bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water/CO2 System at High Pressure and Temperature Conditions: Measurement and Modeling of Density in Equilibrium Liquid and Vapor Phases
Authors: Tabasinejad F. , Barzin Y. , Moore G. R. , Mehta S. A. , Van Fraassen K. C. , Rushing J. A. , Newsham K. E. 
Published: July 2010

Abstract
Accurate density description of saturated liquid and vapor (L-V) phases for the water-CO2 system is important in many fields of engineering and science such as CO2 sequestration, supercritical fluids-based extraction and purification processes, and CO2- related enhanced oil recovery methods. There are only a few studies, mostly dedicated to low pressure and temperature conditions, on densities of equilibrium liquid and vapor phases for this system.
Due to paucity of experimental data at high pressure and high temperature conditions, a series of experiments have been performed to measure the density of both liquid and vapor phases of water/CO2 system from 382 K to 478 K and pressures from 3.48 MPa to 129 MPa. In order to measure the mass of water and volume of gas in the vapor phase, in each experiment the vapor phase of an LV equilibrium system is transferred to an equilibrium flash separator equipped with a desiccant and a gasometer. The gas volume is converted to density based on the ideal behavior of gases at standard conditions. The density of the liquid phase is directly measured by a densitometer.
In addition, a "Two-fluid Model" consisting of the Cubic-Plus-Association equation of state (CPA EOS) and the Henry's law is implemented in phase equilibrium modeling of this system to predict the density of both phases. A comparison between our experimental data, literature data and the results of the model shows the reliability of this model for density prediction of L-V phases of water-CO2 system over a wide range of pressure and temperature conditions.
Role of Gas Markets in Gas Monetization. Case Study: Europe Gas Market Development
Authors: Nikl Harald , Pennington-Bick Debra 
Published: July 2010

Abstract
World gas demand is forecast to increase by more than 40% over the next 20 years. To meet this rising demand, substantial sources of new supplies must be developed. These new supplies are growing in scale and will increasingly come from locations that are further from the major markets of the U.S. and Europe. This increase in scale and distance from consuming markets increases the challenge and complexity of gas monetization. While considerable attention is placed on technology as a driver of gas resource development, from a commercial perspective, the gas markets themselves represent a significant determinant in the ability to monetize gas resources successfully.
This paper addresses the role of gas markets in monetizing gas resources, using the development of the European gas market as a case study. Specifically, the paper describes the evolution of the European gas markets from their traditional country-focused structures, based on long-term oil-indexed contracts, through the emergence of liquid markets in individual countries, to the current development of a pan-European liquid market. The paper considers the key milestones marking each stage of development and the changing role of both market players and regulators in driving that development over time.
Finally, a perspective is provided of the challenges ahead in achieving continued progress in the development of the European gas market. This includes the implications these challenges have for market players and regulators as they seek to create competitive markets that provide reliable gas supply, investment and resource monetization.
Hydrate Formation: Considering the effects of Pressure, Temperature, Composition and Water
Authors: Rajnauth J. , Barrufet M. , Falcone G. 
Published: July 2010

Abstract
The main components in producing natural gas hydrate (whether for gas storage or for transportation), are water and natural gas, at low temperatures and high pressures. Each variable has a significant effect on the formation of gas hydrate. It is therefore critical to analyze the effect of each variable on hydrate formation to ascertain the best conditions required for a successful gas hydrate formation process.
This research evaluates the effect of these critical elements: temperature, pressure, gas composition, and water upon gas hydrate formation. This paper summarizes the findings of a sensitivity analysis using varying natural gas compositions. Results show that the composition of the natural gas can affect the temperature and pressure required for formation of the hydrate. Even more significant is the effect of impurities in the natural gas on the pressure temperature (PT) curves of the hydrate. Carbon dioxide, hydrogen sulfide and nitrogen are the main impurities in natural gas affecting the hydrate formation. At a particular temperature, nitrogen increases the required hydrate formation pressure while both carbon dioxide and hydrogen sulfide lower the required hydrate formation pressure.
The quantity of water required for hydrate formation is an important variable in the process. The water to gas ratio vary depending on the composition of the natural gas and the pressure. Generally the mole ratio of water to natural gas is about 6:1; however, to achieve maximum hydrate formation an incremental increase in water or pressure may be required. This is an interesting trade off between additional water and additional pressure in obtaining maximum volume of hydrate and is shown in this analysis.
Pressure Transient Behavior for Stress-Dependent Fracture Permeability in Naturally Fractured Reservoirs
Authors: Tao Qingfeng , Ghassemi Ahmad , Ehlig-Economides Christine A. 
Published: July 2010

