bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Shale Gas at Nanoscale Using Scan Electron Microscopy, Transmission Electron Microscopy and Atomic Force Microscopy, and Up-scaling to a Petrophysical Model for Water Saturation Evaluation in Shales
Authors: Wu Peng , Aguilera Roberto 
Published: October 2012

Abstract
Due to quick development in horizontal drilling and fracturing technologies, shale gas, formerly considered very difficult if not impossible to recover, has become one of the hottest energy topics. As a significant number of studies focus on fracture stimulation, drilling and completion optimization, only a limited number of studies have been carried out aiming at the investigation of shale structure at nanometer scale due to limited access to scanning electron microscopy (SEM), transmission electron microscopy (TEM) and atomic force microscopy (AFM), and also due to less experience using these instruments in studies of formation rocks.
SEM and TEM are all capable of revealing nano-scale structures of rock samples. AFM also offers some possibilities. In order to obtain images of high quality and ultra-high magnification, sample preparation is the initial and probably most important step in the whole imaging process. Images from low and ultra low permeability formations in the Western Canada Sedimentary Basin are compared with images from other low and ultra low permeability formations reported in the literature. As powerful as these nanoscale capable microscopes are, they all have limitations due to the high instrument cost, limited access and time consuming imaging process. As a result it is difficult and impractical to obtain statistical significant data. To make these instruments of practical value to geoscientists and petroleum engineers, methods and models need to be developed to build a bridge from detailed nanoscale structures to typical lab/field measurements and practical geoscience and engineering-scale applications. In this paper, we propose the concept of a multiple porosity model for evaluation of shale formation based on our observations of the nanopore structure of shales. This includes a model for determining the porosity exponent m in shales and water saturation evaluation. Water saturation curves based on this model are plotted on Pickett Plots for both tight gas and shale formations.
Continuous studies in this area are needed to further explore shale structure in fine detail in order to understand the role of nanopores on shale gas production.
Integrated Multiwell Formation Evaluation for Diagnosing Reservoir Dynamics
Authors: Ma S. Mark , Al-Belowi Ali R. , Al-Mudhhi Mohammed A. , Al-Ali Zaki A. , Zeybek Murat 
Published: October 2012

Abstract
In this paper, a multiwell data integration approach for improved formation evaluation is presented to describe: (1) Mixing between injected fresh water and saline formation water, (2) Water salinity variation vertically across reservoir intervals, and (3) Injected water movement in the reservoir. Data used included static and dynamic time lapse well data as well as a crosswell electromagnetic (CWEM) survey. With this integrated approach, we can answer critical formation evaluation and reservoir management questions, such as why the formation tester (FT) water sample salinity can be very different from the produced water salinity, and why a well located farthest from the injectors can produce water several years earlier than a well located nearest the injectors. Gaining a complete knowledge of water salinity, distribution, both vertically and areally, and water movement in-situ allows better assessment of reservoir saturation changes with time, thereby improving reservoir management.
Hydraulic Fracturing Model Based on Nonlinear Fracture Mechanics: Theory and Simulation
Authors: Jin X. , Shah S. N. , Sheng M. 
Published: October 2012

Abstract
Recent advancements of hydraulic fracturing in complex formations indicate the limitations of traditional fracturing models stem from Linear Elastic Fracture Mechanics (LEFM) theory, which obeys small-scale yielding rule. This rule breaks down in the crack tip region where the strain is extremely large, so Nonlinear Fracture Mechanics (NLFM) is required in studying fracture initiation and propagation phenomena for ductile rocks and pseudo-brittle rocks. The model in this paper studies fracture initiation angle of an inclined fracture/perforation (the term "inclined" is defined as the crack or perforation that does not coincide with the principal stress direction) based on R-criterion, which assumes that fracture propagates in a direction where the distance from crack tip to the elastic/plastic boundary is minimum. The crack tip opening displacement is solved with the combination of Dugdale model and R-criterion. The simulation results indicate that fracture initiation angle for the ductile and pseudo-brittle rock is less than that of a brittle rock. Furthermore, a crack tip opening displacement decreases with inclination angle and minimum in-situ stress and increases with increasing perforation depth. The hydraulic fracturing model presented in this paper opens a door to understanding why/how fracture gets twisted and narrowed near inclined borehole, why/how skin factor increases sharply near wellbore in hydraulic fracturing and helps us learn how to avoid undesired fracture geometry and "screenout" during hydraulic fracturing treatment execution and to maximize ultimate recovery. It is recommended to alleviate fracture twist by increasing pumping pressure and extending perforation depth by about 30% (based on the perforation of 1ft) when the in-situ stresses distribution is not clear. This model finds large application prospect in fracturing formations that are rich in clay or are high pressure high temperature (HPHT) formations.
Lessons Learned from Building a Large Integrated Production Model for Offshore Assets in Nigeria
Authors: Stevenson A. E. , Wanorue E. P. , Okoro E. C. , Ozen Ozgur 
Published: October 2012

