bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Phase Well Control Analysis During Managed Pressure Drilling Operations
Authors: Ma Z. , Vajargah A. Karimi , Ambrus A. , Ashok P. , Chen D. , van Oort E. , May R. , Macpherson J. D. , Becker G. , Curry D. A. 
Published: September 2016

Abstract
The shift towards drilling more complex and challenging wells is continuing in the oil & gas industry. Designing such complex wells with narrow error margins requires advanced well planning tools that account for transient phenomena such as the influx of gas during drilling operations. However, most of the available drilling hydraulics software packages currently do not account for advanced well control modeling options when deploying new drilling techniques such as Managed Pressure Drilling (MPD).
In this paper, we present a novel multi-phase modeling tool that can be deployed in combination with suitable hydraulic models for MPD well control. Its underlying model preserves the transient multi-phase flow behavior of liquid and gas in the well without overly complicating calculation requirements. It is based on coupled conservation equations of mass, momentum, and energy in association with appropriate closure relationships. Several numerical schemes have been utilized to optimize the accuracy and computational efficiency of the software. Furthermore, a user-friendly graphical user interface has been developed for ease of building the simulation cases.
The proposed approach can handle many complexities which occur during a MPD well control incident such as handling multiple influxes from one or several formations, dynamic well control, automated choke control, sudden pump start-up/shut-down, non-Newtonian drilling fluids, arbitrary wellbore path (including directional and horizontal wells), area discontinuity, etc. In addition, this tool can be used to develop and can be used in conjunction with advanced choke control algorithms for MPD. The validity of the software was verified against experimental data from a test well in which a gas kick was induced in a non-Newtonian drilling fluid. The kick was circulated out using the dynamic well control method, which is usually applied during the constant bottom-hole pressure technique of MPD. Parameters such as casing pressure, flow rate in / out of the well, and pit gain were recorded and compared to the simulation results. Excellent agreement was observed between the experimental and simulation results justifying the application of this tool to real-world drilling scenarios.
It will be shown that the new tool can accurately estimate parameters such as maximum casing pressure, annular pressure profile, kick tolerance, flow out, pit gain, gas rising velocity, etc. during MPD operations. Applying advanced numerical schemes makes this tool fast, robust, and efficient. As such, it has the potential to improve well control in general and during MPD operations, thereby enhancing rig safety and reducing non-productive time associated with well control-related trouble events.
Impact of Hydraulic Fracturing Fluid Damage on Shale Gas Well Production Performance
Authors: Eveline Vena F. , Akkutlu I. Yucel , Moridis George J. 
Published: September 2016

Abstract
Much work has been done to accurately simulate shale gas production using horizontal well with hydraulic fractures. In general, these numerical studies have considered single-phase gas transport. However, following the fracturing, fluid-wall interactions can form a damaged zone nearby the fracture characterized by strong capillarity and osmosis effects. To understand the impact of fracturing fluid damage to well production performance, we present a new reservoir multi-phase flow model which includes these mechanisms of formation damage.
In the simulation model, the shale matrix by the fracture is treated as a multi-scale porosity medium including interconnected organic, inorganic slit-shaped, and interlayer clay porosity fields. Prior to fracturing, the matrix holds the gas in the organic and the inorganic pore network, the water in the inorganic and the clay. Imbibition and osmosis mechanisms are included into an existing multi-scale advective-diffusive flow model to describe water-shale interactions following the fracturing. The reservoir flow simulator is fully implicit and based on the integral finite difference method.
The simulation results show that, although fracturing is a rapid process, fluid-wall interactions continuing after fracturing could lead to important imbibition effect during the flowback and production, which allows water to penetrate into the inorganic pore network and displace the gas in-place near the fracture. Osmosis, on the other hand, takes part in the clay interlayer pores due to salt concentration difference between the fracturing fluid and the clay water, because clay in shale matrix acts as a semi-permeable membrane. This leads to pressure build-up in the clay interlayer pores. The pressure build-up, known as clay swelling pressure, exerts additional pressure into the shale matrix which can lead to significant permeability damage during the flowback and production. We measured the propagation speeds of the pressure waves associated with the capillarity and the osmosis.
The new model is used to demonstrate the damage zone formation characteristics and its effect on the flowback dynamics. We also investigated effects of varying salinity contrast between the fracturing fluid and structural water, of varying clay content/type on the shale gas well production performance. Finally, the stress-dependence of the inorganic matrix permeability in the damaged zone is investigated.
The new shale gas reservoir flow simulation model includes additional mechanisms that will allow the practicing engineer to gain insight into a particular case of production in the presence of water-shale interactions. The model can also be implemented into a simulation-based optimization process to design hydraulic-fracturing and flowback procedures for optimal gas production.
A Continued Assessment of the Risk of Migration of Hydrocarbons or Fracturing Fluids into Fresh Water Aquifers in the Piceance, Raton, and San Juan Basins of Colorado
Authors: Stone C. H. , Eustes A. W. , Fleckenstein W. W. 
Published: September 2016

