bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Model Calibration and Pore Throat Radius Determination Using Core Analysis and Nuclear Magnetic Resonance Data in Mixed-Lithology Reservoirs, South Western Venezuela
Authors: Ferrer F. , Vielma M. , Lezama A. 
Published: December 2007

Abstract
In complex geological sequences composed by clastic and carbonatic rocks, where the matrix can be formed by several minerals, such as calcium carbonate, silica and magnesium carbonate, the determination of reservoir properties and rock quality represents a major challenge. Using conventional logs to calculate total and effective porosity in this type of reservoirs can lead to underestimation or overestimation of pore space in the rock and do not provide information about pore size and porosity distribution associated with irreducible water saturation that possibly will impact of reservoir permeability. To address these problems the response of the Nuclear Magnetic Resonance Log was calibrated to the petrophysical and geological properties measured in core. Correlation models were generated for total porosity, permeability and pore throat radius; which could be used in future wells of the area, where core data is not available.
A relation between the predominant pore throat radius calculated with the Pittman R45 equation (1992) and the irreducible water saturation from the Nuclear Magnetic Resonance Log was obtained. From this analysis five petrofacies were obtained: megaporous, macroporous, mesoporous, microporous and nanoporous, being predominant the macroporous, mesoporous, and the nanoporous. Total Porosity from the Nuclear Magnetic Resonance correlates very well with the total porosity data from core analysis. To calibrate permeability values derived from NMR data two different T2 cutoffs and Coates-Timur equation constants were used. Showing a relation with sedimentological facies described in macroscopic whole core analysis.
Seven sedimentary facies type were identified: Limey Sand, Sandy Limestone, Glauconitic Sand, Muddy Sand, Fine-grained Sand, Coarse-grained Sand and Shale. The best types of rocks (megaporous and macroporous) correspond to the best facies (Fine-grained Sand and Coarse-grained Sand). Limey Sand, Muddy Sand and Sandy Limestone were identified in mesoporous, microporous and nanoporous rocks, and most of the glauconitic sand intervals correspond to microporous and nanoporous petrofacies.
Saving Energy in Heavy-Oil Fields in Colombia With Progressive Cavity Pumps
Authors: Ramírez J. , Abril W. , Vargas Leonel , Trivino C. 
Published: December 2007

Abstract
One of the mayor economical impacts in a Project of artificial lift system shift is the associated cost of energy moreover the maintenance and well intervention must be considered. These variables are reflected as addition on the final artificial lift cost selected.
This study was accomplished based on experience at the Teca and Nare fields operated by Omimex Colombia where an artificial lift system shift was performed from Rod Pump (RP) into Progressive Cavity Pump (PCP), achieving significant savings in well downtime and energy comsuption at the same volume of production.
The strategy to develop this project started with the identification of well candidates where steam injection was not feasible then a change on the artifitial lift system was proposed to a set of wells.
Also is highlighted the importance of the operational variables in long term at the moment to choose an artifitial lift system
Production and Video Logging in Horizontal Low-Permeability Gas Wells
Authors: Sask D. , Hundt C. D. , Slade J. M. , Daly P. 
Published: December 2007

Abstract
The intention of this paper is to discuss and recommend effective production logging techniques for low rate horizontal gas wells. Between June 2005 and September 2006, a total of eight wells were evaluated using either traditional production logging (PL) tools or downhole video logging tools. Pressure, temperature, nuclear fluid density, single capacitance, capacitance array, fullbore spinner, caliper, and gamma-ray data were retrieved by production logging methods. Video logging collected thousands of wellbore images as well as pressure and temperature information.
A significant issue in logging horizontal wells is the method of delivering tools into the well. Tubing diameter, open hole diameter, horizontal length, horizontal trajectory and the desired results all influence the selection of conveyance method. The methods used in this study were CoRod, coiled tubing (CT) and wireline tractor.
The production logging data indicated liquid accumulations however the different logging tools showed varying degrees of detail. As an example, the capacitance array tool tended to show liquid with gas pockets while the radioactive density tool and spinner tool indicated 100% liquid. Video logging data provided definitive images of gas bubbles and slugs flowing through liquid.
The objectives of a logging program will dictate either a qualitative or quantitative evaluation. Video logging is an excellent technique to use as a general overview when initially investigating openhole sections. It can provide insight on complex production problems that never would be suspected or detected using traditional production logging methods.
Propellant-Assisted Solution to Perforation Penetration and Breakdown—San Jorge Field, Argentina: Case Histories
Authors: Elnaga Ashraf Aly Abou , Almanza Edgar , Batocchio Marcelo , Folse Kent , Schoener-Scott Martin 
Published: December 2007