Abstract
This paper describes the process and lessons learned from the construction of a large Integrated Production Model (IPM) in Nigeria. The model will be used to determine optimum development plans for connecting the undeveloped and underdeveloped assets in the Joint Venture (JV) Area into the existing producing fields. In addition, it will be used to identify bottlenecks, and to optimize production in the infrastructure for the existing producing assets for a number of years. For this model to be of value for its intended purpose, it needs to be calibrated and maintained over a period of years because this development work is planned over several years. The process used to assemble and calibrate the models, some of the challenges encountered including keeping the models "evergreen", and our results are presented.
A large IPM model was built for the JV Area assets in offshore Nigeria. The model used the existing ten (10) production platform IPM models in the JV Area and added the fluid and gas gathering network to model the entire JV production system infrastructure to the terminal. All of the reservoir and well models were calibrated and the sub-sheet models optimized prior to being combined into the larger model. The large model construction proceeded in stages to ensure the modeling goals could be reached.
Reconciling Retort versus Dean Stark Measurements on Tight Shales
Authors: Handwerger D. A. , Willberg D. , Pagels M. , Rowland B. , Keller J. F. 
Published: October 2012

Abstract
Due to the complexity of tight shale reservoirs, core analysis has become an increasingly important source of data for evaluating these systems. However, as there are no generally agreed upon testing protocols, there are competing methods for obtaining such primary data as fluid saturations and porosity. The two most commonly employed commercial methods are Dean Stark toluene combined thermal and solvent extraction and thermal extraction by retort. However, the impact of these protocols on the rock and its fluid phases is different, primarily due to the abundance of clays. While the Dean Stark extraction produces a total porosity and total water saturation, data suggest significantly elevated values of these parameters relative to what is measured through the retort process, resulting from significantly higher amounts of water recovered. This distinction is fundamentally important for using core analyses in shale for calibrating logs and/or determining reserves, as both methods claim to report the same parameters.
To understand this effect, we have assembled a data set of compatible core analyses from various laboratories from several wells for a tight-gas shale reservoir in the United States. In addition, we conducted thermogravimetric analysis and Karl Fischer Titration with methanol extraction on splits of the same samples. The retort, thermogravimetric, and Karl Fischer data generally agree in the amount of water eluted from the samples (per gram of rock), while the Dean Stark data show significantly more water. We suggest this excess water could be a portion of the structural water in the clays, which should not contribute to porosity and saturation. Additionally, there is a relationship between this excess water and the total clay content from XRD. This correlation to XRD analyses suggests that a correction can be determined, leading to more accurate porosity and saturation values necessary for proper reserves estimations.
Implementation of a CO2 Foam Pilot Study in the SACROC Field: Performance Evaluation
Authors: Sanders Aaron W. , Jones Raymond M. , Linroth Mark , Nguyen Quoc P. 
Published: October 2012

Abstract
A new conformance solution has been developed to help producers reach and recover more oil from existing wells while simultaneously reducing operating expenditures. This new technology successfully addresses shortcomings associated with existing miscible gas EOR (enhanced oil recovery) processes by generating foams of supercritical CO2 fluid and water in the formation which alter mobility and improve vertical conformance. Ultimately, the process can improve the profitability of existing wells by enhancing reservoir sweep efficiency, thereby allowing access to previously bypassed oil. This report describes the technology development process and documents successful field trial results from Kinder Morgan's SACROC field.
Engineering Hydraulic Treatment of Existing Fracture Networks
Authors: Pettitt Will , Damjanac Branko , Hazzard Jim , Han Yanhui , Sanchez-Nagel Marisela , Nagel Neal , Reyes-Montes Juan , Young R. Paul 
Published: October 2012

