bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lithological Controls on Mechanical Anisotropy in Shales to Predict In Situ Stress Magnitudes and Potential for Shearing of Laminations During Fracturing
Authors: Glover Ken , Bozarth Troy , Cui Albert , Wust Raphael 
Published: October 2015

Abstract
Accurate and repeatable assessments of in situ stress magnitudes and orientation in unconventional reservoirs can be complicated by the heterogeneous, inelastic, and/or anisotropic mechanical properties of these rocks and their complex history of burial and diagenesis. The associated vertical and lateral variation in pore pressure and stress through the target zones and bounding intervals can further complicate this effort. For these reasons, some additional factors need to be considered beyond the typical workflow of determining closure stress from standard mini-frac data and using this data to calibrate log derived stress profiles. We present some case study examples from hydrocarbon-producing shales where a more rigorous analysis of the mechanical properties of the shale has allowed a more accurate and repeatable assessment of in situ stress and potential for lamination shearing. Horizontal fracture growth through shear activation of bedding-parallel fabric can be a preferred fracture propagation mechanism in these shales and this behavior can be diagnosed by this improved workflow. In one case study example, in the tight gas Montney siltstone of Western Canada, shear strength anisotropy is shown to be very significant, with bedding parallel shear cohesion less than 10% of the bulk rock cohesion. For such situations it can be shown that shear fracturing of laminations is likely. It has been demonstrated through pressure transient analysis of minifrac injection and flowback data that this can be diagnosed. Many fracturing related mechanisms are also stress dependent and their understanding requires assessment of all in situ stress magnitudes, not just minimum horizontal stress. An improved method of analyzing these stress magnitudes and fracturing mechanisms is described through anisotropy measurements in core samples and a micro-mechanical understanding of the rock fabric. In this way, a petrophysical relationship can be established between anisotropy parameters and rock properties.
A Comprehensive Approach to Sweet-Spot Mapping for Hydraulic Fracturing and CO2 Huff-n-Puff Injection in Chattanooga Shale Formation
Authors: Vinassa M. , Cudjoe S. E. , Gomes Joao Henrique , Ghahfarokhi R. Barati 
Published: October 2015

Abstract
Devonian-Mississippian Chattanooga shale plays in North America are categorized as unconventional reserves with potential hydrocarbon resource accumulations. Unlike Chattanooga shale in the Appalachian region, less effort has been dedicated to its correspondent in the Ozark region. The ultra-tight nature of the formation causes fast decline of the production and small recovery factors. Application of EOR techniques such as CO2 flooding, among other techniques, can potentially improve the recovery of Chattanooga reservoirs. Characterization of these reservoirs is therefore an essential step to fully understand the associated complexities of the reservoir as well as to evaluate the economic viability of their exploitation. This paper therefore presents a fully integrated characterization at multiple scales including petrophysical, geophysical and geological evaluation, geomechanical and geochemical analysis of the black shale sequence in Sumner County, Kansas. Multi-scale dataset for this regional characterization is obtained from laboratory measured petrophysical parameters, well-log measurements as well as post-stack depth (PoSDM) seismic data.
Chattanooga shale in Sumner County has an average TOC of ~2.26 wt. % in the middle shale member with additional organic porosity of 5% and a vitrinite reflectance (Ro %) of 0.62. It is classified as a shale oil resource with OOIP of 4 MMbbl. Petrophysical correlations developed at wellbore vicinity were trained with artificial neural networks (ANNs) and correlated with seismic to provide lateral distribution of such properties farther from the wellbore. Moreover, due to the heavy reliance of unconventional shale plays on fracture network for improved flow conditions, fracture models were developed based on the mineral-brittleness as well as the fracture toughness. Consequently, a complete study based on compositional numerical simulation was conducted to analyze the potential of CO2 as an EOR technique, together with an evaluation of the impact of reservoir and fracture parameters in the well productivity potential. Subsequently, an economic optimization process was also formulated to obtain the best gas injection design for the highest Net Present Value (NPV). The cumulative oil was notably observed to increase by the use of the optimum injection design. Moreover, the huff-n-puff injection of CO2 proved to be a viable option by increasing the final oil recovery from 10% to 53% using optimal parameters.
Viking Stimulation: Case History
Authors: Fyten Glen C. , Taylor Robert S. , Price Darren 
Published: October 2015

