bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Deepwater Well Successfully Drilled in Colombia with a High-Performance Water-Based Fluid
Authors: Marin J. , Shah F. , Serrano M. , Jaramillo A. , Marin C. , Arevalo W. , Priandi G. 
Published: May 2009

Abstract
Deepwater drilling presents significant issues and uncertainties, especially when there is no prior drilling experience in country or only limited offset information is available. Uncertainties about the drilling conditions create additional risk to operators and can cause project budget increases. Therefore, innovative technologies are often implemented to help ensure that the well is drilled efficiently and safely, operators obtain well data and important geological data that can help identify potential reservoirs and wells in the area. Petrobras Colombia undertook the challenge of drilling the first deepwater well in Tayrona BLock located in the Colombian Caribbean, in approximately 1,840 ft water depth. Drilling fluid selection was a key decision to the success of the project due to the nature of the exploratory project, formation uncertainty, environmental footprint, wellbore stability and protecting any potential reservoirs.
A high-performance water-based fluid (HPWBF) was selected to drill the well based on the following criteria; The ability to discharge to the sea without environmental impactEffective inhibition capability to drill reactive clay formationsNon-dispersed, low-solids formulation to improve rate of penetration (ROP)Shear-thinning behavior for excellent hole cleaningHigh and low temperature as well as high-pressure stabilityLubricity, wellbore stability and low equivalent circulating density (ECD) values.
The HPWBF provided excellent performance as demonstrated by trouble-free trips, casing, cementing and wireline logging operations. Rheological properties remained stable during changes in temperature and pressure, confirming reliable fluid stability and reducing costs associated with non productive time (NPT).
Although the inhibition provided by the fluid system was excellent, the wellbore exhibited some mechanical instability related to stress distribution. No bit balling problems were observed and ROP was acceptable most of the time. Wiper trips required less time than expected and did not present any issues. In conclusion, the HPWBF demonstrated excellent performance in all aspects and contributed to the overall project success in obtaining important formation data, minimizing NPT and reducing costs related to fluid and cuttings disposal.
New Correlations for Critical and Subcritical Two-Phase Flow through Surface Chokes in High-Rate Oil Wells
Authors: Al-Attar Hazim H. 
Published: May 2009

Abstract
The critical and subcritical multiphase flow through wellhead restrictions of a prolific oil field in the Middle East is investigated and two sets of new correlations are presented. The first set of correlations is developed by using "40" field tests representing critical flow conditions. The second set of correlations is based on "139" field tests representing subcritical flow conditions of gas-liquid mixtures through wellhead chokes.
For the critical multiphase flow condition, the predicted oil flow rates by the new set of correlations are in excellent agreement with the measured ones. The absolute average percent difference (AAPD) is between "1.88" and "4.37", and the corresponding standard of deviation (SD) is between "2.52" and "6.52". These results are found to be statistically superior to those predicted by other published correlations considered in this work. During the subcritical gas-liquid flow conditions through surface chokes, the accuracy of oil flow rates predicted by the new set of correlations seems to be sensitive to the type and size of the choke being used. For Cameron LD type and 144/64th -inch choke, the oil flow rates predicted by the proposed correlation are superior to those predicted by other methods available in the literature, with AAPD of "8.5". However, for smaller choke sizes of 96/64th and 64/64th -inch, the oil flow rates predicted by the new correlations and other methods are found to be close to each other. For Cameron F type and 144/64th -inch choke size, the oil flow rates predicted by the new correlation are closely matched by those predicted by other published methods, with AAPD of "13.7". For smaller choke sizes of 80/64th and 64/64th -inch few field tests are available and the predications of all methods, including the proposed ones, show similar statistical results. The above findings for Cameron F choke also seem to apply to Beaned wellhead assemblies for this particular oil field.
Feasibility Study of Dual "Backup" Electrical Submersible Pump Based on Risk Analysis
Authors: Pérez Aileen , Caicedo Sergio 
Published: May 2009

Abstract
Electric Submersible Pumping is one of the predominant lift methods used in Barua-Motatán field of Tomoporo district, Venezuela. Each year the increasing number of ESP failures has become in a crucial issue for the Venezuelan oil company (Petróleos de Venezuela – PDVSA) due to the adversely effecting on lifting costs, rig utility and production. A dual ESP (dESP) completion in which the second pump is used as a backup is proposed in this study as an alternative for optimizing production, increasing ESP run life, reducing unscheduled deferments and minimizing ESP related well services and associated costs.
A critical techno – economics analysis of different proposal from local ESP vendors showed that the suitable option due to space restrictions (casing 7-5/8 in.) is a pod type completion in which primary and backup ESPs are in serial. A risk assessment confirmed the feasibility of the application of dESP in Tomoporo district. The Net Present Value (NPV) of using the new scheme completion proposed is always greater that the conventional single ESP scheme. The high initial capital expenditure incurred from the use of the technology is offset by the significant increase in the profit margin related to the decrease in operational cost and steady production. The most important and unexpected achievement was that probabilities of having negative NPV are reduced considerably with dESP as could be confirmed by risk analysis. Finally, dESP application simplifies drilling scheduling which enhances the planning of well interventions.
Viscosity Effect in Cyclone Separators
Authors: Brito A. , Trujillo J. 
Published: May 2009

