bluuebunny/crossref_metadata_2025_split huggingface dataset:
Processing Body and Stress Granule Assembly Occur by Independent and Differentially Regulated Pathways inSaccharomyces cerevisiae
Authors: Shah Khyati H , Zhang Bo , Ramachandran Vidhya , Herman Paul K 
Published: October 2012

AbstractA variety of ribonucleoprotein (RNP) granules form in eukaryotic cells to regulate the translation, decay, and localization of the encapsulated messenger RNA (mRNAs). The work here examined the assembly and function of two highly conserved RNP structures, the processing body (P body) and the stress granule, in the yeast Saccharomyces cerevisiae. These granules are induced by similar stress conditions and contain translationally repressed mRNAs and a partially overlapping set of protein constituents. However, despite these similarities, the data indicate that these RNP complexes are independently assembled and that this assembly is controlled by different signaling pathways. In particular, the cAMP-dependent protein kinase (PKA) was found to control P body formation under all conditions examined. In contrast, the assembly of stress granules was not affected by changes in either PKA or TORC1 signalling activity. Both of these RNP granules were also detected in stationary-phase cells, but each appears at a distinct time. P bodies were formed prior to stationary-phase arrest, and the data suggest that these foci are important for the long-term survival of these quiescent cells. Stress granules, on the other hand, were not assembled until after the cells had entered into the stationary phase of growth and their appearance could therefore serve as a specific marker for the entry into this quiescent state. In all, the results here provide a framework for understanding the assembly of these RNP complexes and suggest that these structures have distinct but important activities in quiescent cells.
Understanding Production Drivers and Challenges in Converting a Vertical to Horizontal Oil Play Utilizing Single Well Modeling
Authors: Gonzales Veronica M. , Barham Michael , Lawless Paul , Cherian Bilu V. , Mata Domingo , Higgins-Borchardt Shannon , Alatrach Samer 
Published: October 2012

Abstract
The recent growth in horizontal well technology has resulted in existing oil and gas vertical development plays to be evaluated for horizontal well applicability. As operators attmept to evaluate the criteria for converting from vertical well plays to horizontal well plays, sound data gathering and modeling become crucial to understand how completion strategies needs to be modified for improved production, without utilizing an expensive trial and error methodology.
The Powder River basin contains a variety of producing shales and sands currently being explored for vialibility (i.e. Niobrara, Frontier, etc). In this study, reservoir and fracture properties are estimated based on hydraulic fracture modeling, rate-transient analysis techniques and production history matching to calibrate log data measurements. The challenges associated with calibration and modeling measurements from petrophysical and rock mechanics models are compared with hydraulic fracture and production modeling results to understand the direction of optimization and future basin growth.
Past experiences are typically the basis for design and implementation of developing a new drilling and completion program. Interpretation of the hydraulic fracture behavior is often inferred from simple diagnostics, and as production ensues the repeatability for success or failure is often attributed to modifying the hydraulic fracturing program or geological influences, which is subject to inconsistency and qualitative introspection. Within this study a single well modeling approach is utilized to understand fracture geometry, correlate this with production history matching results, and distinguish production attribution from hydraulic fracture characteristics or reservoir properties. Exercising this workflow addresses challenges affiliated with modeling fracture propagation and production matching and the gap associated with horizontal well development in existing vertical plays.
Use of Untreated Subsurface Non-Potable Water for Frac Operations
Authors: Pettigrew Dana , Limanowka Andy 
Published: October 2012

