bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Dual Completion Application to Overcome High Oil Viscosity Challenges - Case Study from Pañacocha Field, Ecuador
Authors: Almeida R. , Lomas J. , Madrunero C. , Castillo M. , Chicaiza F. , Silva A. , Contreras C. , Korgemagi A. 
Published: November 2015

Abstract
The Pañacocha field, located on the Northeast part of Ecuador, is part of the Block 12 from Petroamazonas EP in an ecologically sensitive area of the Amazon rainforest.
Heavy oil (less than 14°API) producers Ml and M2 formations in Pañacocha field are not being fully developed due to challenges of handling fluids with viscosities that increase exponentially as their temperature decrease.
This paper shows how the design, planning and installation of an inverted concentric dual completion string combined with the gravel pack technique for sand control and forced convection to minimize fluid heat transfer through the tubing, allowed to produce high viscosity fluids.
A Comprehensive Mathematical Model for Predicting Thermophysical Properties of Superheated Steam in Horizontal Injection Wells Considering Phase Change
Authors: Cao Renyi , Gu Hao 
Published: November 2015

Abstract
Superheated-steam injection in horizontal wells is a complex process, involving not only mass and heat transfer, but also phase change. The objectives of this work are to establish a comprehensive mathematical model for predicting thermophysical properties (i.e. mass flow rate, fluid pressure, the degree of superheat and steam quality) and to analyze the performance of superheated-steam injection in horizontal wells.
In this study, using mass and momentum balance to a differential control volume of a horizontal wellbore, we present governing equations for mass flow rate and pressure drop, respectively. More importantly, phase change behavior of superheated steam is taken into account. Then, implicit equations for both the degree of superheat and steam quality are further derived based on energy balance in the wellbore. Next, the above equations are coupled and solved iteratively for each segment and a calculation flowchart is provided. Finally, the effects of the degree of superheat, injection rate, injection pressure, reservoir permeability and oil viscosity on the profiles of the above thermophysical properties are analyzed in detail.
The results indicate that for a given degree of superheat, the mass flow rate drops faster after superheated steam is cooled to wet steam, but in the same position of the horizontal wellbore, the mass flow rate increases with the degree of superheat. Secondly, we show that enhancing the injection rate maybe a good method to ensure that the toe section of the horizontal well can also be heated effectively, more importantly, the higher the injection rate is, the longer the distance from the phase change point to the heel-position of the horizontal well is, and after phase change occurs, the lower the injection rate is, the faster the steam quality drops. Thirdly, it is found that both the mass flow rate and the degree of superheat in the same position of the horizontal wellbore decrease with injection pressure. Finally, the paper further reveals that when the reservoir permeability is high or the oil viscosity is low, the mass flow rate and the degree of superheat decline rapidly.
Superheated-steam injection in horizontal wells has not been widely reported in the literature. The comprehensive mathematical model proposed in this paper, which is supported by the measured field data, can be adopted to predict the thermophysical properties and to analyze the performance of superheated-steam injection in horizontal wells. In our study, we also consider the phase change behavior of superheated steam that possibly occurs in practice.
Improving Efficiency in Mineralogy and Saturation Determination in Open and Cased Wells with New Generation Spectroscopy
Authors: Bustos U. , Grau J. , Horkowitz J. , Rose D. , Nieves I. , Salazar G. , Chaparro D. , Geney G. , Ulloa J. 
Published: November 2015

