bluuebunny/crossref_metadata_2025_split huggingface dataset:
MPD Concentric Nitrogen Injection Used to Drill a Successful Horizontal Well in Fractured and Depleted Mature Reservoir in Mexico South Region
Authors: Perez-Tellez C. , Urbieta A. , Lupo C. , Castellanos J. M. , Ramirez O. , Puerto G. , Bedoya J. , Gabaldon O. , Beltran J. , Castiblanco G. 
Published: May 2009

Abstract
This paper will focus on design, planning and execution process followed to apply managed pressure drilling (MPD) using a Concentric Casing nitrogen Injection to drill a high angle well in a fractured carbonate mature field. It will be shown how steady state multiphase flow modeling was used to find operating envelope in terms of ECD and hole cleaning and transient flow simulations to predict and select the best parameters to avoid well slugging and pressure instability.
Formation pressure of this flied have been decreasing over the last 25 years with current values down to 0.4 g/cm3 SG. During the previous years, MPD techniques had been implemented using Nitrogen injected through Drill Pipe to overcome operational problems like mud lost circulation and differential sticking. However the high volume of nitrogen inside the drill pipe generates important limitations for conventional MWD tools, but also the use of Electromagnetic tools has limitations in some cases due to high bottom hole temperature or formations resistivity. This situation has restricted the implementation of high angle and horizontal drilling due to reduced possibility to control the trajectory to reach the target in this kind of wells. Three horizontal wells have been previously drilled in this field without very good results. Nevertheless, horizontal wells are required in order to keep the production level above the forecasted declination. Intelligent drill pipe appeared as another option, but also the tools still will be affected by temperature with gasified system.
The nitrogen concentric injection technique was analyzed as a solution to make feasible the use of conventional mud pulse MWD/LWD tools and keeping at the same time bottom holes circulating pressures within the operational window required to avoid circulation losses, assure good hole cleaning and control risk of hole instability.
Once it was determined the feasibility of this technical option, extensive planning sessions were carried out to design specific operational procedures for this application. It was based on steady state and transient flow modeling assuming different operational parameters to evaluate the expected performance of the operation. Exhaustive Risk Analysis and rigorous class room and rig site training were developed to make all the personnel involved in the operation familiar with the desired understanding of the project.
New Method for Extraction Oils and Greases From Produced Water Using Microwave Techniques
Authors: Bezerril R. H. , Ramalho A. M. Zanbotto , Souza K. R. , da Silva D. R. , da Mata W. , Barillas J. L. M. 
Published: May 2009

Abstract
In determining the Oils and Greases contents (TOG), one of the most important step is the extraction procedure, because at this stage occur the segregation of oils and greases from water produced. It is noteworthy that some samples with low levels of TOG in their composition often are not determined by the standard method of reference. In this case, it is essential the availability of a technique that allows the detection and quantification of these low levels. For this reason, this work aims to optimize the determination of oils and greases using a technique of microwave extraction, followed by the determination in the Infrared Spectrometry through the analyzer Infracal TOG/TPH. The evaluation of the efficiency of the proposed methodology was performed by comparison with the conventional technique whose the extraction of organic matter (oils and greases) is done by manual agitation. However, the basic principle of the technique by microwave radiation is in the process of heating/cooling the sample to promote a more efficient extraction of organic matter. The two techniques were evaluated through the following parameters: sample-solvent proportion and time of extraction at 2, 4 and 6 minutes. According to the comparison of results between them, was observed that the replacement of manual extraction by microwave one was more efficient.
A Practical Numerical Approach for Modeling Multiporosity Naturally Fractured Reservoirs
Authors: Arana V. , Pena-Chaparro O. , Cortes-Rubio E. 
Published: May 2009

