bluuebunny/crossref_metadata_2025_split huggingface dataset:
Producing Extra Heavy Oil from Llanos Basin, Colombia, Through Progressive Cavity Pumps and Electric Submersible Pumps: Case Study in the Chichimene Field
Authors: Lopez Uribe J. E. , Chaustre Ruiz A. J. , Ayala Marín C. A. 
Published: September 2014

AbstractThis work aims to present both the learning curve in implementing Electro Submersible Pumps and Progressive Cavity Pumps as methods for artificial lift wells producing extra-heavy oil. In order to study the performance of these systems operate with viscous fluids, they were carried out tests on producing wells and PCPs ESPs installed in field Chichimene viscosity fluids ranging from 3600-4500 cP. Energy consumption, number of failures, volumetric efficiency and other factors which affected assessed when working with highly viscous fluids.The data collected have allowed a better understanding of the impact of temperature and viscosity of the produced fluids in the lifting efficiency, demonstrating that it is possible to verify the performance degradation of ESPs operating in conditions of high viscosity, in terms of energy consumption and useful life.The study shows the main criteria taken into account to work with ESP at the beginning of the development of extra heavy oil reserves, followed by a more detailed assessment of their performance to subsequently perform a pilot test of change of lift system pilot to PCP in field with several wells. At the end it is looking for a change in strategy to reassess the possibility of implementation of PCP systems to develop reserves of extra-heavy oil and a first evaluation of the PCP learning curve two years later.Lessons learned and best practices found, combined with economies of scale will help to develop appropriate production strategies through the use of various artificial lift systems applicable in the exploitation of our fields of heavy and extra heavy oil.
Lessons Learned From Well to Field Level in Developing Heavy-Oil Reservoirs Using Thermal Recovery: Case Studies
Authors: Mehranfar Reza 
Published: September 2014

Abstract
The objective of this paper is to show and demonstrate how technology and especially software application in the field of heavy oil can change our view regarding the method of development and economical feasibility of the pilots. Different real challenges regarding heavy oil exploitation and production have been addressed and the solution has been provided with best in class technology and software in the market at the time of these studies.
The first case is about injected steam conformance in a horizontal well and in a loose fluvial sand reservoir. The lack of conformance has been modeled and after that simulated using proper reservoir modeling and simulation applications. The second case which has been studied is evaluating and feasibility study of implementing of in situ combustion in thin sands which previous attempts of developing them with cyclic steam stimulation was not successful because of high energy loss to the over and under Burdon layers. The third case is to show how efficient production scenarios can be sensitized and selected with application of a reservoir simulator to surface coupler platform technology in a continuous steam injection project. The idea of applying this technology is to bring different domain knowledge and understanding in a common platform in order to optimize energy value.
In this study a wide variety of cases like different reservoir rocks and fluids will be reviewed and due to large amount of materials available the focus will be to a basic explanation of the situation, method of implementation of the technology or solution and ultimately final results that were concluded at the time of study. The idea is to show how different method of development can be considered for field development of heavy oil reservoirs and also how simulation and pilot studies can save a considerable amount of money in these projects.
Applied Technologies for Successful Cementing in Steam Injection Wells in Southern Mexico
Authors: Ramirez-Vazquez F.. , Hernandez-Enriquez R.. , Briseño H.. , Moreno-Colin S. E. 
Published: September 2014

Abstract
Steam injection wells are currently being exploited in the southern region of Mexico. These types of wells can present difficult challenges with respect to cementing operations. For example, the cement composition must be designed properly to withstand the extremely high downhole temperature induced by injected steam. Additionally, lost circulation should be minimized or prevented while cementing. It is also very important to help ensure effective mud removal and help prevent trapping fluids in the annulus, which might cause annular fluid expansion and casing collapse attributed to temperature changes during steam injection operations.
To overcome these challenges, combinations of optimized job procedures and technologies have been applied to wells under such significant conditions, demonstrating improved results. Temperatures the cement slurry encounters during and after placement are estimated using a simulator, which considers the heat transfer phenomena. Using a new generation of resin-based, nonmetallic centralizers attached to the casing has helped improve centralization. High performance thermal cements are the most suitable choices for cementing under these conditions. Displacement of mud has been enhanced using a state-of-the-art 3D simulator to help optimize rheological and density hierarchy.
Applications of these technologies have been successful, helping provide zonal isolation at production zones and helping minimize remedial work attributed to lost circulation. When evaluating cement bond logs (CBLs), the trouble zones present in the reservoir should be considered. These technologies can be applied using appropriate modifications for different global regions where similar challenges are encountered; additionally, they potentially provide cost-beneficial outcomes.
Issue Paper: Aquifer Integrity Under the Influence of Thermal Extraction of Bitumen and Heavy Oil
Authors: Rivera L. E. 
Published: September 2014

