bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracturing Optimization for Unconventional Reservoirs - The Critical Role of the Mechanical Properties of the Natural Fracture Network
Authors: Nagel Neal B. , Garcia Xavier , Lee Byungtark , Sanchez-Nagel Marisela 
Published: October 2012

Abstract
The success of many shale plays depends on the optimal stimulation of natural fractures, and the characterization of the natural fracture systems is a key issue often leading to the construction of a discrete fracture network (DFN). The DFN chiefly consists of fracture spacing, fracture dip, and dip direction from numerous sources, and, in some cases, is matched to well test data allowing for the determination of hydraulic properties. However, a commonly missing component of natural fracture characterization, and the component most important to evaluating the coupled hydro-mechanical behavior of the fractures during a hydraulic fracture stimulation, is the evaluation of the mechanical behavior of the fractures.
The important mechanical parameters of the fractures include: a) elastic properties such as shear and normal stiffness, which relate changes in pore pressure to changes in aperture; b) strength parameters such as cohesion and friction angle, which define when a fracture may shear and open; c) dilational properties, which relate fracture opening to shear slippage; d) fracture toughness, which determines the pressure required to extend a fracture; and e) initial aperture. In this paper, using a new, state-of-the-art, fully-coupled, 3D distinct element hydraulic fracturing simulator, mechanical fracture parameters were evaluated in a parametric study in order to determine their impact on the effectiveness of hydraulic fracture stimulations.
Integrated Microseismic Monitoring for Field Optimization in the Marcellus Shale - A Case Study
Authors: Neuhaus Carl W. , Williams-Stroud Sherilyn , Remington Christine , Barker William B. , Blair Keith , Neshyba Garrett , McCay Taylor 
Published: October 2012

Abstract
The work presented in this paper focuses on an integrative analysis of hydraulic fracture treatments conducted in the Marcellus Shale. The treatments have been monitored by a permanently installed array of buried geophones used to detect microseismic events. These event sets were analyzed in conjunction with available data from other sources, such as well logs and well cores, as well as information on reservoir properties, regional and local geology and other sub-surface structural information. Passive seismic data was acquired by an array of 101 permanently installed geophones buried and cemented in place at a depth of 150 ft in purpose-drilled boreholes covering an area of over 18 square miles providing high resolution stimulation monitoring. The permanent installation of geophones below the surface allows for significant increase in signal-to-noise ratio and consistent comparison of hydraulic fracture treatments for any given number of wells under the array footprint.
This integrative analysis determined how various factors related to the specific reservoir geology in the Marcellus and to what extent the variability of hydraulic fracture treatments impacted the microseismic results. The next step of the evaluation investigated the relationship between hydrocarbon production and the microseismic results, relative to changes in geology and variability of the stimulation approach.
Analysis of stress changes indicated by the microseismic source mechanisms was used to explain the asymmetry of microseismicity about the wellbore. Relationships and statistics of treatment options with respect to the monitoring results were investigated, including the modeled discrete fracture network, the modeled fracture volume, the stimulated reservoir volume, and the cumulative microseismic moment of the event set. The initial production (IP) was compared to reservoir and engineering parameters, such as treatment pressures, sequence of treatments (toe-to-heel vs. zipper-frac), net pressures, and stage spacing, to determine if the variability in the microseismic results is due to engineering differences or to spatially-varying reservoir properties. Simple well test simulations were performed to investigate different fracture and flow models, and compare results to the IP and available reservoir properties.
High Resolution Magnetotellurics for Petroleum Exploration and Development applied on the Unconventional Eagle Ford Shale Play, North of Mexico
Authors: Woods Daniel A. , Manriquez Lopez Alberto , Mecionis Robert J. 
Published: October 2012

