bluuebunny/crossref_metadata_2025 huggingface dataset:
Energy Efficiency Scenarios Following the Energy Trilemma - Argentina's Commitment to COP21
Authors: Cervantes-Bravo R.J. , Ñaupari-Barzol H. , Jimenez-Nieves E.T. , Magnelli D. , Dabrowski A.
Published: May 2017

Energy efficiency in the framework of the energy trilemma will guide to energetic policies focused on economic growth and development of the Developing Countries. Many of the International Organizations: such as the International Energy Agency (IEA) agreed to promote the rational use of the expressed sources in reducing energy intensity to mitigate accelerated climate change through the reduction of CO2 emissions as agreed at COP21 in Paris.

The transition from Oil to Natural Gas in Argentina was marked in the years 1994 - 1999, because of an intense productive activity, causing an exponential increase in consumption. Although, if the Natural Gas less pollutant than oil, currently, the change in the matrix, did not report a reduction of C02 as expected due to the lack of technology and the rational use of these sources as energy. This implied that currently, the share of fossil fuels in the energy matrix more than 84 % above dealer, with nearly 51.1 % of Natural Gas.

Therefore, the study focuses on the energy security of Argentina's growing energy demand and environmental Commitments; through, increased energy efficiency with the assumptions in reducing Energy Intensity towards a more sustainable energy trilemma to the medium and long term. It is worth mentioning that the reduction of the total demand of a country is associated with levels of energy efficiency. In our case, by 2035 an increase in energy efficiency of 19% could we reduce demand 36%; that is, a reduction in energy intensity of 29 % compared to 2015.

The scenarios with reduction in energy intensity by 2035 are 1 %, 1.5 % and 2 % annually, which will involve a reduction in the consumption of primary sources and consequently a reduction in CO2 emissions of 5.3%, 14.4% and 20.2% respectively in each case. In this way, we could diversify the energy matrix progressively, towards more sustainable developments.

To project the demand for primary sources from 2015 to 2035, it is necessary to design a macro-econometric model, based on an annual GDP growth of 2.77% and the projection of energy intensity according to 3 proposed scenarios. Then the relationship population country / world, will enable us to project the maximum allowable CO2 emissions by 2035, with a commitment not to increase the temperature more than 2 °C by 2100 and the commitment of Argentina with COP21 to reduce 15% CO2 emissions by 2030.

Finally, the overall objective of the research will be to adjust energy policies of the country in the medium and long term through of the Evolution of Energy Matrix Primary versus the Evolution of Energy Efficiency, under the precept of securing the demand and comply with COP 21 under a more sustainable energy trilemma.
Optimizing Well Spacing of Multi Fractured Tight Gas Wells in Argentina's Lajas Formation through High Resolution Simulation: Barrosa Norte Field Case Study
Authors: Francos J. P. , Wagner F. , Coppo R. , Santiago E.
Published: May 2017

The area denominated Barrosa Norte, located in the south of Los Barreales and Mari Menuco Lakes (Neuquén Province, Argentina), is the most important Tight Gas development of YPF along with Sierra Barrosa and Aguada Toledo anticlines. Gas production from the unconventional Lajas Tight Gas formation in Barrosa Norte field is increasing as a result of an intense exploitation strategy since its discovery in 2014. Although multi fractured wells have already demonstrated the potential of the Lajas formation in the Neuquén Basin, optimization is still ongoing to determine the optimum well spacing.

The objectives of this paper are:

– To describe the methodology used to build a high resolution numerical model that represents the multi fractured wells in Barrosa Norte field – To present the results of an uncertainty and optimization study that narrows the range of the different uncertainty parameters defined – To describe and to present the infill development strategies evaluated and the optimum well spacing defined for the Barrosa Norte field

A high resolution simulator and a complex automatic workflow in a pre/post processor were used to achieve a history matching of observed production and pressure data of Barrosa Norte wells at well level and at hydraulic fracture level. This was achieved after an uncertainty analysis, which narrowed the range of uncertainty of different parameters, and after the application of optimization algorithms.

The multi fractured wells were modelled through a novel LGR approach to take into consideration the tilt of the reservoir. Several combinations of parameter values were obtained that satisfied the history match, resulting in a range of solutions. Finally, different infill development strategies were evaluated until the optimum well spacing was achieved.

