bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Anisotropic Behavior of Montney Shale Under Indirect Tensile Strength Test
Authors: Keneti S. A. , Wong R. C. 
Published: February 2011

Abstract
Located in a large area spanning the British Columbia and Alberta border, the Montney shale formation is one of the largest economically feasible resource plays in North America. Hydraulic Fracturing is one of the stimulation methods to enhance the gas production in which fractures induced by hydraulic loading are created. Initiation and propagation of hydraulically induced fracture is controlled by in-situ stresses magnitude and orientation and the reservoir tensile strength. If the in-situ stresses composing one vertical and two horizontal stresses are comparable or lie within a narrow range, the tensile strength becomes one of the most important parameters in governing hydraulic fracturing of the reservoir. This paper develops different point and line load tests to determine the tensile strength of Montney shale cores in two perpendicular directions. Test results indicate that Montney shale exhibits a high anisotropy in tensile strength. The tensile strength in the horizontal direction is dominated by the bond strength of the intact structure whereas that in the vertical direction is controlled by the existence of the natural beddings (foliations). This paper also addresses how this anisotropy in tensile strength could affect the pattern of hydraulically induced fractures in the field.
Natural Fracture Characterization From Microseismic Source Mechanisms: A Comparison With FMI Data
Authors: Williams-Stroud S. , Kilpatrick J. E. , Eisner L. , Cornette B. M. , Neale C. 
Published: February 2011

Abstract
Microseismic monitoring of hydraulic fracture stimulation is used to map the extent of fracture growth during the completion of unconventional resource wells. Usually the geometry of the event distributions is used to infer fracture plane orientations, for instance when microseismic events are concentrated along a particular azimuth. Often the induced microseismicity is the result of reactivation of existing fractures in the reservoir. Source mechanism analysis that allows identification of the specific fracturing behavior of individual microseismic events can aid differentiation between reactivation of existing fractures and the creation of new fractures. This paper presents the results from the microseismic monitoring of a Mid-Continent horizontal gas shale well where failure planes of source mechanisms from the microseismic events are compared with fractures identified in a resistivity image log. The source mechanisms originate from failure on existing fracture planes, many of which the image log show to be partially or completely healed. The reactivation of these fracture planes are the dominant failure mechanism detected by the monitoring, but additional fracture planes were also likely stimulated by the treatment but seismicity associated with other fractures has a signal to noise ratio below that required to invert for source mechanisms. Enhanced production resulting from the stimulation is expected to result from a combination of fractures in the natural fracture network; those related to the source mechanisms and other fractures that may be opened aseismically. The result is a well-connected fracture network because of contributions of flow from multiple fracture orientations.
Investigating the Expected Long-Term Production Performance of Shale Reservoirs
Authors: Vassilellis G. D. , Li C. , Seager R. , Moos D. 
Published: February 2011

Abstract
There is worldwide interest in the development of shale plays: North America has attracted noteworthy investments, while other continents are ready to follow that example. Besides the increasing commercial significance of shale plays, traditional volumetric and material balance approaches that are used for petroleum asset evaluation fail to address the special attributes of such formations, or they cannot rely on measurable and practical input. The current practice is to statistically analyze historical records in developed areas and to apply the derived type curves in new areas by assuming performance similarity. Provided that there is a sufficient statistical record base, the assumption of similarity is challenged by the multitude of parameters influencing performance. These tend to differ, introducing considerable uncertainties into predictions. As the advanced drilling and fracture stimulation techniques were introduced in the last decade, historical records support only the early production history, while late performance is extrapolated without many reference points to match.
This paper investigates the applicability of traditional and non-traditional empirical, analytical and numerical methods that are used to predict shale well performance. The goal is to rationalize the link between natural/stimulated rock description with oil and gas recovery mechanisms in a way that is practical at various scales of resolution and covers early and late times. The authors have investigated the application of performance analysis techniques that are fit for macroscopic view and numerical methods that describe multiple mechanisms at a much higher level of resolution. Special features such as flow through fracture networks, gas desorption and geomechanical effects are incorporated in numerical simulation in a way that relates to the measurable petrophysical and geophysical input. Although the application of such macro- and micro-analysis has been examined within only a few case studies, it is suggested that future work would test and improve the application of these shale engineering principals. In retrospect, this study offers an understanding of mechanisms and limitations that can be used for optimization, or for the scaling-up results from a certain area to other areas that differ in natural attributes and may also adopt different design and operational practices.
The simulation exercise reported in this paper represents an idealized situation and it should not be inferred that this can be used to indicate recovery from any specific shale reservoir or well, which would require additional study and appropriate incorporation of practical data that were not available to the authors in the public domain.
Mixing of an Oil Shale With Inert or Reactive Media to Avoid Decarbonation at the Passage of a Combustion Front
Authors: Sennoune M. , Salvador S. , Debenest G. , Mourzenko V. 
Published: February 2011

Abstract

Description of the material
Ground oil shale semicoke was prepared in a laboratory retorting furnace under inert atmosphere. A laboratory combustion cell was then used to operate the combustion of the semicoke added with more or less sand and/or carbonates. This enabled to vary independently the amount of CaCO3 and the amount of fixed carbon in the mix. The temperature of the combustion front propagating in this mix was recorded, together with its velocity. The flue gas was analysed.

