bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated SAGD Thermal Stress Modeling
Authors: Gonzales Adolfo C. , Bajwa Faris J. 
Published: December 2010

Abstract
Among the multiple steam operation technologies, SAGD (Steam-Assisted Gravity Drainage) is one of the most popular techniques for the development of heavy-oil bitumen reservoirs. SAGD (horizontal-well method) operations require the implementation of parallel horizontal-well (injector and producer) single/dual completions to initially warm up the heavy-oil reservoir through early steam-circulation operations. Once the bitumen reaches low viscosity and is mobile, it becomes part of the return flow path, which is typically followed by steam injection into the reservoir to induce full production. The design of steam operations is both technically challenging and costly and depends on several aspects: those related to the reservoir itself and those associated with proper well planning. For an effective steam operation design, understanding how wellbore configuration affects heat transfer, tubulars used in well construction, thermal properties of cement and wellbore fluids, as well as steam operation parameters, like input conditions, flowrates, and duration of steam operations, are very important.
An integrated thermal/stress analysis approach was taken using a commercial thermal-simulator model and stress-analysis tool to first size and optimize steam temperatures, pressures, quality, and heat loss during a typical pre-SAGD operation and post-SAGD-associated injection and production events. Critical stress conditions of tubulars exposed to this SAGD steam loading events were then evaluated and resolved. Finally, an optimum SAGD design was delivered that fulfilled the thermal requirements while ensuring safe tubular design.
This paper details a systematic approach for analysis that includes the impact of formation, fluids, and tubular thermal properties, as well as wellbore configuration (e.g., comparison of single vs. dual completion scenarios applied to a practical scenario). In addition, this paper discusses the use of vacuum-insulated tubing, insulation material, and the use of nitrogen in well configurations as possible heat-loss mitigation solutions. The impact of steam quality, pressure, temperature, flow rate, and time affecting heat distribution downhole is realized through sensitivity analysis. The purpose of the paper is to emphasize the importance of properly defining and identifying the well-configuration components, formations, fluids, thermal properties, steam operation conditions, and the impact they have on effectively planning for heavy oil-bitumen steam SAGD well operations. The paper couples thermal SAGD design with stress analysis and illustrates how to resolve extreme compression resulting from thermal expansion on wellbore tubulars, as typical steam operations involve elevated wellbore temperatures.
A Methodology to Assess Uncertainties and Risks in Heavy Oil Projects
Authors: Ortiz Volcan J. L. , Iskandar R. A. 
Published: December 2010

Abstract
The commercial success of heavy oil projects highly depends on the intensive use of the right combination of technologies and competencies during the life cycle of reservoir assets in order to achieve world class recovery of hydrocarbons, with highly productive wells and flow assurance supported by a reliable production infrastructure including oil upgrading facilities in some cases. When projects are located in environmentally or socially sensitive areas other technologies are required to assure the viability and sustainability of the project.
In this paper we present a methodology to assess uncertainties and risks of heavy oil projects using Front End Loading (FEL) and Life Cycle Costing (LCC) and it is based on comparing data and information systematically during the definition phase vs. results from the execution phase of similar projects. We have applied this methodology successfully in several heavy oil projects providing an alternate approach to complex data hungry methods.
A general model and taxonomy is used to standardize activities performed in the different phases of a heavy oil asset project life cycle allowing adapting and adopting this methodology for any heavy oil field. All activities are classified based on their impact in capital expenditures (CAPEX) and operational expenditures (OPEX) using FEL to establishing the level of definition of each asset component and Life Cycle Costing for comparing different scenarios with combination of technology options. Uncertainty and risk analysis is performed for all cost driven variables by analyzing cause and effects relationships and assigning typical probabilistic distributions for key and important activities in each phase of the heavy oil asset life cycle. The standardized heavy oil asset model provides an acceptable representation of life cycle phases of asset components (natural and physical) so the associated costs can be forecasted probabilistically using data and information from projects in similar assets (analogs) and technologies.
We recommend application of this methodology as an alternative for traditional project planning especially during early phases of a heavy oil assets life cycle particularly discovery and appraisal and we provide a roadmap with hands on description of work flows and techniques so it can be applied by asset project teams who can create data bases with standardized data and information from heavy oil asset projects that can be shared to improve recovery of existing heavy oil resources at worldwide level.
Phase Implementation to Real Time Well Testing Using Fiber Optical Sensing Technology, San Alberto San Antonio Fields: Case Study – Part I
Authors: Ferraris C. G. , Gonzalez L. E. 
Published: December 2010