The traditional LGR method for modelling hydraulic fractures is not best applicable in tilted reservoirs. Therefore an extension of the LGR method was developed proving to better characterize hydraulic fractures. The development of an automatic workflow in a pre/post processor proved to be a key tool for assisted history matching. On top of this, the use of uncertainty and optimization algorithms accelerated the achievement of results.
Use of Interference Tests to Constrain the Spacing of Hydraulically Fractured Wells in Neuquen Shale Oil Reservoirs
Authors: Chen T. , Salas-Porras R. , Mao D. , Jain V. , Thomas M. A. , Kruijs E. , Huckabee P. T. , Stephenson B. J. , Scholten S. O.
Published: May 2017

Well spacing is a key factor in the evaluation of pad economics for hydraulically fractured horizontal wells. The drilling at the wrong well spacing leads to either over-capitalization risk or leaving reserves in the ground both resulting in loss of net present value risk. This paper presents data acquisition techniques that aid in well interference identification and quantification. Integrated analysis of data from a well pad in the Vaca Muerta formation, including microseismic, chemical tracers, geochemical fingerprinting, and pressure measurement, indicates both pressure and production communication between the two wells studied. Then a dedicated interference test is designed and analyzed to provide insights on well spacing. The test consists of alternating shut-in periods of the two wells during which pressure and rate are closely monitored. Analytical and modeling work has quantified the degree of interference to be up to 20% on production rates. This interference test is performed between two ‘semi-confined’ wells. Future multi-well pads are planned to understand the production potential of a fully ‘confined’ well and the interference between neighboring wells, to further understand the well spacing and pad economics.
Historical Production Analysis of VacaMuerta Formation in the Neuquén Basin: A Guide to Understand the Past, Present and Future
Authors: Tagarot-Seadi G. , Vicente M. , Luongo S. A.
Published: May 2017

In this study, the historical production of VacaMuertais evaluated aiming to capture the complexities of this formation in terms of fluids production and recovery performance. This paper integrates the Neuquén province production analysis with the objective to understand the oil and gas historical production behavior in a development area of roughly 12,000 sq mi (31,000 km2).A comprehensive evaluation using public data was conducted to present the contribution and the impact of VacaMuerta oil and gas production on the region and the country.

The VacaMuerta formation represents the most-challenging source of new oil and gas in Argentina, with a huge potential considering the size of the development area in any block across the basin, the reservoir gross thickness and the resulting fluids in place, and the way forward to be achieved regarding the balance between well cost reduction and productivity improvement. There have been important drilling and development efforts in the last 4 years in which both vertical and horizontal wellbore configurations have been implementedand tested over the longterm. However, there are still uncertain factors under evaluation to assess the VacaMuerta formation performance, which achieved 29 million barrels and 124Bcf in December 2016, with 674 oil and gas producer wells.

The workflow focuses on the analysis of historical production for both vertical and horizontal wells, average rates and cumulative production of initial 6 and 12 months, water cut and gas-oil ratio (GOR), decline analysis and vintage performance, with the addition of heterogeneity index plots. Production history statistics and probabilistic analysis were incorporated in the study to summarize and present the evaluation results. Important aspects related to well decline behavior and estimated recovery for the initial years were also analyzed.

In this paper, we present the main findings and results of a complete production analysis of VacaMuerta formation after more than 10 years of production. This paper provides an overview of the historical production performance and the key elements for production forecasting. The integration of this production information with geology, reservoir characterization, well design, and completion and operation strategies provides an essential reference to improve the understanding of the production potential and the visualization and ranking of any well, field, or area in the Neuquén basin.
First Project of Auto-injection in Patagonia Argentina
Authors: Bogan F. , Ordoñez M. N. , Pyczil D. , Salvarredy Aranguren M. , Verde R.
Published: May 2017

This contribution presents the concept of auto-injection with mechanical pump, as an alternative to the initial stage of a waterflooding project without the prior need of building a water treatment and injection pilot plant, aqueducts and injection lines (facilities). This case of study shares the results of this technique applied for first time in the development of a marginal oil field called Cerro Piedra, operated by YPF on the western flank of San Jorge Gulf basin (Patagonia, Argentina).

The auto-injector, unlike a multilayer conventional injector, is self-sufficient and simple injection. It produces and injects briny water in the same wellbore; it is not required to invest on facilities to evaluate waterflooding response. Moreover, it forwards the start of injection and consequently quickens the reservoir's response improving project's profitability.

The fluid enters to the mechanism's circuit by a crossflow piece, where a hollow mechanical pump, driven by an individual pumping unit and hollow rods (4,600 ft maximum depth), produces up to 700 STB/D of water to the wellhead and pressurizes it up to 2,000 psia. At the surface, a measuring bridge registers flow, pressure and temperature. Finally, the pressurized fluid reenters to the well by the annular tubular-rod and passes through the crossflow piece to the injection zone.

The oil field is located 75 miles far away from Las Heras (Santa Cruz, Patagonia Argentina) and 40 miles from the nearest water treatment plant. The San Jorge Gulf basin is filled by a sequence of fluvial sediments which generate thin and low areal extent multilayer reservoirs. Bajo Barreal sedimentary unit is characterized from top to bottom by: briny water levels (3,500-8,000 ppm) to oil productive levels reservoirs. This distribution allows the auto-injector to produce shallow briny water layers and inject it into deeper hydrocarbon reservoirs.

The project includes an initial pilot phase to evaluate the waterflooding response, established with five auto-injectors; an intermediate stage of full development, developed by the completion of the water treatment and injection plant and conversion of eight selective injectors; and a final conversion phase, where the auto-injectors are reconverted to traditional injectors.