Abstract
The impact of underground effects triggered by thermal recovery of bitumen and heavy oils on aquifer integrity has yet to be addressed. Aquifer integrity can be defined as the physical and hydrodynamic setting for which safe groundwater storage and sustainable delivery of water quantity and quality is preserved. Like cap-rock, aquifer integrity under the influence of thermal extraction is expected to deteriorate due to Underground Thermal Effects (UTE), caused by geomechanical modification of the stress path at the reservoir level. Most popular thermal recovery methods causing UTE are Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS) and Steam Flooding (SF). UTE associated with other forms of thermal recovery approaches such as in-situ combustion (ISC) have been less studied and might differ in nature and magnitude from the steam-based ones. Despite the fact, similar UTE are expected. This issue paper addresses the role of UTE on aquifer integrity under the influence of thermal extraction as identified for cap-rock integrity in the bitumen and heavy oil industry. Main UTE are heave, fracturing, lessen of well integrity and heat plume development, which develop or enhance underground process that ultimately impact aquitards and aquifer integrity. Such processes are gas migration, cross formational flow, interwellbore communication and element mobilization. Although impacts of UTE on caprock and reservoir integrity are well known to the bitumen and heavy oil industry, the same on aquifer and aquitard are less understood.
Assessment of Cold-Heavy-Oil Production With Sand CHOPS in Llanos Basin, Colombia
Authors: Andarcia L.. , Bermudez J.. , Suarez A.. 
Published: September 2014

Abstract
Heavy Oil production has been subject of extended research and technological developments during the past 3 decades. These difficult resources have been economically produced by different methods thanks to new technologies and the adoption of best practices to achieve successful projects. However, other production methods have risen directly in the field by trial and error. This is the case of the cold heavy oil production with sands “CHOPS” which is an extended production practice mainly in Lloydminster, Canada. This method have make possible to produce thin sands at economical rates using big hole perforations in vertical wells without sand control. By letting the sand be produced in conjunction with the oil, the so called “wormholes” can be created within the reservoir. These wormholes are structures of about 1 inch diameter that can reach several meters of length beyond the producing well. These high conductive channels help supporting a sustained oil rate for several years using PCP pumps.
The formation of wormholes has already been technically proved during cold production tests carried out in a thin heavy oil bearing sand located in Llanos basin, Colombia. During this test, there was observed communication with another well 25 meters apart from the tested well. Light weight ceramic proppant used to gravel packed the nearby well has migrated to the producing well after sand production. The migration throughout the porous medium of man-made ceramic whit a diameter higher than 1000 microns evidences the creation of high-conductive channels or wormholes. Since then, the potential for CHOPS in this reservoir has been analyzed. The production potential under cold production with sand is studied by analogs and numerical simulation. Factors affecting the operational model needed to achieve a successful project are analyzed.
Evaluation of CO2-EOR Gas Injection in a Heavy-Oil Naturally Fractured Reservoir
Authors: Fuenleal Martinez Jose Nicolas , Abbaszadeh Maghsood , Parra Olguin Roberto , Perez-Martinez Ernesto , Rojas Figueroa Antonio 
Published: September 2014

Abstract
This paper investigates the use of CO2 as an EOR solvent for a heavy oil and high permeability naturally fractured reservoir complex in Mexico. The complex is under partial pressure maintenance by Nitrogen injection. First geological features and production performance are analyzed to discern peculiar pressure trends caused by natural depletion and N2 injection in order to establish the nature of prevailing fluid communication and identify a confined site for CO2 injection testing. An East Block in the North fields due to its unique dynamic faulting characteristics is found nearly compartmentalized to serve as a suitable site for CO2-EOR injection studies. Second, a finely-gridded dual permeability compositional simulation sector model with local grid refinement and boundary flux scheme is constructed and a calibrated 8-component EOS along with full tensor molecular diffusion is implemented to model CO2-EOR process mechanisms. CO2 and N2 injections into the gas cap at varying rates and huff-n-puff injection in the oil column are simulated. The impact of injection rate is illustrated, where injection of CO2 at low rates promotes diffusion and is shown to drain more of the matrix oil. The huff-n-puff simulation cases also indicate increased oil recovery and reduced matrix oil saturation by CO2 injection as compared with N2 injection due to a combination of oil swelling, reduced oil viscosity and partial miscibility with CO2. The paper concludes that the efficiency of CO2 injections is more pronounced at higher reservoir pressures and with no or less volumes of prior injected N2.
Methodology for Determination of Critical Water Saturation According to Pore-Throat-Size Analysis Using Capillary Pressure Made in Core Samples
Authors: Villarroel Atahualpa 
Published: September 2014

