bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrating Geology, Hydraulic Fracturing Modeling, and Reservoir Simulation in the Evaluation of Complex Fluvial Tight Gas Reservoirs
Authors: Ramirez Kelly M. , Cuba Patricia H. , Miskimins Jennifer L. , Anderson Donna S. , Carr Mary M. 
Published: March 2012

Abstract
Hydrocarbon resources such as tight sands have become one of the most sought after types of unconventional plays, given the extensive amounts of gas they contain. In order to access these reserves, the industry is focused on improving hydraulic fracturing techniques with the purpose of increasing gas recovery. However, proper reservoir management practices, in conjunction with improved completion processes, are also key factors for maximizing these gas reserves. Additionally, reservoir understanding becomes even more relevant when dealing with reservoirs deposited in complex fluvial environments.
This paper discusses a study that integrates the accurate stratigraphy and detailed reservoir characterization of a 160-acre 3D fluvial geologic outcrop model populated with analog producing field reservoir properties with detailed hydraulic fracturing modeling to better understand the effects that fluvial depositional environments have on hydraulic fracture growth. Subsequently, the detailed hydraulic fracturing growth parameters are implemented in a robust 3D reservoir simulation model, representing the heterogeneous geologic environment. Reservoir simulation is then used to determine the dynamic flow conditions associated with the fluvial geologic model with the ultimate goal of determining optimum reserve recovery practices such as well spacing and placement, hydraulic fracture design components, etc.
The methodology applied in this study, which starts with the 3D outcrop mapping and characterization, followed by the development of a geostatistical model, hydraulic fracturing modeling, and reservoir simulation is presented. Three different cases, consisting of various well locations and spacing, are described. Results show that the continuity of sand bodies in the near wellbore vicinity, whether part of the completion interval or not, is critical to the ultimate reserve recovery and is a function of the hydraulic fracture growth pattern. Additionally, amalgamation of the sandstone bodies, which also affects the hydraulic fracture growth patterns, has a strong effect on gas recoveries. Finally, for the cases reviewed, the benefits of infill drilling were mainly obvious in reserve acceleration versus reserve addition.
A New Approach to Biocide Application Provides Improved Efficiency in Fracturing Fluids
Authors: Dawson Jeff , Wood Marodi 
Published: March 2012

Abstract
Hydraulic fracturing of oil and gas wells requires high volumes of water. Often these waters originate from rivers, lakes, ponds, and recovered water from previous fracturing treatments. These waters are often infested with aerobic and anaerobic bacteria that can cause multiple problems. These include degradation of fracturing chemicals, down-hole corrosion, biological-based H2S generation, and down-hole flow-impairment due to slime producing bacteria. Historically, these waters have been treated with biocides such as tetrakis (hydroxymethyl) phosphonium sulfate (THPS), glutaraldhyde or quaternary ammonium-based surfactants. Lately, oxidizing biocides such as peracetic acid, chlorine dioxide and hypochlorous acid have been used as environmental alternatives.
Recently, tetrahydro-3,5-dimethyl-l,3,5-thiadiazine-2-thione (Dazomet) has been used as a biocide with good results in the Barnett, Marcellus, Eagle Ford and Haynesville gas shale basins in the US. This biocide is effective against most aerobic and anaerobic bacteria encountered in water sourced for fracturing applications. Although not a fast-killing biocide, it is effective for long-term maintenance of the formation and well with loadings normally about 0.4 L/m3 of 24% active solutions.
Further investigation has now discovered that the combination of this biocide with others has significantly reduced necessary loadings of these biocides to values less than 0.2 L/m3. These Dazometcombinations also tend to show much higher degrees of efficacy, showing superior bacteria management over the single or oxidizing biocides. This enhanced performance also allows for reduced chemical exposure to the environment. The performance of these Dazomet biocide-combinations and field trials will be presented and discussed.
Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks such as Shales
Authors: Sinha S.. , Braun E. M. , Passey Q. R. , Leonardi S. A. , Wood A. C. , Zirkle T.. , Boros J. A. , Kudva R. A. 
Published: March 2012