Abstract
Fractures are the main channels of production/injection in naturally fractured reservoirs; therefore the fracture permeability is a key parameter to production optimization and reservoir management. Pressure depletion in naturally fractured reservoirs can result in effective stress change that, in turn, can change fracture permeability. Recent work described a new model employing a fully coupled poroelastic displacement discontinuity method with a nonlinear fracture deformation model and showed that fracture permeability can decrease or increase with decreasing pore pressure depending on in situ stress conditions. The model application featured in this paper is a radial composite reservoir with a dual porosity inner region surrounded by a homogeneous matrix of infinite extent. Similar models in the literature have not included stress dependent fracture permeability. In this model, fracture permeability values vary spatially and with time. The resulting pressure transient behavior is shown for several cases of potential practical interest including both fracture permeability loss and enhancement. The model behavior offers new explanations for commonly observed pressure transient responses and underscores a need for additional rock mechanical properties to ensure conclusive analysis of these systems. Field data experiences indicate that without such data, interpretations may be seriously flawed.
Approximate Simulation of Complex Reservoirs by Using Commercial Simulator
Authors: Peng Xiaolong , Liang Baosheng , Du Zhimin 
Published: July 2010

Abstract
Complex heterogeneous reservoir exhibits special characteristics, such as multiple storage types, wide range of storage sizes, complicated storage combinations, and various flow behaviors. Most fracture-matrix dual-porosity models in current simulators have difficulties to capture the complicated fluid flow in those complex reservoirs and are not well suitable to be used directly. Some numerical and experimental studies are in process but they have not been available in field practice yet.
This paper considers various impact complex reservoir characteristics and proposes an approximate numerical simulation method on the basis of dual-porosity theory and current simulators. The simulators are extended to more accurately model flow behaviors in the complex reservoirs. Several steps developed in this paper are as follows: First, reservoir storage is categorized into continuous and non-continuous media according to storage scale characteristics, distribution and intensity. In general, small cavities, small fractures, and pores in the rock are continuous while large-scale fractures, big cavities or caves are non-continuous. Second, an M-medium model is determined and applied to the continuous region which has N storage types. M is less than or equal to N. The determination of N is illustrated through a dual-porosity model: a continuous medium with two different storage types (such as vug and fracture) or different scales should be treated by a dual-porosity model only if the direction of the flux is ignorable. A new calculation for the flux transfer is then derived for such fracture-vug dual-porosity system. On the other hand, if the flux is directional, a single-medium model is sufficient to the reservoir simulation. Third, flow in a filled non-continuous medium is described by Darcy's law. Free flow in large unfilled cavities or caves follows Navier-Stokes equation and an approximate approach to using Darcy flow simulation is provided. The determination of the critical value for the cavity permeability is illustrated through a cross-sectional model. Lastly, the complex fracture-vug reservoir is simplified into four types of dual-medium models.
The proposed method is applied to a naturally fractured carbonate reservoir with cavities in the Tarim Basin in China. The simulation results match production data and meet the accuracy required in engineering.
Case History of Horizontal Well Fracturing Performance in the Daqing Oilfield, China
Authors: Wenjun Wang , Liu Xinghui , Pengfei Tang , Yu Liu , Changming Zhao , Zhongsheng Wu 
Published: July 2010

Abstract
The Daqing Oilfield, a huge complex consisting of many individual oil fields, is located in the Songliao basin in northeastern China. As reservoir development continues, the target zones become thinner and tighter. Horizontal well completion and fracture stimulation have thus become applicable. To understand fracture growth behavior and well performance, fracture diagnostic techniques, such as temperature logging and microseismic monitoring, as well as fracture modeling have been performed. The case history in this paper involves fracture treatments in several horizontal wells to target tight oil reservoirs in the Daqing Oilfield. Fracture diagnostic results for one horizontal well indicated that longitudinal fractures were obtained as planned. However, fracture diagnostic results in other horizontal wells in different reservoirs showed that the fracture orientation was off significantly from the designed longitudinal fractures. Several fracture models were calibrated using the fracture diagnostic results. The fracture diagnostic and modeling results were used to optimize fracture design for subsequent well stimulation. This case history demonstrated that integrated studies can help engineers optimize well performance.
The Permeability Factor in Coalbed Methane Well Completions and Production
Authors: Palmer Ian 
Published: July 2010