Abstract
Chevron San Jorge S.R.L. operates in the Loma Negra area and El Trapial field located in the Neuquén Basin, Argentina.
El Trapial wells are characterized by stratified, shallow- to medium-depth reservoirs with permeabilities of 35md to 85md and porosities of 18 to 30%. The wells are completed in oil reservoirs that have been perforated using conventional methods, fracture stimulated to increase production, and later, completed with electro-submersible pumps (ESPs).
To effectively meet the operator's needs for a method that would help optimize well productivity, and at the same time, be cost effective without compromising the results of the operation, an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health, safety and environmental standards was proposed. The propellant-assisted perforating method uses standard perforating components and procedures, thus providing the same safety features available to the industry today when conventional TCP operations are used. The propellant is an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stresses and create perforation breakdown and mild fracturing near the wellbore.
This paper will focus on two case histories describing the methods and improved results obtained from the application of the propellant perforating technique.
The information in this paper will verify that the technique was capable of satisfying the operational challenges in these reservoir types. Instrumental in the success of the propellant-assisted perforating methodology was 1) the proper screening of candidate wells, 2) good pre-job design modeling, and 3) adherence to industry accepted best practices with constant communication.
Geomechanical Application for Drilling Optimization in Marginal Fields, East Venezuela
Authors: Romero Franklin , Yu Woo Kenny , Meaño William , López Wilmer , Balseiro Prudencio , Romero Jorge , Castillo José , Rodríguez Luz Mery , Galíndez Nicolás , Rodríguez Jacqueline 
Published: December 2007

Abstract
This study is intended to show that it is possible to reduce risks, time and costs in well drilling through application of Geomechanics in marginal fields. It refers to the Oritupano-Leona field, East Venezuela, which has more than 700 wells drilled from 1938, 29 of which are horizontal wells.
In spite of the production success, 6 over 29 wells, 25%, presented problems due to hole instability that lead to several stuck pipes, sidetracks and down time.
Drilling parameters of 23 horizontal wells, operational problems, geomechanical information and regional geology were considered for this analysis. Problems associated to mechanical/chemical instability and operational problems were identified. Geomechanical parameters were calculated and analyzed with the specialized software considering pore pressures, mud density, minifrac and electrical logs, where the stress direction was studied with the interpretation of imaging logs and review of the regional stresses. A friction diagram adjusted to the wide of the breakout was applied, whereas vertical stresses were calculated through density log integration. Rock mechanical parameters were product of RSD tests that included rock mechanical resistance analysis (UCS), determination of the internal friction angle and the Poisson's ratio and Young modulus, calculated with the use of neural networks.
Drilling events were visualized in order to define the stability frame of the area for the different operational parameters based in geomechanical parameters previously calculated. With this data a new well design was elaborated integrating trajectory optimization and operational parameters in order to diminish the stability problems.
Different mechanical instability values were identified in the study in three zones of the field, and the safe operating window for drilling and operational parameters was identified for each one, guarantying hole cleaning.
The application of the criteria and recommendations of the results of this study had an outstanding impact on the horizontal well drilling in the Oritupano-Leona field. In 2005, a new record was established with the drilling of the ORM-174, which is the fastest horizontal well drilled in the field history. Two other wells were drilled in 2006 with excellent results.
Plunger-Lift Advancements, Including Velocity and Pressure Analysis
Authors: Morrow Stanley J , Hearn William 
Published: December 2007

Abstract
The interest in and demand for natural gas in the past few years has dramatically shifted the focus for many operators. Plunger lift, which for many years was viewed as a last resort, and somewhat of a nuisance, has gained an all time high in popularity and effectiveness and applicability. Much of the guesswork in evaluating candidates has now been replaced with exotic programs that combine Nodal analysis with performance based calculations.
In recent years both equipment and applications have improved, and the production range of plunger lift now includes many wells previously not possible to produce with plunger lift. Being able to correctly assess applicability, and identify the best type system is reducing the trial and error process previously associated with plunger lift evaluations and operations.
Beam Pumping System Optimization Through Automation
Authors: Sanchez Juan Pablo , Festini Diego , Bel Oscar 
Published: December 2007