This auto-injection strategy allows us to evaluate the waterflooding response in a marginal virgin zone, without needing to build facilities for water treatment. Therefore it gives a sustainable water management of the field. This alternative approach improves at least 2% of original project's profitability, which was planned with the construction of an injection pilot plant.
Automated MPD System in Offshore Gulf of Mexico Further Substantiates Value of Drilling Technique in High-Pressure Zones
Authors: Barbosa Alberto , Gallego Gilbert , Clemente Fabricio , Padilla Rivelino , Mondragón Gabriel Enrique , Balderas Jose Antonio
Published: May 2017

This paper presents a case history that demonstrates the benefits of drilling using automated managed pressure drilling (MPD) technology rather than conventional equipment. Primary factors for the comparison include drilling time, volume of fluid losses to the formation, and performance drilling statistics.

Automated MPD technology provided a non-conventional approach to achieve the main objective during this project. The goal was to reach the planned total depth (TD) in the 8 1/2-in. well section that has a high-pressure zone while reducing pressure-related nonproductive time (NPT). An automatic monitoring and reaction system was used to identify and control undesirable events—such as influxes, losses, ballooning, or all of the above—even when there was no longer a visible operational drilling window available (judging from the pore pressure, collapse pressure, and fracture pressure). Using the automatic MPD system enabled the driller to exercise precise control over bottomhole pressure (BHP) during the entire drilling process, to locate the perfect balance point, to minimize fluid losses and potential influxes, and to drastically reduce NPT.
Shale Reservoir Characterization Using LWD Azimuthal Sonic and Advanced Gas Detection
Authors: Mejia C. , Crosby Z. , Barnett C. , Heard S. , Llanos D. , Marchal D. , Porras J.
Published: May 2017

Unconventional reservoirs such as the Vaca Muerta formation in Argentina continue to be an important source of oil and gas, and represent a vital source of energy for specific segments of the global market. Achieving technical and financial objectives when developing such reservoirs requires operators to manage operational costs while still obtaining sufficient geological, petrophysical, and geomechanical information to successfully evaluate and develop the reservoir. In a recent Vaca Muerta exploration well, LWD resistivity and azimuthal sonic measurements were combined with advanced mud gas analysis of C1 to C8, toluene, and benzene gas components. These two data sources, acquired while drilling, were used in an integrated petrophysical analysis which characterized the stratigraphic variation of key reservoir parameters and geomechanical properties to identify sweet spots for further horizontal well development.

Geomechanical analysis from azimuthally oriented LWD slowness measurements revealed stressinduced anisotropy by identifying the splitting of shear slowness around the wellbore. The comparison with wireline sonic and micro-imaging tools in the same well confirmed the relatively isotropic acoustic response (2-3 % anisotropy) in the upper section and a more anisotropic acoustic response (7-9 % anisotropy) in the lower section of the Vaca Muerta. Additional mechanical properties such as elastic moduli were calculated to evaluate fracability, and the unconfined compressive strength (UCS) was correlated to the mechanical specific energy (MSE) from drilling mechanics measurements to monitor drilling efficiency.

Mud gas ratio analysis revealed variations in reservoir thermal maturity, identifying wet gas and dry gas intervals, while LWD resistivity and sonic data were used to compute TOC (using the Passey overlay method), porosity, and water saturation. The key reservoir quality parameters (TOC, porosity, water saturation, thermal maturity, and clay volume) were then combined with geomechanical properties (Poisson’s ratio, Young’s modulus, and UCS).The resulting interpretation provided a continuous evaluation of the entire Vaca Muerta sequence, facilitating zonation and selection of potential landing points for horizontal development wells.

This comprehensive evaluation from the integration of the LWD azimuthal sonic and advanced mud gas analysis demonstrated a cost-effective solution to characterize the formation which enhances real-time decision making, and provides the basis for optimizing well placement and completion strategies in the Vaca Muerta formation.
Detailed Modeling of Carbonate Acidizing by Coupling a Multi-Purpose Pore-Network Simulator to the Chemistry Package PHREEQC - Application to Chelating Agents
Authors: Ameri A. , Raoof A. , Blonk N. C. , Cnudde V.
Published: May 2017