Abstract
Observations from field monitoring indicate the presence of existing fracture networks significantly affect, and may control, the history of hydraulic treatments. Existing fractures allow pathways for treatment fluids to migrate efficiently through the formation, stimulating connectivity to larger reservoir volumes. This paper examines the relationship between hydraulic treatments and fracture networks, and investigates the ability to engineer the hydraulic conductivity of the stimulated volume. Fracture network engineering (FNE) involves the engineering design of rock mass disturbance through the use of advanced techniques to model fractured rock masses numerically, and then correlate field observations with simulated fractures generated within the models. Modeling algorithms accurately address the hydromechanical physics of hydraulic treatments developed across a range of applications in rock engineering.
A Synthetic Rock Mass (SRM) model is constructed by explicitly defining a discrete fracture network within a modeled rock matrix. Hydraulic treatment into the SRM allows fracture dilatancy, propagation and shearing to be realized in the emergent behavior of the bonded particle model in three dimensions and at the scale of the treated volume. Simulated microseismicity is generated when the fractures are disturbed or propagated providing a method for correlation with field observations. Illustrative models show how hydraulic treatments stimulate fracture networks and generate new hydraulic fractures in volumes not expected in conventional design analysis connecting existing fractures with preferential alignment. By combining SRM models with field observations it is possible to investigate the relation and sensitivity of hydraulic treatments to existing fracture networks, and therefore, engineer the most optimal use of these fractures in the performance of a given project. Developmental challenges are discussed, including the sensitivity of the techniques to fracture network uncertainties and the accurate representation of microseismic source data within the models.
Study on the Volumetric Behavior of Base Oils, Brines, and Drilling Fluids Under Extreme Temperatures and Pressures
Authors: Zamora Mario , Roy Sanjit , Slater Kenneth , Troncoso John 
Published: October 2012

Abstract
Drilling fluid densities vary significantly over wide ranges of temperature and pressure, a concern that is particularly critical in deepwater, Arctic, and high-temperature/high-pressure wells. The variations can impact well integrity, well design, regulatory compliance, and drilling efficiency.
Drilling fluid densities depend on the compressibility and thermal expansion of the fluids (liquids) and solids used in their formulation. Suitable pressure-volume-temperature correlations for these fluids previously have been fairly inaccessible, due primarily to continually changing base fluids and blends, and the lack of readily available test equipment.
This study was conducted to measure the volumetric behavior under extreme temperatures and pressures of a broad range of the oils, synthetics, and brines currently used in industry to prepare oil, synthetic, and water-based drilling fluids. It follows a recent study that successfully qualified the commercially available test equipment.
For the most part, tests were run at temperatures from 36 to 600°F and pressures from atmospheric to 30,000 psi, ranges that generally exceed those used in published studies. Correlation coefficients are provided for reference and to demonstrate their use in a compositional, material-balance model to accurately predict drilling fluid density as a function of temperature and pressure. Tests run on field drilling fluids are included to demonstrate how these data can be used in procedures and software to predict equivalent static densities and hydrostatic pressure during drilling operations.
A New Family of Nanoparticle Based Drilling Fluids
Authors: Sharma Mukul M. , Zhang R. , Chenevert M. E. , Ji L. , Guo Q. , Friedheim J. 
Published: October 2012

Abstract
A new family of water-based drilling fluids that contain nano-particles has been tested to evaluate its interaction with shales. It was shown in an earlier paper that nano-particles dramatically reduce the flow of water into a shale formation. In this study we have developed and tested a new family of commercially available drilling fluids that can be used to drill shales.
Drilling shale formations with water-based fluids offers some tremendous environmental and economic advantages. To date the use of such fluids have been limited to hard shales such as the Barnett. In this paper we have developed and lab tested water-based drilling fluids that contain nano-particles that can be applied to a much broader range of shales.
Water-based drilling fluids have been formulated that incorporate nano-particles in them at a very reasonable cost. The rheology and stability of these muds were tested. A family of such fluids has been developed and tested in the lab. It is found that the muds are quite stable at elevated pressures and temperatures and offer a wide range of rheological properties. These muds also offer good lubricity and are, therefore suitable for applications in drilling the lateral section of the hole in shales. Tests were also conducted to measure the extent of invasion of water into shales when they are exposed to nano-particle based drilling fluids. The invasion into the shale was reduced by 10 to 100 times indicating that wellbore instability problems will be minimized when these muds are used.
Drilling long lateral sections in shales and tight gas reservoirs is often the largest capital cost associated with the development of these resources. Nano-particle based drilling fluids have the potential to significantly cut these drilling and disposal costs and offer significant environmental benefits.
Integrating Improved Environmental Performance into Rig Design
Authors: Delisio Sam , Grosvenor Courtney , Meissner Niels , Ogg Jeremy , Wagner Natalie 
Published: October 2012