Abstract
Determining hydrocarbon saturation in Colombian oilfields is particularly challenging for conventional methods since the formation water in most of the tertiary sand targets is extremely fresh, frequently in the 100 ppm to 3,000 ppm NaCl equivalent range. In these conditions, the uncertainty in resistivity and sigma-based saturation interpretation methods is huge. Recent advances in measurement technology and interpretation including the combined use of dielectric dispersion and radial magnetic resonance provide a considerable uncertainty reduction in water saturation and hydrocarbon mobility evaluation. These open-hole measurements have a very shallow depth of investigation (DOI) and provide valuable information from the flushed zone, at one to four inches within the reservoir.
A new, advanced nuclear spectroscopy tool conveyed on wireline makes a direct total carbon measurement at a DOI from four to nine inches within the reservoir. When the inorganic mineral carbon is subtracted from the total carbon measurement, the resultant total organic carbon (TOC) can be used to directly compute formation hydrocarbon volume and saturation. Validation is available from the slightly shallower dielectric-derived water filled porosity. These combined measurements provide a saturation profile independent of resistivity and salinity, and allow key reservoir evaluation parameters including hydrocarbon type and oil mobility to be evaluated more accurately.
In mature fields, slim carbon-oxygen logging has been the main technique historically for estimating oil saturation behind casing, given its salinity independency. In order to achieve a desirable statistical precision and accuracy, carbon-oxygen data with slim tools requires several logging passes over the zone of interest. A typical acquisition strategy consists of a sigma pass acquired at 1500 ft/h and three or more carbon-oxygen passes acquired around 120 ft/h. In addition to borehole fluid sigma and salinity, these measurements provide information on formation porosity, lithology, matrix properties and oil saturation.
The advanced spectroscopy tool was run in the same wells as the slim carbon-oxygen devices. Comparison of measurements from both services indicates that the advanced spectroscopy device is capable of providing lithology, matrix properties and hydrocarbon volume and saturation from TOC with improved accuracy in a single logging run, at a logging speed five time faster that one single carbon oxygen acquisition pass from the slim logging device. The advanced spectroscopy tool also provides improved precision and the measurement of additional elements compared with previous generation tools, allowing for a more accurate computation of mineral components and matrix properties.
Feasibility of La Grita Member of Early Cretaceous as a Possible Unconventional Reservoir Play. Case Study. Western Venezuela
Authors: Méndez J. N. , Molina A. , Lobo C. , Pautt A. , Luzardo F. 
Published: November 2015

Abstract
This research has been carried out in an area of 678 km2 to the southwest of Maracaibo Lake Basin, where the lower La Grita Member of Early Cretaceous Capacho Formation has an average depth of 7600 ft (2.31 km). La Grita Member consists mainly of calcareous dark grey and laminated shale with oil traces, deposited at about 80 ft (24.38 m) which span from uppermost Albian to Cenomanian. This member represents a transgressive cycle associated with the low section of La Luna Formation (main oil and gas source of the western Venezuela). Besides, this research area has some relative flat in the Cretaceous section with little tectonic affectations, which allow developing unconventional reservoirs.
The methodology proposed by Kuuskraa et al. (2013) to assessment an unconventional reservoir play was used in multidisciplinary studies. A total of 35 wells, one well core, several 2D seismic data, electric logs and geochemical analysis were considered to carry out this study. To make petrophysical analysis the methodology of Passey et al. (1990) was used.
The geochemical data in core samples indicated that this interval shows good conditions for oil generation, where the organic matter percent is between 4.5 – 7.5% of TOC, with a maturity profile in oil window (0.5 – 0.9% Ro). The sedimentation environment suggests that the organic matter is marine. Lithologic description of drill core exhibits calcareous shales with muddy appearance. The Member is composed mineralogically by quartz/feldspar (32), calcite (50%), clay (15%) and other minerals (3%). The brittleness index of the member is around 77%. The electric logs in Member exhibit high radioactivity in some zones possibly associated to abundance of organic content. The petrophysical model matches with core samples results, where the intervals observed with high radioactivity were associated with organic richness. The geomechanical characterization in the area reveals that the state of stress in situ was estimated as normal to transcurrent. Mechanical properties of unit show moderate values of Poisson's ratio (0.23 – 0.26), high values of Young's modulus (0.88 – 4.46 * 106 psi) and UCS (6000 – 13500 psi). The Member can be classified as brittle, according to methodology of Grieser and Bray (2007). Finally, the geochemical and geological features of the member allow suggesting a possible oil play in this area. Moreover, the brittleness index and mineralogical analysis show excellent properties to horizontal hydraulic fracking of rocks.
La Grita Member has never been considered as rock generater of oil in the area. However, the member has reservoirs associated where wells produce oil through natural fractures of the unit. In these reservoirs oil production decrease quickly, affected by low permeability of rocks.
Improved Waterflood Analysis Using the Capacitance-Resistance Model Within a Control Systems Framework
Authors: Holanda Rafael Wanderley , Gildin Eduardo , Jensen Jerry L. 
Published: November 2015

