bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Precompletion Annular Gas Leaks in a Marcellus Lateral
Authors: Moore L. P. , Jones J. E. , Perlman S. H. , Huey T. A. 
Published: June 2012

Abstract
Environmental concerns in Pennsylvania related to Marcellus Shale development are high. One of the issues to which the Pennsylvania Department of Environmental Protection (PADEP) has given a high priority is the threat of methane migration into fresh water as a result of methane leaking to surface from behind casing. This has become a significant problem for Marcellus operators as leaking annuli on both new and existing wells is not uncommon. This paper outlines the steps that Flatirons Development took to demonstrate to PADEP that the annular leaks on a recently drilled and cased Marcellus lateral posed no credible threat to ground water and that completion of the well should be allowed to proceed.
In early June, 2011, Flatirons became aware of bubbling in the water filled cellar of the DU 3-6-1H. This discovery came just as completion operations were set to begin. Subsequent investigation revealed that there were two leaks, one from the production-intermediate annulus and another very small leak from the intermediate-surface annulus. PADEP issued Flatirons a Notice of Violation (NOV) and requested that fracture treating the well not proceed until the issue had been resolved.
Over the following two months, Flatirons implemented a series of diagnostic procedures meant to assess the short and long term environmental threat, determine the cause of the problem, trace the source of the gas, and, if necessary, formulate effective remediation options. Using a variety of tools including ultrasonic imaging, pressure build-ups, noise-temperature logs, gas isotopic analysis, cement sample analysis, and continuous monitoring of annular flow, Flatirons was able to demonstrate that the fresh water aquifer was not threatened by methane migration. This work was presented to PADEP's Gas Well Integrity study group and helped form a basis for revising regulations governing leaking annuli.
Establishing Key Reservoir Parameters with Diagnostic Fracture Injection Testing
Authors: Nojabaei B. , Kabir C. S. 
Published: June 2012

Abstract
Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.
In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.
A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.
Novel Water-base Mud for Shale Gas, Part II: Mud Formulations and Performances
Authors: Riley Meghan , Stamatakis Emanuel , Young Steve , Price Hoelscher Katherine , Stefano Guido De 
Published: June 2012

Abstract
Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability.
The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
Integrated Unconventional Shale Gas Reservoir Modeling: A Worked Example From the Haynesville Shale, De Soto Parish, North Lousiana.
Authors: Díaz de Souza O. C. , Sharp A. J. , Martinez R. C. , Foster R. A. , Simpson M. Reeves , Piekenbrock E. J. , Abou-Sayed I. 
Published: June 2012

Abstract
Production from shale gas reservoirs in the USA has become an important component in the increase of natural gas supply. The Haynesville shale, in particular, is a major contributor in gas supply due mainly to its relatively higher initial deliverability compared to other gas shale plays.
One of the critical questions in developing a play efficiently and economically is the well spacing. There are several approaches to addressing this question. The paper looks at one approach, namely the process behind building a calibrated, history matched multi well reservoir model. The model is run in prediction mode with different sensitivities to answer the well spacing issue. The model honors the initial static and dynamic conditions, is capable of running in a reasonable time and, most importantly, has been useful to management in the decision making process.
In this field case, a half section in the state of Louisiana has been drilled and completed with 4 horizontal multistage producing wells and 2 vertical microseismic monitoring wells, 1 of which was subsequently converted to a downhole pressure monitoring well. During the entire hydraulic fracturing operation, downhole microseismic data were simultaneously recorded in both observation wells. The pressure data from the monitor well acquired during production was entered into the reservoir model as another history matching variable. The microseismic data were used to calculate the fracture parameters and as a limiting constraint in the process. This dual porosity model is a practical example application of the methodology previously described in SPE paper 132180 by Du et al. (2010).
The sections in this paper describe a method for building a reservoir model that honors the static boundary conditions. The model was built in two parts according to the Dual Porosity nature of it: a conventional geological model representing the initial porosity and permeability of the rock matrix, and a second part that models the fracture network generated by the stimulation operations and the pre-existing natural fractures. The paper then explains how this model was tuned to enable a production and pressure history match. There is also a section devoted to the generation and utilization of a critical correlation between pressure depletion and a combined fracture half-length times the square root of permeability (Xf.√k) parameter which greatly reduced the uncertainty caused by the non-uniqueness of the match. Finally, some general conclusions regarding the results are presented.
Hybrid Drill Bit Combining Fixed-Cutter and Roller-Cone Elements Improves Drilling Performance in Marcellus Shale Surface Interval
Authors: Bradford John , Ferrari Anthony , Rickabaugh Caleb , Rothe Mitchell , Tipton Brent 
Published: June 2012

