bluuebunny/crossref_metadata_2025_split huggingface dataset:
Proppant Transport Behavior in Inclined Versus Vertical Hydraulic Fractures: An Experimental Study
Authors: Ba Geri Mohammed , Imqam Abdulmohsin , Dunn-Norman Shari 
Published: October 2018

Abstract
Understanding proppant transport in complex fracture systems plays an essential role in determining propped fracture area, fracture conductivity, and their impact on well productivity and economics. Despite extensive, historical work that has studied proppant transport in vertical fractures, very limited investigation exists regarding proppant transport appraisal in inclined hydraulic fractures. This study provides a better understanding of proppant distribution in inclined hydraulic fractures.
Proppant transport is governed by several factors such as varying of slurry velocity, fracture geometry, proppant size, and proppant concentration. The main purpose of this experimental study is to evaluate the proppant settling and transport and to determine fracture propped area as a function of the key proppant transport factors in different inclined fracture geometry. Low viscosity fracture fluid (slickwater) was used with different particle sizes: 20/40, 40/70, 100- mesh ceramic proppant. To mimic slurry transport in hydraulic fracturing treatments, a 2 ft. × 2 ft. fracture slot model was constructed with gap of 0.25 in. representing the fracture width. Orientation of the fracture model can be adjusted from vertical to inclined positions. Four injection points perpendicular to the wellbore were used to simulate injection through multiple perforations, in addition to single point injection scenarios.
Equilibrium dune height (EDL) is expressed in three regions (near the wellbore, in the center of the fracture, and at the fracture tip) for created fractures. Variations in EDL as a function of the number of perforations that contributed during proppant transport are compared for both vertical and inclined fractures.
Experimental results show that both fracture inclination and number of contributing perforations impact EDL and propped fracture area. Inclination of fractures can have significant impact on proppant transport due to the friction or contact force, which comes from the fracture wall. This friction impacts settling velocity of the proppant and impacts the proppant distribution efficiency inside the fracture. Increasing fracture inclination angle increases fracture propped area. Finally, this work observed that number and perforations and their position play an important role in proppant transport, particularly in inclined fractures.
Modeling Geopressures in a Tight Gas Reservoir, An Argentinean Case
Authors: Guerra Julian , Olmos Martin de , Szelagowski Manuel , Zurita Pablo Ibañez 
Published: October 2018

Abstract
Geopressures modeling has become a critical task in unconventional plays since the high pore pressures found in some areas makes drilling and completion operations particularly challenging. This field study helped to quantify the pore pressure anomalies and understanding the overpressure mechanisms acting in the tight gas reservoir of Rio Neuquen field. To achieve this objective a pore pressure model was built based on seismic attributes and multi well data analysis. This model also helped to establish possible relationships between reservoir performance and those pore pressure anomalies.
The mathematical model used seismic velocities from PSDM tomography and simultaneous inversion for establishing relationships between the elastic rock response and pore pressure, through a series of effective stress-velocity transforms. The model also considers a multi variable analysis to account for other variables affecting seismic response, including porosity, VSH and effective stress, like that proposed by Sayers (2003). Field data from several wells was used to tie the seismic velocities to well logs, while laboratory tests and pressure measurements were used as calibration points for the model, supporting the results of the study. The analysis showed that interval velocities from seismic inversion led to a more representative and accurate pore pressure model than that obtained from the PSDM velocities. The analysis showed that velocity reversals from seismic had a strong stress influence while as confirmed later by ultrasonic lab test analysis and observed pressure data. There were also some lithological and porosity effects in the elastic response of seismic, as evidenced by well logs. This, however, could not be modeled at field scale due to limitations in the available 3D seismic data.
Pore pressure anomalies are expected to be highly influenced by the presence of a nearby overpressurized source rock. The study suggests indeed that that multiple type II overpressure mechanisms can be present in the area, including lateral transfer, HC generation and tectonic load. The model showed that the pressure anomalies are higher as closer is the reservoir to the source rock. Four new wells drilled in the recent campaign probed the accuracy and robustness of the pore pressure predictions.
This work is an excellent case study that shows how pore pressure can be modeled in some tight sands that exhibits a stress sensitive behavior. The pore pressure model helped to evaluate not only gas reserves but also sweet spots, making the 3D pore pressure prediction a powerful tool for exploration, drilling and field development planning.
Smart Expandable Polymer Cement Additive to Improve Zonal Isolation
Authors: Santos Livio , Dahi Taleghani Arash , Li Guoqiang 
Published: October 2018