Application
Propagating a combustion front through a fixed bed is a way to produce oil and a fuel gas from oil shale or to recover energy from oil shale semicoke in the retort process. When operated with air, this process involves high temperatures - typically larger than 1000C□B0C -resulting in the decarbonation of the carbonate matrix and the emission of additional CO2. The aim of this work was to avoid this decarbonation.

Results, Observations, and Conclusions
It is shown that increasing the amount of CaCO3 in the medium (with constant fixed carbon amount) can decrease the combustion front temperature down to 800C□B0C but not below, which is not sufficient to avoid decarbonation. Decreasing the amount of fixed carbon can decrease the temperature down to 600C□B0C, a temperature at which decarbonation occurs only a bit. At this temperature, not all the oxygen in the fed air is used, which results in a slowing down of the combustion front.

Significance of Subject Matter
To our knowledge, no results have been published yet where the two parameters of carbonate amount and fixed carbon amount were varied independently, and where their impact on the front temperature and decarbonation were determined. Avoiding decarbonation in such processes is a potential very significant way to reduce CO2 emissions.
Petrophysical Characterization of the Eagle Ford Shale in South Texas
Authors: Mullen J. 
Published: February 2011

Abstract
The Eagle Ford shale play is an emerging shale play that extends from the Mexican border in south Texas all the way to the East Texas Basin. Developing the play into an economically viable venture encompasses numerous challenges to include:
The shale production characteristics vary across the play. The shale is producing dry gas in some areas and wet gas or oil in others. Some regions are naturally fractured, while others are not. The play must be hydraulically fractured to be economically productive; however, what completion techniques have been successful in one well will not necessarily work in another, even in the same field. Thus, it is critical to consider the local-area reservoir characteristics when trying to complete each well.
This paper focuses primarily on understanding the reservoir by integrating various data-acquisition and reservoir-characterization techniques (i.e., mudlogs, basic openhole logs, and advanced logs, such as Dipole sonic, geochemical, NMR (magnetic resonance-imaging log), and core analysis) to determine the shale's petrophysical characteristics and to thus build a locally validated petrophysical model (shale log) that can be applied to future wells with reduced data-acquisition programs to grade the reservoir. The model is used to ascertain the surrounding lithology and clay typing in addition to the hydrocarbon resource potential of the well. Furthermore, this tool can be used to answer completion questions, such as where the organic-rich zones are located, where to perforate, what the geomechanical issues are, how "fracable" the rock is, and how plastic the rock is.
A New Method for Production Decline Analysis of Tight Gas Formations
Authors: Shahamat Mohammad Sadeq , Aguilera Roberto 
Published: February 2011

Abstract
A new method for evaluation of production decline analysis of a single well in a tight gas formation is presented. The approach is inspired by practical observations from the Cadomin (Lower Cretaceous) and Nikanassin (Upper Jurassic) formations in the Western Canada Sedimentary Basin (WCSB). The Cadomin is encased sometimes in formations of low or ultra-low permeability, which feed the Cadomin, enlarging significantly the ultimate gas recovery (2 to 3 times) of the well and leveling out the gas production rate. The gas feeding can occur through isolated spots due, for example, to the presence of an unconformity.
The proposed method solves the continuity and flow equations for Cadomin-equivalent gas reservoirs and the encasing low and ultra-low permeability formations, which might correspond, for example, to tight or shale gas reservoirs. The new mathematical solution permits integrating the rates at which the well is producing and the rates at which the low or ultra-low permeability source is feeding the Cadomin-equivalent reservoir. Equilibrium is reached when the contribution from the low or ultra-low permeability reservoir is equal to the rate contributed by the Cadomin-equivalent to the wellbore. The proposed method is flexible enough to allow situations in which a higher permeability source might feed a tighter reservoir connected to a wellbore.
The method has application on different types of production declines, for example Arps exponential, hyperbolic and harmonic declines; and more recently developed techniques such as the power law method. The goal of the model, however, is not to replace any of the conventional approaches, which have their place in decline analysis of specific reservoirs, but rather to supplement them on the basis of practical observations that integrate geology of tight gas formations and gas production rates. In the proposed method we get away from Arps’ empirical exponent, b, which has been used (that is good) and abused (that is not good) in the past.
It is concluded that the method developed in this study has application in most types of production declines, including linear and bilinear flow. The solutions are illustrated with actual production rates from tight gas formations in the Western Canada Sedimentary Basin.
The Effect of Heterogeneity on the Character of Density-Driven Natural Convection of CO2 Overlying a Brine Layer
Authors: Farajzadeh R. , Ranganathan P. , Zitha P. L. , Bruining J. 
Published: February 2011