Abstract
The application of hybrid bits saves the operator drilling time by out-drilling conventional roller-cone and fixed-cutter bits in the difficult Marcellus shale surface interval. This interval comprises interbedded sandstone, shale, and siltstone down to 600-1,200 ft. deep. Historically, hammer bits and air have been used to drill the surface interval resulting in high penetration rates. In today's environmentally conscious oil industry, some operators have changed casing profiles to better protect water zones and switched to drilling with mud instead of air. Operators drilling these overbalanced wells typically use conventional roller-cone and fixed-cutter bits depending on the area of the play. The roller-cone bits consistently drill the entire interval, yet achieve slow penetration rates due to the lack of available weight. Fixed-cutter bits have been tested to achieve higher penetration rates. They drill faster than roller-cone bits with the available weight on bit, but are accompanied by dynamic dysfunction that leads to a poor dull condition and seldom complete the entire interval.
Extensive research, testing, and development have produced a hybrid bit combining roller-cone and fixed-cutter elements to address these major challenges. The fixed-cutter elements help provide higher penetration rates with the low available weight on bit. The roller-cone cutting elements help drill through the harder part of the interbedded formation by reducing drilling dysfunctions while maintaining a better dull condition.
This paper is a case study comparing the performance of roller-cone, fixed-cutter, and hybrid bits using field results and drilling data from an operator's Marcellus shale surface interval.
Natural Fracture Identification and Characterization While Drilling Underbalanced
Authors: Norbeck Jack , Fonseca Ernesto , Griffiths D. V. , Wong Sau-Wai 
Published: June 2012

Abstract
An algorithm based on data obtained during underbalanced drilling operations is described for identifying the location and properties of productive natural fractures that are intersected by the wellbore. The criteria used to identify natural fracture locations are (i) total gas concentration measurements from mud logs and (ii) mud pit volume. The paper also describes a simple approach for estimating the fracture permeability. The algorithm is applied to data from three sets of horizontal parallel wells with spacing of roughly 700 ft. In two of the three well pairs considered, conductive fracture locations identified in one well aligned with corresponding features in the parallel well. An attraction of the proposed methodology is that it makes use of data that is commonly recorded during drilling, reducing the need for expensive image log tests. The information obtained from this type of analysis can be used to improve hydraulic fracture treatment designs.
Numerical Simulation of Enhanced Oil Recovery in the Middle Bakken and Upper Three Forks Tight Oil Reservoirs of the Williston Basin
Authors: Iwere F. O. , Heim Robin N. , Cherian B. V. 
Published: June 2012

Abstract
The United States Geologic Survey (USGS) reported in 2008 that undiscovered technically recoverable oil in the Bakken was about 3.6 billion barrels across the U.S. portion of the basin, considering recent successful application of horizontal wells and multistage hydraulic fracturing technologies. As the development of the unconventional resources in the Williston Basin continues beyond the phases of exploration and lease evaluation, optimum well spacing and recovery factor will become forefront considerations in the formulation of asset development strategies. Based on our studies the reservoir producing mechanism is primarily solution gas drive and primary oil recovery factor is lower than 15% of the original oil in-place. This low recovery or very high oil volume remaining in place is a strong motivation to investigate the application of enhanced oil recovery methods in this basin.
This paper describes the construction of numerical simulation models using typical fluid and rock properties for the Bakken and Three Forks, assuming both naturally fractured and single porosity systems and their combinations. Multistage hydraulic fracture properties are determined from well completion engineering and coupled with the flow models. The flow models are constrained by well operating practices implemented by operators across the basin during primary oil production. The results of pressure maintenance methods to arrest the rapid reservoir pressure decline due to large pressure drawdown necessary to produce oil and water, as well as gas (including carbon dioxide) and water injection methods to improve oil recovery are presented.
Quantification of Fracturing Fluid Migration due to Spontaneous Imbibition in Fractured Tight Formations
Authors: Dutta R. , Lee C.-H. , Odumabo S. , Ye P. , Walker S. C. , Karpyn Z. T. , Ayala L. F. 
Published: June 2012

Abstract
During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.
Improved Methodologies for More Accurate Shale Gas Assessments
Authors: Boulis Anastasios , Jayakumar Ramkumar , Lalehrokh Farshad , Lawal Hamed 
Published: June 2012

Abstract
Over the last few decades, shale gas has become an increasingly important global source of natural gas, especially in the United States. According to Polczer (2009) and Krauss (2009), shale gas will greatly expand worldwide and is expected to supply as much as half the natural gas production in North America by 2020. Due to extremely low shale matrix permeability, shale is considered an unconventional source of gas and requires fractures to provide a flow path to the wellbore. Due to uncertainties in quantifying the gas-in-place and identifying flow behavior; estimating the ultimate recoveries in shale gas reservoirs requires new techniques. In this paper, we used four approaches to estimate the ultimate recovery in shale gas wells: two empirical methods (conventional and modified decline curve analysis), analytical modeling and numerical modeling. All four approaches were applied on wells from four different shale plays (Barnett, Haynesville, Marcellus and Woodford).
Designing Completions in Horizontal Shale Gas Wells - Perforation Strategies
Authors: Wutherich Kevin D. , Walker Kirby J. 
Published: June 2012