Abstract
This paper presents the results of the first application of high resolution magnetotellurics, a passive electromagnetic (EM) method, for hydrocarbon exploration in an onshore project in the North of Mexico. In general, controlled source electromagnetic (CSEM) methods are used in combination with magnetotelluric surveys for mapping and imaging subsurface structures for exploration purposes offshore. In this onshore study, high resolution magnetotelluric instrumentation and a novel methodology were developed to capture and analyze frequencies from the naturally occurring electromagnetic waves returning to the surface from the subsurface of the earth. Since natural electromagnetic energy is being captured, magnetotelluric surveying utilizing surface generated higher frequencies satisfies the level of resolution required for depth of investigation, depth accuracy, and thickness resolution in Eagle Ford shale play. The recorded passive electromagnetic data were analyzed, and the raw EM signal demodulated to an audio format for analysis. The resulting audio signal was then interpreted to obtain an estimate of porosity from signal strength and character and fluid contents characteristics from signal phase changes.
The results were integrated and presented in electric log type format, base maps, and cross plots for interpretation, correlation, and identification of hydrocarbon trends along horizons. The main contributions of this work consist of the following. Firstly, our results will enormously contribute in reducing the uncertainty associated with seismic interpretation alone for petroleum exploration to generate new prospects and to validate existing ones. Secondly, as unconventional resources become increasingly important, identification of hydrocarbon bearing fracture and orientation using this technique will contribute to development plans for both: horizontal drilling planning and design and hydraulic fracturing.
Shear Wave Anisotropy Measurement from Azimuthally Focused LWD Sonic Tool
Authors: Mickael Medhat , Barnett Craig , Diab Mohamed 
Published: October 2012

Abstract
A new logging-while-drilling (LWD) logging tool has been developed to measure shear wave anisotropy and provide a wellbore acoustic image. The tool consists of a focused transmitter and six focused receivers. The transmitter fires rapidly and waveforms are acquired in the six receivers as the tool rotates in the borehole. Sixteen azimuthal waveforms are acquired for each receiver and processed to produce compressional and shear velocities of the formation as a function of azimuth.
Anisotropy ratio and maximum/minimum stress directions are determined from the velocity images. Borehole images of the compressional and shear velocities of the formation are also obtained from the azimuthal velocities. This paper shows modeling data of the tool response in different anisotropic formations to assess the accuracy and viability of the measurement. The ability of the measurement to determine formation anisotropy at different borehole inclinations and the sensitivity of the borehole image to the formation acoustic properties are also discussed. Field examples of the anisotropy measurement and the borehole images obtained in vertical, deviated, and horizontal wells are presented.
A Novel Potassium Silicate for Use in Drilling Fluids Targeting Unconventional Hydrocarbons
Authors: McDonald Michael 
Published: October 2012

Abstract
The challenging nature of drilling and producing shale gas plays has favored the use of oil-based drilling fluids. The growing importance of shale gas has placed greater pressure to address environmental issues associated with the drilling and production of these wells. A pressing goal is the development of a highly inhibitive and environmentally friendly water-based drilling fluid. Specifically, the drilling fluid should address wellbore stability issues associated with specific shale gas plays. Such specialized drilling fluids will better stabilize shales and help control drill time and costs.
This paper discusses the research and development of a novel potassium silicate as a shale stabilizer for certain shale gas plays. This novel potassium silicate differs from conventional potassium silicate by significantly increasing the level of dissolved silicate to potassium. The resulting potassium silicate is chemically more reactive and can more easily undergo the polymerization and precipitation reaction. These reactions are the shale stabilization mechanisms most often associated with sodium and potassium silicate. Laboratory investigation indicates drilling fluids formulated with this more vitreous potassium silicate show a high degree of effectiveness at preventing shale delamination and sealing micro fractures.
Drilling fluids formulated with conventional potassium silicate can often be disposed using surface methods such as mix-bury-cover, land spreading or land spraying. However, depending on receiving soil or the concentration of potassium silicate in the drilling fluid, it sometimes becomes necessary to treat the associated drill waste with a calcium-based amendment or send the waste to an approved waste management facility. The reduced alkalinity and more siliceous nature of high ratio potassium silicates provides for a drilling fluid with lower salinity as measured by electrical conductivity and sodium adsorption ratio. Resulting drill waste can more easily meet the salinity requirements associated with using surface disposal methods.
Hydraulic Fracturing Design and Its Effects on Oil Recovery in Bakken Formation
Authors: Chen Shengnan , Wang Xiaoqi 
Published: October 2012

Abstract
Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.
Minimum Horizontal Stress Profile From Logging Data for Montney Formation of North East British Columbia
Authors: Song Lisa , Hareland Geir 
Published: October 2012

