bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigating Aperture-Based Stress-Dependent Permeability and Capillary Pressure in Rock Fractures
Authors: Huo Da , Li Boxiao , Benson Sally M. 
Published: October 2014

Abstract
Understanding multi-phase fluid flow behavior in fractured porous media is crucial for developing fractured hydrocarbon reservoirs, implementing hydraulic fracturing, and predicting potential leakage in gas and CO2 storage. The goal of this research is to investigate stress-dependent permeability and capillary pressure in rock fractures. Laboratory measurements of fracture aperture distributions have been made using CT scanning under various conditions of effective stress. By applying the stress-dependent aperture data, numerical simulation is employed to model the change of permeability and capillary pressure in the rock fracture as a function of the effective stress.
The stress-dependent aperture distribution data demonstrates that increasing stress results in two effects: (1); the mean aperture will decrease; (2); the variance of aperture distribution will increase. Experimental results show that permeability will drop by 73% when effective stress increases from 0.34MPa to 22.06MPa. As the variance of aperture distribution increases with stress, the plateau area of the capillary pressure curve tends to grow steeper, indicating that capillary behavior changes from more fracture-like to more porous media-like. The impacts of mean and variance of aperture distributions on permeability and capillary pressure are separately analyzed. The mean aperture decrease will reduce permeability and increase entry pressure. The variance increase will reduce permeability, the pore size distribution index and entry pressure. By analyzing the stress-dependent mean and variance of aperture distributions, this paper provides a more straightforward way for estimating stress-dependent permeability and capillary pressure in rock fractures.
Eco-Friendly Biodegradable Materials For Diversion And Zonal Isolation Of Multiple Stage Horizontal Well Completions: Case Histories From Marcellus Shale Hydraulic Fracturing
Authors: Arnold David , Fragachan Francisco 
Published: October 2014

Abstract
The use of mechanical diverters in the oil and gas industry has been a common practice for decades, typically deploying perf ball sealers, degradeable balls, rock salt, dissolvable flakes, and incorporating downhole equipment such as sliding sleeves or straddle-packer systems. With multiple stage operations and horizontal wells becoming the industry norm, there is a need for a more permanent and reliable technology that is easily deployable and will seal previously stimulated perforations and zones from untreated perforations. This paper describes case histories from horizontal Marcellus Shale wells treated with degradable diversion materials applicable at a broad bottom-hole temperature range, maintains integrity under treating pressures and remains in place for the entire duration of well completion operations.
There are a number of scenarios for which biodegradable materials are applicable: zonal isolation for horizontal wells with multiple perforation clusters, vertical wells treated through tubing where bridge plugs cannot be used, sealing off perforations for re-stimulation treatments as opposed to squeezing the perfs, and sealing off perforations after treating through coiled-tubing.
The results from the wells treated at the Marcellus Shale showed compelling evidence that temporary mechanical bridging agents can effectively replace bridge plugs and maintain zonal isolation. The concentrations of the diverter system used were optimized during the treatments and achieved typical pressure increases of 300–1,200 psi per stage and complete seal-off pressures of 3,600–4,000 psi. The information presented in this paper will show the capabilities of using this material and the potential applications for multiple stage stimulation treatments. The pressure responses from the treatments show the ability of the materials to remain in place throughout the treatment of the well, and the details of the successful treatment execution and production results will be presented. The production results of the candidate wells also showed production rates higher than neighboring wells and wells typical for that area.
Going Long – Overcoming Challenges in Completing 3600m Laterals
Authors: Liston R. , Lynn C. , Shell B. Layton , Fraser E. 
Published: October 2014

Abstract
Recent trends in unconventional oil and gas developments have seen longer horizontal wells drilled to achieve greater reservoir contact while minimizing cost and surface impact. Challenges for completing longer laterals include achieving effective fracture stimulation and performing clean out of the well bore after stimulation is complete. A case study was performed in Shell Groundbirch, an unconventional gas development in British Colombia, Canada, focusing on stimulation and extended reach cleanouts. Five long lateral wells +3600m lateral length with measured depth to true vertical depth ratio of 2.5, were drilled and completed; the resulting wells are 60% longer than the standard development well. Based on operational efficiency, coiled tubing (CT) was determined to be the preferred method for performing the millouts and well cleanup. 73.0 mm CT with an aggressive taper can reach the required set-down depths with enough weight on bit available to mill-out all completion plugs. Operational plans and milling tools were developed to maximize the probability of success. This paper outlines the technical details which contribute to an important case study that can help define and push the limits of extended reach CT interventions in industry.
The Condition of Capillary Condensation and Its Effects on Gas-In-Place of Unconventional Gas Condensate Reservoirs
Authors: Li B. , Mezzatesta A. , Thern H. , Zhang B. , Wu J. , Zhang H. 
Published: October 2014