Abstract
As sustainability and environmental stewardship become an elevated priority in energy policy around the world, the oil and gas industry faces ever-more-stringent regulations, while investors and stakeholders increasingly expect quantification of environmental performance and health and safety factors. With these evolving concerns and pressure from customers, the public, and government to reduce environmental impact, the financial costs and public backlash from making mistakes are growing. As the liaison between the public and many natural resources, the oil and gas industry is in a very important position to protect and sustain these resources for future generations. Thus, technological advances and a re-evaluation of standard drilling practices are required in the field in order to continue meeting the nation's growing energy demand while simultaneously working to eliminate environmental and human safety hazards via equipment automation; reduced air emissions, water consumptions, fuel use, land use, and waste streams; improved well control technology; and use of more energy-efficient materials. These advances are also a prerequisite to improve market access to environmentally-sensitive areas and heavily regulated regions of the world. A shared goal between supply companies and operators to develop and deploy environmentally-friendly drilling solutions based on operator and customer needs, public concerns, and government regulations will help move the industry toward a safer, more efficient, zero-spill, low-carbon future. This paper discusses some of the technologies and examples of how effectively managing environmental performance are also good business practice.
Production Analysis in the Eagle Ford Shale — Best Practices for Diagnostic Interpretations, Analysis, and Modeling
Authors: Ilk D. , Broussard N. J. , Blasingame T. A. 
Published: October 2012

Abstract
The Eagle Ford Shale (South Texas, USA) is emerging as the foremost "liquids-rich" shale play in North America. As such, the use of production data analysis in the Eagle Ford Shale has tremendous importance in:
Determining well/reservoir properties; Establishing completion effectiveness; and Estimating future production.
The Eagle Ford Shale presents additional difficulty in the form of fluid behavior characterization. Near-critical PVT behavior (as in the case of the Eagle Ford Shale) is an important component of well performance, which cannot be overlooked during analysis and modeling. The results of this work address the common challenges encountered during production analysis and modeling of the Eagle Ford shale wells. In particular, it is shown that significant differences are observed in production forecast due to characterization of the fluid. This work provides a systematic workflow to analyze and forecast production data in near-critical reservoirs with examples from the Eagle Ford Shale and delivers more insight into analysis of production data in unconventional "liquids-rich" reservoirs, and offers to decrease the uncertainty related with production forecast that is mainly caused by lack of understanding of "near-critical" fluid behavior.
Shear-Enhanced Two-Phase Flow Properties in Athabasca Sands
Authors: Hamza Syed M. , Olson Jon E. , Holder Jon 
Published: October 2012

Abstract
Field results in Steam Assisted Gravity Drainage (SAGD) heavy oil operations suggest formation permeability changes during production operations. We investigate this process using samples constructed from loose Athabasca sand. Our results indicate that permeability changes (absolute and relative) and endpoint oil and water saturation variation are a function of loading boundary conditions. Triaxial loading paths (increasing mean stress) show increased permeability with sample dilatancy upon failure at low confining stress (100 to 400 psi) that diminishes when run at higher confining stress (800 psi). Residual oil saturation increases during compaction and decreases during dilation while initial water saturation decreases during compaction and increases during dilation. Radial extension tests (decreasing mean stress) result in larger increases in permeability upon failure and dilatancy, and lower residual oil and higher initial water saturations. Finally, failure induced by unloading through pore pressure increase, run under fixed displacement, fixed stress, or mixed axial versus confining boundary conditions, show minimal permeability changes until the effective stresses approach zero. However, the increase in initial water saturation and decrease in residual oil saturation are as significant as or greater than what was seen in the triaxial compression and radial extension tests. Overall, results show that lab experiments support increased permeability due to steam injection operations in heavy oil, and more importantly, the observed reduction in residual oil saturation implies SAGD induced deformation should improve recovery factors.
Technology and Equipment Design for Global Shale Markets
Authors: Brantley Lydia , Major Thomas 
Published: October 2012

Abstract
Shale gas is widely considered to be revolutionizing the industry in the U.S. Various countries have begun shale exploration, but none have begun pursuing it with the aggressive growth characteristic of the North American experience. While the price of natural gas in some regions can be three to five times higher than in the U.S., the nature of lease agreements, geological characteristics, and political and societal factors all shape different emerging shale development models.
In North America, variations in shale gas plays have resulted in differences in technology and equipment design. The Horn River, for example, is located in a flat environment with very cold winters, while the Marcellus is located in a population-dense area with small local roads. These examples result in differences to field, well, and equipment design. This will be exaggerated as we move to international locations. In Europe, for example, road regulations restrict weight and dimensions, requiring rigs to break into smaller modules, and limiting the horsepower on a single fracture pumping unit. Novel fracture methods, such as pin-point fracturing, may be given different considerations internationally, potentially reducing horsepower requirements. Additionally, as international markets move into commercial development of resources, the truck traffic, emissions reduction, and need for smaller overall surface footprint will likely drive the market toward more wells per pad. This will cause rig design to follow closely the development seen in Canada's multi-well pad design with load limits and equipment designed more like the Marcellus.
This paper investigates the impact of varying emerging global markets on the future of technology and innovation in shale and tight gas reservoirs. The influences such as geological, political, and infrastructure on equipment design for varying gas reservoirs will be discussed.