bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantifying the Effect of Drilling Azimuth in Shale Gas Reservoirs
Authors: Wutherich Kevin , Xu Lili , Walker Kirby , Sawyer Walter , Reese Stephen , Aso Isaac 
Published: August 2013

Abstract
With the advent of horizontal drilling and fracturing low-permeability reservoirs to produce hydrocarbons, it has become common practice within most fields to drill wells in the direction of minimum horizontal stress in a normal stress region to maximize production and minimize drilling risk. The primary reason for this is that induced fractures tend to propagate along the plane containing the intermediate and maximum stresses (typically overburden and maximum horizontal stresses in a normally stressed region), which, under these conditions, is perpendicular to the horizontal wellbore. This allows for maximum extension away from the wellbore into the reservoir allowing for maximum reservoir contact by the induced fractures. This has been consistently demonstrated to provide the maximum coverage.
However, it is sometimes the case that wells are drilled at an azimuth that is not in line with the minimum stress. This might be due to such things as irregular lease boundaries or perhaps even variations in localized stress regimes that cause the stress direction to shift from the expected regional stress directions. These changes in a drilled well's azimuth with respect to minimum in-situ stress can have a significant effect on stimulation effectiveness and, eventually, the estimated ultimate recovery (EUR) of the wells.
A study of off-azimuth drilling addressed issues of how to determine minimum stress direction, the effect of such drilling on wellbore stability and the safe mud-weight window, how the completion design might be affected, and how to estimate the expected changes in productivity. Theoretical and empirical data were used to quantify these effects; data used included wireline logs, publicly available production data, microseismic data, and computer simulations, with a particular emphasis on the Marcellus shale.
What can we Learn from Existing Completions? : A Shale Gas Case Study
Authors: Jayakumar R. , Yalavarthi R. , Nyaabba C. , Rai R. 
Published: August 2013

Abstract
In recent years, a demand for clean burning fossil fuel and advancements in horizontal drilling has resulted in an increase in shale activity around the world. Due to extremely low shale matrix permeability, shale resources require successful hydraulic fracturing for the economic viability of a well. Operators have experimented with various completion methodologies to determine their potential, hoping to find the best completion practice for their shale play. A recent decline in natural gas prices have reduced the leverage needed for extensive experimentation. As a result, understanding the existing completion design has become critical.
In this paper, we compared multiple pairs of wells drilled in close proximity but have varying performance in each pair. The reservoir properties are based on the petrophysical analysis of the offset pilot well. As the wells in the pair share same petrophysical properties, the difference in performance should be related to changes in completion characteristics. This paper demonstrates workflow for determining completion characteristics by calibrating well performance to the fracture characteristics. A hydraulic fracture model incorporating rock geo-mechanical properties and actual fracture treatment data provides the estimate of hydraulic and propped fracture dimensions and properties. The results show how the changes in completion impact fracturing behavior can be correlated to observed well performance. The approach leverages current completion data weather successful or unsuccessful to build a knowledgebase which can guide us towards optimal future completion strategies sooner by reducing the amount of trial and error required.
A Systematic Study for Refracturing Modeling Under Different Scenarios in Shale Reservoirs
Authors: Jayakumar R. , Rai R. , Boulis A. , Araque-Martinez Aura 
Published: August 2013

Abstract
A key characteristic in unconventional reservoirs development is that they need massive hydraulic fracturing to create high permeability conduits to connect the reservoir to the wellbore and assure appropriate flow rates to make the development economical. In general, production performance for this type of reservoirs show an early high inflow followed by a steep decline. Refracture jobs have been a common practice to mitigate the flow rate decline and revitalize wells productivity.
In this paper, a wide range of possible refrac configurations are evaluated using synthetic models. Parameters such as fracture spacing, matrix permeability, fracture conductivity, fracture orientation and refrac locations were varied to study their impact on the success of the refrac job. Results showed significant impact on both the overall productivity, recovery and the economic value. The results show the impact of refracturing in higher permeability cases (greater than micro Darcy) is not as economical as in the low permeability scenarios (less than micro Darcy). Results also show a possible threshold in fracture spacing (60 – 80 ft between clusters) below which refracturing may not an economical completion strategy. In scenarios where the initial fracture conductivity is severely degraded, refrac can be an alternative to improve the net present value (NPV) and estimated ultimate recovery (EUR). Under the conditions of this study, fracture re-orientation cases show improvement in recovery factor (RF) but does not have a significant impact on the overall NPV. The timing of refrac has a large impact on both the NPV and recovery for the wells. In all cases, NPV was used to define optimal condition for each scenario evaluated.
All cases presented demonstrate potential impact of refracturing for a typical range of properties in shale reservoirs. The results shown in the paper could be used as a catalogue for better decision support to estimate the impact of refracturing in field cases under similar configurations to determine whether refrac will beneficial.
Evaluation of Quintuple Porosity in Shale Petroleum Reservoirs
Authors: Lopez Bruno , Aguilera Roberto 
Published: August 2013

