bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimating Drillpipe Body Wear to Improve Drilling Performance in Challenging Shale Plays
Authors: Kumar Aniket , Samuel Robello , Granger Scott 
Published: October 2014

Abstract
The recent advances in drilling activities in shale plays have led to unprecedented challenges that need to be addressed to improve the drilling performance. One of the challenges, experienced especially in the Bakken formation, is a very high rate of drillpipe body wear. The drillpipe body wears out more quickly than the tool joints, thus reducing the life of the tube. Consequently, a mechanism to analyze the pipe body contact would be useful in understanding the downhole scenario and would help to reduce the wear.
This study uses the finite element analysis to perform a step-by-step investigation of the drillpipe body wear during the drilling of a typical Bakken well using field data. The model helps to calculate the clearance of the center of the pipe body from the wellbore for each joint of pipe and further estimates the side force if there is any contact. The side force analysis is then used to predict the downhole wear in the pipe body under the given drilling parameters.
The field case study presented compares the performance of 4-in., 4¼-in., and 4½-in. drillpipe from the kickoff point in the 8¾-in. build section. It also analyzes the 4-in. and 4¼-in. drillpipe in the 6-in. lateral section to the target depth. The study also critically examined the influence of drilling parameters on pipe performance to better understand downhole conditions. Based on this analysis, recommendations are provided to mitigate drillpipe body wear for shale drilling environments. This study has the potential to be fully implemented to improve the drill string design in shale plays to reduce drilling times, increase drilling efficiency, and reduce costs by maximizing the life of the drillpipe.
Long Term Effect of Natural Fractures Closure on Gas Production from Unconventional Reservoirs
Authors: Aybar Umut , Eshkalak Mohammad O. , Sepehrnoori Kamy , Patzek Tad 
Published: October 2014

Abstract
Observed trends of long-term production forecasts of unconventional assets tend to secure US energy supply for decades to come. Also, recent innovations in horizontal drilling and hydraulic fracturing support such trends to be economically viable. However, triggered fractures in an unconventional reservoir rapidly shrink and will result in significant long-term production loss. Hence, it is essential to quantify the effect of fracture closure on long-term production. In this paper, the permeability changes of secondary fracture network are investigated with respect to the effect on the long-term gas production from unconventional reservoirs.
A simple analytical trilinear model is improved in order to handle the constant bottom-hole pressure production and analyze the cumulative gas production by considering the effect of stress on natural fracture permeability. Moreover, a sensitivity study is performed to identify the influence of uncertain parameters on cumulative production and consequently detect a condition in which the pressure-dependent natural fracture effects on production are severe.
It is observed that the pressure-dependent natural fracture permeability can cause up to ten percent less cumulative production than the constant natural fracture permeability conditions. The improved analytical model is very fast compared to the commercial numerical simulators. The advantage of this approach is in obtaining a quick and accurate assessment for operators in the pre-evaluation process of the complex production behavior of their unconventional resources. The findings of this paper provide insights into long-term investment of unconventional reservoirs and guide decision making for the secondary or tertiary enhancement treatments of unconventional wells, such as re-fracturing.
Fracture Conductivity Decrease Due to Proppant Deformation and Crushing, a Parametrical Study
Authors: Han Jiahang , Wang John Yilin 
Published: October 2014

Abstract
Sustainable high fracture conductivity is a key to successful stimulation. The reduction of hydraulic fracture conductivity due to proppant deformation and crushing is frequently observed. Previous researches are based on laboratory experiments and empirical correlations, which can not fully explain proppant damage in field cases. In this paper, we applied our fully coupled fluid flow and geomechanical model to further understand the proppant pack deformation and crushing.
Parametric studies on wellbore and reservoir pressures, formation properties, and proppant biot constant were performed to understand proppant deformation and crushing in different conditions. Additionally, an analytical model for avoiding proppant crushing was developed for fractured wells.
Through this research, we found fracture conductivity loss due to deformation and crushing are severer than laboratory results. Large deformation and high probability of crushing were observed near wellbore according to the net pressure. Fast flow back (low bottom hole pressure) would generate large proppant crushed zone. Various reservoir properties as pressure gradient, formation stiffness, and matrix permeability were also investigated. Strong proppant is highly recommended for natural fractures, and hydraulic fracture near well bore especially for tight formations. Small chock size (high BHP) is also recommended during early production. Additionally, a simple analytical model is provided, accoding to the parametrical studies, for operating well without breaking proppant pack.
Enhancement of Filtration Properties in Surfactant-Based and Polymeric Fluids by Nanoparticles
Authors: Fakoya M. F. , Shah S. N. 
Published: October 2014