Abstract
The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The mission of this SRN is to provide a logical, science- based framework for evaluating the environmental, economic, and social trade-offs between development of natural gas resources and protection of water and air resources and to convey the results of these evaluations to the public in a way that improves the development of policies and regulations governing natural gas and oil development. In a previous paper (Fleckenstein et al 2015), the risk of shallow aquifer contamination was examined for the Denver-Julesburg Basin in Colorado, specifically for the largest field in the basin, the Wattenberg Field. Similar methods were used to assess the risk of wellbore failure leading to fresh water aquafer contamination for the Piceance, Raton, and San Juan Basins in Colorado.
Wellbore construction methods, especially casing and cementing practices for the protection of fresh water aquifers, have been reviewed in these three basins. The wells in the three basins were classified based on coverage of water and hydrocarbon zones as well as age. The assessment confirms that natural gas migration occurs infrequently, but can happen from poorly constructed wellbores. There has been no occurrence of hydraulic fracturing fluid contamination, which was confirmed by our analysis. The significance of these results is to help quantify the risks associated with natural gas development, as related to the contamination of surface aquifers. These results are helping to shape the discussion of the risks of natural gas development and will assist in identifying areas of improved well construction and hydraulic fracturing practices to minimize risk.
The Impact of Geomechanics and Perforations on Hydraulic Fracture Initiation and Complexity in Horizontal Well Completions
Authors: Waters George , Weng Xiaowei 
Published: September 2016

Abstract
As is well known, hydraulically fractured horizontal wells have been extremely successful in the development of low permeability reservoirs throughout the world. The vast majority of these completions employ cased and cemented wellbores drilled approximately in the direction of minimum horizontal stress. Multiple, relatively short perforation clusters are included within each frac stage along the lateral. This efficiently creates many hydraulic fractures propagating orthogonal to the well, but it does not insure that each perf cluster is effectively stimulated.
Many efforts have been made to improve the effectiveness of horizontal completions. This has mainly focused on using lateral measurements to place perforation clusters in rock of similar stress so they are more likely to be successfully stimulated. But this ignores the impact of formation initiation pressure and tectonics on fracture initiation. In addition, the number, dimensions and orientation of the perforations in each cluster can greatly influence the effectiveness of the stimulation at each initiation point.
To address these issues a near-wellbore fracture initiation calculator has been developed that predicts whether a fracture will initiate at a perforation, the minimum initiation pressure, the fracture initiation location and orientation at each perforation, and the injection rate into each perforation. These parameters are a function of the casing size and orientation, the mechanical properties of the rock and cement, the principle effective stresses, and properties of the perforations.
A series of sensitivities have been performed to quantify the impact of injection rate, tectonic setting, stress variation between clusters, and perforation properties on hydraulic fracture creation, orientation and complexity at each perf cluster. The sensitivities demonstrate that fractures may not initiate at many clusters and that within an active cluster some perforations may not be accepting fluid. Incorporating the results from this model enables engineers to design completions that insure all perforation clusters are effectively stimulated and near-well fracture complexity is minimized.
This methodology does not just look at a single perforation, or cluster. Instead, it accounts for the stress variation between multiple perforation clusters within a frac stage, in addition to perforation orientation, dimensions and eccentricity, to predict the likelihood that each perforation cluster will be stimulated. By employing this methodology one can better design a perforating system and optimize perforation placement within a lateral to insure hydraulic fractures are created at all perforation clusters.
Cost Effective Monitoring and Visualization System Used for Real-Time Monitoring of Downhole Operations from the Wellhead
Authors: Hlidek Barry T. , Potts Douglas , Quinlan Andrew 
Published: September 2016