Abstract
The use of a quintuple porosity system for calculation of original petroleum in place (OPIP) in shales is important as neglecting some of the porosities can result in pessimistic values of OPIP and production rates. Based on the concept of Total Petroleum System (Magoon and Beaumont, 1999) the word ‘Petroleum’ includes (1) thermal and biological hydrocarbon gas, (2) condensates, (3) crude oils and (4) natural bitumen. In the case of natural gas, the gas is trapped and stored in shale in different ways: (1) gas adsorbed in the kerogen material, (2) free gas trapped in nonorganic inter-particle (matrix) porosity, (3) free gas trapped in microfracture and slot porosity, (4) free gas stored in hydraulic fractures created during the stimulation of the shale reservoir, and (5) free gas trapped in a pore network developed within the organic matter or kerogen. An additional storage element is provided by gas dissolved in kerogen.
The governing equations that describe the gas mass balance in the quintuple porosity model are presented in detail. The series and parallel gas transport approaches discussed previously in the literature are shown to be special cases of the new general gas transport formulation developed in this study. The effects of permeability stress-dependency are taken into account. Real data from Devonian gas shales are used to illustrate the effect of free gas, adsorbed gas and dissolved gas in a material balance crossplot of P/Z vs. cumulative gas production.
Historically, the large contribution of organic porosity, natural fractures and hydraulic fractures that can contribute a significant amount of free petroleum in place has not been taken into account. And many of the laboratory experiments used for determining data utilized in computations of OPIP and production rates have been carried out in crushed samples, which by their very nature do not generally preserve natural fractures, slots and all the porosity present in the organic matter. This leads to pessimistic values of OPIP and rates. This helps to explain the larger than anticipated rates and recoveries of natural gas from some of these formations, for example Devonian shales, which have been producing for several decades.
Although the quintuple porosity characterization mentioned above indicates very heterogeneous systems, the production performance is less heterogeneous than that of carbonates, sandstones and naturally fractured tight reservoirs. This surprising result is demonstrated with the use of actual production data from various petroleum reservoirs around the world. The subject matter is significant because of the large volume of petroleum resources in shales throughout the world, which probably are underestimated because of not considering in a single model all types of porosity discussed in this study.
Geomechanical Reservoir Characterization with Microseismic Data
Authors: Tarrahi Mohammadali , Jafarpour Behnam , Ghassemi Ahmad 
Published: August 2013

Abstract
Bulk fluid injection into low permeability geologic formations been observed to trigger microearthquakes (MEQs). Triggering of MEQ events has been linked to pore pressure, temperature, and in-situ stress variations. The resulting clouds of micro-seismic events are believed to carry information about the underlying coupled flow, geomechanics, and thermal processes and, hence, rock hydraulic and mechanical properties. We develop a framework for integrating injection-induced microseismic events as monitoring data to infer reservoir property distributions. To model the reservoir stimulation and induced microseismicity, we use a fully coupled thermo-poroelastic model with coupled heat transport, fluid flow, and rock deformation capabilities as forward model and apply the ensemble Kalman filter (EnKF) data assimilation algorithm invert MEQ measurements. Because discrete MEQ events are not amenable to continuous estimation methods, we first use a kernel density estimation (KDE) method to convert the observed cloud of MEQ events into a continuous seismicity density map. We then apply a variant of the EnKF to integrate the resulting continuous seismicity density map to estimate, individually and jointly, heterogeneous hydraulic and geomechanical rock property distributions such as permeability, Young's modulus, tensile strength and Cohesion. We apply a spectral projection approach to decorrelate the spatially correlated observation of MEQ for improved EnKF implementation. We use numerical experiments to evaluate the performance of the developed methods.
Effect of Low-Concentration HCl on the Mineralogical, Mechanical, and Physical Properties of Shale Rocks
Authors: Morsy Samiha , Hetherington C. J. , Sheng J. J. 
Published: August 2013