Abstract
Currently, there are few available publications regarding the application of nanotechnology in fluid loss control; hence, this technology needs more exploration. During hydraulic fracturing, fracture conductivity damage and other problems associated with excessive leak-off rate can be significantly curtailed by utilizing nano-fluid systems that evolve from further research studies.
An experimental study is presented on the application of nanotechnology on filtration properties of surfactant-based fluids (SBF), polymeric fluids, and SBF-polymeric fluid blends. The concentration of SBF is 5%, while that of polymeric fluids is 33 lb/Mgal guar. Besides, both fluids contained 4% potassium chloride (KCl). Additionally, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25% vol. and 25/75% vol. respectively. Nano-fluids were prepared by adding 20 nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4% wt., to the clean fluids. Filtration tests were conducted with a wall mount filter press, and at ambient temperature and 100 psi differential pressure.
Excellent results were displayed with surfactant-based nano-fluids and Blend-A nano-fluids, but their outcome at 0.24 and 0.4% wt. respectively is slightly better. Polymeric nano-fluids and Blend-B nano-fluids revealed very good results, with better outcome at 0.24 and 0.058% wt. respectively. A trial run was made with a commercially available fluid loss additive (polyanionic cellulose, PAC) in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Furthermore, Blend-A nano-fluid, at 0.058% wt., is selected as the best based on performance evaluation and economic analysis. In conclusion, the selected Blend-A nano-fluid at 0.058% wt. was optimized at lower nanoparticle concentrations (0.02, 0.01 and 0.002% wt.) in order to probe further into its filtration performance. Interestingly, using Blend-A nano-fluid at 0.002% wt., as regards the initial recommendation of 0.058% wt., reduces the cost of nanoparticles required for preparing 1 barrel of this fluid by 96.6%. Therefore, Blend-A nano-fluid is recommended for use at nanoparticles concentration of 0.002% wt.
The application of Blend-A nano-fluid will promote fluid economy, substantially reduce fluid loss and fracture conductivity damage, and enhance production from unconventional reservoirs.
History Matching and Rate Forecasting in Unconventional Oil Reservoirs Using an Approximate Analytical Solution to the Double Porosity Model
Authors: Ogunyomi B. A. , Patzek T. W. , Lake L. W. , Kabir C. S. 
Published: October 2014

Abstract
Production data from most fractured-horizontal wells in gas and liquid-rich unconventional reservoirs plot as straight lines with a one half slope on a log-log plot of rate versus time. This production signature (half slope) is identical to that expected from a one-dimensional linear flow from reservoir matrix to the fracture face, when production occurs at constant-bottomhole pressure. In addition, microseismic data obtained around these fractured wells suggest that an area of enhanced permeability is developed around the horizontal well, and outside this region is an undisturbed part of the reservoir with low permeability. Based on these observations geoscientists have, in general, adopted the conceptual double-porosity model in modeling production from fractured horizontal wells in unconventional reservoirs. The analytical solution to this mathematical model exists in Laplace space but it cannot be inverted back to real-time space without using a numerical inversion algorithm. We present a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional-oil reservoirs.
The first step in developing the approximate solution was to convert the systems of partial differential equations for the dual-porosity model into a system of ordinary-differential equations. After which we developed a function that gives the relationship between the average pressures in the high-and the low-permeability regions. Using this relationship, the system of ordinary differential equations was solved and used to obtain a rate/time function that can be used to predict oil production from unconventional reservoirs. The approximate solution was validated with numerical reservoir simulation.
We then performed a sensitivity analysis on the model parameters to understand how the model behaves. Once the model was validated and tested, we applied it to field production data by partially history matching and forecasting the expected ultimate recovery. The rate/time function fits production data and also yields realistic estimates of ultimate oil recovery. We also investigated the existence of any correlation between the model-derived parameters and available reservoir and well completion parameters.
Fully Coupled Finite Element Model to Study Fault Reactivation during Multiple Hydraulic Fracturing in Heterogeneous Tight Formations
Authors: Zhong Ruizhi , Bao Jinqing , Fathi Ebrahim 
Published: October 2014

