. Over the years software packages such as Eclipse has been able to provide valuable information on the possible placement options for such wells when production logging tool (PLT) data have not been available. The development of multi-lateral drilling/completion technology has further complicated the placement challenges in such wells.
In this paper Eclipse simulation data has been linked to SQUEEZE designs software for two subsea production wells completed with multi laterals and sliding sleeves to allow selective placement of the squeeze treatment. The objective of the study was to evaluate the options of bullhead deployment in terms of both laterals being open during the squeeze vs two squeeze stages being sized and selectively placed into each lateral again via bullhead deployment, but this time using the sliding sleeve technology to divert the chemical.
Information on cross flow issues, the pump rates required to allow effective placement are presented, along with the differences in chemical volumes, pump time and soak times required for the two potential treatment options. The finding from this study show the clear advantages in terms of treatment volumes, reduced clean up time and extended treatment life (reduced intervention frequency) of bullhead deployment of two squeeze steps, one to each lateral, achieved by utilizing the sliding sleeve technology in these two production wells.
Study of Thermal Stability of Scale Inhibitors and its Impact on Processing Plants
Authors: Rosa Katia Regina , Bezerra Maria Carmen , Fontes Rosane Alves , Ponzio Eduardo Ariel , Rocha Anderson Araújo 
Published: April 2016

Abstract
Petroleum, which is one of the most complex mixtures existing in nature, is equilibrated and coexists with the aqueous phase at reservoir conditions. However, depending on the oil viscosity, strong emulsions may be formed due to the high shear imposed by the production process. As a consequence higher temperatures conditions are necessary for the oil separation treatment. Therefore it is important to assure that scale inhibitors are thermally stable and able to act in what are considered extreme temperatures such as the ones used in heat exchangers, for example 16 °C. This work aimed to evaluate the influence of temperature in the scale inhibition activity for different active materials of chemical inhibitors, such as: Nitrilotris (methylene) tri phosphonic acid (NTP), Diethylenetriamine penta (methylphosphonic acid) (DETPMP), and polyvinyl sulphonate (PVS). Aqueous inhibitor solutions were aged in the temperature conditions between 60 to 160 °C for different times (6, 12 and 24 hours). Raman spectroscopy, NMR (31P, 1H and 13C) and FT-MS techniques were used to characterize chemical species from aged and original inhibitor solutions. Different from previous works, these techniques allow identification of some degradations products. Additionally, dynamic performance tests were conducted to evaluate scale inhibitor performance of the solutions. Results of the chemical characterization of the original and thermally aged PVS showed no compositional differences. Dynamic testing for barium sulphate scale showed that minimum effective concentrations remained constant in all assays. However, for the NTP and DETPMP products, at the highest temperature (160 °C, after 24 hours of testing) some degradation products were identified, such as methyl phosphonic acid, and especially, amino methyl phosphonic acid. As a consequence of the structural breakdown of the phosphonate molecules, confirmed by chemical analysis using FT-MS and NMR, the efficiency of inhibition of barium sulphate scale was reduced. The paper presents a methodology to evaluate and understand the behavior of different chemical inhibitors for extreme temperature conditions and highlights the demand for new stable molecules for high temperatures.
Estimation of Transport Diffusivity of Natural Gas in Organic Matter Using Molecular Dynamics Simulation
Authors: He Shuai , Ning Yang , Chen Tianluo , Liu Honglin , Wang Hongyan , Qin Guan 
Published: April 2016