In this study, an effective method is developed to couple the multi-directional pore-network (MDPN) model, called PoreFlow, with the chemistry simulator PHREEQC in order to simulate the reactive flow of chelating agents into carbonate media. A novel method based on solving a 1D chemical reactions and projecting the chemistry in the 3D pore scale flow field is developed, which significantly increased the computational efficiency. Results from several simulations are presented to demonstrate the capability of PoreFlow and the developed method to mimic reactive transport of chelating agents in porous media. It is also shown that the interactions between chelating agents and carbonate rocks can be accurately modeled by implementing the proper multi-step protonation kinetic of chelating agents versus pH. The developed model is capable of computing the change in porosity and the 3D flow field due to calcite dissolution by the progress of chemical reactions. In addition, the evolving flow model provides the corresponding relationship between porosity and permeability for a specific porous media. The model successfully reproduced the experimentally observed permeability changes due to the creation of wormholes at various acid flow rates. The results are validated by comparing the simulation outputs to the micro-CT images taken from the samples after the chelating experiments. Moreover, it is shown that the average dissolution rate for heterogeneous carbonate rocks is not only governed by the pore-scale physical heterogeneities but also by the local chemical equilibrium and speciation of chelating agents at various pH values.
Prediction of PVT Properties in Crude Oil Using Machine Learning Techniques MLT
Authors: Ramirez A. M. , Valle G. A. , Romero F. , Jaimes M.
Published: May 2017

A new mathematical model is proposed using machine learning techniques for estimating PVT fluids properties such as bubble pressure and oil formation volume factor as a function of the solution gas-oil ratio, gas specific gravity, oil specific gravity, and temperature.

The result obtained with this new approach are compared with previous published correlations. The proposed method for PVT properties estimation consists of two stages: data decorrelation through Principal Component Analysis (PCA) and PVT properties estimation through an Artificial Neural Network (ANN). Data decorrelation is used to reduce redundancy in the data, which decrease the number of neurons and hidden layers needed for an ANN to achieve a high accuracy estimation. In the development of the proposed method there were used 504 points obtained from the literature as follows: 360 for training, 40 for cross-correlation and 104 for testing. The present model was compared with empirical correlations of PVT fluids properties in terms of absolute average percent error, standard deviation, and correlation coefficient; using worldwide experimental PVT data.

The results obtained show that the proposed model provides better estimation and higher accuracy than the published empirical correlations. The present model provides predictions of the bubble pressure and formation volume factor with a correlation coefficient approximately of 98%. Trend tests were performed to check the behavior of the predicted values of bubble pressure and formation volume factor for any change in reservoir temperature, solution gas-oil ratio, gas gravity and stock-tank oil gravity.

The model was based on artificial neural networks, and developed using 504 published data sets from the Middle East, Malaysia, and North Sea fields. This improvement in PVT calculation accuracy will be of invaluable support for simulations and designs applied in Oil industry.
Visualization of Opportunities through Quick Workflows and Methods for Reservoir Characterization and Correlation
Authors: Saccomano A. F. , Limeres A. C.
Published: May 2017

The purpose of this paper is to present some alternative workflows and methods that can be used for a quick initial reservoir characterization. We apply these methods in different fields to analyze stratigraphic correlation, sand distribution, and recovery opportunities.

We analized Spontaneus Potential (SP) and Resistivity (R) logs, the only two curves run in the wells of the old mature fields studied. We built envelope curves for them, which are moving window averages that capture SP or R values for shales and clean sands. These curves are applied to compute the shale volume (Vsh) as an automatic multiwell process that takes into account formation and well variations in a simple way. We compared this Vsh with a traditional petrophysiscal interpretation and showed good validation results in many oilfields. We used this Vsh to build a simple sand-shale log and then a 3D model, analyzing spatial trends and connected volumes, which helped visualize main production units and waterflooded intervals. By means of simple calculations, it is also possible to determine non perforated hydrocarbon-bearing sands, and obtain a list of workover opportunities in a quick way. Zones for a possible EOR project could also be determined.

Additionally, we computed a derivative for the base envelope curve of R, which shows large scale variations in rock properties. We find vertical patterns in wells that can be followed for long distances, showing great lateral continuity, and helping determine a stratigraphic correlation between different oilfields. Although it has low resolution, it captures the main stratigraphic features.

Lastly, we computed a probabilistic forecast in 3D for each fluid type observed at swabbing tests. This is a routine workflow based on nearby swabbing tests, and should be simply used as a quick guide.

The envelope curves proved to be useful for a quick log normalization, baseline shift correction, Vsh calculation, and regional trend analysis. All these approaches are very effective in big fields with hundreds of wells and multiple layered reservoirs due to the speedy methodology. They are useful in visualization stages as an initial project overview.
A Novel Correlation for Predicting Permeability Impairment Due to Calcite Deposition in Sandstone Porous Media
Authors: Santos N. , Carrillo Moreno L. F. , Carreño Hernandez J. H. , Rodriguez Molina J. J. , Martinez Lopez R. A. , Modelamiento de Procesos Hidrocarburos G.
Published: May 2017