Abstract
After 30 years of CBM production in the USA, and internationally more recently, general principles and decision trees have emerged to guide an operator in choosing a well completion based on permeability. If enough permeability measurements are made, well completions can be prioritized, and hybrid well completions evaluated. The benefits of horizontal and multilateral wells are made clear. Low permeability is a serious challenge for CBM ventures, and further success will entail finding regions of enhanced permeability, utilizing horizontal wells, and "creating" permeability by new-paradigm methods. Perm-based guidelines for CBM well completions are given, which include permeability bands and benchmarks. Industry success has led to two benchmarks for evaluating ahead of full-field development (1) commercial success from reservoir parameters, and (2) effectiveness of well completions. The perm-based guidelines are simple and practical, and should benefit any CBM completions strategy. We also re-examine the striking observations of permeability increases with depletion (10-100 times) in the San Juan basin. The latest attempts to model and match the strong permeability increases with depletion in the San Juan basin are evaluated. Although there remain differences, a consensus has been obtained for some reservoir parameters.
Modeling Shear Dominated Hydraulic Fracturing as a Coupled Fluid-solid Interaction
Authors: Nassir M. , Settari A. , Wan R. 
Published: July 2010

Abstract
Microseismic monitoring in Barnett Shale indicates elliptical zones of failure propagating away from the wellbore and confirms the development of shear fracturing as the main failure mechanism arising from hydraulic fracturing operation. This paper presents a new technique for numerical modeling of both the creation and propagation of shear fractures in fluid induced fracturing. The method employs a coupled geomechanical/single phase flow code. The main role of the geomechanical module is to predict shear failure and provide fracture information to the flow module so that the permeability tensor can be updated accordingly during any coupling loop. In this paper, the technique, constitutive models and formulation implemented to develop the code are briefly presented. Brick type finite elements are used to model the geomechanical as well as the flow parts of the coupled problem. At any time step, the change in the effective stress tensor induced by the block pressure alteration is calculated in the geomechanical module. If the block is not initially fractured, it will be transformed into a fractured block when the shear failure criterion is attained. A pseudo continuum technique is developed and implemented to describe the mechanical behaviour of the fractured rock in which both normal and shear deformation of the fracture are taken into consideration. An example problem is shown to illustrate the application of this work to hydraulic fracturing modeling. This fundamental integrated study is an important advancement in fracture modeling as previous published techniques do not model the shear mechanism rigorously. The work can be extended and applied in other types of fluid injection operations which involve fracturing, such as coalbed methane and CO2 storage.
Reduced-Variables Method for General-Purpose Compositional Reservoir Simulation
Authors: Pan Huanquan , Tchelepi Hamdi A. 
Published: July 2010

Abstract
Compositional flow simulation is necessary for planning EOR (Enhanced Oil Recovery) and CO2 sequestration projects. We refer to the standard approach for performing the Phase Equilibrium (PE) computations as the Conventional-Variables (CV) method. In compositional simulation, the cost of PE calculations increases dramatically as the number of components increases, and the PE computations can become the most time consuming part of a simulation run. To reduce the number of components, lumping procedures are used, but that often entails the loss of possibly important phase-behavior information. The Reduced-Variables (RV) method is a robust and efficient scheme for PE calculations. However, there is limited information regarding the performance of RV in practical compositional flow simulation (i.e., coupled flow, transport, and thermodynamics). For example, there is only one published work with small 2D IMPEC (IMplicit Pressure, Explicit Compositions) simulations. Here, we integrated the RV method with a General Purpose Research Simulator (GPRS). This modular, object-oriented, computational framework allows us to make direct performance comparisons of RV- and CV-based compositional simulations. We use five different fluids, ranging from 6 to 26 components, and we focus on challenging multi-contact miscible displacements. We use two reservoir models: the first is the top layer of the SPE10 problem, and the second is a Discrete Fracture Model (DFM) with unstructured grids. The RV-based simulations are significantly more efficient than state-of-the-art CV-based computations. For the problems we describe here, the RV-based PE calculations can be up to seven times more efficient than the standard (CV-based) approach, and the total simulation time using RV can be a quarter of that used by the standard method. We show that the cost of the RV method for PE calculations is a linear function of the number of reduced variables, and we show that the total simulation time using RV is a weak function of the number of components used to describe the fluid. These properties of the RV approach enable us to study complex EOR processes in large-scale reservoir models, where large numbers of components and grid blocks are required. We propose that generalpurpose simulators use the RV approach for the PE computations associated with large-scale compositional simulations.
Impact of Rock Microstructures on the Supercritical CO2 Enhanced Gas Recovery
Authors: Wang J. G. , Liu Jianxin , Liu Jishan , Chen Zhongwei 
Published: July 2010