Abstract
Due to the uncertainty in shale reservoir simulation, increasing attention has been drawn to the investigation of nano-scale transport behavior in heterogeneous shale rocks. Molecular dynamics simulation has become a widely-used simulation technique to investigate molecular behaviors at nanoscale. In this paper, we combined one of the state-of-art pore characterization techniques with molecular dynamics simulation to study the natural gas transport behavior in complex nano-pore networks in organic matter. Representative kerogen molecule is selected based on thermal maturity and the origin. Methane molecule is chosen to represent natural gas. Equilibrium molecular dynamic simulations have been performed to construct kerogen clusters and the structural properties of the organic matter have been studied. As a building block, the amorphous kerogen clusters were inserted into the digital rock obtained from focused ion beam scanning electron microscopy (FIB-SEM). Then, non-equilibrium molecular dynamics simulations were performed to study the transport behavior of natural gas in the reconstructed nano-scale digital rock. The transport diffusivity coefficients were thus determined by following the Fick's first-order diffusion equation. The proposed method provides a new insight into the understanding of nano-scale transport behavior of natural gas in shales, which is crucial to the prediction of long-term production performance and reserve estimation in larger-scale reservoir simulation.
Stability Analysis and Equilibrium Considerations in Tight Formations
Authors: Sherafati Marjan , Jessen Kristian 
Published: April 2016

Abstract
Despite the large potential of unconventional resources, many unknowns still exist regarding the physics controlling the extraction processes in these settings. These include accurate representation of phase equilibrium in tight formations and effective implementation of relevant models in simulation tools. In this work, we analyze the numerical aspects of including capillarity phenomena in VLE calculations in an effort to arrive at robust and efficient algorithms for stability analysis that can be used in compositional modeling/simulation of unconventional reservoirs.
When a fluid is confined in pore spaces of nanometer size, significant interfacial curvatures may occur that can result in large capillary pressures between the liquid and vapor phases: The pressure difference between the two phases will likely affect the vapor-liquid equilibrium state. Previous efforts have shown that this effect is negligible for conventional reservoirs (with pores in the micron range) and current commercial reservoir simulators ignore the effect of capillary pressure in the VLE calculations. However, experimental and modeling efforts have shown that ignoring capillary pressure in the VLE calculations will not be a valid approximation for unconventional (tight) reservoirs.
In this work, we specifically look at the effects of including capillary pressure in stability analysis. While the equality of chemical potentials is a necessary condition for equilibrium, it is not a sufficient one. A sufficient condition for equilibrium is the minimization of Gibbs energy, and the latter can be tested using the tangent plane distance (TPD) criteria. We show that stability analysis testing based on the TPD criteria remains valid for systems with large capillary pressures and propose effective/robust algorithms for stability testing. The proposed algorithms are tested for multicomponent reservoir fluid systems over a range of relevant T, P and pore radii.
Capillary Pressure Effect on Hydrocarbon Phase Behavior in Unconventional Reservoirs
Authors: Zhang Yuan , Lashgari Hamid R. , Di Yuan , Sepehrnoori Kamy 
Published: April 2016

Abstract
Small pore sizes on the order of nanometers in the shale gas and tight oil reservoir formations can lead to a large capillary pressure. The presence of capillary pressure significantly affects both the thermodynamic behavior of fluid mixtures and the fluid flow process. Although there have been some attempts to study the effect of capillary pressure on phase behavior, it has not been clearly understood in the application considering multiple components in tight oil reservoirs. In this work, we present a methodology to calculate the phase behavior of CO2/hydrocarbon systems in the presence of capillary pressure. We modify the Peng-Robinson equation of state considering inequalities of hydrocarbon liquid and vapor pressures. The criterion of Gibbs free energy minimization and Rachford-Rice flash calculation are applied in the phase equilibrium calculation. The Young-Laplace equation is utilized to calculate capillary pressure. The Newton-Raphson method is used to solve the nonlinear phase equilibrium equations. We validate the methodology against two experimental measurements and a published numerical model. Subsequently, binary mixture and one typical fluid from the Bakken Formation are used to study the influence of capillarity in the unconventional reservoir. The simulation results indicate that capillary pressure plays an important role in the phase equilibrium calculation when pore size is less than 50 nm. Additionally, the bubble-point pressure of Bakken oil reduces nearby 500 psi when the nano-pore size is 10 nm. The developed method can address the thermodynamics governing unconventional reservoirs and provide better understanding of the phase behavior of CO2/hydrocarbon systems in the case of CO2 injection into unconventional reservoirs.
Rock Characterization in Unconventional Reservoirs: A Comparative Study of Bakken, Eagle Ford, and Niobrara Formations
Authors: Cho Younki , Eker Erdinc , Uzun Ilkay , Yin Xiaolong , Kazemi Hossein 
Published: April 2016