Abstract
One of the critical issues that might happen in some oil and gas wells is the failure of the cement sheaths and its debonding from the casing string. Cement shrinkage during setting is regarded as one of the main causes behind formation of microannulus cracks. In this paper, a new class of polymer-based expandable additives is presented in the form of fibers to address shrinkage and debonding issues in the subsurface. The proposed fiber additives are made from shape memory polymers. These fibers expand upon exposure to temperatures above certain limits; which is selected to be below the temperature of the cementing zone. In this situation, the expansion occurs before the cement setting but after its placement. If the expansion occurs after cement setting, it may lead to microfractures. As a result of the controlled expansion of the cement paste, the creation of channels and fluid migration can be minimized while maintaining the mechanical properties required for cement integrity. Considering the inert property of the proposed additive, the cement water ratio and its chemical properties do not change. The cement expansion, fluid loss, gel strength, compressive strength, and tensile strength of the samples containing these fibers are examined by destructive and non-destructive methods and presented here. The proposed class of expandable additives can help the operators reach sustainable well integrity by improving the bonding between the cement and casing.
Vaca Muerta Numerical Simulation: A Warning in Compositional Modelling
Authors: Bosco Sergio , Suarez Mariano , Savoy Elisabet 
Published: October 2018

Abstract
The paper highlights the limitations in the use of cubic equations of state (CEOS), for modelling reservoir behavior of liquid phase (black and volatile oil), in highly undersaturated reservoirs. This is important in high shrinkage volatile oils for which complex dependence of fluid behavior with composition is found.
Vaca Muerta formation fluids run from medium black oils to very dry gas, according to source rock maturity. High shrinkage volatile oil and very rich gas condensate are found and compositional variation is areally continuous. Despite this huge difference in fluid nature, where saturation pressures are present, more than 200 kg/cm2 undersaturation are reported.
Due to the complex dependence of fluid behavior with composition for near critical gas condensate and volatile oil, the use of compositional modelling is mandatory.
Reservoir pressure evolution with production and recovery calculations rely largely on compressibility, which itself is not a fitting parameter for usual CEOS. A very good fit for liquid volumes in CEOS, i.e. less than 5 % maximum error in volume, leads to unacceptable differences in compressibility (over 30 %).
To compare the consequences in production of this difference, a black oil model was run with different fluid scenarios: one with experimental compressibility and other two with compressibility obtained from CEOS. In the model, all formation, fracture and other fluid properties are the same, as well as the BHP imposed.
The results from numerical simulation show that rates and cumulative production from CEOS compressibility scenarios are half of those obtained with experimental compressibility. Part of this difference may be explained from fluid behavior alone, and the remaining is due to poral compressibility and fracture conductivities related to the different trends in pressure.
The CEOS are the only ones implemented up to now in the commercially available compositional numerical simulators. In this paper we show the limitation of these CEOS for the description of highly undersaturated volatile oil reservoirs.
Field Development Optimization Through Integrated Geosciences and Engineering Analysis
Authors: Hren Agustin , Exler Victor Ariel , Peacock Horacio , Schmidt Roberto , Pellicer Marcelo Daniel , Lamberghini Lucia , Gait Jorge 
Published: October 2018

Abstract
Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells.
However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model.
A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations.
This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.
Experience in Lateral Well and Perf Cluster Spacing for Shale Dry Gas
Authors: Chiarandini Fabio David 
Published: October 2018

Abstract
The objective of this work is to present an integrated methodology/workflow for optimizing lateral well spacing and fracture spacing for unconventional reservoirs based on multiple experience in Marcellus shale gas development. Optimal well plans and completion designs, based on geology and reservoir characterization, are key elements in developing economic projects. Well performance and reserves at a pad level can be improved thought coordinated efforts from multi-functional disciplines.
Workflow incorporates data integration and main analysis to be performed from all involved disciplines. Main disciplines are geology, reservoir and production engineering, drilling and completions teams, decision and economic evaluation and cost assurance process. A full set of reservoir modeling, economic analysis tools are described in the document. Workflow is optimized with a loop, where main routine and non-routine surveillance is used mainly for interference analysis and further optimization on both spacing for the factory-style development.
Reservoir simulation fed into two separate workflows. One is a single pad economic model and or DOE which incorporates decision analysis techniques. The other is a portfolio analysis with pads scheduled to fill a midstream capacity constraint through time. Both cases balance the increased capital costs against accelerated and increased production. The portfolio analysis tool is useful in understanding impacts of tighter well lateral and cluster spacing, particularly how they influenced capital costs over time. Additionally, results are compared with analog data and competitor analysis.
Methodology was field tested. Workflow application demonstrates that optimum lateral well spacing and cluster spacing in dry gas core area would have a positive impact on EUR (estimated ultimate recovery) at a pad level. Also, pad drilling and Completion optimizations provide increased NPV (net present value) and incremental DPI (discount profit investment) ratio.
The experience in lateral well and perf cluster spacing for shale dry gas for geometric completions is an example of how to manage uncertainty through cross-functional collaboration.
Workflow can be used as inputs in pilot test for well spacing and as a process to justify surveillance needs using value of information techniques.
Type Curves for Vaca Muerta Horizontal Wells
Authors: Johanis Pablo Esteban 
Published: October 2018