Abstract
This work presents a very practical and simple technique to numerically simulate the multiphase flow in multiporosity naturally fractured petroleum reservoirs. A correct modeling of Naturally Fractured Reservoirs requires both good understanding of the physics of the flow through the formation and its correct implementation in a Numerical Reservoir Simulator. Some history matches in Naturally Fractured Reservoirs have showed that the traditional double porosity formulation used since the end of the 60's sometimes does not show good results.
Even though the modeling of naturally fractured reservoirs has been developed through more than five decades, there is still and will be a considerable research activity to obtain a practical and robust modeling for this type of reservoirs.
The proposed method assumes a nested serial flow among the different porosity systems that have been identified. Only the most outer porous medium is considered as continuous and therefore, it carries the flow to the producing wells. The rest of the systems are considered discontinuous, interacting themselves only locally. After applying the Newton method to the discretized system of nonlinear equations, a tri-diagonal matrix block structure is obtained, which is reduced by applying cyclically the Schur complement. This algorithm can be implemented straightforward in a non-fractured multiphase reservoir simulator. It is shown that this approach can model any multiporosity naturally fractured reservoir as long as the fluid transfer functions between mediums could be represented by the quasi-steady-state flow assumption, which is the Warren and Root model.
Results show that the behavior of multiporosity reservoir simulated as double porosity systems result in non-realistic reservoir performance and therefore wrong make-decisions.
New Product for Inhibition of Calcium Carbonate Scale in Natural Gas and Oil Facilities Based on Aloe Vera: Application in Venezuelan Oilfields
Authors: Castillo L. A. , Torin E. V. , Garcia J. A. , Carrasquero M. A. , Navas M. , Viloria A. 
Published: May 2009

Abstract
Scales are secondary deposits constituted by inorganic chemical compounds present in an anthropogenic system. They are generated by changes in the thermodynamic, kinetic and hydrodynamics conditions[1] when formation fluids are produced, or by mutual physicochemical incompatibility between production and injection fluids. Therefore, they can jeopardize the integrity, good condition and useful lifetime of geological formations, producing and injection wells, surface facilities and pipelines, increasing the industry operation costs.
Generally, these problems had been mitigated by using conventional technologies based on chemical compounds (polyphosphate, carboxylic compounds, among others), that generate environmental liabilities and represent high costs for the industry.
Recently, PDVSA Intevep, S.A. has developed a scale inhibitor product based on Aloe vera plant chemical component[2], that offers equal or in some cases better efficiency than conventional chemical treatments, on the same conditions of evaluation. In addition, it offers the potential benefits of a lower environmental impact.
In this study, the performance of this anti-scale polysaccharide-based product was evaluated in the laboratory, simulating oil and water transfer system from flow stations to tanks, producing wells with high water content and injection wells. After, the product was evaluated in pilot field tests in two wells during about 50 days each: Barinas's production well with about 3200 BPD, 98% water and high scale tendency by Oddo-Thompson method at bottomhole.Monagas's production well with about 2200 BPD, 74% water and high scale tendency by Stiff and Davis method at wellhead.
In both cases, the pilot field tests were successful. The scale inhibitor product developed was more efficient than commercial products used in those production wells.
First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador
Authors: Davila E. , Almeida R. , Vela I. , Pazos J. , Coello K. , Chinellato F. , Humbert O. , Porturas F. 
Published: May 2009

Abstract
Horizontal wells are superior in production and recovery to conventional wells, however they are subjected to early water coning towards the heel (water can breakthrough anywhere in the well not only at the heel, due to permeability (K) variation and proximity of water traps). Furthermore, conventional completions do not handle effectivley heterogeneity or permeability contrasts exposed along the sand face. The ICD controls and interrogates more optimally both rock and fluid properties in the reservoir, hence delaying early water breakthrough. This early water breakthrough causes reduction in potential hydrocarbon recovery; the operation of the ICD is minimizing reserves left behind. If water breaks through in a well without ICD, these hydrocarbons are lost and cannot be drained subsequently.
This paper covers the design and application of new open hole sand face completion architectures equipped with Inflow Control Device technology (first in Ecuador) in Block 15. The design and well preparation prior to completion operations and results are presented for two types of formations e.g. consolidated and non-consolidated.
Detailed simulation models were performed and discussed with the Client prior to the drilling operations. The models are run using nodal analysis software and include the reservoir simulation grid.
A-priori simulations explored several scenarios to address and compare different uncertainty issues, flow conditions, well rates and pressure drawdowns both in the pre-planning and final installation of the completion.
The final design incorporates a removable housing ICD hardware, this allows on-site nozzle changes to create relevant delta P, to enhance well performance just after the well has been drilled and uses the real time data from the final logging operations.
The real time logs were then evaluated while the well was drilled and used to refine the final simulation model prior to completion installation in the ground.
The ICD completion architecture was successfully installed in consolidated sandstone and non-consolidated formations, with permeability varying from 250 mD to about 1D. The hydrocarbons viscosities varied from 5 cP, 8 cP, to 12 cP (consolidated sandstone, Well 1) and between 19 cP to 21 cP (non-consolidated formation, Well 2).
Well 1 in the consolidated formation is flowing with equipment ESP and its initial production was about 4000 BOPD dry oil, currently the water cut raised slowly from 1.5% about 24%. Well 2 required well conditioning and performing as expected.
The key advantage of using ICD is that it balances the flow across the entire horizontal section; delays early water breakthrough and uniform areal drainage.
It is concluded that Inflow Control Device proven technology is beneficial and successful in Bloque 15, Ecuador and its application will be considered in other fields.
Case History: Hydrocarbon Production Optimization in Cerro Dragon Using Latest Formation Evaluation and Perforating Technologies
Authors: Espina C. , Baldassa D. , Avagnina D. , Bonapace J. , Lopez E. , Quintavalla C. , Sorenson F. 
Published: May 2009