Abstract
Fresh water is being extensively used for fracturing operations to stimulate both gas and oil shale wells. Once used for this purpose, the water is either disposed of, or needs extensive treatment to recondition it for further fracturing operations. Producers in the Horn River Basin have access to a huge underground non-potable aquifer that is deeper than the fresh water zones and shallower than the shale gas wells that require fracture treatment for stimulation. The question is, how to use this water resource to economically fracture stimulate the shale gas wells?
Extensive testing on the water quality of the Debolt aquifer indicated that the Debolt water remains stable if kept above the bubble point pressure, but existing positive displacement frac pumps cannot pump this water in its stable and untreated condition. However, a centrifugal pump can pump this water in its stable and untreated condition, but current designs are for 42 MPa maximum operating pressures, which are too low for use in shale well fracturing operations. A newly developed 69 MPa High Pressure Horizontal Pumping System (HPHPS) was designed and tested to provide a pump capable of utilizing raw Debolt water as a fracture fluid.
This paper will discuss the use of an HPS (Horizontal Pumping System) pump, designed to provide high pressures of up to 69 MPa, enabling this pump to be used as a High Pressure Horizontal Pumping System (HPHPS) frac pump.
This pump was successfully used in the Horn River Basin of North Eastern British Columbia to pump Debolt source water (a saline, sour and gassy aquifer), untreated during fracturing operations in 2010 and again in 2011. Additional testing of this prototype HPHPS frac pump is being conducted during the 2012 frac campaign. This paper will discuss the field operating procedures and performance of this style of pump during this large frac campaign.
Usage of an HPHPS frac pump also enables a Pressurized Frac On Demand (PFOD) system to be used to fully exploit the use of this method for water supply to a frac system.
Practical Analytical Model to Simulate Production of Horizontal Wells with Branch Fractures
Authors: Stalgorova E. , Mattar L. 
Published: October 2012

Abstract
A common way to produce hydrocarbons from tight reservoirs is to use horizontal wells with multiple hydraulic fractures. In many cases, fractures do not have a simple bi-wing shape, but are branched. For modeling purposes, branch-fracturing can be represented by a high permeability region near each fracture, while the bulk of the space between the fractures remains unstimulated.
This paper presents an analytical model to simulate the flow rate and pressures for such a reservoir system. The model is a variation on the tri-linear flow solution. It is simple, and flexible enough to be applicable to multi-frac horizontal wells. The model takes into account three linear flow regimes: flow within the fracture (at very early time), flow within the stimulated region towards the fracture and flow within the un-stimulated region towards stimulated region. The model was validated by comparing its results with synthetic data sets generated using numerical simulation; the results showed excellent agreement.
This paper illustrates the various flow regimes and how they are affected by reservoir and completion parameters. The characteristic features of each flow regime are demonstrated using typecurves. History matching of actual field case is presented to illustrate the practicality of the model. The proposed analytical solution provides a practical alternative to numerical solutions, and saves significant computational time.
An Experimental Study of Spontaneous Imbibition in Horn River Shales
Authors: Makhanov K. , Dehghanpour H. , Kuru E. 
Published: October 2012

Abstract
Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered? Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance.
We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring, porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data.
The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly higher than that of the oleic phases.
Predicting Growth and Decay of Hydraulic Fracture Width in Porous Media Subjected to Isothermal and Non-isothermal Flow
Authors: Tran David , Settari A. (Tony) , Nghiem Long 
Published: October 2012

Abstract
Based on the continuum thermo-poroelastic theory, a new analytical formula of fracture width is developed to quickly predict its transient growth or decay. The effects of the poroelastic stress (also called backstress) and thermal stress are taken into account. The counterbalance between the effects of backstress and thermal stress (in case of injection of cold fluid) is shown to be a function of flow and thermal properties and can be easily demonstrated by the formula developed. The analytical formula of fracture width is not complicated and does not require complex calculations. Different phenomena affecting the magnitude of fracture width are easily examined, such as the presence or absence of leak-off, isothermal or non-isothermal fracturing as well as initial effective stress in the formation. Results show that the fracture width continuously decays with time due to the effect of pore pressure when there is leak-off. On the other hand, the fracture width will grow with time by the influence of thermal stress when cold fluid is injected. Unlike cold fluid, when hot fluid is used, the crack may close completely and the speed of the process will depend upon the temperature of the injected fluid. Formulae for penetration depths for pressure and temperature are also developed and applied to the crack width equation so that time-dependent maximum apertures and crack profiles can be computed. The analytical solution has also been validated by the finite element numerical method.
Fast Track Analysis of Shale Numerical Models
Authors: Kalantari-Dahaghi A. , Esmaili S. , Mohaghegh S. D. 
Published: October 2012