Abstract
Liquid-rich shale reservoirs contribute immensely to the United States oil and gas production. Because Bakken, Lower Eagle Ford, and Niobrara formations have different mineralogy, pore structure, organic content, and fluid compositions, it is critical to differentiate the unique characteristics of each formation for field development and oil and gas production. The latter information is also useful in well stimulation design and hydraulic fracturing.
This paper presents an experimental study of mineralogy, pore-size distribution, pore geometry, and spatial correlation between minerals and pores to identify the effect of micro-scale properties on flow behavior. Porosity and permeability of several core samples from the Middle Bakken, Lower Eagle Ford, and Niobrara formations were studied and the results, using mercury injection capillary pressure (MICP), X-Ray diffraction (XRD), and scanning electron microscopy (SEM), were shown. Finally, a workflow that estimates cementation factor combining the results obtained from MICP measurements and GRI crushed core analysis will be presented.
A Practical and Rigorous Approach for Production Data Analysis in Unconventional Wells
Authors: Holy R. W. , Ozkan E. 
Published: April 2016

Abstract
A new approach for production data analysis in unconventional reservoirs is presented. Unlike the existing decline-curve analysis methods, this approach is not empirical and it is theoretically rigorous. The basis of the approach is an anomalous diffusion model for the performance of fractured horizontal wells surrounded by a stimulated reservoir volume. In the anomalous diffusion model, instead of Darcy's Law, a more general constitutional relation is used to incorporate the non-local and hereditary nature of flow in highly heterogeneous nanoporous media. The sub- or super-diffusive state of flow can be deduced from the slope of the straight line on the log-log plot of rate vs. time. Nonnecessity of a detailed description of the intrinsic properties and spatial distribution of matrix and fracture constitutes the practical advantage of the model. The reduced number of parameters can be conveniently estimated from production data and used in the anomalous diffusion model to predict future production. In this paper, a one-dimensional numerical model is implemented and applied to two Barnett shale gas wells and compared to common empirical models. It is shown that, even with limited completion, reservoir, and production data, the anomalous diffusion model has the potential to capture the production characteristics. Moreover, the model can be used to run sensitivities on actual system variables such as hydraulic fracture length, height and spacing, as well as to account for changing operating conditions.
Hydraulic Fracturing Placement Issues on Horizontal Wells in the Mancos Shale, San Juan Basin: Case Study of Possible Causes, Solutions, and Results
Authors: McCarthy Caitlin , Garcia Mariano 
Published: April 2016