Abstract
In the 90's, after success in drilling wells deeper than 5,000 meters with high production rates between 80 to 120 MMSCFD of production, Petrobras decided to continuously measure pressure on their high productivity wells (7″ production tubing) because of the difficulty they experienced when running gauges in the production mode after the wells were completed.
Therefore, the decision was made to use permanent electronic gauges to obtain downhole pressure as it was a proven technology and optical sensing technology (fiber optics) was new to the industry. At that time, four wells in the San Antonio and San Alberto fields were completed with electronic gauges with different results….one did not work, one failed at the beginning, one failed months later, and one worked intermittently.
Petrobras' objective to have real time downhole pressure did not change, and they planned for the next workovers of their wells to use optical sensing technology instead of electronic gauges. These specifications were required on their next bid, and the four wells were assigned to Weatherford International. Since that time, this technology is working in the four wells in the San Antonio and San Alberto fields, and there have only been small problems on surface equipment connections, which were corrected promptly.
Because of this success, Petrobras decided last year to implement optical sensing technology in all of their new wells because it was the only proven technology that could support the high vibration, produced by the 7″ tubing wells, and high temperature. The decision was taken one step further to install fiber optic downhole flowmeters on the intelligent completion wells. The use of this technology, complemented with the online PanSystem™ well test analysis software, enables real time well testing.
A Unique Sand Control Screen that Enhances Productivity
Authors: Woiceshyn G. , Russell T. , Caulfield I. 
Published: December 2010

Abstract
Today's conventional sand control screens, such as slotted liner, wire wrap, and premium mesh (both fusion-bonded or "soft-sintered"), retain sand via arrays of single-sized gaps. Although open flow area and mechanical strength differ among such screens, the sand retention mechanism is virtually the same—2 dimensional and gap-based—and performance is sensitive to the particle size distribution (PSD), which is not always well defined or constant along a horizontal wellbore. A very different sand control screen was developed that consists of a ~6 mm thick bed of highly compressed stainless steel wool and is protected by a perforated jacket with about 40% open flow area. The wool fibers criss-cross randomly to create a wide distribution of angular (rhombohedral) pores designed to retain a wide range of PSDs without plugging. Furthermore, this unique, three dimensional filter allows more "harmless fines" to pass, especially during startup, thereby creating an enhanced permeability layer of sand against the screen.
About 1 million feet of this screen has been installed to date (mostly in producers but also in injectors) in a wide range of applications—SAGD, cyclic steam, steam drive, conventional heavy and light oil, gas, gas hydrates, and water producers/injectors—with a remarkably high success rate. Due to its high flow capacity and strength, it has become popular for pump protection and for re-completions inside failed screens. Furthermore, this screen has been successfully replacing gravel packing in certain fields due to its enhanced performance characteristics and lower cost. It has proven attractive for standalone completions in long horizontals where the PSD is either poorly defined or varies significantly from heel to toe.
This paper presents the highlights of recent laboratory testing and field experience that demonstrate the screen's wide range of application, robust characteristics, and unique ability to enhance productivity and handle a wide range of sands with one "gauge". The screen's limitations are also presented.
With today's emphasis on standalone screen (SAS) completions, cost reduction and long horizontals, a presentation of this screen's properties and recent performance is very timely. Furthermore, this screen has recently been combined with inflow control devices (ICDs) to equalize toe-to-heel flux in order to prevent/delay water/gas coning and also minimize watercut if/when water eventually migrates to the wellbore.
Turbidite Chicontepec Formation, Channel Chicontepec, Mexico: A Diagenetic and Petrophysical Study to Optimize the Completions Corralillo Area
Authors: Estrada E. , Vielma M. , Morales J. , Estrada J. , Tineo F. , Gomez G. 
Published: December 2010