Abstract
Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the "ground-truth" for permeability in the 10 – 10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.
Assessment of an Unusual European Shale Gas Play: The Cambro-Ordovician Alum Shale, Southern Sweden
Authors: Pool Wilfred , Geluk Mark , Abels Janneke , Tiley Graham , Idiz Erdem , Leenaarts Elise 
Published: March 2012

Abstract
In 2008 Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe.
The licenses covered the Höllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons.
The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting).
80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.
Benchmarking Unconventional Well Performance Predictions
Authors: van den Bosch Rainer , Paiva Antonio 
Published: March 2012

Abstract
The hydrocarbon industry is constantly challenged to improve subsurface description and operating practices to maximize returns on capital employed. Well locations are typically identified by continuously improving the geologic and reservoir engineering modeling. As a consequence, and on an on-going basis, refinements in drilling and stimulation practices are introduced based on a better understanding of rock and fluid interaction.
However, over the near term it is difficult to validate the impact of changing processes. It takes typically several months before stabilized flow conditions are established such that well performance can be determined with confidence from decline curve analysis. Moreover, it takes several years before robust and reliable estimated ultimate recovery (EUR) predictions can be made. Hence, the findings are obtained often too late to influence ongoing unconventional field development, especially in manufacturing pad development that is characterized by high levels of drilling and completion activities.
In this work we propose a benchmarking system that enhances the forecasting of long-term well performance, based on metrics of short-term well behavior. The metrics are routinely recorded from the first day of production such as peak month production or 3, 6, 12 and 24 month cumulative production. The process is refined continuously as and when new information becomes available and the added value of the information is quantified. A new key performance indicator (KPI) condenses the range of predicted outcomes into a single number via a simple numerical function that allocates increasing cost for increasing misclassification. The range is 0% = no predictive capability of the system to 100% = perfect predictive capability of the system. This approach enables a transparent and unbiased benchmarking of the system’s prediction capability for each metric.
In adding to the analytical toolkit, the key objective of this benchmarking method is to support decision making on an ongoing development, well before the entire program has been executed. Possible applications include: Early confirmation of successful well placement.Early indication of the impact on well performance as a result of changes to drilling and stimulation procedures.A ‘conditional probabilistic’ outlook of long-term well behavior to better define well/field economic scenarios and to guide reserve bookings.
This process has been developed using public data from the data rich fields Barnett in Texas, Fayetteville in Arkansas and Woodford in Oklahoma. This process is also viable for plays with scarce data and is able to be refined with increasing data availability.
Understanding Hydraulic Fracture Stimulated Horizontal Eagle Ford Completions
Authors: Shelley Robert , Saugier Luke , Al-Tailji Wadhah , Guliyev Nijat , Shah Koras 
Published: March 2012

Abstract
This paper will present results from a modeling effort to derive best practices for the completion of hydraulically fractured horizontal Eagle Ford wells. The well, reservoir, completion/frac and production information used in this evaluation were provided by an operator from a five-county area in Texas.
Hydraulically fractured horizontal completions pose significant modeling and evaluation challenges. This is primarily due to two issues: 1) lack of well-specific data about the reservoir/rock properties, and 2) improper assumptions used in the modeling process. As shown in this paper, a data-driven approach to modeling these completions provides a much needed pragmatic perspective, identifies high-impact parameters and provides direction about how to improve the effectiveness of these complex completions.
Sensitivities performed on the predictive data model indicate that well-to-well variation in reservoir quality and geology has a dominant effect on Eagle Ford production. In addition, issues such as fracture spacing, frac volume, perforation distribution, proppant selection and wellbore length also affect well production and economics. A summary of completion and frac methodology for the Eagle Ford, in addition to a ranking of controllable (completion and frac design) and non-controllable (reservoir and geology) parameters that affect Eagle Ford production, will be included in this paper.
The information contained in this paper will be useful to those interested in reservoir, completion and frac parameters that affect production from shales analogous to the Eagle Ford. Reservoir quality, completion and frac methodology effects on production results will be quantified in this paper.
Visualizing Stress Trajectories around Hydraullicaly Pressurized Wellbores
Authors: Weijermars Ruud , Schultz-Ela Dan 
Published: March 2012