Abstract
The Mancos shale in the San Juan basin can present challenging conditions when hydraulic fracturing treatments are performed in horizontal wells. Some of the issues while completing a well in the Mancos can be caused by overall geomechanics and reservoir properties; for example, high horizontal stress anisotropy and the presence of discontinuities, such as microfractures and lamination. This paper presents three case studies in which hydraulic fracturing placement issues were explored.
Normally, the interactions of geomechanics and reservoir properties cause high treating pressures or premature screenouts, as presented in previous publications. Ramurthy et al. (2009a, 2009b) and Potocki (2012) explain how and why properties, such as process zone stress (PZS), pressure-dependent leakoff (PDL), and geomechanics, can affect the hydraulic fracturing conditions and production results. Depending on how the well is completed, these challenging conditions can be either enhanced or minimized. When the reservoir and geomechanics are not taken into consideration in the completion design of the well, issues can occur during the hydraulic fracturing of the formation.
Issues including screenouts, pressure outs, and high pressure while trying to initiate the fracture can lead to the formation not allowing the placement of the designed treatment, improper stimulation of the reservoir, excessive completion costs, and more commonly than not, poor production. This paper presents three case studies. In all three studies, similar reservoir characteristics and geomechanical conditions occur, which pose challenging obstacles for both completion and production. The challenges were each addressed in different ways, resulting in different outcomes. In one case, no action was taken to mitigate these obstacles. In the second case, the area was studied using analysis service data, treatment data, and public information. This knowledge was applied to assist in the completion of the treatment without issues. In a more recent case, in a well with similar conditions as the two previous studies, only a portion of the recommendations were applied, with mixed results.
This paper presents the knowledge gained from the three case studies conducted in the Mancos shale, San Juan basin. General suggestions are presented when similar conditions are encountered while completing a well.
Pore-Scale Permeability Calculation Using CFD and DSMC Techniques
Authors: Mohammadmoradi Peyman , Kantzas Apostolos 
Published: April 2016

Abstract
Numerical experiments are performed to evaluate the capability and examine the computational costs and tradeoffs of numerical and analytical approaches for apparent gas permeability calculation. Considering the dominancy of capillary force in pore level studies, two-phase distribution maps are constructed within micro and nano-scale scale media using a quasi-static technique. The distribution profile of the non-wetting phase is then extracted to predict the effective permeability and analyze the effect of water saturation. To investigate the effect of gas slippage on the accuracy of the results, both Computational Fluid Dynamics (CFD) and Direct Simulation Monte Carlo (DSMC) techniques are applied in a wide gas pressure range. The results reveal that the continuum theory is valid for a specific pore size and gas pressure range and its accuracy is strongly dependent on the Knudsen number value. DSMC simulation case studies demonstrate that in case of proper medium characterization, a tuned Klinkenberg correlation is capable of providing satisfying predictions within both slippage and transition flow regimes.
Modeling PVT Behavior of Gas-Condensate System Under Pore Confinement Effects: Implications for Rate-Transient Analysis of Gas-Condensate Shale Plays
Authors: Haghshenas B. , Qanbari F. , Clarkson C. R. , Chen S. N 
Published: April 2016

Abstract
Rate-transient analysis (RTA) is a robust technique for evaluating reservoir/stimulation properties and for forecasting production from shale reservoirs. However, knowledge of fluid storage and flow mechanisms, and controlling rock and fluid parameters, is critical for obtaining meaningful information from RTA.
It is common practice to use PVT data measured in laboratories (i.e. bulk fluid properties) for reservoir modeling and production data analysis purposes. These measurement techniques were developed for conventional reservoirs and cannot explain some of the anomalous fluid production behaviors observed for shale gas-condensate wells, such as long-term constant gas/oil ratio (GOR) trends. One explanation for this behavior is that the PVT properties of fluids are affected by confinement in nano-scale pores, and hence deviate from bulk fluid properties.
In order to study the effects of pore confinement on fluid properties in shales, the simplified local density (SLD) model is used. The SLD model can be used to estimate fluid density gradients from pore wall to pore center, and therefore explicitly considers pore geometry in adsorption modeling. This model can also be used to adjust the confined fluid critical properties, phase envelope and viscosity. Significant shifts in phase envelope and fluid properties due to pore confinement are observed in this work. Importantly, the corrected equation-of-state predicts a later onset for condensate dropout in shale reservoirs than for bulk systems. The SLD model is also used to estimate adsorbed layer thickness, which in turn is used to modify flow calculations.
The corrections for fluid properties, adsorbed layer thickness and non-Darcy flow are then analytically incorporated into transient linear flow analysis of nanoporous shale gas-condensate wells. Analysis of simulated cases using the "corrected" (for pore confinement effects) and "uncorrected" RTA is performed to quantify errors associated with the latter.
This study demonstrates that failure to account for pore confinement effects on fluid properties and fluid flow results in errors in linear flow parameter estimation using RTA, but the error depends on the fluid composition, pore size, permeability and pressure. The effects of pore confinement should therefore be considered for proper evaluation of shale gas-condensate reservoirs using analytical or numerical methods.
Simultaneous Estimation of Intrinsic Permeability, Effective Porosity, PoreVolume Compressibility, and Klinkenberg-Slip Factor of Ultra-Tight Rock Samples Based on Laboratory Pressure-Step-Decay Method
Authors: Dadmohammadi Y. , Misra S. , Sondergeld C. H. , Rai C. S. 
Published: April 2016

