bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diversion - Be Careful What You Ask For
Authors: Senters C. W. , Leonard R. S. , Ramos C. R. , Wood T. M. , Woodroof R. A. 
Published: October 2017

Abstract
Success of a fracture stimulation treatment depends upon complete coverage of all targeted intervals. Diversion techniques are being applied in new well completions to achieve greater cluster treatment efficiency and to access additional rock. The objective of this study is to characterize diversion and to utilize near-wellbore diagnostics to determine the effectiveness of diversion. Multiple basins are included in this study, incorporating a variety of drilling and completion practices.
Proppant tracing and temperature logging provide near-wellbore diagnostics to evaluate the new rock contacted as a result of diversion. Tracers injected during the treatment at various intervals before and after diversion can be used to determine cluster efficiency as well as the overall changes to a stage as a result of the diversion. Temperature logging is used to determine cooling effects of the treatment and is correlated back to the near-wellbore proppant coverage. The combination of multiple diagnostics provides additional confirmation of the treatment coverage or in some cases the lack thereof.
The results of this study show examples of both effective and ineffective diversion. Effective near-wellbore diversion is defined as diversion that results in accessing clusters that were previously not stimulated or under-stimulated. In many cases the surface treating pressure response due to diversion does not correlate to its effectiveness. Optimizing the design and deployment of the diversion process often results in improvement of treatment effectiveness. The results of this study are grouped by Anadarko Basin, Permian Basin, Eagle Ford, and Williston Basin and show the effectiveness of a variety of diversion techniques.
Through a combination of diagnostic techniques, diversion is evaluated on new well completions. Over 30 wells are included in this study across multiple basins. The overall stage coverage is evaluated along with the effectiveness of near-wellbore diversion to achieve this coverage. These learnings can be applied to optimize diversion designs for future wells in these and other basins.
Integrated Reservoir-Network Simulation Improves Modeling and Selection of Subsea Boosting Systems for a Deepwater Development
Authors: Seth Gaurav , Valbuena Ernesto , Tam Soong , Da Sie Will , Kumar Hemant , Arias Brian , Price Troy 
Published: October 2017

Abstract
This manuscript presents the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field management strategies incorporating flow-line routing, field and gathering network constraints and rate allocation. Novel techniques to model subsea networks enable the selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deep water assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value.
Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, as this involves novel modeling techniques for boosting systems (pumps). The robust approach ensures consistency of phase behavior across the system components, identification of pump requirements, production optimization and cost reduction. Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts.
The integrated model uses Inflow Performance Relationships (IPR) from reservoir simulation and vertical lift tables to generate Performance Curves (PC), representing well deliverability as a function of Tubing Head Pressure. Comprehensive field management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints into a single operating rate. Well operating rate, is also a function of pump power, pump suction pressure and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity.
Two components of the subsea boosting system, single- and multi-phase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints into a single operating rate provides tremendous computational performance improvement. Moreover, unlike typical optimization problems, adding more constraints to the system did not affect computational performance significantly.
A New Well Positioning Technique: Access-Independent Ranging Solution for Providing Accurate Well Completion
Authors: Wu Hsu-Hsiang , Hinke Sean , Fan Yijing 
Published: October 2017

Abstract
Magnetic ranging has been used in heavy oil drilling environments, primarily in steam-assisted gravity drainage (SAGD) applications, to eliminate accumulated directional survey errors. SAGD applications require drilling several pairs of horizontal, parallel wells separated by a few meters. More than 2,000 well pairs have been drilled using a ranging technique in which a device generating a magnetic field is deployed in one of the SAGD wells, and a device to measure the magnetic field is deployed in the adjacent SAGD well. This ranging technique has succeeded in accurately controlling the desired separations and directions relatively between the well pairs. However, the cost for access to both wellbores of the well pair has created a high demand for new ranging techniques that require access to only drilling wellbore.
This paper presents a new well positioning method that provides innovative magnetic ranging without access to the wellbore of a target well through the use of surface excitation. The surface excitation is connected to the wellhead of the target well to transmit a current signal along the cased-hole target well; the array gradiometer in the nearby drilling well receives the corresponding magnetic fields and calculates the relative distance and direction between the two wells. The active magnetic, wellbore access-independent, magnetic ranging system provides several advantages over currently available systems, including reduced cost and risk to the operator, improved equipment logistics, elimination of the wireline ranging tool deployment, and reduced personnel to deliver the service, relative to current commercial systems.
Various laboratory tests and field trials based on a discovery tool were conducted exclusively in SAGD wells to validate the proposed concept and to demonstrate the capabilities of providing reliable and accurate ranging data for relative well positioning and well placement applications. The results show excellent agreement on ranging distance and direction measurements between the discovery tool and the industry standard tool. The described logging while drilling (LWD) technique presents an alternative ranging method to existing wireline techniques in SAGD applications. It is also applicable in wellbore intersection and well positioning applications without a target wellbore access.
The Role of Pore Pressure Depletion in Propagation of New Hydraulic Fractures during Refracturing of Horizontal Wells
Authors: Rezaei Ali , Rafiee Mehdi , Siddiqui Fahd , Soliman Mohamed , Bornia Giorgio 
Published: October 2017