Abstract
In shale gas reservoirs, the adsorption of gas can be multi-layer adsorption because of the presence of small pores and heavy hydrocarbon components in the kerogen portion of the source rock. Particularly, in unconventional gas condensate reservoirs, the gas can become condensate, filling the pores at pressures different from the dew-point pressure of the bulk fluid. The commonly used Langmuir isotherm does not provide a valid model for capillary condensation because it is based on the assumption that the adsorption mechanism is a monolayer adsorption.
To solve this problem, we developed a method to compute the adsorption isotherms of capillary condensation for multi-component hydrocarbons, based on the general Kelvin equation. However, this method was limited to pressures below the lower dew-point pressure, due to the assumption of incompressible liquid and closeness to the dew-point pressure of the bulk fluid.
In this work we extended the adsorption and gas in place models for capillary condensation to the high pressure range. Based on fundamental thermodynamic principles, we developed an iterative method to determine the dew point shift caused by pore confinement. This method is applied to determine the phase of the confined hydrocarbons, as well as to compute the hydrocarbons in place at the initial reservoir condition. Furthermore, we analyzed the properties of the confined fluid and checked the capillary condensation effects on the gas in place caused by fluid composition, pore size distribution, temperature, and pressure. This methodology is also applied to the Eagle Ford shale formation. The analysis results show that the gas in place can be underestimated with the conventional model by more than 10% if the initial pressure is lower than the shifted dew-point pressure.
Borehole Flow Monitoring using a Non-intrusive Passive Distributed Acoustic Sensing (DAS)
Authors: Finfer D. C. , Mahue V. , Shatalin S. V. , Parker T. R. , Farhadiroushan M. 
Published: October 2014

Abstract
Historically in-well flow measurement has been challenged by downhole power requirements and post-installation inflexibility. Distributed acoustic sensing makes it possible to monitor the acoustic field along the entire length of a standard fiber optic cable, and therefore facilitate flow monitoring without any downhole electric power requirements. Further, the distributed nature of such systems enables post-installation adaptability as the production profile evolves. Partly as a result of this flexibility, distributed acoustic sensors have now started to gain momentum as a recognized solution for in-well flow surveillance.
In this paper, Silixa will present recent development work showing how distributed technology can enable high accuracy flow monitoring. Emerging results will be used to show how array processing of flow noise can be used to develop production data. Examples from the laboratory will be used to demonstrate these advanced techniques. It will be seen that advanced signal processing can be combined with knowledge concerning the physics of fluid-acoustic interactions to make determinations concerning the flow within a well. Finally, it will be shown that there exists strong promise for this upstream technology in a broad variety of well-types.
Enhanced Vapour Extraction (VAPEX) of Heavy Oils through Foamy Oil Flow and Viscous Fingering
Authors: Jia Xinfeng , Gu Yongan 
Published: October 2014

Abstract
Solvent vapour extraction (VAPEX) has shown great potential to recover heavy oil reserves. However, the application of the VAPEX technique is limited by its low oil production rate, which is caused by the slow mass transfer and inefficient gravity drainage. Hence, increasing the heavy oil–solvent mixing process and introducing more production mechanisms are imperative to enhance the performance of VAPEX. This paper proposes a new process, namely enhanced VAPEX, in which the solvent-chamber pressure is dynamically operated rather than constantly maintained throughout the production process. During the enhanced VAPEX process, pressure in the solvent chamber is cyclically depleted to induced foamy oil flow, which not only adds oil production but also increases contact area. In addition, a high-pressure non-condensable gas is applied to induce fingering phenomenon, which enlarges the heavy oil–solvent contact area. The enhanced VAPEX process is experimentally evaluated in this study. It is found that gas fingers can penetrate deep into the oil zone. In addition, foamy oil flow not only increases oil production but also improves mass transfer. Experimental results show that the oil production rate of the conventional VAPEX process was increased by 182% by the enhanced VAPEX process.
The Value Added of Five Years SPE-PRMS
Authors: Kreft Eric , Godderij Raymond , Scheffers Berend 
Published: October 2014