Abstract
The operating plan generation of a reservoir is based on an effective dynamic characterization for recovery of reserves. To achieve this goal we must prepare, the model describes the interaction between the rock and the fluids present in the reservoir, as well as contributing to the achievement of the original reserves in place, facilitates the reproduction of the behavior of a reservoir to be undergone some enhanced recovery process. For this reason it was necessary to develop a methodology for determination of critical water saturation according to the size of Throat Poral by capillary pressure analysis performed on core samples of the fields belonging to developed areas of the Orinoco Oil Belt.
In this study we propose a methodology that combined with the little information that may exist in a specific area leads to a better use of that information as a representative model of the entire stratigraphic column.
These results can then be used as input for reservoir simulation models belonging to these fields, allowing the representation of heterogeneity present in the same anisotropy obtaining a representative distribution of the fluids and with this a more accurate estimation of reserves hydrocarbons and their movement within the reservoir, and generating operating plans with excellent results in the estimated potential wells.
In this case the method used yielded a correlation of critical water saturation as a function of pore throat radius, with an adjustment of 90% with respect to laboratory measurements.
Assisted Extra Heavy Oil Sampling by Electromagnetic Heating
Authors: Bermúdez J.. , Acosta W.. , Andarcia L.. , Suarez A.. , Vaca P.. , Pasalic D.. , Okoniewski M.. 
Published: September 2014

AbstractSampling extra heavy oil becomes a challenging operation when viscosities overcome 3000 cp at reservoir temperature. The acquisition of quality samples that allow obtaining accurate viscosity measurements and initial solution gas, among other fluid characterization measurements, is crucial, since they are key parameters to identify and select reservoir strategies. Samples that are commonly gathered from such reservoirs come from mud tanks during drilling, which bring uncertainty due to chemical contamination, and from preserved cores, which usually cannot provide sufficient volume for the required analysis.A new sampling technique presented in this paper, involves an operation assisted by electromagnetic heating. This technology has been studied since the 70s, with some field trials in the 90s, and is currently subject of renewed interest due to better design and prediction methods. It consists of applying radiofrequency heating through use of an antenna positioned in front of the zone of interest. The target zone heats up due to the water molecules oscillation induced by the electromagnetic waves. The increment of reservoir temperature reduces the extra heavy oil (EHO) viscosity and allows such viscous fluid to flow. After heating a substantial fluid volume, the downhole sampling operation with a wireline tool can be started. Heated volume and temperature increment become key parameters to have a successful operation.The heating process is simulated using a coupled reservoir and electromagnetic (EM) simulator. The thermal and electromagnetic models are created for a reservoir with standard conditions found in Colombian Llanos basin, which is the type of reservoir where this heating technology will be applied. Multiple simulations of the heating process using different radio frecuencies (RF) power levels, frequencies and antenna lengths were performed to identify the optimum combination which would allow fastest heating process.
Well Testing Characterization of Heavy-Oil Naturally Fractured Vuggy Reservoirs
Authors: Camacho-V. Rodolfo , Gómez Susana , Vásquez-C. Mario , Fuenleal-M. Norma , Castillo-R. Tomás , Ramos Gustavo , Minutti M. Carlos , Mesejo Alejandro , Fuentes-C. Gorgonio 
Published: September 2014