Abstract
Refracturing of a horizontal well is a method to restore the productivity of the well in unconventional reservoirs after the expected production decline. Placement of new fractures in a system that has been already depleted poses new challenges for operators. These challenges are due to the altered stress zones resulting from the expected pore volume depletion and corresponding pressure decline. In this study, refracturing propagation issues in a horizontal well are studied.
A fully coupled poroelastic displacement discontinuity model has been developed to study refrac propagation in horizontal wells. Displacement discontinuity is a powerful numerical method for studying hydraulic fracture problems. The model has been verified using available analytical solutions for undrained and drained fracture behaviors. Maximum horizontal stress criterion is used to account for the fracture propagation. Several cases are analyzed using the model. For each set, scenarios that increase the chance of successful refracturing are suggested.
Results of this study show that pore pressure depletion is the key factor in defining extent and severity of stress redistribution zones in the reservoir. The effect of pore pressure is shown to be asymmetric in horizontal wells between two parallel fractures. It is observed that the stress anisotropy between two parallel fractures decreases and it increases between the tips of two fractures. After a certain time, stress anisotropy in the area between two fractures becomes negative which means that the horizontal stresses orientation is reversed in that area. Placing any new fracture in the stress-reversed area causes an unwanted change in direction of fracture propagation and eventually an intersection between new and old fractures. In addition, because of the stress redistribution, new fracture tends to propagate toward the nearest old fracture in a single well. This tendency increases as pore pressure depletion becomes greater, increasing risk of refracturing failure. A sensitivity analysis is performed on spacing and length of the old fractures to investigate the best possible treatment plan in terms of these variables.
Results that are obtained by this study give better understanding about propagation of new fractures as well as old fractures in refracturing process. Moreover, it introduces a very efficient method that aids in the design of refracturing processes in depleted horizontal wells.
Effect of Poroelasticity, Pore Confinement, Molecular-to-Inertial Transport, and Threshold Pressure on Flow of Gas through Hydraulically-Fractured Shale-Gas Reservoirs
Authors: Civan Faruk 
Published: October 2017

Abstract
Transport of gas in nano-permeability shale-gas reservoirs involves complex processes of absorption, adsorption, poroelasticity, alterations of gas properties by pore-confinement, and significant deviations from Darcy-type flow. While recent modifications of Darcy’s law can account for molecular transport in shale depending on the Knudsen conditions, they nevertheless omit the corrections due to convective acceleration and inertial flow occurring through natural fractures and induced fractures formed by hydraulic fracturing and the threshold pressure gradient below which reservoir fluids cannot flow. This paper presents a physically rigorous modeling of shale-gas transport by considering the relevant effects in nanopores and fractures to derive a proper gas storage and transport model. This provides an improved model accounting for complex transport processes in organic and inorganic materials intersected by natural and induced fractures. A non-Darcy equation, comprehensive gas storage model, and quantification of relevant parameters are developed. The model is used to simulate gas transport in laboratory shale-core tests conducted under near-real shale-gas reservoir conditions.
Effect of Confinement on Bubble Point Temperature Shift of Hydrocarbon Mixtures: Experimental Investigation Using Nanofluidic Devices
Authors: Alfi Mehrdad , Nasrabadi Hadi , Banerjee Debjyoti 
Published: October 2017