Abstract
This paper presents case history results documenting the impact of changes to oil and water production in the Viking formation. This body of work applies in general to stimulation of the Viking as well and potentially other formations with high clay content. By understanding which variables have had the most impact on Viking production, it is possible to more effectively design future stimulation treatments. Some areas that previously lagged in production have now become the best producing Viking assets.
The areas studied were Red Water, Plato, and Dodsland. The wells studied were drilled horizontally using cemented casing. Hydrajet perforating was used for each fracture stage. The fracturing treatments were pumped through coiled tubing at a typical rate of 1.5 m3/min, or less using inflatable packers above and below the desired set of perforations to provide isolation. Typical fracturing treatments used 7 tonnes of 16/30 proppant and were placed using a borate crosslinked guar fluid system.
The primary design changes that have led to these improvements in production include the following: Control of clay fines migration, given that clay content in the Viking formation can exceed 50 vol%.Control of clay swelling.Prevention of paraffin precipitation caused by injected fracturing fluids having a temperature below the cloud point of the wax in the crude.Paraffin crystal structure modification to help mitigate production issues associated with any precipitated paraffin.Use of larger proppant sizes, higher proppant concentrations, and more aggressive proppant schedules.Optimization of fracture size and spacing. Because this has been the basis of much of the success in the Viking formation in recent years, a detailed discussion follows.
Production Trends From The Exploitation of Horizontal Completions in the Upper Cretaceous Formations of the Powder River Basin: A Look Back on Five Years of Development
Authors: Ruhle William , Orth Jon 
Published: October 2015

Abstract
The Powder River Basin in Wyoming has been exploited for the production of oil and gas for several decades. The development of horizontal drilling combined with large volume multi-stage hydraulic fracturing has initiated a new era of oil and gas production. More than 900 horizontal wells have been drilled in the Upper Cretaceous reservoirs of the Powder River Basin. Oil and gas producers often target more than one formation within any given acreage position. The focus of development has been in the Frontier Formation, the Turner sandy member, the Shannon and Sussex sandstone members of the Cody Shale, and the Parkman sandstone member of the Mesaverde Formation, along with the Niobrara Formation as an oil resource play.
This paper presents a historical review of the completion designs and production trends from horizontal wells completed in the Upper Cretaceous formations. With a focus on multistage completions, well performance indicators are used in conjunction with a spatial sampling algorithm to identify dominant production influences attributed to completion and stimulation design.
Using public records, a database was created, cataloging a completion metrics, including lateral pay length, fracture stage spacing, mass and type of fracture proppant, volume and type of fracturing fluid, and current production records. Correlations between fracture treatment design and hydrocarbon production are provided for each formation. Production type curves, initial production rates, and effective decline rates are presented for each formation. Geospatial trends in hydrocarbon properties, such as gas-oil ratio (GOR) and oil gravity are provided.
The catalog of data and correlations provides a useful reference for exploring or developing acreage within the basin.
Optimizing completion programs can be fast-tracked through the analysis of preceding completions and early time production indicators.
Insights into Surfactant Containing Fracturing Fluids Inducing Microcracks and Spontaneously Imbibing in Shale Rocks
Authors: Xu Liang , He Kai , Nguyen Christina 
Published: October 2015