Abstract
The gas liquid cyclone separator is a device that works as a result of the centrifugal force acting on the denser phase of a two-phase flow. This causes the liquid phase which is denser than the gas, to move outward to the cyclone wall. The separated gas comes out by the top, the crude/water blend comes out by the bottom as a two phase stream. The separation time is almost instantaneous and due to its simple design, no moving parts and low cost, the cyclone separators have become an attractive solution for the new oil an gas field developments.
The liquid viscosity has a predominant influence in the performance of this kind of separators. As the liquid viscosity increases the shear stresses increase too producing a higher dissipation of the vortex intensity and as a consequence the separation efficiency is diminished. Therefore, the cyclone operational envelope for heavy oils is reduced as compared to light oils.
This paper presents the status of the gas-liquid cyclones separation studies related to their performance when used with high viscosity liquids. Experimental and computational studies from different sources, including PDVSA Intevep, are presented for different types of cyclones, with liquid viscosity between 1 and 1500 cP.
Jusepin Main Station Separation Facilities Upgrade by Means of Integrated Multiphase Solutions
Authors: Trujillo J. , Brito A. 
Published: May 2009

Abstract
The Jusepin main station is a facility designed to process 460.000 B/D of oil and 500 MMSCFD of natural gas produced from El Furrial field, located in the northeastern Venezuela. It consists of eight modules and started operations in late 80's handling a relatively low GOR. A gas injection program was implemented in late 90's as secondary recovery method. As a result the GOR increased 3 times generating bottlenecks in the modules I, II and III. The modules II and III share the inlet and outlet manifolds and therefore, operate as one. An upgrade of the mid pressure separation trains and gas scrubbers of modules I, II and III was required as these surface handling facilities have proven to be the primary constrain limiting the operator's production increasing plan.
This paper will describe the facilities constrains and discuss the proposed debottlenecking steps based on integrating several multiphase simple solutions to address most problems. These problems include: constrained gas handling capacity, uneven phase splitting in the modules II and III common inlet manifold and presence of hydrodynamic slugs in the inlet lines. The Cylindrical Cyclone Gas Liquid (CCGL) separation technology was chosen to increase the modules separation capacity due to its compactness, fabrication simplicity and proven high efficiency. Two identical CCGL arrangements were proposed, one for module I and the other for modules II and III. Two solutions were selected to promote the even flow distribution: a new symmetrical common inlet manifold for the modules II and III and flow splitters in every T-junction of the new inlet manifolds. Finally, the dimensions of the inlet lines were designed based on the classical Kelvin Helmholtz theory to promote the transition from slug flow to stratified flow.
The combination of these simple multiphase solutions will enable to double the current separation capacity of the modules and reduce the liquid carry over to the compressor plants maintaining the operational interruptions and downtime caused by modifications and tie-ins at a minimum.
Enabling Technology: An Overview of Offshore Innovations in the Oil Industry
Authors: Amado L. C. N. 
Published: May 2009

Abstract
Big accumulations found in the past are not likely to occur again. On the contrary several small size reservoirs may still be there, unless a new play be discovered. With global demand for oil decreasing, small accumulations may deliver the goods but and easy oil has become scarcer and we need to start looking at more difficult reservoirs from which to produce hydrocarbons. The actual production decline in existing fields may pose a challenge in the future together with geopolitics and technology. depletion rates and Geopolitics are complex variables to predict. Technology on the other hand can still be designed fit for purposes. This paper is about the road map to technology, including innovations and emerging ones, that will be needed by the oil industry to succeed in unlocking new plays. It is about enabling technology, i.e, to make technology able to do something for us now.
The Transient Well Test Analysis of Fractured-Vuggy Triple-Porosity Reservoir With the Quadratic Pressure Gradient Term
Authors: Nie Renshi , Jia Yonglu , Yu Jia , Liu Bin , Liu Yongliang 
Published: May 2009