Formation damage due to calcite deposition is currently an issue in the five sedimentary basins producers of hydrocarbons in Colombia. At this moment, over 100,000 BOPD are in risk due to this kind of damage. A lab-scale correlation is developed which contemplates thermodynamic and hydrodynamic parameters for predicting the Calcium Carbonate formation tendency in Sandstones. An experimental methodology to recreate the continuous deposition of CaCO3 was implemented using Berea sandstones, scalating different production rates and varying the physicochemical composition of the formation water, reproducing accurately the concentrations of the ions Ca++ of Colombian oilfields (consisting currently the biggest issue in this sort of formation damage). The used methodology consisted in a factorial experimental design, which allows the optimal combination of thermodynamic parameters (represented by the Ca++ concentration) and hydrodynamic parameters (represented by injection rates), along a series of rock-fluid interaction experiments which exhibited a permeability impairment of approximately 80%. The correlation was developed using a specialized software. The proposed correlation predicts the permeability impairment with an 80% adjustment of experimental data. This correlation is valid for low permeability values (less than 150 mD), field-scale velocities between 1 and 10 ft/day, and contemplates regular values of Ca++ ions concentration for Colombian oilfields. Furthermore, the correlation was validated with experimental data obtained at several flow rates (between 1 and 3 cc/min), several temperatures (150 -250°F) and several concentration of Ca++ ions (250-650 ppm). This proposed correlation is the basis to develop a deterministic model, which quantifies the depth, severity and production losses related to this phenomenon.
Impact of Clay Type on SAGD Performance Part II: Microscopic Scale Analysis of Clay-Sand-Asphaltene Interactions in Spent Rock
Authors: Kar Taniya , Hascakir Berna
Published: May 2017

This study focusses on the impact of wettability alteration of reservoir clays on the overall efficiency of Steam Assisted Gravity Drainage (SAGD). Samples from two SAGD experiments were investigatedSAGD1, consisting of kaolinite in the oil-sand packing and SAGD2, consisting of a mixture of kaolinite (90 wt%) and illite (10 wt%). The residual oil saturation from two different zones (inside steam chamber and steam chamber edge) from each SAGD experiment was determined from spent rock samples. Series of systematic optical microscopy analyses were carried out on clay-sand and clay-sand-asphaltene mixtures under steam and water exposure to represent the inside steam chamber zone and steam chamber edge, respectively. The higher residual oil saturation for SAGD2 was associated with the wettability alteration of illite in the reservoir at the steam chamber edge, leading to significant illite-asphaltene association. The pore-bridging property of illite was also observed, adversely affecting reservoir permeability. Kaolinite-asphaltene interactions in the presence of liquid water, on the other hand, were found to be temporary and not binding. Our findings suggest that wettability of clays plays an important role in determining the efficiency of SAGD process, controlled mainly by the polar asphaltene fractions in bitumen reservoirs with high asphaltene concentrations.
Dual Porosity Modeling for Shale Gas Wells in the Vaca Muerta Formation
Authors: Manestar G. J. , Thompson A.
Published: May 2017

The Vaca Muerta shale has been developed for oil and gas production since 2010 and to date nearly 500 wells have been drilled. The large amount of static and dynamic information from these wells has enabled fracture design and production strategy optimization. This paper details the methodology used to integrate all available data in 3D models, in order to understand the impact of rock properties in the production.

The model was simulated using a commercial reservoir simulator, showing that hydraulic fractures are acting as a dual porosity system with a large conductivity (~10 D) connecting a low permeability matrix (~100 nD).

We studied multiple wells in the history match (HM), using separator pressure and choke size as the control variables for the wells, and rates and pressures as comparison variables. A multi-segmented well approach was used to describe the pressure drop inside the well, and a vertical lift performance (VLP) table to describe the flow from the tubing all along to the separator including the wellhead choke.

The static model included the seismic interpretation, stratigraphic framework, geomechanical and petrophysical characterization. Rock permeability, initial pore pressure and total fracture pore volume were calibrated with field measurements used as constraints in the HM process.

Fracture conductivity degradation was introduced in the model to explain observed changes in the wells productivity. Laboratory tests are being designed to validate these hypotheses.

We established early in the project that individual well HM were not unique. It was only through the HM of multiple wells that we were able to reduce the range of uncertainties affecting well performance (matrix permeability, initial water saturation and fracture height). This has given us a more reliable tool to obtain ultimate recovery estimation ranges.

The described model showed a good prediction of a well with water lift problems, giving an accurate forecast for the incremental gas rate after a tubing diameter change. We concluded that the multi-segmented well model is a good representation of the water hold-up fraction behavior.

This methodology enables us to integrate all the knowledge of the subsurface into a model that can be run in short simulation time (~30 minutes), allowing us to iterate quickly during the HM process. The model can be run for single wells or multiple wells and is flexible to adapt for new areas.

We plan to use this methodology to design and monitor pilots in new blocks and to evaluate different development plans for existing projects.
Evaluation of Mobility Control with Nanoparticle-Stabilized CO2 Foam
Authors: Emrani A. S. , Ibrahim A. F. , Nasr-El-Din H. A.
Published: May 2017

CO2 foam has been used for different oil and gas applications such as hydraulic fracturing and enhanced oil recovery (EOR). Foam is used as a fracturing fluid to develop unconventional reservoirs and specifically water-sensitive reservoirs. It is also employed as an EOR fluid to control fluids mobility and improve sweep efficiency. Moreover, using foam as a hydraulic fracturing fluid provides rapid cleanup during flowback. Although it is common to use surfactants to generate and stabilize foams, they tend to degrade at high-temperatures (>212°F) and in high-salinity environments. Adding nanoparticles is a new technique to stabilize CO2 foams that supports the proppant-carrying requirements for fracturing fluids. The present work evaluates new foaming solutions that incorporate nanoparticles to investigate the mobility-control performance when these foams are used as hydraulic fracturing fluid.