Abstract
A major challenge of multistage completion systems is visualizing and verifying critical operations, especially during high pressure pumping operations, such as hydraulic fracturing. An innovative new technology has been developed to detect and visualize those key completion operations using easily installed surface equipment. This paper describes the real-time visualization system (RTVS), its deployment and operation, and includes examples from the field.
Several methods are currently available to monitor operational events that are critical to the successful execution of a multistage fracturing program. Traditionally, surface pressure signatures and manual methods are used to verify completion equipment functions. However, in many cases the signature is not present or is ambiguous. Microseismic and fiber optic systems are complex and expensive to deploy. The new RTVS method is a surface deployed; non-invasive, self-contained system that provides easy to use high resolution data. The system provides visual representation of downhole and surface events using a unique and specialized array of electronic sensors.
The ruggedized, monitoring system can be rapidly deployed and installed by a single operator, with little or no interference with concurrent surface or downhole operations. Power supply and instrumentation is portable with a very small footprint acceptable for onshore and offshore applications. The system operates independently from conventional pressure measurement, and is designed to provide real-time feedback during completion operations.
During multistage hydraulic fracturing operations, the system will positively verify the function of fracture ball deployment, ball seating, and sliding sleeves, as well as setting of liner hangers and mechanical packers. RTVS can also detect coiled tubing sleeve location and operation, perforating gun firing, plug setting, and function of other downhole and related surface equipment. Additionally, the system has the ability to detect failure of downhole equipment, such as casing or tubing breaches in real-time during hydraulic fracturing operations. Real-time monitoring enables on-the-fly optimization of the fracture treatment and eliminates uncertainty regarding deployment and operation of downhole equipment.
This non-invasive, cost-effective completion equipment and stimulation treatment monitoring system is the first technology of its kind. Combining an array of sensors and innovative signal analysis, this easily deployed system can detect operation and failure of surface and downhole equipment. Real-time monitoring of wellsite events can improve decision making on location, optimizing completion operations, and improving well economics.
New Generation of MPD Drilling Software - From Quantifying to Control
Authors: Rostami S. Ameen , Gumus F. , Simpkins D. , Pobedinski I. , Kinik K. , Rajabi M. Mir 
Published: September 2016

Abstract
Realizing the potential benefits automation brings, many operators have turned to managed pressure drilling (MPD) techniques as a technical and cost-reward solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. The evolving industry shift toward MPD-ready rigs demonstrates the significant need for a reliable software system to interact with the equipment and simultaneously deliver enhanced models able to precisely control annular pressure in geological complexities where drilling windows are narrow.
Several studies have demonstrated the operational benefits of MPD through the application of the constant bottom hole pressure (CBHP) method, imbedded automated kick detection, and control capabilities. MPD technology relies substantially on applying surface back pressure (SBP) using automated chokes to precisely control the annular pressure profile in a closed loop circulation system. During drilling, CBHP connections, mud displacements and fluid anomaly incidents, the SBP is dynamically adjusted in response to operational changes that yield annular pressure changes; such as circulation rate, top drive speed, and rate of penetration to name a few.
The integrated MPD drilling software platform is used in combination with interactive models and surface and downhole data measurement in a unified computing system to enhance real-time analysis of drilling performance. By employing real-time models such as hydraulics, well control, pore and fracture pressure estimation, surge and swab, and drilling optimization torque and drag, the system quantifies the boundaries and aid in understanding the real operational limits. Additional software platform applications deliver the common integration baseline that enables both operations within the pre-drilling, while drilling and post analysis. The current automated MPD software has been successfully used in several onshore and offshore wells with narrow drilling windows. This paper discusses the applications and the newest developments in the MPD integrated software to automatically and precisely manage wellbore pressure. The results to be presented include the summary of planning, while drilling analysis, and post drilling analysis of an offshore case study where a detailed parametric analysis of measured and estimated data are compared.
Geospatial Analysis of Compositional Variations across the Eagle Ford and Barnett Shale Plays
Authors: McMillan M. D. , Nwachukwu C. R. , Rahnema H. 
Published: September 2016

Abstract
Liquid-rich shale (LRS) wells have shown abrupt changes in production rates and fluid composition. In order to maintain high liquid hydrocarbon production rates over the life of well, as well as proper reserve estimation, a better understanding of the in-situ reservoir fluids is required. In this work, an investigation is performed on the areal and vertical geospatial fluid property variations across the Barnett and Eagle Ford. Available Barnett PVT data was adjudged as entirely nonrepresentative and a multi-contact recombination procedure has been implemented to improve estimates of in-situ reservoir composition. Eagle Ford is known to be highly under-saturated and with no concerns about representativeness identified through data validation, these were accepted and utilized without modification. Ternary diagrams indicating fluid type, vertical variations of OGR, C7+ and API gravity were investigated. Maps were created to review areal variations of these properties (API gravity, C7+, and initial OGR), and finally the decline of OGR with time was studied.
Our study used publicly available data to confirm compositional variation across the Barnett and Eagle Ford. Regions were defined based on initial producing OGR and the decline of this property with time. The created maps present not only ranges and trends for OGR, API gravity and well stream C7+ parameters but the methodologies can be applied to assessing other fields.
Molecular Dynamics Study of Carbon Dioxide Storage in Carbon-Based Organic Nanopores
Authors: Kazemi Mohammad , Takbiri-Borujeni Ali 
Published: September 2016