Abstract
A great amount of hydrocarbon pore volume in unconventional petroleum reservoirs is distributed in pores of very small sizes, ranging from a nanometer to 100 nm pores. In such a small pore size, fluid-rock interactions play a dominant role in determining the phase behavior of hydrocarbons, which can lead to significant deviations in phase behavior, and significant errors in reserves estimation and reservoir simulations regularly performed by commercial simulators. In our research, we investigated the fluid phase behavior of hydrocarbon liquids when confined in nano-sized pores. For this end, we employed state of the art technology called lab-on-a-chip technology to mimic shale rock media in a nanofluidic chip. This novel method gives us the ability to directly visualize hydrocarbon liquid inside nano-sized pores and measure fluid properties. Using nanofluidic chips as a nano-scale PVT cell, we have been able to measure the bubble point temperature and its changes under confinement effect in pore sizes of 10 nm, 50 nm and 100 nm. We have performed experiments for binary mixtures of hydrocarbons (pentane/hexane, pentane/heptane) and a ternary hydrocarbon mixture (pentane/hexane/heptane).
The results of our study shows that at 10 nm pores, the confinement has a significate effect on alteration of hydrocarbon phase behavior by increasing the bubble point temperature. On the other hand, the quantity of such effects on bubble point temperature is almost negligible at pore sizes of 50 nm and 100 nm. As a conclusion, confinement effect is significant in form of molecule-pore interactions, which leads to a significant effect on bubble point temperature. Furthermore, molecule–wall interactions that lead to alteration of phase behavior of hydrocarbons do not have a significant influence on the common molecule–molecule interactions at pore size of 50 nm and 100 nm, leading to bubble point temperatures close to those of bulk media.
Modeling of the Interaction Between Asphaltene and Water for Multiphase Reservoir Fluids by Use of Cubic-Plus-Association Equation of State
Authors: Jia Wenlong , Okuno Ryosuke 
Published: October 2017

Abstract
Asphaltene is a group of complex compounds commonly present in reservoir fluids, especially in viscous oils. It is conceivable that asphaltene strongly interacts with water through hydrogen bonding, affecting phase behavior of water/oil mixtures with/without forming an asphaltene-rich phase. Modeling of these polar components in reservoir fluids is challenging with cubic equations of state (EOS) due to the size-symmetricity and self- and cross-associations of asphaltene and water.
In this research, the cubic-plus-association (CPA) EOS is applied to represent complex multiphase behavior associated with water and asphaltene. Asphaltene-containing heavy oils are characterized by the CPA EOS with four pseudo components (asphaltene and the other three pseudo components) based on their experimental data. Asphaltene is the only associating component in the oil models. Then, multiphase behavior data for mixtures of water with each of these oils are represented by the CPA EOS. Calculated phase behavior by the CPA EOS models is compared with experimental data and also with the Peng-Robinson EOS for several cases. This paper also presents a new correlation for binary interaction parameters (BIPs) for water with n-alkanes for the CPA EOS on the basis of experimental data for three-phase coexistence for water/n-alkane binaries (Brunner 1990).
In case studies, the CPA EOS is shown to be able to represent multiphase behavior for water/oil mixtures with up to four equilibrium phases: asphaltene-rich, solvent-rich, aqueous, and vapor phases. In particular, the CPA EOS is successfully applied to bitumen/water mixtures, involving asphaltene-water emulsion, water solubility in bitumen, and their continuous transition with varying temperature. Furthermore, results show that the CPA EOS can reasonably represent the multiphase data measured for a n-butane/bitumen/water mixture that were not accurately correlated with the PR EOS in the literature. Modeling an asphaltene-rich phase in several cases is possible only with consideration of the water-asphaltene interaction, which is worth the additional complexities of the CPA EOS in comparison with the PR EOS.
Estimating Ultra Low Permeability at Multiple Locations Using Simultaneous Impulse Tests: A Fit for Purpose Pressure Transient Solution and Its Field Application
Authors: Zhan Lang , Fair Phil S. , Dombrowski Robert J. , Quint Edwin N. , Cao Richard 
Published: October 2017