Abstract
Horizontal cased hole completions have become the accepted practice for completing wells in many shale gas plays. There has been a great deal of focus on how to optimize these completions. One of the most important, yet least discussed, concepts in horizontal shale completion optimization strategies is how to perforate to optimize for both placement efficiency of the hydraulic fracture treatment as well as production.
Some of the perforation scheme characteristics that typically need consideration are as follows:The number of perforation clusters for each fracture stageThe optimum number of perforations per clusterThe distance between perforation clustersThe length of each perforated intervalShot density, phasing and perforation charge typeOptimal location to place the clusters
Taking into account all of these considerations and using an optimized perforation strategy can be the difference between placing a fracture as per design or experiencing high treatment pressures throughout the stimulation treatment and prematurely aborting the job part way through. Even more importantly, properly engineered perforations can improve overall production by ensuring an equal fracture treatment through each perforation cluster as well as improving wellbore connectivity to the fracture.
This paper looks at all these outlined aspects through a number of different means including a literature review, the use of simulation tools, and case studies from the Marcellus shale. Ultimately, a strategy for optimized perforations is presented with specific focus on shale gas horizontal wells in the Marcellus with further application to other shale gas plays.
Nanopore Structure Analysis and Permeability Predictions for a Tight Gas/Shale Reservoir Using Low-Pressure Adsorption and Mercury Intrusion Techniques
Authors: Clarkson C. R. , Wood J. M. , Burgis S. E. , Aquino S. D. , Freeman M. , Birss V. 
Published: June 2012

Abstract
The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize due to a wide pore size distribution, with a significant pore volume in the nanopore range. A variety of methods are typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range.
In this work, we investigate the use of non-destructive, low-pressure adsorption methods, in particular low pressure N2 adsorption analysis, to infer pore shape, and to determine pore size distributions of a tight gas/shale reservoir in Western Canada. Unlike previous studies, core plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure to be analyzed. Further, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which MICP and permeability measurements were previously made, allowing a more direct comparison with these techniques. Pore size distributions determined from two isotherm interpretation methods (BJH Theory and Density Functional Theory), are in reasonable agreement with MICP, for that portion of the pore size distribution sampled by both. The pore geometry is interpreted to be slit-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, SEM imaging and the character of measured permeability stress-dependence. Although correlations between inorganic composition and total organic carbon (TOC) and dominant pore throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore throat size and highest permeability, as estimated from MICP. The presence of stress-relief-induced microfractures, however, appears to affect lab-derived (pressure-decay and pulse-decay) estimates of permeability, even after application of confining pressure.
Based on the premise of slit-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, using dominant pore throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly over-predicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries.
Production Data Analysis in Unconventional Reservoirs with Rate-Normalized Pressure (RNP): Theory, Methodology, and Applications
Authors: Samandarli Orkhan , Valbuena Ernesto , Ehlig-Economides Christine 
Published: June 2012

Abstract
Unconventional reservoirs, shale gas and oil for instance, have proven to be an important contributor to hydrocarbon production in North America. Horizontal wells with multiple transverse fractures unlocked these unconventional resources by attaining profitable production rates and increasing gas reserves for future years. A critical challenge in these types of reservoirs is characterizing the stimulated reservoir volume (SRV), by estimating the effective productive volume created during stimulation and quantifying the permeability of the formation.
Recent approaches for rate and pressure data deconvolution have emphasized the benefits of using buildup responses acquired whenever the well is shut-in, often for operational reasons, to assess significant insights about heterogeneity and compartmentalization in conventional reservoirs. However, deconvolution performs poorly when the initial reservoir pressure is unknown and might generate ambiguous results when pressure data accuracy is questionable.
Regular measurements of daily production rates and wellhead flowing pressures can provide important information about well completion, stimulation, and formation parameters. With effective data processing, rate-normalized pressure (RNP) converts variable-rate and variable-pressure data to an equivalent of the drawdown pressure response to constant-rate production. This reveals flow regimes that enable direct estimation of the formation permeability and the productive fracture extent in the SRV. Subsequently, observed field rates and pressures can be matched with a global model to refine the estimates from the flow regime analysis. Although numerical models can be used to match the data, in this study we employed an analytical flow regime equations that provides fast and accurate results that can be easily programmed.
The proposed methodology was applied to production data from Barnett shale wells providing excellent results and demonstrating an efficient, fast, and cost effective method to estimate critical well and formation parameters in unconventional reservoirs. The same methodology can be used to diagnose wells from other unconventional resources.