Abstract
The increasing number of drilled, completed, and produced horizontal wells in Vaca Muerta enables strengthening the generation of its type curves. The samples can be categorized by produced fluid, landing zone, and eventually by other criteria, reaching statistical significance and, thereby, enabling the preparation of type curves specific to each criterion.
Public domain monthly production data, combined with directional, completion, and hydraulic fracturing records related to horizontal wells in Vaca Muerta, were gathered, building a database that as of December 2017, included 254 wells. Each well was classified according to fluid produced, landing zone, and well location relative to slope breaks of progradant facies. The monthly produced volumes are expressed in equivalent barrels of oil and normalized to 1,000 m of stimulated lateral length.
For each class considered, percentiles 90, 50, and 10 of a recomputed monthly series were calculated, as well as the average. The series best-fit theoretical curves were generated and are proposed as type curves.
More than 200 new entries were added to a legacy database that had been used to estimate normalized standard production and appraise stimulation trends. In this way, the data sample reached greater statistical significance and included a longer series of monthly production data, making it possible to obtain production type curves with smaller deviation and more robust means and averages. Progress was made in the discrimination of the entire set of horizontal wells in Vaca Muerta by preparing type curves for wells producing black oil, intermediate wet fluids, and dry gas. Production accumulations increase from one production type to the next in the order listed.
Relevant to landing zone criteria, discriminated type curves are presented for the "kitchen" (basal section of the formation, which reaches the highest organic and shale content)," the "organic" level (inmediate overlaying section of high organic content), and the lower and the upper prograding facies (shaly limestone sequences in the middle and upper sections of the formation). Particularly for the oil-producing wells, the type curves reveal the increased production in the "kitchen" and upper progradant levels.
The elaboration of best-fit curves to the series of typical P90, P50, and P10 data, with its generatrix algorithm, provides a simple aid to approximate production estimates and economic evaluation of projects.
Completion Efficiency Evaluation in Horizontal Wells and its Importance in Vaca Muerta Formation
Authors: Moreyra Juan Domingo , Palacios Ricardo 
Published: October 2018

Abstract
In Argentina, unconventional reservoir development learning processes have been continuously advancing, specially lowering project costs in Vaca Muerta's different zones, light oil, gas-condensate and dry gas. However, the actual international oil and gas prices are forcing companies to search for additional improvements to keep on developing these fields.
Vaca Muerta Oil and gas potential with big pay thickness requires the review of completion efficiency and its incidence on initial hydrocarbons production in order to improve the project cash flow.
The analysis should be focused on horizontal wells-orthogonal fractures interface which, in Argentina, has not been properly evaluated, leading us to underestimate the production loss by using the status quo of approved technologies for our projects.
Big thicknesses increase the pressure loss effects due to flow convergence from the fracture into the well, to which we have to add the near wellbore bottleneck causing a conductivity reduction due to inappropriate final concentration design, over flush and proppant grain size and quality that are not capable of holding the confining pressure, in special in some of the completion technologies.
In dry gas and gas-condensate reservoirs, non-Darcy effects and condensate accumulation in the SRV when pressure drops below the dew point, are also influenced by an inappropriate completion.
Vaca Muerta over pressure forces us to pay attention to plays whit high production due better reservoir characteristics and SRV quality induced by fracturing.
Interfaces must be designed to support such high pressures and maintain a good fracture conductivity. Technology review and selection is strongly recommended, in special in those where treatment is divided into multiple fracturing in different clusters with over flush to clean the well and/or displace guns/plugs and ball fractures between stages.
Benefits from obtaining bigger and more stable SRV through new microproppant technologies and longer horizontal wells, will not be appreciated if fractures-wellbore interfaces are not improved allowing a better fluids evacuation into the wellbore by reducing restrictions to flow. At the same time, available literature shows dissimilar results when looking to improve cash flow through refracturing depleted wells.
The purpose of this article is to show the importance of including the evaluation of production loss magnitude and its incidence on the project cash flow. This will allow considering different completion strategies on each project, some of them already available. Changes in fracture design and proppant quality will lead to a better and more stable fracture-wellbore interface.
Drilling Horizontal Well of 3200m Lateral Length in Vaca Muerta Formation
Authors: Medina Jonatan , Salcedo Gervasio Jose , Olave Sergio Eduardo 
Published: October 2018