This study specifically investigates the effect of nanoparticles on the stability of alpha olefin sulfonate (AOS) foam and the corresponding mobility-reduction factor (MRF), which indicates the apparent fluid viscosity at high-temperature and high salinity. To achieve this objective, foamability and foam stability tests were conducted at 77 and 150°F. Foam stability was studied for various solutions using a high-pressure view chamber (HPVC) setup to find the optimal solution, at which higher foam stability in the CO2 foam system can be reached. Coreflood tests were also conducted on different Buff Berea sandstone cores at both 77 and 250°F. CO2 gas was injected with the different solutions simultaneously to generate foam with 80% quality. The pressure drop across the core was then measured to estimate the MRF.

The results of this work show that foam half-life decreases as the temperature increases from 77 to 180°F. Nanoparticle-based foams are more stable over time compared to those stabilized by surfactant. AOS, as an anionic surfactant, improves the MRF by 300% compared to brine alone. Adding silica nanoparticles to the AOS solution improves the foam stability and increases the MRF eight-fold. At 250°F, the AOS solution retained foam stability, while the MRF increases to 28 compared to foam at room temperature.

Surfactants may degrade at high temperatures, and hence, cannot be used to stabilize foam. Protecting surfactants from being degraded and improving the foam stability is of great importance and can be achieved by adding nanoparticles to the solution. Nanoparticle solutions can be used to improve CO2 foam stability. Adding nanoparticles is highly recommended for hydraulic fracturing applications, particularly in fracturing stimulation at high-temperatures.
Mature Field Revitalization Using Polymer Flooding: Palogrande - Cebú Field Case
Authors: Pérez R. , Castro Garcia R. H. , Jimenez R. , Maya G. A. , Leon Hinestrosa J. M. , Reyes J. D. , Mendez A. , Castillo Mejia A. F. , Romero M. P. , Fernandez Bedoya F. , Quintero Roa L. M. , Quintero H.
Published: May 2017

Increasing oil recovery by water injection is the most extended technology in the world; however, excessive water production is one of the main threats for the longevity of oil fields. It results in increased production cost and higher capital investment requirements in surface facilities to produce and handle water. To revitalize mature fields Ecopetrol has taken major steps in applying enhanced oil recovery methods (EOR) and some other technologies. Polymer flooding represents the most common chemical enhanced oil recovery (CEOR) method implemented at field scale as a strategy, increasing oil production and reducing water cut.

This work presents the implemented procedure during design, execution and monitoring of the polymer flooding pilot test as a strategy to revitalize Palogrande - Cebú field. Developed strategy for this pilot is described, incluiding operational and reservoir parameters analysis, injection facilities considerations, strategy for increase injectivity, water source characteristics, polymer solution quality (QA/QC) and vertical swept efficiency correction.

Polymer injection started in May- 2015. At december 2016, cumulative polymer injection reached 1.6 million barrels distributed between two injectors at a range polymer concentration between 200 – 1500 ppm and injection rates between 2000 – 3200 BPD per pattern. Production initial response has been positive with a cumulative incremental that exceeds the 85,000 barrels of oil with reduction of water cuts of up to 10%. Additionally, no polymer production has been detected in any of the offset producers of pilot injectors.

The polymer flooding pilot test have allowed the assimilation of learned lessons, best practices for continual improvement in the operation of such processes, incremental oil production; water cut reduction and increases in the fluid levels for the offset producers. Based on the pilot success, the feasibility of expanding this EOR method is evaluated as strategy to revitalize this field.
New Methodology for Pore Pressure Prediction Using Well Logs and Divergent Area
Authors: Velázquez-Cruz D. , Espinosa-Castañeda G. , Díaz-Viera M. A. , Leyte-Guerrero F.
Published: May 2017