Abstract
Multiple hydraulic fracturing is a proven stimulation technique to improve hydrocarbon production especially in tight, unconventional hydrocarbon bearing reservoirs. A two dimensional (2D) plane strain model, based on linear elastic fracture mechanics (LEFM), has been developed to study multiple fracture propagation and their impact on reactivation of underground discontinuities such as faults. New model solves coupled non-local relationship between fracture width and net pressure in the fracture and non-linear dependence of fluid flow on fracture width and its linear dependence on pressure gradient using finite element method.
In this paper, multiple hydraulic fracturing with different number of fractures, fracture spacing and reservoir rock properties are considered. It is found that the number of hydraulic fractures and their spacing significantly impacts fractures geometry and ultimately production performance. The impact found to be more pronounced in heterogeneous reservoir with multiple layers. Slip-tendency analysis performed to investigate the possibility of fault reactivation and discontinuities failure in surrounding areas. Simulation results clearly show dynamics of stable and unstable zones around the hydraulic fracturing area. Discontinuities failure in reactivation zones leads to increase the permeability of formation therefore improving hydraulic fracturing performance. This study is a unique approach for our further understanding of multiple hydraulic fracturing, and it is important for the development of sound numerical hydraulic fracturing optimization models.
Cost Effective Treatment of Produced Water Using Co-Produced Energy Sources
Authors: Abdallah Issah 
Published: October 2014

Abstract
Produced water (PW) treatment is a daunting significant challenge that continues to have negative impacts on the oil and gas industry, especially, small oil producers. The total dissolved solids (TDS) in produced water from most oil fields can be higher than 250,000ppm (parts per million) in concentration and may also contain a significant percentage of dissolved organic carbons. Many small oil producing companies operate at the edge of profitability; the current cost of treating a barrel of produced water can exceed $2.50 if the operator has to pay for hauling and disposal. This can make it uneconomical to operate mature producing wells which tend towards high watercuts.
As part of a RPSEA (Research Partnership to Secure Energy for America) research project, a Humidification-Dehumidification (HDH) Unit (figure 3) has been built tested and optimized to treat PW using co-produced heat and active solar energy. This has very low electricity consumption and has been tested to process PW at a cost less than $0.50 per barrel if co-produced, or latent heat sources are used. The HDH Unit effectively treats produced water with varying degrees of inorganic dissolved solids concentration and yields fresh water with TDS in the neighborhood of 400ppm when optimized for maximum throughput which is suitable for most oil field activities, irrigation, and could satisfy other basic human needs of water. The existing 80ft3 HDH Unit can process about 50 barrels of PW per day with high total dissolve solids concentration, and reducing this waste stream into concentrated waste and fresh water. Each pass of PW through the system has approximately 19% efficiency with some variations due to changes in seasonal humidity and temperature.
The process works using simple thermodynamic principles. Air (at atmospheric pressure) has the capacity to tremendously increase water vapor saturation pressure to about 50Kpa when the temperature is about 180°F. Consequently, the efficiency of the unit is primarily contingent on ambient temperature and relative humidity. The system uses the high solar radiations prevalent in the Southwest United States to heat PW to about 180°F which is then pumped into an 80ft3 stainless steel that has evaporation and condensation compartments; air is then pumped into the Unit through the opposite direction (to the water) for the humidification of the air at elevated temperature. The heated and humidified air is then cooled to or below dew point to produce fresh water.
Graptolite shale - worldwide distributed Ordovician and Silurian source rock
Authors: Agapitov I. 
Published: October 2014

Abstract
Graptolite shales are a type of fossil shales that contain a large number of graptolite imprints and remains. These deposits are characterized by high TOC contents (Corg = 2–18%). Based on the data of many studies, graptolite shales are one of the main hydrocarbon sources that formed oil and gas fields in Paleozoic deposits around the world, e.g., the Silurian graptolite shales make up to 9–15% of all hydrocarbons that form the oil and gas fields in the largest petroleum basins.
The main accumulation areas of graptolite shales during the Ordovician were the margins of Baltica, Laurentian, and Gondwana (Yapetus Ocean shelf). One of the belts (northern) extended from the southern periphery of the Baltic Shield to the Appalachian Basin; another (southern) belt stretched from the sedimentary basins of the African–Arabian margin of Gondwana to the shelf and continental slope of southern Laurentia, the present-day Western Interior Coal Region, Permian basin, and Ouachita belt. In the Silurian, the southern (northern Gondwanan) belt began to play the leading role, while another northern belt incorporated the southern regions of Baltica and the microcontinents approaching to it (Armorica, Perunica, and Iberica). In the sedimentary basins of Laurentia, Silurian graptolite shales were not widespread; they are reported only for east Greenland and in the Michigan basin. The contribution of Paleozoic graptolite shales into the generation of hydrocarbons that formed multiple oil and gas fields worldwide is quite high. Based on the data of G. Ulmishek and H. Klemme (1991), oil-and-gas source rocks of Ordovician and Silurian ages, which are mostly graptolite shales, produced up to 9% of all the hydrocarbon reserves discovered by the late 20th century. For particular regions, this contribution was even more. It is believed that Silurian graptolite shales produced 80 to 90% of the hydrocarbons stored in giant oil field of North Africa. The Silurian graptolite shales are also thought to have played the main role in the formation of the South Pars/North Field gas condensate field in the Persian Gulf, which is the largest field for natural gas in the world.
During work with more than 41 publications schemes of distribution of graptolitic shales in Ordovician and Silurian was composed. Such knowledge about source rock is one of the many steps to Petroliferous basins insight.
Characterization and Modeling of a Thick Carbonate Transition Zone
Authors: Gomes Jorge C. 
Published: October 2014