Abstract
The SPE-PRMS reserves reporting system has been adopted by EBN since 2009. As of that date a new PRMS project database has been developed. It currently contains more than 1000 hydrocarbon projects in the prospective, contingent and reserves categories. The annual (176 million BOE) and historic production (7.5 billion mln BOE) of over 250 oil and gas fields is stored on a monthly basis.
Apart from annual reserves reporting, the database is used for tracking and estimating hydrocarbon project maturation in the Netherlands. Each project contains a production forecast, and a prognosis of its maturation from resource to reserves in production, inclusive probability of maturation (POM) and probability of success (POS). Project attributes give insight in historic and future development of hydrocarbon plays and themes, such as Dutch tight gas and offshore infill drilling potential.
The implementation of the PRMS has significantly contributed to the understanding of the hydrocarbon maturation process in the Netherlands. It has proven a valuable system for hydrocarbon maturation analysis and reporting. It provides insight in the current and future activities of the Dutch E&P Industry. It offers the opportunity to steer on a national level to optimize future hydrocarbon production. It is highly appreciated by both technical staff and managers. The value of applying PRMS with project attributes is demonstrated by various examples.
MPD Techniques Optimize HPHT Well Control
Authors: Elmore Robert J. , Medley George H. , Goodwin Robert C. 
Published: October 2014

Abstract
The subject High Pressure High Temperature (HPHT) well proved extremely challenging with reservoir BHT of 334°F and approximate 13, 900 psi reservoir pressure. Managed Pressure Drilling (MPD) was originally selected to avoid a classic "Kick-Loss-Kick" scenario while drilling deep Austin Chalk formation wells in East Texas. While a secondary goal of MPD ("to ascertain the downhole pressure environment limits") was accomplished, the greatest benefit of MPD was seen while handling several well control incidents that occurred in the HPHT reservoir section. Optimal control of these incidents was facilitated by modification to the MPD technique and reconfiguration of the BOPE to allow for more appropriate application of the MPD equipment.
During drilling, a combination of high temperature and fluid properties (drilling fluid and reservoir fluid) resulted in repeated failures of the annular preventer and at least one variable bore ram (VBR) element failure at low pressure relative to the equipment rating. Ultimate integration of BOPE and MPD equipment allowed drilling with MW at or near balance to reservoir pressure.
Following and during trips, allowance had to be made for mud property changes caused by heating or cooling effects at both the surface and downhole. The mud property changes affected Equivalent Circulating Density (ECD) while drilling and tripping. Mud monitoring proved critical.
As HPHT and drilling technology mature, the line between flow control and well control begins to blur. Rather than transitioning from one to the other and back, the drilling and well control activities tend to become parts of a single process. This process, as described in the paper, must take into account the effect of variations in drilling fluid properties. Knowledge of the exposure limitations to pressure, temperature and other parameters and the effects on composition of pressure sealing elements in all surface and downhole tools is critical. The operator must also account for the effect of HPHT on specialty equipment such as RCDs, extra choke manifolds or manifold elements, and additional monitors. Adjustments in utilization and acquisition of slow pump rate information, use of the entire active pit system while circulating out kicks, and handling uncertainties in the downhole pressure regime are also part of this process. How alternative casing design affects well control while circulating a kick (influx) and using other unconventional drilling techniques will also be described.
Extending Lateral Length Using Casing Floatation to Reduce Field Development Cost in Shale Gas Plays
Authors: Blake R. 
Published: October 2014

Abstract
Operating in a low margin gas environment, operators look for new ways to reduce costs and efficiently develop reserves. Shell Canada Limited ("Shell"), operating in the Montney shale gas field located in NE British Columbia, Canada, used casing floatation techniques to extend lateral lengths. Increasing lateral length reduces well cost per lateral meter. This is because drilling the reservoir section is the least expensive segment due to high penetration rates. Extended lateral lengths also create new options for more economical and sustainable field development as fewer wells are required to cover acreage and it reduces dead space.
Shell uses a mono-bore casing design with average lateral lengths of 1800m at a TVD of 2300m. The goal of the project was to double lateral length to 3600m. At these depths, extending much beyond the current design is not possible due to theoretical casing lock-up from excess drag during conventional casing running. Casing floatation was chosen to extend the lateral reach of the wells and mitigate casing lock up because it is a cost effective, simple technology. Casing rotation and setting a deep intermediate string to reduce drag were also evaluated but deemed too cost prohibitive or technically unfeasible.
This paper documents the process and successful results of Shell's undertaking in doubling lateral length using casing floatation technology on five test wells in the area. It also provides detailed evaluation of post-run data to calibrate casing running models and the future impact of these results on an economical field development.
Practices Maintain Straight Hole in Crooked Hole Conditions, While Also Enabling Significant Gains in Drill Rate
Authors: Knudsen Steven D. , Dupriest Fred , Zemach Ezra , Blankenship Douglas A. 
Published: October 2014