Abstract
This paper aims at triple porosity reservoir with fracture and vugs, according to basic percolation principle the nonlinear well testing model with quadratic pressure gradient is established, considering wellbore storage and skin, for both the unsteady interporosity flow of the matrix to fracture and the unsteady interporosity flow of vugs to fracture. By use of variable substitution, linearizing the flow equation, the model is solved, and the Laplace space analytic solution is obtained, and then the real space solution is procured by use of Stehfest numerical inversion. So the pressure and the pressure derivative log-log new type curves are drawn up. Sensitivities of the type curves affected by different parameters are analyzed, including the influence of the quadratic pressure gradient coefficient β, fluid capacitance coefficient and interporosity flow factor, which are the main parameters that can reflect the traits of fractured-vuggy triple porosity reservoir. The impact of (lower case beta) under certain conditions is extremely intense, and the dimensionless pressure error may be up to 20% and dimensionless pressure derivative error may be up to 30%. Especially for low permeability reservoirs and heavy oil reservoirs, there is a bigger β; therefore the deviation of type curves between the linear model and nonlinear model is much obvious.
In the end, the example match explanation of a Carbonate well in Tarim oilfield is made, which shows that there are some differences in the explanation results between linear and nonlinear model, and the error of explanation results is very close to theoretical error, so the quadratic pressure gradient should not be neglected, and that the nonlinear percolation law is the actual flow law of oil in porous medium, and that the parameter values of nonlinear model explanation are more precise than those of linear model explanation, so the research on the nonlinear flow model and its application with quadratic pressure gradient should be undoubtedly strengthened and stressed. The results available in this paper can be further used in the study of the flow rule and the well test analysis of fractured-vuggy carbonate reservoir.
Assessment of the Potential and Economic Performance for ECBM Recovery and CO2 Sequestration
Authors: Gonzalez R. , Schepers K. , Riestenberg D. , Koperna G. , Oudinot A. 
Published: May 2009

Abstract
An Enhanced Coalbed Methane (ECBM) reservoir simulation study was performed to investigate what levels of initial permeability would be required to successfully implement a CO2 injection project for different levels of coal rank, and whether advanced development strategies could extend the window of applicability to lower permeability coal reservoir environments. To perform the study, a matrix of simulation scenarios that consisted of three coal ranks (low, medium and high), three permeability values (1, 10 and 100 mD), three types of injection wells (vertical damaged, vertical stimulated, and multi-branch horizontal), and two types of production wells (vertical and pinnate) were established.
Results, initially analyzed from a production perspective, lead to unexpected conclusions stimulating the controversy and the initiative for future research. For instance, due to the high CO2/CH4 replacement ratio for low rank coals, and the associated coal swelling and permeability reduction, the study indicated that primary recovery production is essentially identical to those reservoir productions under the proposed injection schemes (and any considered permeability level). Certainly, pinnate producers showed better performances than vertical ones. For medium rank coals, successful sweep can be achieved with vertical wells in a high coal permeability environment, but advanced pattern strategies would be required if the permeability is in the other orders. In high rank coals, coal swelling with CO2 injection is minimized, so successful sweep can be achieved in the high and medium coal permeability environments with vertical wells, but advanced pattern strategies would be required in a 1 mD coal permeability environment.
Corresponding economic analyses accompanying the production implied additional perspectives to be considered for decision management. Promising scenarios from the production point of view are not necessarily profitable under relatively standard conditions. Due to the serious limitations in the existing need knowledge base, these findings can be used as initial screening criteria for identifying reservoir environments and development strategies amenable to CO2-ECBM/sequestration projects.
Optimization and Process Control of a Reverse Osmosis Treatment for Oilfield Brines
Authors: Barrufet M. A. , Mareth B. C. 
Published: May 2009

Abstract
Fresh-water resources in many of the world's oil producing region are scarce, while produced water from oil wells is plentiful, though high salinity and other contaminants make it unfit for most applications. Disposing of this water is a great expense to oil producers. This paper advances a technology developed to treat produced water by reverse osmosis and oil adsorption to render it suitable for agricultural or industrial use, while simultaneously reducing disposal costs. Pilot testing of the process thus far has demonstrated the technology's capability to produce good-quality water, but process optimization and control yet to be fully addressed are focuses of this work.
We developed a computer model of the process using a dynamic simulator, Aspen Dynamics, to determine the energy consumption of various process design alternatives, and to test control strategies. We proposed process control schemes using basic feedback control methods with PI controllers. By preserving the mechanical energy of the concentrate stream of the reverse osmosis membrane, we found that process energy requirements can be reduced several-fold from that of the previously developed configuration.
Evaluation of Renewable Energy as Source of Power for Desalination of Oilfield Brines
Authors: Barrufet M. A. , Mareth B. C. 
Published: May 2009