Abstract
Conventional laboratory characterization of ultra-tight reservoir rock samples involves separate laboratory measurements on different core plugs or on crushed rock samples. Heterogeneity and anisotropy of ultra-tight reservoir samples adversely influence the laboratory correlation among various measured and estimated petrophysical properties.
We apply an inversion algorithm to simultaneously estimate the intrinsic permeability, effective porosity at ambient condition, pore-volume compressibility, and Klinkenberg-slip factor of an ultra-tight pyrophyllite sample from a single laboratory-based pressure-step-decay measurement. In doing so, we circumvent the effects of heterogeneity and account for the pore-pressure dependency of apparent permeability and effective porosity. Moreover, the time and resource requirements are drastically reduced in comparison to those required when performing multiple experiments that separately estimate the aforementioned petrophysical properties.
The inversion algorithm is valid for nitrogen injection pressure in the range of 50 to 500 psi. The algorithm assumes ideal-gas behavior of the injected nitrogen, 1D isothermal laminar gas flow, homogeneity of the core, pressure-independent gas viscosity, inverse-pressure dependence of the apparent permeability, pressure-independent Klinkenberg-slip factor, non-negligible pore-volume compressibility, pressure-dependent effective porosity, negligible inertial effects, negligibly small pressure gradients, and time-invariant confining pressure.
Estimated apparent permeability and effective porosity of the pyrophyllite samples exhibit strong pore- pressure dependence; consequently, both the properties vary substantially along the sample length during the pressure-step-decay measurement. On an average, the effective porosity of the pyrophyllite samples increased by 100% and the apparent permeability decreased by 75% when the pore pressure increased from 50 psi to 500 psi during the measurement. The average values ki, ϕ0, Cp, and b of the nine pyrophyllite samples were estimated to be 40 nd, 0.03, 2×10−3 psi−1, and 100 psi, respectively.
Optimization of Chock Valves for Fracture Clean-up in Tight Gas Condensate Reservoirs
Authors: Zhang Kai , Liu Qingquan , Wang Kun , Jing Gary , Zhang Shihan , Zhan Jie , Wu Keliu , Chen Shengnan , Chen Zhangxin 
Published: April 2016

Abstract
Hydraulic fracturing is a vital technique to unlock tight gas condensate reservoirs. The efficiency of clean-up in tight gas condensate reservoirs has a tremendous effect on well delivery. During hydraulic fracturing flowback operations, only part of fracturing fluids flows back to the surface, resulting in discrepancies between the expected fracture length and the effective production fracture length. A reasonable choke size during fracture clean-up can help to maximize the fracture conductivity.
In order to get a maximum amount of fracturing fluids flowing back to the surface and a least amount of proppants flowing back, optimization of a chock valve in operations is investigated. Furthermore, effects of a proppant size and well types including vertical and horizontal wells on chock valve adjustments are presented.
A chock is adjusted by gradually increasing its diameter as fractures start to close. In addition, the chock size needs to be bigger in a horizontal well than that in a vertical well under the same conditions. If the fracture width close to a proppant size, the chock size will be bigger as the proppant diameter increases; if the fracture width is much larger than the diameter of the proppants, the chock size will be larger with a larger diameter of proppants prior to fracture closure. However, the optimum chock size will be smaller with a larger size of proppants after fracture closure.