Abstract
One of the major challenges in efficiently developing ultra-tight or shale reservoirs is to obtain reliable permeability distribution. Ultra low permeability and very strong stratification or heterogeneity in the formations require conducting long duration tests at multiple locations in a well to attain a complete reservoir characterization. Because of these characteristics, existing tools or methods that work well for conventional reservoirs are usually not applicable for ultra-low permeability formations. An innovative reservoir monitoring/testing tool system was developed and successfully applied to fields in both USA and Canada (Zhan et al. 2016). The tool created multiple pressure pulses at targeted locations simultaneously along monitoring wells for zonal in-situ permeability estimations as well as long term formation pressure monitoring. Existing pressure transient solutions are incapable of handling the measured data when potential zonal pressure interferences appear. A fit-for-purpose pressure solution, the associated optimization algorithm and suitable data interpretation workflow, was developed to analyze the data whenever commercial software tools are inadequate. The new solution fully considers all impulses as well as potential interferences among them through suitable superposition. In-situ permeability values at all involved zones can be obtained through a combination of individual impulse analyses and systematic multiple impulse inversions.
The new pressure transient solution was verified through comprehensive synthetic cases using numerical simulations. The results show that the solution can handle either fully or partially open wellbore in each zone and properly considers cross-flow between formation layers. In addition, it allows any number of perforated intervals and formation layers where the number of the perforated intervals is less than that of the formation layers. Field examples demonstrates applicability of the new solution and the data interpretation workflow to formation permeability down to tens of Nano-Darcy. The detailed zonal permeability distribution in the formation enables a more representative reservoir model for better hydraulic fracturing design and field development optimization.
Experimental Verification of Changing Bubble Points of Oils in Shales: Effect of Preferential Absorption by Kerogen and Confinement of Fluids
Authors: Pathak Manas , Velasco Raul , Panja Palash , Deo Milind D. 
Published: October 2017

Abstract
The economic and increased production of oil and gas from shale plays in the United States plays a key role in the country's energy independence. There are many factors that govern increased production of oil and gas from shales. One such factor is the assessment of the correct in-situ oil bubble point in shales which is critical in the optimization of hydrocarbon production. Shales are nano porous organic-rich sedimentary rocks that act as both source and reservoir oil and gas systems. The effect of nano pore confinement on the bubble point of oil in shales has been widely studied and documented in the SPE papers. However, the effect of organic matter presence on the bubble point of oil in shales has not been explored. The researchers at the University of Utah has studied both the effects by performing molecular scale simulations, thermodynamic modeling and experiments using analytical tools. This paper discusses the experimental effect of the presence of nano pores and organic matter on the bubble points of oil in shales.
Experiments are performed on isolated type I kerogen with multiple pure component hydrocarbons and crude oil. Differential Scanning Calorimeter (DSC) was used to perform experiments on mixture of kerogen and hydrocarbons. The DSC data shows that the presence of kerogen and presence of nano pores changes the bubble point temperature. There is a suppression in the bubble point temperature of oil in presence of type I kerogen. This suppression is larger in the boiling point temperatures of pure polar and non-polar components (nitrobenzene, heptane) when in presence of kerogen. The paper discusses the possible reasons for the suppression seen due to the two effects and the reason behind the difference in the suppression seen with changing hydrocarbon liquid (polar vs non-polar vs H-bonding). Any multicomponent mixture of hydrocarbons such as oil will be split into an absorbed (in kerogen) phase and a free phase as a result of preferential absorption of preferred components by kerogen. Changes in the composition of oil in kerogen due to such a phase split will change the bubble point of oil in kerogen. This is known as effect of presence of kerogen. The free phase stays under the confinement in the nano poresof kerogen. The bubble points of confined oils are different than the bubble point of bulk oil due to dominant pore-wall and fluid interaction under nano-confinement.
Real Time Downhole Measurements During Deepwater Fracpack Completions in the Gulf of Mexico
Authors: Hawthorn Andy , Aguilar Sergio 
Published: October 2017

Abstract
As the industry looks to develop wells in more technically and operationally demanding environments, the potential challenges increase. The result is that the need to more fully understand what is happening downhole throughout the well construction process is critical. An effective telemetry system that can reliably provide valuable data from downhole to the surface is, therefore, an important tool during well construction activities. Current data telemetry platforms such as mud pulse, wired drillpipe (WDP) or electromagnetic (EM) systems are subject to significant limitations. These could be operating restrictions, relatively low bandwidth and complicated installation with associated high implementation costs, all of which lead to increased barriers to deployment. This paper discusses a novel acoustic technology that allows downhole data transmission to the surface real time in a wireless manner. The results of two field cases where this technology was deployed are presented. The paper also aims to quantify the advantages of downhole data and its positive impact on decision making in these well operations.