The pore pressure prediction is the most important process in the design of drilling wells. This paper depicts a new methodology to analyze pore pressure based on both, the normal compaction theory of sediments and the way that normal behavior diverges when it is interrupted. Much has been written on the topic; however, even today a high percentage of non-productive time (NPT) in drilling activities is related to pore pressure and wellbore instability problems. Here, a new methodology is proposed to improve the accuracy of calculated pore pressure from well logs and seismic data. Moreover, this new methodology allows, under specific conditions, to determine pore pressure in carbonates and other reservoir rocks. The compaction process defines the normal trend of porosity indicators with depth, the fluid retention depth and those rock bodies diverging from a normal compaction trend. The divergence detection procedure includes the identification of both, transitional changes of the porosity indicators (shale) and those that are parallel to normal compaction trend (reservoir rock); they allow to build a divergent area. When the divergent area is defined, the pore pressure calculation can be done using a pore pressure model based on normal compaction theory and well logs or interval velocity data from seismic. Misleading prediction of geopressures for a particular area are linked to: misunderstandings of pore pressure origins there, the limited scope of pore pressure models based on well logs and to miscalculations of the key parameters of pore pressure models. This work discuss the impact of these key parameters in the pore pressure prognosis. Analysis of actual cases showing the impact of miscalculation of overburden stress on pore pressure estimations, normal compaction trend definition and pore pressure calculations are presented using divergent area along with the Eaton model. The conclusions support the following statements: well log density data cannot be used to calculate the overburden pressure and under some conditions, the divergence methodology can be used to calculate pore pressures in carbonates. Furthermore, the divergent area method eliminate the use of shale points in pore pressure prognosis.
Water Imbibition EOR Proposal for Shale Oil Scenarios
Authors: Tuero F. , Crotti M M. , Labayen I.
Published: May 2017

In Shale plays, EUR relies almost exclusively on "primary" production with practically no account for Enhanced Oil Recovery (EOR) practices. However, many remarkable facts are sometimes considered as "anecdotic" or pointed out as outliers, rather than including them as part of a coherent explicative model. Both, included in the literature and commented by the operators, we have repeatedly found many cases reporting such "anomalous" facts such as: (i) Low liquid recoveries during flow back periods, (ii) Rapid salinization of flow back water, (iii) Higher productivities correlating with lower percent of flow back recoveries, (iv) Early oil production right after flowback starts, (v) Shales described as "thirsty" or "dehydrated" (meaning lower water saturation than expected due to its pore geometry) and (vi) the evidence of huge capillary pressures, developed and supported by well documented overpressures.

After accepting these "anomalies" as an intimate part of the behavior of these non-conventional scenarios, we get many major consequences in the way we could develop and exploit them. Thus, we propose a new methodology that consists on a novel operative sequence to enhance oil production in multi stage frac Shale Oil scenarios.

The main mechanism involves countercurrent water imbibition processes, and consists of a cyclic scheme of (i) water injection, (ii) soaking and (iii) production periods that could be repeated until capillary effects fade out. This methodology, if proven successful, means a complete shift of the current exploitation practices, probably leading to a new paradigm in the way these unconventional resources could be developed and produced.

This proposal, if proved successful, should have a paramount impact in the appraisal and economics of these types of resources development, not only improving recoveries with low cost operations to transform resources into reserves, but also leveraging operational issues such as paraffin deposition, pressure maintenance, potential acid treatments, etc.

The approach involves a de risking process in three stages (i) conceptual, (ii) theoretical and (iii) experimental (lab and field tests). This paper describes the status of development of the analysis and the findings so far, which show encouraging results to continue imrproving the technique and perform additional field testing.
Real-Time Monitoring of Naturally Fractured Carbonate Reservoir Stimulation Using Distributed Temperature Sensing: Case Study from Offshore Mexico
Authors: Vazquez J. , Inda L. , Medina E. , Narvaez I. E. , Gleaves J.
Published: May 2017

Fluid allocation is a common challenge in the stimulation of naturally fractured reservoirs in offshore Mexico. Multiple or large pay zones with thief intervals can cause preferable fluid admission to such zones. Using distributed temperature sensing (DTS), fluid-treatment distribution can be monitored in real time for this type of reservoir, and modifications can be made on the fly to improve fluid coverage. Monitoring with DTS can help optimize treatment economics and improve productivity.

A reintervention to increase production in naturally fractured reservoirs involves improved stimulation schedules and the use of diverters to achieve fluid distribution across perforated intervals. Variable permeability and a potential for heterogeneous zones in the reservoir are a challenge for these types of wells. This document discusses a treatment performed to successfully stimulate a four-interval well using DTS measurements to monitor placement in real time. A gas-lift test was also performed during the monitoring operation to help identify the producing zone before the main stimulation began. The information gathered during the treatment helped the operator understand the production behavior of the well and acquire additional information for upcoming treatments.

During the well intervention, the following information was obtained to help determine the success of the treatment: Fluid allocation was verified during and after injectivity testing (including differential temperature gradient) to help determine initial admission zones. This information enabled an appropriate schedule to be designed for the acid treatment.A gas-lift mandrel was used, and the zone contribution was qualitatively evaluated during this test.The stimulation treatment and the diverter stages were monitored in real time. The percentage of admission was calculated for each open interval, and a correlation using previous production-logging-tool data was performed.Early flowback of the well was observed.