Abstract
Surfactants are typically added into fracturing fluids to assist flowback and/or enhance oil and gas production from liquids-rich shale formations. Two primary benefits that can be overlooked are the potential capability of surfactants to initiate microcracks near primary fractures and spontaneous imbibition farther into the formation rocks. With the additional initiation of microcracks and access to hydrocarbon reserves, initial production can be enhanced and production declines, over time, can also be mitigated.
In this study, new mechanisms for surfactants to initiate microcracks and accelerate crack growth are proposed in which the speed of microcrack propagation could be controlled by the rate at which surfactant is advected to the crack tip by means of induced Marangoi flows (Vella et al. 2006). The accelerated crack growth is related to a decrease of the crack surface energy enabled in the presence of surfactant.
On the other hand, a new mechanism has been previously proposed for increasing the contact area between fracturing fluids and the matrix. The working hypothesis is that a surfactant, when properly tailored to treatment fluids, can spontaneously spread in the matrix and access additional hydrocarbon reserves.
The data indicate that fracturing designs could be further optimized by using a surfactant to activate more cracks. The shut-in time immediately after fracturing also could be crucial for enhanced well productivity. An extended shut-in time could result in the additional initiation of microcracks, farther penetration of fracturing fluids into the matrix, and greater oil recovery in liquids-rich shale plays.
Evaluating the Diagenetic Alteration and Structural Integrity of Volcanic Ash Beds within the Eagle Ford Shale
Authors: Calvin Christina , Diaz Helena Gamero , Mosse Laurent , Miller Camron , Fisher Kevin 
Published: October 2015

Abstract
Ash deposits are found interbedded within organic mudstones such as the Vaca Muerta, Niobrara and Eagle Ford shales. Alteration of ash deposits interbedded within mudstones and shales have presented challenges for completion and production including pinching of fractures and swelling upon contact with drilling and completion fluids. This paper will review the mineralogic and petrologic variations in altered ash beds found within the Eagle Ford and examine the impact these chemical and physical properties can have on completion. The paper will also present a methodology for detection of ash beds using high-resolution measurements. Understanding and detecting the mineralogic variation between the altered ash beds will enable better completion and minimize risk during production.
A Study of Mercury Intrusion on Montney Formation Rocks and How It Relates to Permeability
Authors: Salimifard B. , Ruth D. W. , Nassichuk B. 
Published: October 2015

Abstract
The Montney Formation, a tight unconventional reservoir in Western Canada, has been explored for the past two decades and over the last 10 years has moved towards being a primary exploration target. Qualitative and quantitative petrophysical analysis of the Montney Formation has always been a challenge to researchers. Reservoir characterization is generally hindered by lab-based methods for permeability estimation, proper estimation of the pore size distribution and development of correlations between the rock properties and hydraulic flow.
This report examines results from permeametry, mercury porosimetry, helium pycnometry and scanning electron microscopy (SEM) images performed on 53 samples of the Montney Formation to understand the complicated pore network structure of the rock and study the predictive power of a permeability prediction model.
Pulse-Decay permeability is measured on cores at effective reservoir pressure. Crushed samples are used to obtain mercury capillary pressure, pore size distribution curves, GRI and mercury porosity and matrix permeability. SEM images are used to study pore development and porosity as well as investigating the presence of microfractures. The permeabilities of these samples range from 10 nanodarcies to 0.1 milidarcies and porosities range from 2-10 percent. Due to high surface intrusions in the mercury porosimetry tests, extraction of pore size distributions and capillary pressure curves are problematic and cut-offs are applied based on the derivative of the capillary pressure curve to help understand the complicated pore network of the rock and correlate it with permeability.
This study shows that mercury porosimetry results can be used to categorize the rocks into subcategories for further analysis. Different methods correlating rock properties to permeability are examined. The results specifically indicate that pulse-decay permeability is influenced by over-burden pressure and the presence of microfractures and that the appropriate pore diameter shows consistent correlation with the derivative of the capillary pressure curve.
Miscible CO2 Simultaneous Water-And-Gas (CO2-SWAG) Injection in the Bakken Formation
Authors: Gong Yanbin , Gu Yongan 
Published: October 2015