Abstract
Microfrac or fall off injection test is a technique used to accurately measure minimum horizontal stress directly in the formation. However, other than being expensive and time consuming, this test does not give a continuous minimum horizontal stress profile. Continuous minimum horizontal stress profile is especially important for hydraulic fracturing design for the tight Montney formation. This study utilizes logging data and core reports to generate the minimum horizontal stress profile for two Montney wells in North East British Columbia. Specific value of tectonic stress determined from injection fall off analysis is also included in the calculation.
The first method, conventional method, calculates minimum horizontal stress by solving linear poroelasticity equations with vertical stress equal to the overburden. Closure pressure from fall-off injection test is used as a calibration point to acquire tectonic stress. The second method incorporates the tectonic, thermal effect and rock mechanical properties at each incremental depth to generate the minimum horizontal stress. The third method, vertical transverse isotropy (VTI), is conducted assuming different rock properties on the vertical and horizontal direction and also different tectonic strain for the maximum and minimum direction.
The conventional method yields the lowest minimum horizontal stress magnitude without any distinctive characteristic. On several zones, the VTI method shows higher stress magnitude above Montney and reveals some good zone containment for hydraulic fracturing design, which the conventional method does not provide. From the injection fall off analysis, a second closure pressure with lower value than the first closure is believed to represent the overburden stress. It is concluded that this area has a thrust fault regime in which overburden stress is the least principle stress.
An NMR Study of Shale Wettability and Effective Surface Relaxivity
Authors: Sulucarnain Ismail , Sondergeld Carl H. , Rai Chandra S. 
Published: October 2012

Abstract
Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) test for an oil/brine/rock system are difficult to apply to shales due to their extremely low permeability, usually in the nanodarcy range. Earlier Nuclear Magnetic Resonance (NMR) studies on Berea sandstone showed consistency with standard wettablity measurements and served as a calibration standard. A total of 10 core plugs from an Ordovician organic rich shale were analyzed. The T2 NMR signature of the imbibed dodecane and brine occurred mostly at relaxation times faster than their measured bulk relaxation of 1 and 3 second, respectively, indicating that surface relaxation is dominant. The Ordovician organic rich shale display mixed wettability. Three of the samples had a high affinity for dodecane, as a result of the organic pores present in the samples. This result was consistent with the NMR spectra in both sequences as well as the gravimetric analysis. The main advantage NMR has over the traditional methods is that we are able to see where the fluids are being imbibed.
Mercury injection capillary pressure (MICP) characterizes the distribution of pore throats while NMR responds to the pore bodies. Assuming the throats and bodeies are equivalent, a scaling factor was used to match the NMR spectra and the MICP curves to estimate the effective surface relaxivity for the shale samples. The range of the effective surface relaxivities ranged between 0.5μm/sec to 3.1μm/sec with an average of 1.7 ± 1.0 μm/sec. Mineralogy variations were observed across the 10 shale samples but showed a correlation which suggests that the effective surface relaxivity is dependent on mineralogy.
Improving Gas Production and Reducing Fracture Face Damage using a Microemulsion Surfactant—Field Trail in Burgos Basin, Mexico
Authors: Lopez-Bonetti Elias , Rodriguez Levi , Coronel Hugo , Garza Domingo , Martinez-Melo Luis , Bailon Leonel 
Published: October 2012

Abstract
Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.
Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico—located in the North-East area of the country and bordered with South Texas in the USA—problems still persist.
This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.
This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.
Developing a Predictor for Degradation of High Strength Corrodible Tripping Balls used in Multi-Zone Fracturing Treatments in Unconventional Hydrocarbon Reservoirs
Authors: Carrejo Nick , Mathur Vipul , Mazyar Oleg A. , Gaudette Sean 
Published: October 2012