Abstract
Supercritical CO2 can be used as a driving gas to displace the native gas CH4 for methane production enhancement. A preferential flow path may result in an earlier CO2 breakthrough. This early breakthrough will in turn reduce the overall sweeping efficiency. In this study, numerical simulations for the supercritical CO2 enhanced gas recovery were conducted on a virtual rock core which contains an inclined fracture for potential preferential flow paths. This paper contains four parts. First, a 3D virtual core is expressed by local porosity. X-ray CT scanning captures a series of 2D digital images of the rock sample. Each 2D CT image is then processed to ascribe a map of pixel values. This map is related with local porosity through threshold techniques. These 2D CT images are then used to build a 3D virtual rock core within which the porosity is defined at each voxel. Second, other physical properties such as diffusivity and permeability within the core are introduced through their empirical relationships with the porosity. Third, a convection and diffusion equation is formulated based on the CO2 injection-driven flow. In this equation, the heterogeneity of the rock core is introduced via the distribution of initial porosity. Further, its convection velocity is proportional to the concentration gradient of the injected CO2 and the diffusive coefficient is contributed by both molecular and hydrodynamic diffusions. Therefore, a porosity-based finite element CO2-CH4 displacement model is completely formulated. Finally, the effects of fracture-induced heterogeneity on mass transfer and local diffusion mechanisms are numerically studied. The dramatic impact of the preferential pathway on the earlier CO2 breakthrough as well as the overall gas recovery is observed in the numerical simulations.
Challenges of Using Electrical Submersible Pump (ESP) in High Free Gas Applications
Authors: Bagci A. Suat , Kece Murat , Nava Jocsiris 
Published: July 2010

Abstract
One of the limitations of achieving full potential in pumped wells is the presence of excessive free gas at pump intake. Presence of free gas at pump intake affects the pump performance negatively, reducing the liquid rates and the pressure added by the pump. This performance reduction may sometimes be quite severe, resulting in unstable pump operation, significant production losses, lower reliability and increased operating costs due to premature equipment failure. Currently some operators need to produce wells under challenging operational conditions with very high free gas ratios. ESP in wells with a high free gas liquid ratio that requires the use of special gas handling technologies is becoming more and more common. Recent advances in ESP gas handling technologies expand the use of ESPs to more gassy applications in the industry.
This paper presents the methods used, the results and learnings from the application of ESPs with various gas handling technologies based on real field data. Present natural flow conditions were simulated to determine the operating envelope for each well. ESPs were evaluated for the selected design ranges governed by the drawdown (bubble point) constraints. The operating envelopes for each selected well were established over its life cycle with various free gas volumes and water cuts.
The paper confirms that ESP can operate successfully with the pump intake gas fraction up to 75% through use of appropriate gas handling technologies and challenging the norms.
A Study and Application of Multi-section Acidizing Technology with Original Production String in Horizontal Well
Authors: He Liu , Fangjun Biao 
Published: July 2010

Abstract
The formation damageability of drilling and completion fluids on horizontal wells is more critical than on vertical wells, due to longer horizontal section of horizontal wells and the larger reservoir exposure area during operations, resulting in rapid productivity decrease. As such, acidizing techniques for horizontal well is an important solution to increase the reservoir productivity. However, the long horizontal section passes through various lithology layers due to geological heterogeneity. This cause the mud invasion time and formation damage degrees are different in various layers. All factors will bring in potential negative impacts derived from common acidizing and coiled tubing acidizing and lead to non-uniform acid distribution and poor acidizing effect. Therefore, it is necessary to make use the mechanical multi-section acidizing technology. For that, the wellbore should be divided into several sections according to the reservoir lithology, physical characteristics, and damage degree to realize the purposes of acid uniform distribution and productivity increase. Conventional process is hard to acidize the multi-sections in horizontal wells, because the deflected section exist in horizontal well and the target layer is located at horizontal section, which make downhole string operations more complicated, and stresses in horizontal well is quite different from that of vertical well. The ball-shooting sliding sleeve mechanical multi-section acidizing string is available to resolve these problems successfully. This string is made up with safety joint, connected vessel, hydraulic anchor, centralizer, spring sand blasting devise, K344-110 packer, low density ball, etc, with 40 MPa tolerance pressure and 90°C tolerance temperature. It can perform enforced sectionalizing. Four times shooting, five sections treatments, and residual liquid's reverse circulation cleanup and backflow after acidizing process can be carried out through the original production string in this technique. In addition, only 110 mm diameter of the packer outer, additional installation of centralizer at two ends and the application of connected vessel can reduce not only upward loads of the string, but also potential hazards of pipe stuck, and provide the feasibility for releasing pipes and fishing operations. Up to now, 12 wells and 36 layers have been conducted the multi-section acidizing technique in Daqing Oilfield, the greatest treatment is up to 4 sections with one trip string, the success rate is 100%. Considerable yield increase effect is available. It is statistic 5.9 m3/d average fluid increase, 4.8 t/d average oil increase, and 182% the average productivity increase rate of single well in the early stage after the operation. The horizontal well acidizing technique provides an efficient way to develop oil field in the peripheral areas of Daqing Oilfield and has a wide application in prospect with lower costs, higher efficiency and simpler operation.