Abstract
In this paper, miscible CO2 simultaneous water-and-gas (CO2-SWAG) injection in the tight Bakken formation was experimentally studied. The effective viscosities of high-salinity water and supercritical CO2 mixtures with twelve different water volume fractions were measured at the actual reservoir conditions by using a capillary viscometer. A total of six coreflood tests with four different miscible CO2-EOR schemes were conducted in the tight reservoir core plugs collected from the Bakken formation (Canada). It was found that the measured effective viscosity of the saline water-CO2 mixture was increased with the water volume fraction and can be reasonably modeled by using the Arrhenius equation. The coreflood test results indicated that the miscible CO2-SWAG injection with an injected water-gas ratio (WGR) of 1:3 in volume had the highest oil recovery factor (RF). The miscible CO2 water-alternating-gas (CO2-WAG) injection achieved a slightly higher oil RF than that of the miscible CO2 secondary flooding, whereas the miscible CO2 tertiary flooding after mature waterflooding had the lowest oil RF. In addition, the WGR showed strong effects on the fluid production trends of the miscible CO2-SWAG injection. A water bank might be formed ahead of the water-CO2 mixture in the miscible CO2-SWAG injection with a higher injected WGR of 1:1 or 3:1. Furthermore, the mobility ratio of the injected fluid(s) to light crude oil was calculated based on the measured steady-state flow rate and pressure gradient in each coreflood test. In comparison with water or CO2 alone, the water-CO2 mixture had a lower mobility in the tight reservoir core plugs. Hence, the highest oil RF of the optimum CO2-SWAG injection with the lowest injected WGR of 1:3 was attributed to a substantially weakened waterblocking effect and a well-controlled water-CO2 mobility.
Modeling the Kerogen 3D Molecular Structure
Authors: Zhang Zhenyu , Jamili Ahmad 
Published: October 2015

Abstract
During the past decade, there has been a surge in the production of shale oil and this trend is expected to continue in future due to the abundant shale oil reserve. Currently, one main issue with shale oil production is the low primary recovery factors still less than 10%. Therefore, efficient enhanced oil recovery methods are highly desired to improve shale oil recovery. As an essential component of shale, kerogen plays a key role in generation, adsorption, storage and migration of hydrocarbons in shale as well as the geomechanical properties of shale. On the other hand, during the shale oil extraction process, shale oil can be produced from kerogen by pyrolysis, hydrogenation, or thermal dissolution reactions. The basis to improve the efficiency of both recovery and extraction processes is to establish and clarify the molecular structure of kerogen. Previously, some 2D molecular structures of kerogen have been proposed based on some characterization techniques, such as nuclear magnetic resonance (NMR) and mass spectrospcoy. However, the physical and chemical properties of kerogen are essentially determined by its 3D stereochemical molecular configuration.
In this work, according to the 2D molecular structure of Green River oil shale kerogen from literature, a 3D solid state model of kerogen was built based on molecular dynamics(MD) simulation method. The kerogen of Green River oil shale is a mixture of seven molecules that are held together by physical adsorption mechanism. This kerogen belongs to type I based on O/C (0.026) and H/C (1.57) ratios. An adsorption method was applied to combine the seven molecules together. By changing the adsorption sequences of the seven molecules, a total of 24 possible 3D nanocluster models of kerogen were obtained. Then the 3D nanocluster structure with the lowest energy was further applied to build the solid state model of kerogen at 298k under 1 atm based on a MD simulation method. The final 3D solid state model of kerogen was used to calculate the density, mechanical properties, NMR, IR and Raman spectra of kerogen. The theoretical results agree well with the experimental data. The density from the 3D structure was calculated as 0.968 g/cm3 which falls in the range of experimental results from 0.95 to 1.45 g/cm3. The calculated Young's modulus, Poisson ratio, compressibility, bulk modulus and shear modulus are 3.50 GPa, 0.25, 370.64 TPa-1, 2.63 GPa and 1.37 GPa respectively that matches the experimental results very well. The calculated spectral data are also in accord with the experimental results. These results will help us better understand the physical and chemical properties of Green River oil shale kerogen. Moreover, the calculated properties of kerogen can be applied to implement new techniques or improve existing methods for enhancing oil recovery from shale oil resources.
A Comprehensive Approach to Rate-Time Production Analysis for Unconventional Resources
Authors: Cox S. A. , Lee J. , Sutton R. P. , Cox J. A. 
Published: October 2015