Abstract
Latest advances in shale gas reservoir simulation and modeling have made it possible to optimize and enhance the production from organic rich shale gas reservoirs.
Reservoir simulator is no longer used with a simple description of the complex shale gas reservoirs, but with multiple, equally probable realizations to allow risk assessment. Nevertheless, the perennial challenge in shale reservoir modeling is to strike a balance between explicit representation of reservoir complexity and long simulation run time for multiple realizations.
Focus of this study is on the development, calibration and validation of a Shale Surrogate Reservoir Model (AI-based proxy model) that represents a series of complex shale numerical simulation models. The Shale Surrogate Reservoir Model is then used for fast track analysis of the shale numerical model. Reservoir simulation model for a generic shale gas reservoir are constructed using a popular commercial simulator that is capable of handling complex fracture network (natural and multiple stages of hydraulic fractures), different sorption types (instantaneous and time dependent one), and capturing long transient nature of the flow in shale matrix. Validation of the Shale Surrogate Reservoir model using several blind simulation runs is also presented.
Shale Surrogate Reservoir Model is a replica for the numerical simulation model with response that is measured in fractions of a second. As such, it provides the means for comprehensive and fast track analysis of the model in a relatively short period of time, allowing the reservoir engineer to scrutinize different realizations and propose development strategies.
Recent Achievements Within E-Line Milling
Authors: MacLeod Anthony , Greenlee James , Henriques Kristine 
Published: October 2012

Abstract
Since the concept of milling obstructions on electric line (e-line) was introduced in 2005, operators around the world have applied this technique successfully removing downhole valves, plugs, scales, cement and nipple profiles achieving cost-effective and time-efficient interventions.
Recently, a series of e-line milling operations were performed to remove repeater-sub and ball-seat restrictions in oil producing horizontal wellbores located in Southeast Saskatchewan. The low pressure reservoirs favored intervention technologies that did not require excessive hydrostatic head. Operators have traditionally used nitrogen mixed with water to prevent damage to the reservoir and to maintain circulation; however, this reduces the amount of torque that can be achieved at the bit, and causes stalling and sticking issues.
Using a combination of tractor and milling technology on e-line in these wells provided the required torque for milling with a steady and constant weight on bit throughout the wellbore for removal of ball seat restrictions.
This paper presents the latest achievements within e-line milling in Canada. The paper will discuss best practices of date as well as a discussion of e-line milling challenges through three case studies in Canada.
Software Development for Petrophysical Analysis of Shale and Tight Formations
Authors: Yu Guang , Aguilera Roberto 
Published: October 2012

Abstract
Shale and tight formations have long been a challenge for petrophysical interpretation. In the case of shales, the presence of clays and organic matter, complex mineralogy and pore structure make the log responses complicated. In tight reservoirs, the presence of connected and non-connected dissolution pores, microfractures and slot porosity also complicates the interpretations. This work seeks to integrate and digitize new petrophysical techniques and procedures that address these problems into a software system to assist with shale and tight reservoirs characterization.
A petrophysics software system that includes dual and triple porosity models as well as elastic geomechanical properties has been developed to assist with the evaluation of shale and tight formations. Some critical petrophysical parameters can be quantified, such as matrix, fracture, non-connected and effective porosities, water saturation, total organic carbon, level of organic metamorphism, flow regimes (continuous vs. diffusion-like) at any pressure of interest, as well as Young modulus, Poisson’s ratio and minimum horizontal stress. Based on these estimates, detailed shale and tight reservoirs characteristics can be analyzed and the original hydrocarbons in place can be determined with good accuracy.
Practical workflows for calculating each parameter are also organized and integrated. Object-oriented programming techniques are utilized for the development of this software considering its development life cycle for large-scale software development. Optimization capacity adopted in the current development for the reuse of the software components for future development is also explained.
Two case studies using data from the Nikanassin formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB) and the Haynesville shale formation in Texas are presented to illustrate the software development and the application of the software. Conventional well log data, such as gamma ray, density, neutron, acoustic, resistivity, and cores and drill cuttings are utilized in the examples, which is further validated with other sources of information.
It is concluded that the methodology developed in this software will prove valuable and facilitate the petrophysical evaluation of shale and tight formations.
What Don’t We Know About Self Sourced Oil Reservoirs: Challenges and Potential Solutions
Authors: Larter Steve , Huang Haiping , Bennett Barry , Snowdon Lloyd 
Published: October 2012