Abstract
Naturally, tight carbonate reservoirs exhibit thick transition zones [TZ's] that contain large amounts of oil initially in place [OIIP] and hence significant addition of reserves could be left behind. TZ's are characterized by two-phase flow of both water and oil and there are experimental and field evidences indicating that wettability variation with respect to height above free water level [FWL] is a reality. This variation has to be accounted for in the dynamic model to accurately capture the reservoir performance. However, in real field applications, the situation becomes more complicated while production due to hysteresis effect.
To model rock and fluid property [SCAL/PVT] variations across TZ's and its effect on fluid distribution and ultimate oil recovery, a thorough criterion is required to capture all these variations and their inter-relationships. This was done by developing a mechanistic flow model using a unique approach to model wettability variation with respect to depth and space, taking into account thick TZ. This is extremely important for all professionals involved in field development activities to better understand the fluid flow behavior of porous carbonates at different heights above the FWL, as a function of oil trapping and rock wettability. The simulation work presented here is a continuation of the research done by Carvalho, Dias et al. [1] on the behavior of mixed-wet, oil-wet and water-wet systems for a cyclic carbonate reservoir with different rock types.
Cognitive Responses to Partitioned Pricing of Consumption Taxes: Consequences for State and Local Tax Revenues
Authors: Blanthorne Cynthia , Roberts Michael L. 
Published: October 2014

ABSTRACT
How do taxpayers respond cognitively to add-on sales taxes versus all-inclusive excise taxes? If structural variations produce cognitive differences, then do the differences affect buying behavior? These are important questions because consumer spending drives the U.S. economy and directly determines the amount of tax revenues collected from consumption taxes.
If the negative opinion that people have about taxes (Tax Foundation 2009) increases the saliency of the tax, then an add-on sales tax might decrease consumer spending more than an all-inclusive excise tax pricing structure. Instead, results suggest that demand is higher when the add-on component is a sales tax as compared to an excise tax that is embedded into the total price. The effects on demand are even more pronounced and people recall lower prices when the add-on sales tax is presented as a percentage of the base price—as is generally the case in the U.S.—rather than as an additional currency component.
Data Availability: Contact the authors.
Cosmopolitan Whiteness
Authors: Saraswati L. Ayu 
Published: October 2014

Abstract
Previous scholarship on the immense popularity of skin-whitening frames this practice as revealing women's desire to emulate whiteness and upper class white populations (Burke 1996; Peiss 1998; Hall 2005). Others have focused on whitening practices to highlight the working of racialized color hierarchy and European/Euro-American hegemony in local and global contexts (Hunter 2005; Pierre 2008; Glenn 2009;). This article breaks away from these established theoretical trajectories by arguing that desire for “whiteness” is not the same as desire for “Caucasian whiteness.” Examining advertisements for skin-whitening products in the Indonesian version of Cosmopolitan and skin-tanning products in the American version of Cosmopolitan, I point out the construction of “cosmopolitan whiteness.” Whiteness is not simply racialized or nationalized as such, but transnationalized. Whiteness is represented as “cosmopolitanness,” embodying transnational mobility.
The record 2013 Southern Hemisphere sea-ice extent maximum
Authors: Reid Phil , Stammerjohn Sharon , Massom Rob , Scambos Ted , Lieser Jan 
Published: October 2014

AbstractObservations of Southern Hemisphere sea ice from passive microwave satellite measurements show that a new record maximum extent of 19.58 x 106 km2 was reached on 30 September 2013; the extent is just over two standard deviations above the 1979-2012 mean and follows a similar record (19.48x 106km2) in 2012. On the record day in 2013, sea-ice extent was greater than the 30 year average (1981-2010) in nearly all Southern Ocean regions. For the year as a whole, Southern Hemisphere sea-ice area and extent were well above average, and numerous monthly and daily records were broken. Analysis of anomaly patterns and the atmospheric and oceanic events suggests that a sequence of regional wind and cold-freshened surface waters is likely responsible for the record maximum and the generally high 2013 extent. In particular, the Ross Sea sector experienced a combination of cold southerly winds associated with the position and depth of the Amundsen Sea low, and lower than normal sea surface temperatures (up to 2°C below normal). The resulting very high anomaly in ice extent in this region was a major component of the overall record maximum.