Abstract
The Capacitance Resistance Model (CRM) is a fast way for modeling and simulating gas and waterflooding recovery processes, making it a useful tool for improving flood management in real-time. CRM is an input-output and material balance-based model, and requires only injection and production history, which are the most readily available data gathered throughout the production life of a reservoir. In this work, the CRM input-output relationship is explored by representing the CRM with state-space (SS) equations. The linear system SS equations define the relationship between inputs, outputs and states to completely describe system dynamics. The SS-CRM is a multi-input/multi-output (matrix) representation, which provides more insight into reservoir behavior than analyzing performance on a well-by-well basis. Thus, it is computationally faster and easier to apply in fields with large numbers of wells. The CRM parameters are estimated using a grey-box system identification algorithm. The matrix form of the CRM history matching and a sensitivity analysis to the CRM parameters estimates are presented. Minimal realizations and reduced order models are easily obtained with the SS-CRM approach. The performance of three CRM representations are analyzed: integrated (ICRM), producer based (CRMP) and injector-producer based (CRMIP). The methodology developed here is tested in two reservoir systems, homogeneous with flow barriers and channelized. We find that the ICRM does not reproduce the rate fluctuations as well as the CRMP and CRMIP. The CRMP works well for wells in low heterogeneity regions but not as well as the CRMIP in more heterogeneous areas, e.g. near the flanks of channel deposits. This new approach facilitates closed-loop reservoir management by enabling CRM's use for linear control algorithms, which can improve tracking performance and predictability, and is amenable to real-time optimization.
Increased Well Productivity from the Use of Carbon Dioxide to Foam Fracturing Fluids During a Refracturing Treatment in Saudi Arabia
Authors: Al-Dhamen Mohammed , Soriano Eduardo 
Published: November 2015

Abstract
CO2 has been a significant part of the advancement and development of hydraulic fracturing. This technology was proven in the 1970s as an energy source to help recovery of well stimulation fluids and is predominantly used to stimulate tight sandstone reservoirs because it is both clean and effective. The first application of CO2 in Saudi Arabia is discussed, highlighting its success in terms of 50% increased productivity, quick cleanup, and reduced water volume.
Classically, conventional hydraulic fracturing (acid or proppant) has been used to maximize long-term production and minimize near wellbore (NWB) damage. This paper discusses how CO2 fracturing can offer more advantages by reducing or eliminating the use of the underground water. It also provides a gas drive solution for effective cleanup. CO2 can be used to significantly reduce interfacial tension and resultant capillary forces, thus helping remove fracturing fluid, connate water, and emulsion blocks, which are among the primary damage mechanisms when fracturing gas wells.
CO2 has been a significant part of the advancement and development of hydraulic fracturing since the 1970s, but mostly just in the US during those early days. This paper discusses in detail the first application in Saudi Arabia using CO2 to foam a proppant fracturing treatment. The implementation of this technology was successful. This was demonstrated by the resultant 50% productivity increase in the study well. Using this method allowed a very fast and effective cleanup compared to other wells fractured using conventional crosslinked fluid methods. Additionally, using this method provided the added benefit of reducing water volume, which is a critical factor in this area because of limited water availability.
The first CO2 application in Saudi Arabia is discussed, highlighting its success in a resultant 50% productivity increase. The method allowed fast and effective cleanup compared to wells fractured using conventional crosslinked fluids. Additional benefits included reduced water volume, which was critical in this area because of limited resources.
A Tuning Strategy to Align Static and Dynamic Modelling
Authors: Bourge J.-P. , Bolaños M. J. , Lafournère J.-P. , Naranjo Leon M. A. , Vega Torres J. , Archard G. , Suter A. , Castillo F. 
Published: November 2015

Abstract
The main aim of geological modeling is to include all available data, such as seismic data, well logs, and core data, and to combine these data with more descriptive information, such as the geoscientist's understanding of the conceptual geological model and their experiences in similar environments, to predict the reservoir properties between the wells. However, in many cases, when the static model is passed to the reservoir engineer for history matching, the detailed geological knowledge and uncertainty is not fully utilized. This can lead to a model that may match the production data but actually has very little predictive power.
Depositional maps provide very useful constraints on model building. By giving a visual representation of the geological context, they can incorporate well and seismic information and the dynamic characteristics recognized from the production data, tracer information in cases of water injection, and pressure information. However, there always remains a degree of uncertainty with respect to the geometries and orientations of the geobodies, so the tuning of the maps is, by definition, an iterative process. This coupling between static and dynamic modeling is critical to achieve true discipline integration, aiming to retain the key information from each domain.
This paper presents an iterative technique to update these depositional maps in the areas of uncertainty between the wells. The required changes to honor production data and reservoir pressure trends during the history match are translated into facies modifications that are validated in terms of being consistent with both the control well data and with the conceptual depositional model.
This methodology was applied to the modeling of Shushufindi field, Ecuador. The long-term field development plan is being guided by a fine-scaled geocellular model that was designed to capture the geology at a high resolution. The workflow adopted required the collaborative efforts of the geology, geophysics, petrophysics, and reservoir engineering team members throughout the entire process.
Modeling Wax Appearance Temperature
Authors: Rocha T. S. , Costa G. M. , Embiruçu M. 
Published: November 2015