Abstract
This paper presents the advances on the characterization of Naturally Fractured Vuggy Reservoirs (NFVR) located in the South East Gulf of Mexico. Halos, fractures and vugs were characterized through well tests using the triple porosity–double permeability (3φ-2k) model. Through the analysis of well and imagelogs was determined the predominance of high vuggyporosity producing intervals, so that the pressure data were analyzed using a triple porosity-double permeability (3φ -2k) approach, with total and partial penetration. These NFVRs have vuggy and fracture porosity, with triple porosity, matrix, fractures, and vugs, or matrix, vugs with their halos. In both cases, the 3φ-2k model is appropriate to characterize these fields. These models, recently presented involve the determination of 9 and 13 parameters, for total and partial penetration, respectively, which implies challenges in terms of the uniqueness of the results. In this way, it is suggested to consider information from other sources like cores, well logs, and image logs, in order to select characteristic values for some of the parameters of the model of interpretation, specifically the storage ratios for vugs and fractures, ωv and ωf, and in this way to eliminate the non-uniqueness problem. Thus, the integration of static and dynamic information is a key element for a complete description of NFVR.
The 3φ-2k model allows better data fits than the classical dual-porosity model, obtaining more information related to the interactions of the three different media. The sum of vuggy and fracture porosity obtained from 3φ-2k model is not equal to the secondary porosity obtained from the dual-porosity model.
If partial penetration effects are present, it is recommended to perform the analysis taking into account these effects because information on the vertical communication of vugs and fractures can be obtained with the 3φ-2k model. It is confirmed through the analysis of well-tests with partial penetration that the vertical communication of vugs can be more important than the horizontal communication. It is crucial to obtain fracture and vug connectivity in both horizontal and vertical direction, mainly because these reservoirs are sharing a common aquifer.
The objective of this work is to demonstrate the application of a 3φ-2k model to determine several parameters related to reserves and productivity of NFVR. Vertical connectivity of both vugs and fractures are important parameters when an aquifer is underlying heavy oil NFVR, because these areas could establish preferential routes for the advancement of water.
Transient Shape Factors for Thermal Flow Simulation in Naturally Fractured Reservoirs: A Concept
Authors: Taabbodi L.. , Chen Z.. , Geiger S.. 
Published: September 2014

Abstract
A significant number of naturally fractured reservoirs (NFRs) discovered in the world contain heavy and extra heavy oil. These reservoirs are important resources; however, the nature of naturally fractured reservoirs, especially those containing heavy and extra heavy oil, presents many unique and complex challenges for reservoir modeling and simulation. There have been a number of attempts over the last 50 years to develop methods to improve our understanding as to how the fracture systems impact oil recovery. For many decades, the dual-porosity approach has been the most popular and effective technique in modeling of NFRs. This approach separates the fracture and matrix systems into two different continua, each with its own set of properties. Fluid exchange between matrix and fractures is modeled through a Transfer Function (TF), while a shape factor describes the fracture-matrix surface area. However, the fracture-matrix fluid interaction is not yet fully understood for thermal processes, which represents a significant unknown in thermal reservoir simulation of NFRs containing (ultra) heavy oil.
In this paper an extensive literature survey was initiated to establish a detailed understanding as to how shape factors are utilized for modeling non-isothermal, fracture-matrix fluid exchange in fractured reservoirs. The most appropriate way is to treat the shape factor as a time-dependent quantity to capture the pertinent features of non-isothermal fluid flow in fractured reservoirs. A series of numerical simulations have been conducted using the simulator STARS from Computer Modeling Group Ltd. in order to analyze the performance of existing transfer functions and shape factor formulations for dual-porosity, multiphase flow systems in thermal reservoir simulation. Based on this analysis, we introduce the concept of a new, transient shape factor for non-isothermal, dual-porosity models and compare our new concept with the existing shape factor models. The results from this study clearly confirm that a transient shape factor is required for an appropriate modeling of a thermal recovery process in NFRs when using dual-porosity formulations.
Design and Construction of an Electrostatic Generator in an Experimental Test Bench, to Inhibit the Precipitation of Paraffinic Waxes
Authors: Jiménez C. C. , Campo B.. , Arias M.. , Vargas H.. , Ariza E.. 
Published: September 2014

Abstract
The present article describes the design and construction of a device able of establishing an electrostatic field parallel to a flux of a liquid into a pipe. The generator device bases its operation on a flat parallel plate configuration under a voltage. The model E=V/d used to describe the electrostatic behavior is validated in two different ways: the first one is a lab experience and the second one through a simulation run. In the lab experience are gotten (in an indirect way) the electrostatic field magnitude and the liquid's electrical permittivity. Through the simulation run and the experimental permittivity value, is estimated, besides the intensity, the geometrical disposition of the generated field. It's validated an operation rank for the electrostatic field intensity between 0 and 1 [kV/mm]. The recommended rank for distance between the plates is from 5 to 14 [mm]. For an oil pump with a caudal between 5 and 55 [l/min], the time exposure is between 10,71 and 329,1[ms].