The production expected from the treatment was 800 BOPD. The stimulation treatment was considered successful, with an initial production of 1,050 BOPD (a 31% increase from the target). The information gathered during this treatment can also help modify upcoming treatments in the wells of this field with similar characteristics. Combined pre-treatment production monitoring and monitoring stimulation treatments in naturally fractured reservoirs using DTS helps identify the main producing zones and improves stimulation fluid distribution into lower-permeability intervals. This technique allows for performing treatment changes on the fly to attempt to achieve better zonal distribution and increase the productivity index in the wells.
Innovative Engineering Workflows as Part of Digital Oil Field Implementation for Production Optimization of a Gas Asset MEXICO, PEMEX AIV
Authors: Espinola O. , Castrejon R. , Yanez J. A. , Torres A. , Martinez R. , Guzman J. D. , Ramirez J. R. , Ramos R.
Published: May 2017

This paper describes several engineering workflows as part of the Digital Oil Field Solution implemented in a Gas Asset where there are different technical challenges. The main objective of this technology application is to revert the production decrease and optimize the operations in the asset, enhancing the capabilities of monitoring and surveillance and also to improve the analysis capability, taking the advantage of the benefits of the real time instrumentation, data integration, data quality, in addition to the definition of a complete automation process for all the information in different frequencies covering all the stages such as: data acquisition, transmission, integration, until monitoring and surveillance. With the implementation of operational and engineering workflows better efficiencies can be achieved, improving in time of response, and the decision making process, having tools for early anomaly detection to take proactively corrective actions that minimize the deferred production and losses.
Economic Analysis of the Law in Bolivia and the Declaration on the Rights of Indigenous People and Potential Social Implications for New Discoveries
Authors: Lopez Monterrey C. A.
Published: May 2017

Over last 10 years, Bolivia has gone through a process of significant transformation of its legal system: starting with a new Political Constitution of the State and continuing with new Laws, Supreme Decrees and Regulations that have affected society as a whole and some had specific and direct impact on the new discoveries due to the process of consultation and compensation of Indigenous People when their lands are affected by oil and gas field developments. This paper intent to demonstrate how those norms don't provide the economic balance that could render the norm to be considered as efficient. This paper does not analyse specific initiatives taken by private companies in accordance with their internal policies regarding sustainable development of local indigenous communities.
Investigation on the Impact of Voidage Replacement Ratio and Other Parameters on the Performances of Polymer Flood in Heavy Oil Based on Field Data
Authors: Delamaide Eric
Published: May 2017

Polymer flooding has now become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous pilots have taken place these last few years and field expansions are currently ongoing in several fields such as Pelican Lake (Canada), Marmul (Oman), Bohai Bay (China), Diadema (Argentina) and Patos Marinza (Albania).

As a result of these recent developments, field data has now become available in large quantity and can be used to provide guidance on the impact of various parameters on expected flood performances. For instance, a comparison of primary, secondary and tertiary polymer flood performances based on the analysis of several polymer flood patterns in Pelican Lake was presented in 2016 (Delamaide, 2016).

The present paper proposes to go further and to investigate the impact of parameters such as pore volume injected, well length, well spacing or Voidage Replacement Ratio (VRR) on polymer flood performances, based on data from fields in Canada and other parts of the world.

The performances of over 70 patterns belonging to several heavy oil polymer floods were analyzed and the impact of VRR, well spacing, well length and other parameters on recovery was evaluated. The calculations were performed using actual reservoir and production data whenever possible and published data in other cases.

Despite a large scatter in the data due to the wide range of reservoir conditions investigated, it is possible to distinguish interesting trends. For instance, higher VRR corresponds to lower recovery and recovery is fairly well correlated to injected pore volumes.

This paper will provide guidance to engineers designing polymer floods in heavy oil fields, allowing to adjust some of the design parameters to improve field response. In addition, the results can also be used to benchmark reservoir simulation results which can often be too optimistic or to compare performances of pilot projects in other fields.
Materials for Controlling Severe Lost Circulation - Laboratory Evaluation
Authors: Miranda C. R. , Oliveira J. L. , Cavalcante G. M. , d'Almeida A. R. , Pereira R. F. , Santos R. L. , Surmas R.
Published: May 2017

Lost circulation is still today one of the most costly problems for oil and gas operators. It may occur into permeable formations, depleted zones, induced or nature fractures and cavernous formations while drilling, cementing or during workover jobs in the well.

This paper focus on the evaluation of bridging and reactive systems in remediating severe losses based on their performance in a dedicated experimental facility.

Laboratory apparatus commonly used to evaluate lost circulation materials generally consist in modified API-fluid loss devices using slotted metal discs, ceramic discs or natural cores. These devices are suitable to simulate permeable formations or depleted zones, but they do not simulate severe lost circulation scenarios that occur in induced or nature fractures and in cavernous formations. For that reason, a specific laboratory apparatus was built, where the performance of several materials was evaluated and classified according to different severity levels.

This paper summarizes the efficiency of available commercial bridging (granular, fibers and flakes) and reactive systems in remediating severe losses according to different severity levels imposed in the developed severe lost circulation apparatus.

Besides commercial products alredy used to control losses, hydrated bentonite pellets have been evaluated as bridging material.