bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 (&gt;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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.