Abstract
Decline curve analysis in unconventional reservoirs is challenging due to the extremely low reservoir flow capacity coupled with the completion techniques and production practices used to achieve economic rates. The primary flow regimes for these wells include transient bilinear flow, transient linear flow, boundary-influenced flow and possibly long-term linear flow. It is commonly believed that the dominant flow regime in unconventional developments will be transient linear flow; however, boundary-influenced flow may be even more important. Classical decline curve analysis techniques are applicable only during the boundary-influenced flow period. Frequently, a hyperbolic form equation is utilized and this practice used by the industry over the entire life of the well results in excessively high decline exponents which can lead to optimistic forecasts of future performance. This technique can be improved for unconventional plays by imposing limits to the final decline. However, current methods to constrain the final decline are based on historical vertical well performance and rules of thumb which introduce a high degree of uncertainty. A number of these plays have now reached a level of maturity that will allow characterization of their long term decline performance. This paper presents a comprehensive technique to analyze production history using a flow regime based workflow to guide classic decline curve analysis. The technique identifies the onset of boundary-influenced flow and thus provides a consistent approach to evaluate late time decline characteristics which will improve the forecast results. In addition to providing guidance for decline curve analysis, the proposed workflow can also be used to evaluate completion efficiency by relating the time to boundary-influenced flow to the stimulated reservoir volume. The practical application of this this technique will be presented using field studies of active unconventional developments.
Managed Pressure Drilling Significantly Reduces Drilling Costs on Extremely Challenging UltraHT Wells in the Gulf of Thailand
Authors: Loux Fabrice , Bunyak Michael John , Kongpat Nitipong , Pattanapong Kamolchai , Eagark Pasuk , Rubianto Irwan , Gallo Fernando , Intravichit Jittipong , Charnvit Kerati , Prasetia Andi Eka , Houng N. H. 
Published: October 2015

Abstract
PTTEP in the Gulf of Thailand faced costly challenges while conventionally drilling several narrow operating window ultra high temperature (ultraHT) wells with formation temperature up to 220°C (428°F). In the ultraHT sections, the operator encountered serious ballooning issues that resulted in severe non-productive time (NPT) and difficulty reaching well total depth (TD). Additionally, formation pressure uncertainty in the steep pressure ramp region posed additional drilling challenges due to high risk of influxes.
PTTEP decided to utilize managed pressure drilling (MPD) to overcome the complex ultraHT wells. The strategy involved designing a hydrostatically underbalanced mud weight to prevent ballooning and to enable optimal drilling flowrates. The automated MPD was used to continuously maintain bottomhole pressure (BHP) above pore pressure to avoid influxes. Furthermore, the MPD system was also used to safely identify formation pressures by performing static flow checks (SFC). Dynamic formation integrity tests (DFIT) and dynamic leak-off tests (DLOT) conducted while drilling accurately identified the losses limit and ballooning gradient. At well TD, special rollover procedures were implemented to displace trip mud weight in order to safely control the well prior to pulling out of hole, taking into account extreme thermal effects on bottomhole pressure (BHP) reduction.
PTTEP was able to drill through the narrow operating window and avoid problems associated with typical ultraHT condition, including ballooning, loss and influx events. Moreover, MPD allowed the operator to drill efficiently while identifying the actual drilling window to establish wellbore pressure boundaries. Importantly, the operator was able to log the well to obtain the necessary geological data. As a result, the operator cut well costs by 50%, a total of USD 5 million, and saved 20 days of drilling time.
The paper will share the success story of MPD application in drilling challenging ultraHT wells in the Gulf of Thailand. The paper will describe the drilling solutions to solve the well problems and the lessons learnt as part of knowledge sharing.