Abstract
Multi-point hydraulic fracturing in unconventional hydrocarbon-bearing shale reservoirs has proven to greatly enhance production economics. Recent technology has allowed for as many as 40 individual fracture points. Tripping balls are a major component of these multi-point fracturing systems and are used to actuate fracturing sleeves to pinpoint fracture initiation and placement. While seated on ball seats, the tripping balls may experience pressures approaching 10,000psi. However, following a successful formation fracture, the tripping balls may hinder production. Potential problems relate to the tripping balls becoming stuck on the fracturing seats. Tripping balls remaining in the lateral can also lead to problems if wellbore re-entry is required. These production risks can lead to significantly increased costs and potential lost production. A new, high-strength corrodible material has been developed for tripping balls to alleviate potential problems in these unconventional reservoirs. This material has yielded an interventionless means of flow assurance. The mechanical properties and degradation rates of these newly engineered materials have been investigated to determine the downhole characteristics. The characterization results of these materials are discussed in an effort to develop a method for accurately predicting the timeframe in which these high-strength corrodible tripping balls fully degrade, and thus eliminate possible production risks. The testing included investigations of the degradation rates of these materials in brines, and at various temperatures. Materials were also pressure tested on multiple ball seat configurations used in the multi-zone fracturing systems1.
Analysis of Finding and Development Costs in Western Canada: Looking for Most Cost Efficient Unconventional Plays
Authors: Virine Lev , Turchin Sergey 
Published: October 2012

Abstract
Petroleum producers are currently engaged in significant expenditure towards exploration and development in unconventional oil and gas plays in Western Canada. Finding & Development costs are different in various plays and strategies. But where the producer should focus their resources to achieve most cost efficient production?
The paper describes methodology of analysis of Finding & Development cost. A probabilistic model was developed to quantitatively assess exploration and development expenditure, production, and reserves for various producers for different oil and gas plays. The model employs a number of key performance indicators (KPIs) such as Finding & Development costs with and without acquisitions, reserves life, reinvestment, and others.
The methodology was applied to a comprehensive study of Finding & Development expenditure in Western Canada focused mostly on unconventional oil and gas. The study included more than 80 oil and gas companies. Each company may be involved in exploration and development of many plays. The expenditure, production, and reserves were analyzed for the last 12 years. The companies were subdivided into three groups based on their production. Each company’s Finding & Development costs and other KPIs were calculated for Western Canada as a whole and for a particular strategy or play where the company was operating, as well as for CBM, tight, and shale gas.
The study found significant variance in finding and development cost in Western Canada. All companies and all strategies are ranked based on their Finding & Development costs and other KPIs. The results of the study can be applied to the comparative analysis of efficiency of the exploration and development expenditure, which in turn can help improve portfolio management and decision making processes.
Real Time Measurement of Borehole Shape and Diameter by Using Ultrasonic Caliper in Different Drilling Fluid and Wellbore Conditions for Detecting Instabilities
Authors: Elahifar Behzad , Esmaeili Abdolali , Fruhwirth Rudolf K. , Thonhauser Gerhard 
Published: October 2012

Abstract
Drilling programs continue to push into new and more complicated environments. As a result, accurate measurements of drilling data in real time are becoming more critical by means of minimizing the risks as well as the costs. An ultrasonic caliper sensor is a key measurement for determining the borehole diameter in MWD and LWD tools. Important is the use of ultrasonic caliper tools to offer a method for calculating borehole volumes, on the final bit run, the sensor collects data while tripping out of the hole for determining borehole size and furthermore required cement volumes. Real-time applications of ultrasonic caliper measurements also strongly support the early detection of borehole instability.
This paper describes the experiments related to the accuracy of the ultrasonic sensor measurements for estimation of the wellbore diameter. A fully automated test robot has been designed and tests have been performed in different fluids and geometrical conditions. That test robot allows emulating vertical as well as lateral movements of a sensor head in an artificial wellbore which can be run with different fluids. The results of the tests were compared and the weak points and problems of the sensor for detecting the echoes were determined. Numerical simulation of the ultrasonic measurements and comparison of the simulated results to the recorded data gives estimates about the accuracy dependency to different drilling conditions. Tests with different decentralized positions of the ultrasonic caliper tool inside the wellbore give estimates about the accuracy dependence with respect to the decentralization of the tool. Finally measurements were performed in wellbores with geometrical anomalies like washouts and squeezing formations. It is shown that such anomalies can be detected in an appropriate accuracy if circle fitting methods like the Kasa method in combination with robust error models are applied.