Abstract
The efficiency of mixing in density-driven natural-convection is largely governed by the aquifer permeability, which is heterogeneous in practice. The character (fingering, stable mixing or channeling) of flow-driven mixing processes depends primarily on the permeability heterogeneity character of the aquifer, i.e., on its degree of permeability variance (Dykstra-Parsons coefficient) and the correlation length. Here we follow the ideas of Waggoner et al. (1992) to identify different flow regimes of a density-driven natural convection flow by numerical simulation. Heterogeneous fields are generated with the spectral method of Shinozuka and Jan (1972), because the method allows the use of power-law variograms. We observe from our simulations that the rate of mass transfer of CO2 into water is higher for heterogeneous media.
Characterization of Leakage through Cap-Rock with Application to CO2 Storage in Aquifers - Single Injector and Single Monitoring Well
Authors: Zeidouni M. , Pooladi-Darvish M. 
Published: February 2011

Abstract
The geological storage of carbon dioxide provides the possibility of maintaining access to fossil energy, while reducing emissions of carbon dioxide (CO2) to the atmosphere. One of the essential concerns in geologic storage is the risk of CO2 leakage from the storage formations. Leakage occurs through possible pathways in the seal, which include a) transmissive faults, b) abandoned wells (penetrating the entire seal or part of it), c) active wells that partially penetrate the seal, d) and local seal weakness and fractures.
CO2 leakage to the subsurface formations can adversely affect the existing and potential energy and mineral resources and shallow ground water resources and soils. As such, detection and characterization of CO2 leakage pathways from storage formations into overlying formations is necessary. The target aquifer could be tested for the leakage pathways before CO2 storage. This will allow for the determination of proper storage aquifers and locations for the injection wells. In this work, we suggest a flow and pressure test and present an inverse methodology to detect and characterize leakage pathways based on the pressure data.
The flow test is based on the injection (or production) of water into (or from) a storage aquifer at a constant rate. The pressure is measured at a monitoring well in an aquifer overlying the storage aquifer, which is separated by an aquitard. The objective of the test is to locate and characterize any leakage through the separating aquitard. The interpretation method is based on forward and inverse solutions of a new analytical model presented in an earlier work. We present an inverse procedure to obtain the leakage pathway transmissibility and location, based on the pressure measurements in an observation well completed in the monitoring aquifer. Inversion analysis is utilized to evaluate the capability of leakage parameters’ estimation through pressure monitoring.
Experimental Study of Capillary Effect in CO2 Solvent Extraction Process for Oil Sands
Authors: Rabiei Faradonbeh M. , Harding T. G. , Dong M. , Abedi J. 
Published: February 2011

Abstract
Bitumen may be separated from oil sand in surface mining operations by using an anhydrous process in which oil sand is mixed with a low boiling solvent such as naphtha. While the majority of bitumen is removed from the sand there is a residual amount of bitumen that remains on the sand and this residue also contains some of the solvent used in the process. It is important to effectively recover as much of the solvent trapped in the spent solids as possible. After most of the bitumen-solvent mixture has been removed from the sand, pressurized CO2 can be used as an anti-solvent to displace residual solvent in the spent sand bed.
In this study, an experimental investigation is made of the effect of capillary force to enhance solvent recovery by mechanical separation, before proceeding to CO2 extraction. Using a thin, semi-permeable layer can facilitate drainage of the solvent from coated sand by capillary force. The results indicate that by using a micro filter the solvent saturation in the sand can be decreased to about half of solvent saturation achievable without using a membrane. It is also possible to further decrease the solvent saturation in sand by pressurizing the air above the sand bed, but it is a slow process.
This experimental study suggests that higher efficiency can be obtained by this simple method and that it has potential to reduce the amount of CO2 required for the next step of solvent recovery by gas extraction.
Multiphase Flow Measurements Sensitivity Assessment and Management - A Cost Effective Methodology for Surveillance Engineers and Field Operators
Authors: Sherief Mohamed , Al-Hassani Khaled K. , Al-Ameri Ammar F. , Abdou Medhat K. 
Published: February 2011