Abstract
Recent economic conditions in the oilfield have given extra emphasis for operators to look for new ways to improve production operations and reduce operating costs. One means of doing this for rod pumped wells is utilizing Rod Pump Controllers (RPC). They have been available for over ten years in Argentina and only a relatively small percentage of operators have utilized it.
This paper presents the theoretical and practical benefits obtained with the inclusion of RPCs in beam pumping systems:
Energy saving: Despite the energy cost is not high in Argentina, the actual crisis force us to decrease the energy consumption through any circumstance.
Production Optimization: In general, any increase in well production is a result of the RPC providing immediate significant operating information to allow early detection and identification of potential pumping problems.
Expense Reduction: If a pumping system experiments a fluid pound or a system failure (i.e., stuck pump, pump "sanded-up", parted rod strings, tubing leak, etc.) the RPC will take action immediately.
Manpower Utilization: Since a RPC can provide fault messages related to the problem it has identified, corrective action is more easily determined.
The document shows a short technical description of the RPC and the Telemetry Software.
Then, to demonstrate reality results, a test realized in Lomita oilfield (Rincón de Los Sauces – RepsolYPF) will be exhibited. On it, some practical advantages will be put on view. Finally, a comparison between production controls, failures indexes and energy consumption before and after the test will be presented.
A Parametric Study of Reservoir Parameter for Micellar Solution Injection Process in Oil Reservoirs of Northeast Brazil
Authors: Medeiros H. O. , Barillas J. L. M. , Dutra T. V. , Mata W. 
Published: December 2007

Abstract
Chemical flooding is a process that improves recovery efficiency based on injection of a chemical system that contains surfactants and polymers. Surfactants are substances that alter the interfacial tension and promote a miscible displacement with residual oil. Polymers decrease the water mobility and, in this process, it is injected after the surfactant injection to promote an immiscible displacement of the micellar bank. Diverse operational and reservoir parameters can influence the micellar injection process. This work analyses the oil recovery efficiency of this process in reservoirs with characteristics of existing reservoirs in the northeast region of Brazil, identifying the optimal applicability parameters and the possible technical viability with these characteristics. The numerical study was done using the commercial software "Stars -CMG" (Computer Modelling Group).
The reservoir parameters evaluated were: porosity, permeability, oil viscosity and initial oil saturation, according to some Brazilian northeast reservoirs characteristics, in order to obtain the applicability of the process with these reservoir characteristics, and the optimal application conditions. Then, an analysis of the operational parameters was carried through, with the objective of optimizing the process. The results showed improved recovery efficiencies for diverse reservoir characteristic encountered in the State of "Rio Grande do Norte". For the cases and reservoir conditions studied, the most critical factor that affects the micellar process was initial oil saturation, and the process optimization showed an increase on cumulative oil and on recovery factor. An increase in oil recovery with small costs is the search of petroleum industries together with academic institutions because of uncertain oil price. Therefore, it may be necessary the study of different processes to improve recovery efficiency such as chemical flooding.
Recoverable Reserve Estimation in a Tight Gas Reservoir During the Exploration Stage, Neuquen, Argentina
Authors: Ucan Sezai , Olmos Sebastian , Valencio Daniel , Mosquera Alfonso , Alonso Jorge , Marin Horacio 
Published: December 2007

Abstract
A rapid and an effective reservoir simulation model was built based on limited information. 3D seismic impedance, two exploratory wells' log interpretation, a core data, and a well test consisting of an isochronal test and, several months later, an extended flow followed by long build up test were basic available data for this field. The main objective of this study is to estimate recoverable reserve with or without hydraulic fracturing in Mulichinco formation at the Paso Del Indio Field.
Material balance and decline curve analyses have important limitations to estimate ultimate recoverable reserves in the tight gas reservoirs. Well types that are derived from the conceptual simulation models do not reflect the effective drainage area or permeability heterogeneity in the field. A representative permeability in well spacing area should be averaged harmonically or geometrically. In order to estimate the ultimate recoverable reserves in the tight gas reservoirs, permeability heterogeneity or the effective available drainage area to hydraulic fractures should be simulated effectively. Relatively small changes in permeability can results in unsuccessful fracture design and in uneconomical flow rates.
A very quick and effective simple reservoir simulation model was established to estimate recoverable reserves rather than using conventional volumetric, material balance, and decline curve analysis in tight gas reservoirs. Not having any production histories, well test information was used very successfully as history matching information to validate the geological, petrophysical, and PVT models.
Insertable PC Pumps Reduce Operation Costs
Authors: Martinez Miguel Angel , Lopez K. Jorge Mario 
Published: December 2007