Abstract
With large scale production of gas from shale resources, large volumes of pore space have been vacated. Therefore, there is a large capacity for storage of carbon dioxide in these resources. Furthermore, due to the higher affinity of the organic matter to carbon dioxide compared to methane, injection of carbon dioxide can replace the adsorbed methane and therefore, enhances the recovery of natural gas. The objective for this work is to investigate the sorption (adsorption of carbon dioxide and desorption of methane) in carbon-based organic channels using Molecular Dynamics (MD) simulations.
In this study, adsorption isotherms of methane and carbon dioxide are compared by performing grand canonical Monte Carlo (GCMC) simulations in identical setups of carbon channels. Excess and absolute adsorption isotherms of these gases are plotted and compared. Furthermore, the surface selectivity of carbon dioxide over methane is computed to determine the competitive adsorption of these two gases. To simulate the displacement process, MD simulations of displacement of methane molecules with carbon dioxide molecules in presence and absence of pressure gradients are performed. The results are compared for different values of gas pressures and pressure gradients.
According to the results, adsorption capability of carbon dioxide is found to be higher than that of methane under the same pressure and temperature. The selectivity values of carbon dioxide over methane is found to be higher than the ones for pressure range of 100 to 200 atm, which shows that carbon dioxide molecules have higher affinity to the surface compared with methane. It is also found that carbon dioxide molecules replace adsorbed methane molecules due to their higher affinity to the surface. Concentration of methane sharply decreases as carbon dioxide molecules are introduced in the channel. The results show that the amount of carbon dioxide storage and methane production rate increases as injection pressure increases. The results in this study can impact on the research and development of new tools for both candidate selection (selection of the sites for carbon dioxide storage) and development of predictive models for estimating of the amount of carbon dioxide intake.
Interpretation and Analysis of Transient Sandface and Wellbore Temperature Data
Authors: Onur M. , Ulker G. , Kocak S. , Gok I. M. 
Published: September 2016

Abstract
In this paper, we provide new analytical and semi-analytical solutions based on a coupled wellbore/reservoir thermal model to investigate the information content of transient temperature measurement made within the vertical wellbore across from the producing horizon or at a gauge depth above it during drawdown and buildup tests. Our investigation leads to new interpretation/analysis methodologies of sandface and wellbore transient temperature data based on temperature-derivative and straight line methods for estimating near wellbore and far field formation parameters. Slightly compressible, single-phase, and homogeneous infinite-acting reservoir system with skin effect is considered. The analytical solutions accounts for Joule-Thomson heating/cooling, adiabatic fluid expansion, conduction and convection effects both in the wellbore and reservoir. The development of the analytical and semi-analytical solutions is based on the fact that the effects of temperature changes on wellbore and reservoir pressure transient data can be neglected so that the wellbore mass and momentum and reservoir pressure diffusivity equations and thermal energy balance equations in the wellbore and reservoir can be decoupled. The semi-analytical solution for predicting sandface temperatures is verified by use of a general purpose thermal simulator. Wellbore temperatures at a certain gauge depth are evaluated through analytical steady-state and transient wellbore temperature equations which couple the semi-analytical reservoir temperature model based on the conventional wellbore storage model or the more general model accounting for momentum effects in the wellbore. Results show that drawdown sandface temperatures are totally dominated by advection, whereas buildup sandface temperature data are dominated by conduction. Drawdown and buildup sandface temperature data exhibit two semilog straight lines; one at early-times reflecting the effects of adiabatic fluid expansion in the in the skin zone near the wellbore, whereas the late-time semilog straight line reflecting the Joule-Thomson effects and exhibiting the non-skin zone properties. For temperature measurements made at locations above the producing horizon, the wellbore temperature is strongle dependent upon distance above the producing horizon, geothermal gradient, and radial heat losses from the wellbore fluid to the formation on the way to gauge. Our results indicate that skin-zone properties seems very difficult to estimate from the drawdown and buildup wellbore temperatures unless the gauge location is not far from the producing zone. Buildup wellbore temperature seems mostly dominated by wellbore heat losses as compared to drawdown wellbore temperature data and hence cannot reflect the formation properties.