Abstract
Oil and gas-bearing shale formations have received a great deal of interest in recent years, especially in North America. Oil and gas from shale could make a significant contribution to global hydrocarbon production. However, their development has been hindered by the complexity of drilling and completion strategies, which must be adapted in response to shale's mineralogy and physical properties. Matrix acidizing is commonly used as a pre-flush to the hydraulic fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In some plays it is used as the main stimulation technique (e.g. Monterey shale, California). In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations were evaluated, and the effects on their physical properties are described. Samples of Eagle Ford, Mancos, Barnett and Marcellus shale formations were exposed to different concentrations of HCl (1-3 wt%). Based on experimental observations, mass loss, and X-ray diffraction studies, the samples lost as much as 16 wt. % calcite when treated with 3 wt% of HCl for three hours. Post-reaction measurements show increases in porosity in all experiments, which was attributed to calcite dissolution in Eagle Ford samples and to crack development in Mancos, Barnett, and Marcellus samples. Eagle Ford samples showed the greatest reduction in Young's Modulus ranging from 25-82% when exposed to 1-3 wt% HCl solutions and 75% when exposed to 5 wt% NaCl saline solution at 200°F.
Generalized Inflow Performance Relationship (IPR) for Horizontal Wells
Authors: Mohammadnia Mohammadreza , Akbari Babak , Shahri Mojtaba P. , Shi Zhaorui , Zhang Holden 
Published: August 2013

Abstract
The horizontal well technology can solve different problems of production from tight formations where conventional technology fails. The aim of this study is to develop a generalized IPR for an oil reservoir in which a well is drilled horizontally. A reservoir simulator is used to simulate the production through this well to construct the IPR curves. A simulation matrix is designed by changing well geometry, well position and rock properties. The IPR data obtained from the numerical simulations are fitted to a Vogel-type relationship and the values of the coefficient, b, are calculated corresponding to different conditions. Consequently, a statistical analysis method is used to determine which factors in the simulation matrix have a significant effect on the value of b. The results show that the only significant factor is the vertical to horizontal permeability ratio of the reservoir. Using the Vogel-type IPR and the correlation for b obtained from statistical analysis in terms of the vertical to horizontal permeability ratio, an IPR suitable for horizontal well productivity is developed taking into account the reservoir and well parameters. In this relationship, the factor b is a function of the vertical to horizontal permeability ratio. The new model is tested against random simulations that are not included in the original simulation matrix for the model development, and better agreement is observed compared to the predictions of previous IPR's available in the literature.
Coupling Mechanical Changes of a Fracture to Hydraulic Changes
Authors: Crandall Dustin , Gill Magdalena , McIntyre Dustin L , Bromhal Grant S 
Published: August 2013

Abstract
Flow within fractured shale is a topic of interest for both production from non-traditional fractured shale reservoirs and for estimating the leakage potential through sealing formations above geologic carbon dioxide repositories. The hydraulic aperture of a fracture describes how much fluid can be transported though a fracture; this is similar to permeability through porous media. The advantage of determining a hydraulic aperture as opposed to fracture permeability is that this fracture fluid transport property can be scaled up to discrete fracture reservoir simulators, such as NFFLOW. Unfortunately, many parameters can affect the hydraulic aperture of an individual fracture, including the roughness of the fracture surfaces, the average mechanical aperture of the fracture, and the tortuosity of the flow path within the fracture volume. For this study, we examine the relationship between the mechanical aperture of individual fractures and the hydraulic aperture of that fracture.
Within the computed tomography/core flow facility at the National Energy Technology Laboratory we have examined changes in hydraulic aperture of individual fractures with changes in the confining stresses that externally act upon the fractured samples. Tests were conducted with locally sourced shaly limestone from a depth of approximately 200 ft. Initial and numerical results show that the volume change in the fracture is a non-linear function of the confining pressure, and that this mechanical change reduces the individual fracture permeability rapidly as the fracture is first compressed.
Optimizing Surfactant Additives for Low-Permeability Wet Gas Formations: A Laboratory Approach for Correlating Capillary Pressure and Emulsion Tendency with Surfactant Performance
Authors: Xu Liang 
Published: August 2013

Abstract
For low-permeability gas reservoirs, surfactants are typically added into fracturing cocktails to lower the capillary pressure in the pore spaces to enable a faster return of fracturing water to the surface, thereby providing additional surface area for gas flow. Capillary pressure inside pore spaces, however, is not straightforward to predict or correlated to the performance of the surfactant that is to be used during fracturing. In this paper, a laboratory approach is presented for comparing surfactant performance by using the Washburn method for surfactant imbibition in crushed core particles from various unconventional formations, such as the Marcellus formation. Through analysis of the initial slopes of the imbibition curves over time at different salinities, it is possible to predict which surfactant would more effectively lower capillary pressure. In addition, gas production is often accompanied by condensate, which can accumulate in the near-wellbore (NWB) region, causing poor inflow performance. To overcome this issue, a transient or short-lived condensate-in-water emulsion is likely required to mobilize condensate more efficiently. Performing emulsion tendency analysis assisted with visual inspection demonstrated that weakly emulsifying surfactants are likely a better choice than typical field standard non-emulsifying surfactants.
Production data from the Barnett formation are presented to validate the performance of the surfactant selected from imbibition and emulsion tendency analysis.
Modeling Guidelines for Analyzing and Forecasting Shale Well Performance
Authors: Kanfar M. S. , Alkouh A. B. , Wattenbarger R. A. 
Published: August 2013