ABSTRACT

OBJECTIVES
At a time when the demand for energy is growing in Argentina, operators are seeking to improve the profitability of unconventional oilfields by drilling wells with longer lateral lengths (up to 3200 meter), allowing a larger area to be drained by single wellbore, minimizing overall development cost.
This paper outlines methods and resources used to drill this long lateral well along with the limitations that arose during the planning and execution phase.

METHODS, PROCEDURES, PROCESES
Currently the development of the unconventional oilfield in the Loma Campana and El Orejano oil areas are established with wellbore design of 3 casing strings, drilling the production zone (Vaca Muerta) in an open hole of 6-1/8" and completing it with 5" casing; achieving horizontal lengths between 2400 m to 2600 m with a maximum of 2715 m.
The current configuration of these types of wells is in a technical limit stage, due to the maximum hydraulic power that the available drilling equipment possesses and the loss of efficiency with its consequent increase in costs in the completion stage. It is for this reason and looking to increase the number of fracture stages per well, that the construction of a well of robust architecture and greater extension was considered.

RESULTS, OBSERVATIONS, CONCLUSIONS
The design change contemplated 3 casing of higher diameters 13 3/8," 9 5/8" and production section in 5 ½". This design requires drilling production open hole section in 8-½" diameter. This allowed to increase the lateral length to 3200 m, avoided reaching the hydraulic power limit of the drilling equipment and maintained the same design of stimulation while preserving the efficiency.

ADITIONAL INFORMATION
The presentation of the paper consists of the technical feasibility analysis, contemplating the uncertainties regarding drilling fluid hydraulic behavior, torque & drag, the operational results of the experience, and the resulting cost analysis.
A Multiscale Approach to Simulation of Fluid Flow in Tight Porous Media
Authors: Giro Ronaldo , Bryant Peter William , Carneiro Queiroz da Silva Guilherme , Neumann Rodrigo F. , Engel Michael , Steiner Mathias B. 
Published: October 2018

Abstract
Recently the world has seen tremendous growth in oil and gas production from unconventional reservoirs, such as tight-gas sands, gas and oil shales, and heavy oil and tar sands. This growth can be attributed in part to technological developments in fracturing and stimulating well production, and in part to the availability of oil and gas resources in shale. Around 75% of the sedimentary rocks on earth are clastic nanoporous rocks, which are often referred to as "shales". These shales contain most of the world's oil and probably gas resources as well, but only a small fraction can be recovered using the latest technology – typically around 5% for oil and 20% for gas. What seems to be missing is an understanding of the fundamental interactions between fluids and rock surfaces, and of the dynamics of fluids in pores with sizes ranging from a few nanometers (10−9m) to micrometers (10−6m). Filling these gaps in our knowledge will help to develop improved recovery strategies and better prediction of production.
Here we present a multiscale simulation approach meant to bridge these gaps. All Atom Classical Molecular Dynamics (AAMD), a simulation method at the scale of atoms and molecules, is used to tune parameters used in Many-Body Dissipative Particle Dynamics (MDPD), which is a mesoscale simulation method. In nanopores, a majority of the fluid interacts with the rock surface and therefore cannot be treated as bulk fluid. To capture resulting phenomena, a low level of coarse-graining was used for MDPD. This, however, limits the domain of two-fluid MDPD simulations to a single capillary. To reach the scale of true porous media, we extract parameters describing the dynamic effects of fluid-fluid interface shapes on capillary pressures, and these are used in a dynamic capillary network simulation of fluids moving through pore spaces.
Results from MDPD simulations show the extraction of dynamic variables, such as dynamic contact angle and capillary pressure as a function of speed and pore diameter, to feed a capillary network model. The dynamic network model results then reveal how modifying the molecular interactions manifests at the pore scale.
With our hierarchical multiscale approach, we can bridge the gaps from molecular-level, chemical phenomena up to flow in porous media in a physically and thermodynamically consistent manner and with a minimum of unknown parameters. We can thus investigate not only if but why and how EOR strategies for shale succeed or fail.