Abstract
A new approach, using stress functions, reveals how each component of the stress regime affects the stress pattern around the wellbore. The effect of tectonic far field stress on the stress trajectories in the host rock near a wellbore is visualized in a series of plots with the analytical stress trajectory solutions for a large range of net pressures on the wellbore. The deviatoric stresses around a wellbore result from the dynamic superposition of (1) far field tectonic stress, (2) near wellbore stress due to lithostatic pressure near the open hole, (3) pore over-pressure or under-pressure in the host rock, and (4) hydraulic pressure applied on the wellbore. The principal stress trajectory plots are used to determine the suitable options for well orientations and to delineate stress trajectory control of the incipient brittle failure patterns for hydrofracs and wellbore breakouts. Our approach provides fundamental insight, with an important practical application for improved understanding of the growth of hydrofractures.
Exploring Shale Basins using Existing Wells
Authors: Pitcher Jason , Kwong Shan , Yarus Jeffrey , Mullen Mike 
Published: March 2012

Abstract
In the search for unconventional shale plays with commercial potential, many operators have properties in petroprovince basins containing wells through potentially productive shale zones. These shales were often encountered as part of exploration or development programs for deeper conventional targets. Often, the overlying shale is known to have had gas or oil shows reported during initial drilling, but little or no additional geological data was acquired at the time.
This paper discusses the workflow and method to use the minimal information from these existing wells, and to quantitatively incorporate them into a basin exploration program. The process begins with a single new well, such as a sidetrack from an existing well, which is evaluated with the full array of open hole logging tools. Coring (conventional or sidewall), DFIT tests, and other shale-specific logging tools are performed on this initial well. Pre-existing wells that penetrate the objective shale can also be quantitatively assessed for relevant shale properties by using specialized logging tools, such as a combined through-casing pulsed neutron and sonic tool, to map relevant shale properties. These tools are calibrated to the open hole data to generate a wider distribution of data points containing critical shale properties that can be demonstrated to have a strong relationship with production.
After the data acquisition process has been performed, the data are combined with existing seismic and structural information to delineate the best areas for further evaluation. Using modern mapping tools, a basin can be rapidly appraised to identify sweet spots, providing further exploration targets for evaluation drilling.
This paper discusses limitations, best practices, workflows, and methods, and includes an example of a European shale evaluation log to demonstrate this exploration technique.
Microseismic Monitoring of Fracture Networks During Hydraulic Stimulation: Beyond Event Locations
Authors: Kendall J-M.. , Verdon J. P. , Baird A.. , Wuestefeld A.. , Rutledge J. T. 
Published: March 2012

AbstractThe successful exploitation of tight-gas reservoirs requires fracture networks, sometimes naturally occurring, often hydraulically stimulated. Borehole microseismic data acquired in such environments hold great promise for characterising such fractures or sweet spots. The loci of seismic events delineate active faults and reveal fracture development in response to stimulation. However, a great deal more can be extracted from these microseismic data. For example, inversions of shear-wave splitting data provide a robust means of mapping fracture densities and preferred orientations, useful information for drilling programs. They can also be used to track temporal variations in fracture compliances, which are indicative of fluid flow and enhanced permeability in response to stimulation. Furthermore, the frequency-dependent nature of shear-wave splitting is very sensitive to size of fractures and their fluidfill composition. Here we demonstrate the feasibility of using such analysis of shear-wave splitting measurements on data acquired during hydraulic stimulation of a tight-gas sandstone in the Cotton Valley field in Carthage, West Texas.
Can We Achieve Acceptable Fracture Conductivity Using WaterFracs?
Authors: Mcdaniel B. W. 
Published: March 2012