Abstract
There are many mathematical models for production data analysis of shale wells. Certain models assume a set of parallel hydraulic fractures perpendicular to a horizontal well. Some of these models include natural fractures perpendicular to the hydraulic fractures. In these models, there is uncertainty in whether transient linear flow is dominated by fractures or matrix. Identification of the medium in transient flow usually requires assuming fracture properties. In this paper, we introduce an identification method which does not require explicit knowledge of fracture properties. This work also helps forecast wells which have not reached boundary dominated flow decline.
The paper focuses on four fracture distribution models that could describe shale wells. We introduce the identification procedure to determine the true fracture distribution model for a region. Once the model is identified, it is possible to determine whether linear flow is dominated by matrix or fractures. Identification of the true model can also improve forecast accuracy. The model identification procedure is based on the assumption that rock and fluid properties are similar within the region of interest.
Shale wells often exhibit long transient linear flow. Forecast projection is uncertain because the end of linear flow cannot be calculated without knowledge of fracture properties. The model identification procedure presented here enables more accurate production forecast and analysis. In addition, model identification might help optimize fracture design for future wells. This work reduces uncertainty and eliminates inapplicable models.
New Technology Enables Rigs With Limited Pump Pressure Capacity to Utilize the Latest Friction Reduction Technology
Authors: Burnett Timm , Gee Ryan , Martinez Jose , Carson Christopher , Canuel Léo 
Published: August 2013

Abstract
This paper presents a case study of the successful use of existing friction reduction technology coupled with advanced tool designs to allow optimization of the friction reduction system for the application.
Friction reduction in vertical, directional and horizontal wells can be critical to enable the transfer of weight to the drill bit. Excessive friction can limit the driller's ability to maintain tool face and to get weight to the bit, thus limiting the depth and accuracy of the well. There are various tools currently on the market that help mitigate friction in different ways; the most commonly used tool is the Drilling Agitator System (DAS).
A limitation for these tools in some cases is the amount of pressure drop these tools create, which increases the stand pipe pressure while drilling. This can be a limitation for contractors and operators who are already reaching the limits of their pump pressure capacity with their current drilling BHAs. This limitation prevents a segment of the drilling market from the ability to use these friction reduction tools. Additionally, as the need to drill farther horizontally to retrieve natural resources increases, the need for a low pressure friction reduction tool that can effectively break friction while adding a smaller amount of pressure to the drilling system is more desireable.
This paper focuses on the development of an advanced tool design capable of reducing the amount of pressure added to the stand pipe by the Drilling Agitator System (DAS). A discussion of the design of the tools, case histories and field trial results will be presented.
Key Parameters Affecting Successful Hydraulic Fracture Design and Optimized Production in Unconventional Wells
Authors: Meyer Bruce R. , Bazan Lucas W. , Brown Eric K. , Brinzer Bill C. 
Published: August 2013

Abstract
Multi-stage/multi-cluster hydraulic fracturing in horizontal wellbores is a key technology driving the development of unconventional resources in North America. It has been observed that complex fracture behavior can result from hydraulic fracture stimulation in these unconventional horizontal wells. Given the rapid pace of development, many operators strive to standardize their completion program to drive consistency, and efficiency, in operations and well performance. Unfortunately, the hydraulic fracture treatments may not be properly designed to maximize well deliverability, but instead focus on maximizing contacted reservoir volume (CRV). Generating fracture complexity is important in unconventional reservoirs, but maximum reservoir contact does not necessarily translate to an effectively stimulated reservoir with conductive fracture paths back to the wellbore.
Hydraulic fracture modeling in resource plays is challenging and often reduced to rules of thumb and design concepts taken from other shale plays. Key parameters that should be considered to maximize production in unconventional reservoirs are not dissimilar to the key parameters proven successful time and again in conventional completion designs and fracturing treatments.
The need for improved proppant pack permeability and fracture conductivity in unconventional wells has been well documented. However, there are additional completion and design considerations for unconventional wells such as natural fracture saturation, mid-field fracture complexity (MFFC), mechanical fracture interaction and transverse fracture production interference.
This paper summarizes a number of important considerations and key parameters that are necessary to design successful hydraulic fracture treatments and enhance productivity in unconventional wells. Application and considerations of these parameters will help provide the operator with a systematic, engineering based design method for optimizing multistage/multi-cluster hydraulic fracture treatments in horizontal wellbores.