Abstract
Wax precipitation is one of the most important flow assurance problems that cause a decrease of oil production rates, an increase of energy consumption and failure of facilities. A very simple and accurate model can be used as a fundamental tool to predict and prevent solid precipitation at different conditions. An extension of the Won (1986) model is presented that calculates the Wax Appearance Temperature (WAT) considering the temperature dependence of the solubility parameters of the individual components in the liquid and solid phases as well as the molar volumes of the individual components. In addition to predict WAT, the liquid and the solid composition in equilibrium are estimated without having available the Paraffins, Naphtenes and Aromatics (PNA) analysis. Results are compared for 18 oils from literature data. Regarding the experimental data it is enough to know only the molar fraction and the molecular weight of each component. Even if the oil composition is known only up to C7+ fraction the extension of residue is possible through Pedersen et al. (1989) method. A percentile absolute average deviation of about 2% to 3% for WAT was obtained.
Wellbore Stability Analysis: A Stochastic Approach Applied to a Colombian Cretaceous Formation
Authors: Plazas F. , Calderon Z. , Quintero Y. 
Published: November 2015

Abstract
Implementing a stochastic approach along with the conventional wellbore stability analysis enables to take into account uncertainty from input data in order to obtain more realistic and reliable predictions which improve decision making process in drilling operations. By means of the methodology proposed, the uncertainty assessment for each parameter can be addressed through distinct methods depending on available information, and a sensitivity analysis is used as complement to the Monte Carlo Simulation to identify those lesser impact variables which can be treated as deterministic values and so that processing time is reduced.
As result of this workflow, quantified uncertainties are propagated into model and probability distributions for collapse and fracture mud weights are generated, and a mud weight window as a function of success probability for drilling without instability problems is built. Ultimately, a study case is developed to assess the probabilistic mud weight window for a drilling process in a Cretaceous Colombian formation.
Predictability, Distribution and Characteristics of the Unconventional Resources in Latin America
Authors: Gomez M. G. , Rebay G. , Robles F. , Hurtado M. 
Published: November 2015

Abstract
An investigation of the factors controlling the regional distribution of unconventional reservoirs - organic rich shales / carbonates - in Latin America, included the analysis and identification of the vertical relationship and characteristics between the reservoirs of different basins. The analysis provided evidence to understand why different formations in different basins have similar potential and supports a proposed interpretation.
The study is based on the analysis of the main source rocks which are being developed or targeted as unconventional reservoirs. These reservoirs grouped by basin, age, formation, and characteristics such as depositional environment, extension, lithology, thickness, depth, organic content, and kerogen type were analyzed. More than 20 basins in Latin America and 30 formations considered source rock, from Silurian to Cretaceous, have been evaluated (Figure 1). The paleogeography, in particular the distribution of the marine and terrestrial environments, at the moment of the deposition of these rocks was used to understand their presence and distribution in the subsurface.
Figure 1 Evaluated Basins, Organic Rich Shales and Age.
The distribution of relevant Latin America's unconventional resources is related to a sum of very well-known global factors closely associated with the extent of the Jurassic- Cretaceous seas in times of high eustatic levels, when most of the sediments generating unconventional resources were deposited. Proper interpretation and knowledge of the distribution of Mesozoic seas and their coeval events enables predicting the location of unconventional reservoirs, understanding the reason for their existence, and anticipating the main characteristics to be found in these rocks.
The geographical distribution of some of the most representative unconventional reservoirs in the main basins of Latin America relates to the regional event causing the deposition of these rocks during the Upper Cretaceous. Sediments of this age include formations in the north of South America, such as La Luna, Querecual, Naparima Hill and equivalents, which are synchronous with deposits such as Eagle Ford and Agua Nueva formations. The Upper Jurassic and Lower Cretaceous comprise a second group of unconventional reservoirs among which is the extended Vaca Muerta formation.
Understanding the relationship between occurrence, genesis and distribution of unconventional reservoirs in Latin America is fundamental to predicting the presence of these reservoirs, using global factors such as tectonic plate distribution and sea level. The summary with the characteristics of each of these reservoirs can be used as a guide to understand the magnitude of the hydrocarbon potential.