Abstract
After 1970, the technology of hydraulic fracturing began to quickly accelerate, especially as to the industry focus on fracture conductivity. We saw a transformation in our frac fluids as we moved away from crudes and thin water gels to higher viscosity emulsion systems, foamed gels, and even crosslinked gel systems that could deliver significantly more proppant as we chased after better fracture conductivity. Using these more viscous gels we moved to "Massive Hydraulic Fracturing" of tight gas sand formations. This grew to multi-million pound proppant placements as the age of crosslinked gels began to dominate most of the fracture stimulation landscape as we tried to place very long, highly conductive fractures. However, the decade of the 1970’s also had Claude Cooke showing us that sand was a very limited proppant for deeper wells, and then later showing that gel residue could seriously reduce insitu fracture conductivities! (Cooke 1973; 1975; 1976; 1977) During the early 1980’s North America experienced the greatest rig activity ever, but then the mid-80’s gave us the greatest crash the oilfield had ever seen! Fortunately, this also resulted in our industry laboratories having the time to upgrade testing equipment and procedures to "realistic" test conditions for evaluation of packed proppant bed conductivity. This meant longer testing times, high temperatures, and with exposure to frac fluids. This research would subsequently launch the search for better gel breakers and lower residue gels (which continues today).
Unexpectedly, in the 1990’s a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs (WaterFracs), placing only 15-20% as much proppant as crosslink gel fracs, yet claiming equal or better overall economics. To add further consternation, George Mitchell found another application for WaterFracs and eventually showed the world that a hydrocarbon-source shale formation, the Barnett, can actually be a commercial producer itself. During the early 2000’s, the combination of long horizontals, and extreme multi-stage hydraulic fracturing (mostly using Waterfracs) turned the Barnett Shale into the launching pad of our present-day madhouse search for the next great shale play to chase.
It is clear that long horizontal completions and WaterFrac stimulation methods have played an important role in opening the door to economic success in the numerous "resource plays" (i.e. shales). In this paper we will investigate if WaterFrac treatments are violating or upholding (?) one of our most significant fracturing beliefs: Fracture Conductivity should be optimized. Until we moved to the ultra-low formation permeabilities, we would generally say we should try to maximize our conductivity, but with WaterFracs designs it often seems we may instead be minimizing it, and this will be discussed here.
Experimental Measurements of mechanical parameters of Class G cement
Authors: Teodoriu Catalin , Yuan Zhaoguang , Schubert Jerome , Amani Mahmood 
Published: March 2012

Abstract
The new quest of unconventional resources is the achievement of well integrity which is highlighted by the inadequacy of conventional cementing procedures to provide zonal isolation. High temperatures and pressures or even post-cementing stresses imposed on the cement sheath as a result of casing pressure testing and formation integrity tests set in motion events which could compromise the long term integrity of the cement sheath due to fatigue. Knowledge of the mechanism of fatigue in cement and factors that affect it such as the magnitude of the load, strength and composition of the cement, mechanical properties of the cement and pattern of load cycles are important to achieve a realistic design of a cement system that will be subjected to fatigue loading. Such a design will go a long way to ensure the long term integrity of a well operating under downhole conditions. Finite element investigations help engineers to assess the stress magnitude and evolution for a given well configuration, but when structural calculations for casing-cement system are required, missing input parameters reduce the quality of the results.
In order to have reliable data we performed an extensive experimental work using Class G cement in order to measure the principal parameters for mechanical structural calculations: compressive and tensile strength, Young modulus, Poison Ratio. The data was measured under room conditions and elevated temperature and pressure. The results were also extrapolated for a time period for more than 300 days.
The paper will provide an excellent data inventory for class G cement that can be used when mechanical studies on cement, like finite element studies, are required.