Abstract
A hybrid system of wind, solar, and diesel generators could provide an efficient alternative for powering water desalination projects in remote oilfield locations in Texas. Disposal of produced water from oil and gas wells is a costly procedure for production companies, but water-to-oil production ratios exceed 10:1 (by volume) at many wellsites. Much of the petroleum produced in the United States and elsewhere is found in arid regions that could benefit greatly if the produced water could be purified sufficiently for agricultural, industrial, or potable use. Our previous research identified and validated treatment options capable of recovering a high proportion of fresh water from oilfield brine. In this paper we further the earlier research by examining the possibility of using renewable energy to power the units in "off the power grid" situations. A macro-driven spreadsheet was created to allow for quick and easy cost comparisons of renewable energy sources for a variety of scenarios. Using this tool, wind and solar costs were compared for cities in regions throughout Texas. The renewable energy resource showing the greatest potential was wind power, with the analysis showing that in windy regions such as the Texas Panhandle, wind-generated power costs are lower than those generated with diesel fuel.
Acid Stimulation of Geothermal Wells in Central America
Authors: Gomez Julio , Forero Leandro , Barrios Luz , Porras Enrique 
Published: May 2009

Abstract
Unconventional energy sources have become one of the keys to keep the world energy supply along with a sustainable development. In Central America, geothermal power is one of the most important energy sources, given the limited fossil fuel reserves in the area. The region imports 75% of its energy requirements, and geothermal-generated electricity in many countries represents 10 – 25% of the national supply. In fact, Central America is one of the world's richest regions in geothermal resources, according the world energy council.
Despite that the region has an estimated potential for geothermal electricity generation of 4,000 MW, the actual installed capacity is only 508 MW (CIA world fact book). Most of the geothermal projects in Central America produce below their potential due to two main factors: depletion and low productivity (or injectivity) due to scaling in tubulars and formation damage. The damage is typically due to several causes, including drilling mud damage, production fines migration, silica plugging and scales in the reservoir.
This paper describes the results of a five-year well stimulation campaign in El Salvador and Nicaragua, in several geothermal fields, run by different operators. More than 20 stimulation treatments were performed using different acid systems in volcanic and metamorphic rocks. The laboratory observations, their analyses and corroboration with the field data show that the combination of a properly designed treatment and special acid blends has lead to significant improvements in the stimulation of such reservoirs. Comparison of results in different reservoirs with varying stimulation treatments is also included as reference.
Valuation of a Real Options Portfolio
Authors: Oscar Bravo Mendoza , Alfredo Mogollón Monroy Luis , Dario Parra Vega José 
Published: May 2009

Summary
This study aims to define a methodology supported in the concept of Real Options that will allow measuring the impact of variations in the execution of projects, on the value of the investment portfolio of the Production Vice-presidency of Ecopetrol S.A. (PRV). The proposed methodology involves the classification of the potential value of the Real Options and the valuation of the same using the Binomial method, the Montecarlo simulation, and the calculation of explicit volatility; while proposing the 3D graphic representation of the so called portfolio of Real Options.
The resulting methodology was validated using a real case of variation in two projects of the PRV portfolio in the year 2006 and it was possible to determine the way such change impacted the value of the same. This study aims to generate an important advance in management's way of thinking at Ecopetrol S.A., and the petroleum industry at large, basically in the recognition of the value that the sagacity of management decisions, regarding investment projects, has over the portfolio of the company.
Three Levels of Zonal-Isolation Assurance Deployed To Maximize Life of Well Cement-Sheath Reliability and Value: Case Histories From Latin America
Authors: Ramos X. , Martinez C. , Hunter W. , Ravi K. 
Published: May 2009

Abstract
The main purpose of the primary cement job is to provide zonal isolation for the life of the well. To achieve good initial annular isolation and allow the formation to be produced reliably, it is necessary to effectively displace all the drilling fluid from the well.
This can be achieved by using a combination of recognized industry best practices, such as centralization, drilling-fluid conditioning, application of spacers and flushes, maximizing displacement rates, and movement of the casing. Conventionally, success can be measured using a variety of cement-bond logs. Such logs are generally run after cement- slurry placement and before well operation; therefore, they only provide an initial assessment of the annular isolation achieved.
Work has shown that an initially competent cement sheath assessed using a cement-bond log can be damaged under the stresses exerted on it during the life of the well. These stresses can range from planned changes in wellbore-fluid density during the completion phase of a well to unpredictable well events. Therefore, to fulfill the main purpose of a primary cement job, a life-of-well approach to cement-sheath design is recommended.
This paper describes the successful use of three levels of zonal-isolation technology used to improve reliability and productivity for a number of wells in Ecuador. The first level of zonal-isolation technology used was finite-element-analysis (FEA)-based modeling to determine if the cement sheath would withstand the predicted operational loadings on the well. For the second level of zonal-isolation technology, an engineered-cement system with suitable sealing properties for the well was designed, developed, and deployed. For the third level, swell-packer technology was used to address the potential challenge of incomplete mud displacement.
A comparative analysis of conventional cement versus deployment of the three levels of life-of-well zonal-isolation technology is provided.