Abstract
This work is the result of authors' experience in complex reservoirs such as the calcitic-lithic sandstones of the Chicontepec Formation, in the Chipontepec Channel Basin. These rocks, highly reactive to acids, present problems of low permeability; they are often fractured but production decline rapidly in time. The diagenesis experienced by these reservoirs is very complicated because the large amount of carbonate lithics, igneous and metamorphic components present, which can be mixed with detrital clays and dissolution of fossils (moldic porosity).
The Chicontepec Formation is a turbidite sequence deposited in shallow waters in a submarine canyon with submarine fans, benthic foraminifera, some charred plant remains, and graded and convolute cross-lamination. It is composed by alternating well cemented calcareous-clayey-sandstones, and dark gray calcareous shale. It exhibits conglomerate horizons, consisting of chert and platform limestone clasts. Petrographically it is composed by very fine grained to middle and, occasionally, course litarenite; consisting of carbonate lithic (mudstone), monocrystalline quartz, plagioclase (sericitized) and a minor lithic igneous, metamorphic, silt and shale components.
The main authigenic cements are kaolinite, chlorite, calcite, ankerite and interstratified I/S. The facies described from core samples were adjusted with microfacies obtained from thin sections where permeabilities ranging 0.1 to 400 milidarcy, and porosities between 4 to 15% and occasionally 20% could be differentiated. The described type of porosity is mainly intergranular, with some intragranular and moldic porosity.
The analysis of high technology logs, such as magnetic resonance and image logs, permitted us facies modeling by using a 3D multivariate analysis of Coates permeability, effective porosity, shale volume and volume of irreducible water to represent facies described in the analyzed core samples and to obtain an integrated Petrophysical-Geological model. The study of these diagenetic facies allowed us to predict which of the electro-facies were susceptible to high reactivity and select the best candidates for stimulation.
Marlim Field: An Optimization Study on a Mature Field
Authors: Bampi Dirceu , Costa Odair José 
Published: December 2010

Abstract
Giant fields contribute to a significant portion of the total hydrocarbon production in Brazil. The majority of these fields are in advanced exploitation stages. This paper describes a drainage optimization study performed on the Marlim field, a giant and mature field located in the Brazilian Campos Basin.
Two optimization steps were carried out in this paper: (1) horizontal and vertical placement of sixteen new producer wells, and (2) given the best well targets distribution obtained in the previous step, determination of which wells have the potential for future sidetracks for optimizing these well placements after the original well abandonment.
Possible targets for the original sixteen wells and the surrounding targets corresponding to possible sidetrack wells were chosen based on the inspection of post-processed maps, such as the thickness of mobile hydrocarbons at specific reservoir exploitation dates while taking into account their structural and stratigraphic characteristics. Both the well placement optimization and the best time to perform the sidetrack were obtained using a global metaheuristic optimizer based on reservoir flow simulations. These studies analyzed the most appropriate economical criteria (water-cut limit and the minimum oil rate) to abandon the original well and perform the sidetrack.
The result of the first optimization increased the cumulative oil production in 46.5 million barrels (7.4 million std m3) over the base case, which was previously obtained by a high-quality extensive trial-and-error manual process. Given that some well positions defined in the manual optimization did not change after a large number of simulation runs were performed by the optimizer, the authors could attest the quality of the previous work. The second optimization provided an increase of 15.7 million barrels (2.5 million std m3) in aggregate output relative to the first optimization, with six well candidates to sidetrack. This work concluded that the water-cut limit and minimum oil rate economic criteria had a very strong influence on the objective function as a result of the fact that the timing of well abandonments in favor of their sidetracked wells is key to anticipate oil production.
At the cost of several reservoir flow simulations, this optimization methodology was able to improve the recoverable oil volume by accelerating the oil production and, as a result, the new well locations proposal became more economically attractive.
Regreening of Arid and Semiarid Areas by Using Produced Water from Oil Production in the Development of Agroindustrial Projects of Biodiesel Production
Authors: Farfan L. E. , Brinez D. F. , Perez G. S. , Pachon R. A. , Chavarro Jorge I. 
Published: December 2010

AbstractThe north of Huila state has an extension of 4360 km2 with of arid and semi-arid area conditions where the main limitation for agricultural production is both water deficit and low development of the dry ecosystem soils. Two hundred oil wells which produce 125.000 BWPD are located in this area; a 72% of this water is required for being re-injected to maintain reservoir pressure, but the remaining of water cannot be spilled out due to its chemical features that can contaminate the environment, for this reason the remaining water must be also re-injected.The strategy of re-greening of arid and semi-arid areas with the use of produced water from oil production is possible through the treatment by reverse osmosis in a scheme continuous of reactor tanks that allow the removal of salts, chlorides and dissolved metals in water, and then can be use in the irrigation of 142 hectares of Jatropha crop for the Bio-Diesel production that is a cheaper alternative than water re-injection.With this research program ECOPETROL S.A., Huila-Tolima Operation District, supports the ONU's initiative of combating the desertification because it contributes to the recovery of arid and semi-arid areas through the development of environmentally friendly projects; also, it converts a problem for oil industry into a innovation solution that creates agricultural Jobs, news sources of renewable energy, improve of life quality of the population using technological applications in severe environmental conditions.
Application of Multiphase Meters in Gas Condensate Wells with High Flow
Authors: Navarrete C. , Gamboa E. 
Published: December 2010