Abstract
Bottom hole assembly (BHA) designs were assessed in field trials for their ability to achieve critical low inclination requirements, while simultaneously enabling high drill rates. Because angle has historically been controlled by reducing weight on bit (WOB), these are often competing priorities. The use of real time surveillance of mechanical specific energy (MSE) provided unique insights into the bit dysfunction that occurs with many practices used to control angle. These quantitative insights supported the development of BHA and operating practices that maintained low angle while also achieving major gains in drilling performance.
The McGinness Hills field in Lander County Nevada is a geothermal operation with wells drilled in hard metamorphic and crystalline formations. Wellbore inclinations must be maintained below 2.0 degrees in the critical 20 inch interval in order to allow use of lineshaft pumps, which is challenging in the required hole sizes and rock hardness. Formation strengths are similar to petroleum operations in the Rockies and West Texas.
Pendulum and packed-hole assemblies were tested, and straight motors and slick assemblies were used for corrections. Well build rates were assumed to be controlled by the three-point curvature in the lower assembly and stabilizer placement was modified to control this curvature. The effectiveness of the curvature control as WOB was increased was evaluated from inclination measurements. Real time MSE analysis was used to manage bit operating performance and to determine the root causes of bit dysfunction.
The results demonstrated that packed-hole assemblies could be designed that controlled inclination while enabling 2-3 times higher WOB, and that the use of pendulum assemblies should be eliminated. Packed assemblies drilled 87% faster. The increased WOB resulted in higher drill rates, major reduction in whirl and extended bit life, which are equally important performance objectives in hard rock drilling. The use of MSE surveillance allowed the physical processes to be understood deterministically, so that the philosophical design principles can be applied in other petroleum and geothermal operations.
Developing an Innovative Nano-Coated, Smart Material to Optimize Efficiency of Oilfield Completion Applications
Authors: Carrejo N. , Espinoza O. R. , Wibowo H. , Gaudette S. L. 
Published: October 2014

Abstract
As the oil and gas industry moves to more unconventional completions and drilling of ultra-deep, high-pressure wells, emerging technologies will be required to increase reliability while maximizing performance and minimizing operational costs. The development of a high-strength disintegrating metallic (HSDM) is one such technology, as it incorporates high ultimate compressive strength (UCS) and an engineered disintegrating mechanism tailored per application. The high-strength rating of HSDM pushed the development of disintegrating gas lift valves (GLV) and frac balls capable holding 15 ksi frac pressures. The ability for the new composite metallic to disintegrate in common wellbore fluids provided flow assurance by eliminating production risks provided by common frac balls. These applications proved the reliability of the material with hundreds of GLVs and thousands of frac balls utilized in wells around the world. This smart material has since been incorporated into ball seats and high-impacting telescoping ports (HITP) to increase the efficiency of delivery systems in hydraulic fracturing or acid stimulation treatments. The disintegration mechanism of the HSDM allows the ball seat to completely dissolve, eliminating the need to run a mill-out operation to increase the flow area of the production string. The HSDM is highly compatible with oil-based mud systems allowing this smart material to be incorporated within drilling liners or extended-reach production strings while operating as a fluid loss barrier. This application enables the operator to ensure proper fluid placement, while having the option to displace to brine systems or acid to remove the HSDM barriers to provide formation access. This paper will outline the development of this innovative smart material and discuss the inclusion and functionality of HSDM within the described applications.
Microfluidic Platform for PVT Measurements
Authors: Molla Shahnawaz , Mostowfi Farshid 
Published: October 2014

Abstract
In this work, we present a small-scale pressure/volume/temperature (PVT) cell which allows for the measurement of saturation pressure and phase-volume ratio using only a few microliters of reservoir fluid sample. This novel PVT measurement technique has been successfully tested on a wide spectrum of live reservoir fluids at elevated pressure (86 MPa) and temperature (150°C).
In the microfluidic PVT platform, the small microfluidic device performs the same function as the laboratory-scale pressurized visual PVT system. At the heart of the microfluidic device is a long and narrow capillary, densely packed in a serpentine shape, embedded on the device. The capillary is nearly 1-m long and has a total volume of 5 μl. The microfluidic device is fabricated using glass and silicon which allows visual monitoring of a fluid sample at various pressures and temperatures. To acquire PVT data, the pressure in the capillary is systematically reduced to accurately detect the appearance of micron-size gas bubbles in a sample at saturation pressure. Due to the small thermal mass of the device, the temperature of the sample can be changed rapidly, which enables the measurement of multiple saturation pressures in quick succession. Below the saturation pressure, the growing gas bubbles form a segmented gas-liquid distribution in the capillary. The lengths of the liquid and gas segments are measured in real-time using an automated image capturing and analysis tool to determine the gas-liquid phase-volume ratio at a given pressure.
Validation tests have proven this technique to be repeatable and feasible for rapid PVT measurements of black oils. The results presented in this study demonstrate that the microfluidic PVT system performs at the same level as the conventional PVT with significantly smaller sample volume and faster turnaround. The microfluidic PVT system is demonstrated to have the potential to become a reliable and portable measurement platform.