Abstract
While light tight oil reservoirs such as found in Bakken and Cardium style plays can be stimulated by fracturing, significant oil production from true shale reservoirs dominated by clay size fraction sediments may not be feasible, even when reservoirs are fractured, if current oil storage models in source rocks are valid. We look at the source rock knowledgebase and the gaps in our understanding relevant to assessing oil production from shale sections. Despite over four decades of study of petroleum source rocks by geochemists, our mechanistic understanding of them remains at best qualitative and inadequate for quantitative reservoir characterisation purposes. Past studies emphasised molecular chemistry details and gross mass balance studies at large scale, but only few detailed mechanistic studies of actual physical process and transport function during generation and primary migration are available. Empiricism and generality dominate current concepts and most R&D peaked in the 1980s when Oil Company R&D spending was at its highest, but declined after that. Today there are many areas of uncertainty, but reassuringly, research is starting again and crucially, abundant core samples, which were largely absent before, are now also available. There has also been a revolution in the understanding of shale sedimentology which forces us to reexamine many of our earlier precepts about source rock formation and suggests that in the absence of naturally fractured silica or carbonate intervals within source rocks, such as found in the Monterey Fm., very small scale collateral silt and sand horizons may be locally important small scale reservoirs in typical shales. The bulk of the oil storage in source rocks however is in kerogen, where dominantly diffusive rather than Darcy flow processes operate and where fracturing may have little impact on productivity. We look at the technical barriers, both theoretical and analytical, to understanding true shale dominated reservoir oil production potential.
Integration of Production Data for Estimation of Natural Fracture Properties in Tight Gas Reservoirs Using Ensemble Kalman Filter
Authors: Nejadi Siavash , Leung Juliana , Trivedi Japan J 
Published: October 2012

Abstract
Productivity in deep-basin tight gas reservoirs can be improved significantly by natural fracture enhanced permeability. Therefore, deviated and horizontal wells are often drilled to intersect highly fractured formations. Unfortunately, fractured reservoirs are highly heterogeneous, often characterized by probability distributions of fracture properties in a discrete fracture network (DFN) model. In addition, the relationship between recovery response and model parameters is vastly non-linear, rendering the process of conditioning reservoir models to both static and dynamic (production) data challenging.
In the current paper, a novel approach is presented for uncertainty assessment and characterization of fractured reservoir model parameters using data from diverse sources. First, Monte Carlo based techniques were used to generate multiple DFN models conditioned to geological and tectonic information, accounting for the uncertainty associated with static data. Next, each model or realization was upscaled for flow simulation. Finally, Ensemble Kalman Filter (EnKF), a data assimilation technique that has been used for assisted history matching, was employed to update the DFN models using production data. In order to ensure positive definiteness of the updated permeability tensors, to reduce the size of model parameter space, and to eliminate the redundancy between parameters for improved convergence, principal component analysis was performed such that only the main principal components of the full permeability tensor and sigma factors were updated through EnKF algorithm.
The qualities of the history-matched models were assessed by comparing the spatial distribution of the updated model parameters with the initial ensemble, as well as the Root Mean Square Error (RMSE) of the predicted data mismatch. The results clearly demonstrate that, characterization of fractured reservoirs combining DFN modeling with updating principal components of the upscaled model parameters through EnKF has the potential to resolve the shortfall of traditional techniques for history matching of such complicated reservoirs. The proposed approach can be used effectively to update reservoir models and optimize development plans in unconventional gas reservoirs using continuous flow and pressure measurements.