Abstract
This paper presents the experience of Camisea project, the largest complex of Gas-Condensate fields developed in Peru, with the application of multiphase meters in high productivity wells in remote locations where the continuous supervision and monitoring of the main production variables of each well are essential, above all volumes of gas and liquids without separation.
Thus, the technology of multiphase meters helps making decisions with its information as online well performance, trend analyses, quick diagnostics and the optimization of the production. Lessons learned are presented based on field tests in different wells in Camisea. What's more, we share experiences with the use of this technology in different applications.
Microporosity and Laminations in Non-Archie Reservoirs Create Challenges for Water-Saturation Computation and Reserves Evaluation: Camisea, Peru
Authors: Markley M. , Seminario F. , Gabulle J. , Luquez J. 
Published: December 2010

Abstract
The Camisea-area gas reservoirs are world-class reservoirs with production from 15 wells producing more than 1.2 Bcf/day and 85000 BCPD from the jungles of Peru. These reservoirs consist of stacked dune and marine sands that have undergone substantial diagenesis. The salinities in these reservoirs are low by "Archie-standards". Extensive coring has been done in all of the reservoir intervals in the three main fields of San Martin, Pagoreni and Cashiriari. These cores show macro, meso and micro porosity distributions. The upper-most sands, Cretaceous Vivian and Chonta are shallow marine and tidal depositions, while the pre-Cretaceous Nia and Permian Noi-Ene sands are continental deposits mainly composed of eolian facies. Resistivities vary widely and gamma ray responses are both high and low in reservoir intervals. In some intervals there is very poor correlation between the gamma ray and the very low clay volumes due to feldspar content. The micro-porosity creates a "low-resistivity" pay effect and irreducible water content in the reservoir that is not related to clay porosity. High iron residues also may cause some complications for the interpretation. A combined approach of cores and logs was used to minimize uncertainty and maximize confidence in the results. Special core analysis was done to analyze the Archie exponents of "m" and "n" in the different formations. Core capillary pressures were also measured in conjunction with nuclear magnetic resonance core measurements to analyze irreducible water volumes. All three measurements were used to guide computation of water saturations from the logs in these environments, formation-by-formation. The objective was to use the core analysis parameters as a guide to validate computation of saturations and reserves in the most appropriate and accurate manner. Small errors in saturation would cause very large uncertainties in producible reserves from this mammoth field. Examples of the special core analysis results, SEM analysis, complex pore structure, and log analysis approach will be used to show the integration of the data to make the most accurate computation of reserves.
New Inert Tubing-Conveyed Large-Bore Sampling System for Deep-Water Cased-Hole Applications
Authors: Barros R. , Irani C. , Delano F. , Araripe P. , Filho H. 
Published: December 2010

Abstract
A number of extremely promising deep water hydrocarbon plays have been identified off the East coast of Brazil that continue to pose technical challenges in the collection of accurate reservoir characterization information. Early exploratory programs have identified the large potential of these opportunities, and national oil companies (NOCs) as well as international oil companies (IOCs) have begun significant activity directed at exploiting these reserves. Because of water depths and significant strata depths that have to be penetrated to reach these reserves, considerable effort has been expended to keep costs under control without compromising the quality of the information collected. Additionally, operational issues and the opportunity for improved reservoir characterization have prompted the use of large-bore strings that will allow an increase in production rates and improved fluid hydraulics, while also facilitating the exploitation of various zonal isolation mechanisms crucial for multi-zone investigations.
This paper discusses a sampling system that was modified to meet stringent bottomhole single-phase sampling requirements in this challenging environment. The new system was developed from a well-established, proven five-in. sampling system that was adapted to a larger-bore configuration for use in deepwater applications. The resulting bottomhole sampling system is ideally suited for extreme HPHT (400°F and 20,000 psi) applications in cased-hole environments. All the samplers are inert to facilitate a representative hydrogen-sulfide analysis, and the multiple samplers can collectively deliver a significant volume (3,600 cc) of single-phase reservoir fluid. The sample carrier is also equipped to accommodate memory gauges that can provide a quantitative measure of the sampler's representative status during recovery.
The large bore sampling system has already demonstrated its exceptional performance in deep-water field applications, and a number of field studies will be presented. The availability of this large-bore sampling system has significantly impacted the present capability to successfully collect representative bottomhole samples in demanding offshore environments. Also significant for most of the clients is the larger volume of sample collected, since there has been a strong push for sampling tools that offer larger-volume capacity as well as reliability and improved economic efficiency.