Abstract
Multiphase flow measurements (MPFM) have gained the oil and gas industry focus since the early 90’s(1) due to its continuous improved performance and ease of remote operations (1). Different MPFM systems have been developed but none of them can be referred to as absolutely accurate (3). One of the commonly used systems combines Venturi meter with gamma ray fraction meter (4). The latter is simple, robust and extremely accurate for a given composition based on physical measurements. However, the sensitivity of the nuclear attenuation to heavy atoms can lead to drastic uncertainties on Water Liquid Ratio (WLR) measurements. Therefore, applications where heavy atoms composition changes with time represent an operational and economical shortcoming for surveillance engineers and field operators due to the need to frequently update the configuration data set of such MPFM systems every time the wellstream composition changes.
This paper provides surveillance engineers and field operators with a methodology that has been developed and validated while commissioning new permanent MPFM units on three major onshore fields in the UAE. Several sensitivity studies were carried out to determine the impact of lumping well configuration profiles into groups and assess the MPFM measurements sensitivity to various physical and compositional flow parameters such as phase densities, viscosities, %H2S, %CO2 and water salinity. It also offers a cost effective solution in order to optimize the time and cost required for initial and/or frequent MPFM configuration work by introducing pre-determined configuration data sets that takes into account the wellstream compositional variation with time.
The suggested methodology was applied on 247 wells producing from five different reservoirs. It has significantly reduced the man-hour required to complete the individual well profile configuration from 60 days to 8 days. Once the methodology is implemented, it requires no further vendor support and no frequent physical reconfiguration. For MPFM systems that do not rely on nuclear attenuation technology, the methodology still can be applied to identify measurements sensitivity envelope to any physical, chemical and/or mechanical parameters.
Geomechanical Modeling for Wellbore Stability during Drilling Nahr Umr Shales in a field in Petroleum Development Oman
Authors: Al-Wardy Widad , Urdaneta Oscar Portillo 
Published: February 2011

Abstract
Drilling through Nahr Umr shales has been a challenge in many fields in North of Oman due to the weak nature of these shales. Increased difficulty is faced during drilling if the knowledge of the geomechanical parameters is limited especially the in situ stress magnitude and direction in the formation drilled. Problems such as borehole collapse and stuck pipes cause major delays in drilling time due to borehole cleaning and sidetracking in this specific field. This time delay and other recovery measures undertaken has cost huge amount of money that can be significantly reduced if the geomechanical parameters such as rock strength and in situ stresses of Nahr Umr are known. This can be then used to obtain the appropriate mud weight to drill a well in any desired direction in order to minimize borehole failure.
The geomechanical properties of Nahr Umr shales across North of Oman are not very well covered. Unfortunately acquiring such data always comes last on the list of the petroleum engineers due to lack of awareness of the importance of such data in appropriately calculating the drilling parameters. This specific field had some good data obtained through lab and field measurements that can be used in building a geomechanical model. This included parameters such as unconfined compressive strength of the rock (UCS), Poisson’s ratio, Young’s modulus, and in situ stress magnitude and direction. These parameters were used to build a geomechanical model for Nahr Umr shales for this specific area. This model was then used as input in wellbore stability analysis tool. The same geomechanical model can be used for Nahr Umr shale in any near by area if there isn’t any data available for that specific area however for more accurate analysis it is always better to acquire data for the area of interest.
In this paper some problems during drilling the Nahr Umr shales will be discussed. Also, the workflow of building a geomechanical model in order to use it in wellbore stability analysis will be described. The output results will summarize the minimum required mud weight and unconfined compressive strength (UCS) for drilling a well in any direction in a form of lower hemisphere plots.
The preferred direction for drilling inclined well through Nahr Umr shales in this field was found to be in the maximum horizontal stress direction (SHmax) which is the NE-SW direction. Drilling in the minimum horizontal stress direction (Shmin) which is perpendicular to SHmax was found to be more risky for which mud weight has be raised to avoid borehole failure.
Understanding the geomechanics in this field, in addition to other drilling practices, has contributed in reducing well delivering times from 36.8 days on average in 2009 to 30.1 days in 2010 to date, mainly due to reduction in borehole failure related problems.
Horn River Frac Water: Past, Present, and Future
Authors: Pond J. , Zerbe T. , Odland K. 
Published: February 2011

Abstract
An uninterrupted economical supply of frac water is critical to the successful development of the Horn River Devonian shales. and Apache have progressed our water supply from tank truck delivery of fresh surface waters to an integrated, subsurface saline water treating and distribution system. The current system is designed to deliver water at a rate of 16 m3/min to a maximum daily volume of 16,000 m3 or enough water for 3–4 fracs per day. This presentation will discuss our experiences with fresh surface waters, the design and implementation of the pilot plant and the design, construction and operation of the full scale sour water processing plant. Another aspect that will be discussed are the water source wells including geology, drilling, completion and high volume lift systems.