Abstract
With the main objective of reducing working times of rig equipments and this way costs for operator companies an insertable Progress Cavity Pump (PCP) has been developed. This pump is designed to be anchored in the top (by cups) and with a 2 7/8" anchor in the bottom section.
This kind of pumps can be installed in wells where beam pumped systems were installed before, and vice versa, avoiding the production string pulling. So if a change from a beam pumped system to PCP system is required, utilizing this new design, the rig activity would be limited to: pulling rod string, changing the pump and installing the string again. If a fast mounting rig is used to realize the replacement, the working time could be shorter.
Other advantage of insertable PCP is that the production flow rates has been increased, obtaining a several range of applications.
This paper presents a short technical description of and some tests of insertable PC Pumps in different wells of Guadales and Lomas Del Cuy oilfields (Area Guadal – Las Heras – Repsol YPF). Theses pumps were tried at different depths, stresses, hydraulic powers and other well conditions in order to demonstrate the same performance of traditional PC Pumps.
An economical analysis exhibits the convenience and some qualitative benefits of installing insertable PC Pumps in a certain range of wells, depending on their flow rates, especially when a beam pumped system will be replaced for a PC Pumped system. Besides it provides a future projection of insertable PC Pumps installations in the mentioned oilfields.
A Composite Determination of Mechanical Rock Properties for Stimulation Design (What To Do When You Don't Have a Sonic Log)
Authors: Mullen Mike , Roundtree Russel , Barree Bob 
Published: December 2007

Abstract
In the Rocky Mountain region of the US, nearly every well is hydraulic fracture stimulated to produce commercial volumes of oil and gas. The starting point for designing these treatments is an understanding of the in-situ stress profile. To calculate the in-situ stress profile, one must have an understanding of the mechanical rock properties and the pore pressure variations throughout the wellbore. Pore pressure can be measured in the permeable zones and in-situ stress can be calculated by the modeling of closure stress from pre-fracture pressure testing. But these tests are rarely performed in the nonreservoir rocks above and below the fracture stimulation treatment. The challenge for the stimulation design engineer is to determine the mechanical rock properties in and around the treatment interval. Calculating in-situ stress with the uniaxial strain equation requires the knowledge of Poisson's ratio, Young's modulus, pore pressure, and overburden pressure. Classically, the static Poisson's ratio (PR) and Young's modulus (YMS) are calculated by using the results from a dipole sonic log. However, in most fields, less than 1% of the wells requiring stimulation have dipole sonic data.
In the absence of dipole sonic information, conventional wireline log data can be used to quite effectively calculate mechanical rock properties by using basic petrophysical relationships and artificial neural networks. The composite method to determine mechanical rock properties uses five methods to estimate the compressional slowness (DTC), seven methods to estimate shear slowness (DTS), eight methods to estimate PR, and and nine methods to determine YMS. The composite model PR and YMS are error minimized by a weighted averaging technique that honors the most reliable correlations. The composite modeled PR and YMS values are then used as inputs for a continuous calculation of the minimum horizontal stress (Shmin).
The validation of the new composite model PR and YMS was confirmed in three ways. First, the composite model results are compared to the values determined in the lab from actual core samples. Second, the composite model results were compared to calculations using measured DTC and DTS in wells where dipole sonic tool measurements were recorded across a field in Wyoming. Finally, the composite model results were validated by using stimulation treatment pressure history matches on the Pinedale anticline in southwestern Wyoming. The goal of the composite model is to provide a robust rock property solution with or without sonic log data to eliminate the mechanical rock properties as a variable in fracture stimulation treatment design and history matching.
Olefin Based Synthetic Drilling Fluids' Volumetric Behavior Under Downhole Conditions
Authors: Demirdal Barkim , Cunha J. C. 
Published: December 2007

Abstract
Usual practice in drilling engineering is to determine drilling fluid density at surface conditions assuming that drilling fluid density does not change with changing downhole conditions. This assumption may result in inaccuracy while estimating static and dynamic pressures in the wellbore especially when synthetic based drilling fluids are used. Inaccurate estimation of pressure profile in the annulus can lead to severe well problems such as kicks, drilling fluid losses and wellbore instability. In addition, inaccurate pressure profile estimation can affect the success of Managed Pressure Drilling (MPD) operations which require real time knowledge of wellbore pressures in order to keep it between formation pore and fracture pressures using a control choke placed on the return line of the annulus.
Effects of pressure and temperature on volumetric behavior of two olefin based synthetic oils are investigated in this study using a mercury free PVT system. The olefin based synthetic oils used in this study are C16C18 internal olefin and C12C14 linear alpha olefin. In order to simulate deep offshore situations the temperature is ranged between 25 °C and 175 °C, while the pressure is ranged between 0 psig and 14,000 psig.
In addition, volumetric performances of olefin based synthetic oil systems under investigation are compared with those of water, brine solution, mineral oil, diesel oil and n-paraffin based oil under similar conditions.
The study shows that synthetic based oils' volumetric properties are more sensitive to pressure and temperature conditions compared to water, brine solutions, mineral oil and diesel oil. Once emulsion systems containing synthetic based oils are used, density change with respect to downhole conditions should be modeled to increase the reliability of pressure profile calculations.