Abstract
Successful hydrocarbon production in the San Jorge basin requires precise understanding of the great variability in reservoir and fluid properties to determine the reservoir production capacity and achieve the optimum wellbore – reservoir connectivity during perforating.
Efforts to increase hydrocarbon production in the Cerro Dragon area of the San Jorge Gulf basin have been fueled by a combination of the latest formation evaluation, such Nuclear Magnetic Resonance (NMR) and perforating technologies associated with the extensive experience acquired during several years of team work between the operator and the service company.
The operator's needs for a method to help optimize well productivity and, at the same time, be cost effective without compromising the results of the operation required an improvement over traditional tubing-conveyed perforation (TCP). A propellant-assisted perforating (PAP) method that could optimize well productivity while maintaining stringent health safety and environmental standards was proposed. The PAP method uses an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stress and creates perforation breakdown and mild fracturing near the wellbore. Standard perforating components and procedures are used, which provides the same safety features as when conventional TCP operations are used.
This paper focuses on different applications for the PAP method. It also describes the benefits of its use in the San Jorge basin, including enhancing connectivity beyond a damaged zone for better production and near the water contact, where hydraulic fracturing is not feasible, as well as reducing the hydraulic horsepower required for perforation breakdown to obtain production from marginal wells and pre-frac stimulation.
Changing Shale Strengths With Invert Emulsion Drilling Fluids: Theory, Measurement, and Modeling
Authors: Hemphill T. , Duran W. 
Published: May 2009

AbstractProblems with wellbore stability while drilling in shale have plagued the drilling industry for a long time. For good reason, the bulk of trouble-related problems while drilling have been in shales, and great expeditures in time and money are made each year dealing with the problem. However, shale interaction with drilling fluids in the drilling process remains a complex and often misunderstood area of study. By comparison, fewer wellbore stability problems occur while drilling with invert emulsion fluids (IEF) than when water-based drilling fluids are used. The theory of shale interaction with invert emulsions is briefly reviewed in this paper.Actual measurements of changes in shale strength of two shales have been recently made using a new test device from the University of Oklahoma. Two very different shales were studied: one from a deepwater environment and the other a more-competent shale cored in a land-drilling operation. These shales were exposed to invert emulsions having different water phase salinities, and the stresses required to cause sample failure were measured under in-situ conditions. The results showed use of invert emulsions under some conditions weakened the shales, while under other conditions, the shales were strengthened. These results were then interpreted using current osmotic pressure and membrane efficiency theory of invert emulsions.The results were compared to the elastic and porochemoelastic modeling using the rock mechanical properties determined in the laboratory testing. Using a set of drilling and wellbore in-situ stress conditions, traditional elastic wellbore stability modeling is used to predict the changes in tangential stress in the wellbore wall. Next, porochemoelastic modeling is used to predict changes in pore pressure as a function of time and of IEF water phase salinity (WPS). These results are then discussed in relation to the changes in shale strength seen in the laboratory.Knowing that there are significant differences in rock strengths of shales exposed to invert emulsions having varying water phase activity levels, the drilling engineer can more effectively plan future wells, especially those having narrow safe drilling windows.
Wavelet Filtering of Permanent Downhole Gauge Data
Authors: Ortiz C. E. P. , Aguiar R. B. , Pires A. P. 
Published: May 2009

Abstract
Permanent downhole gauges (PDG) for pressure and temperature are very common in oil and gas wells. The data collected by PDG's are used for monitoring the well condition and reservoir performance and, additionally, may provide new and complementary information for reservoir characterization. PDG record data at high sample rates, usually as high as thousands per hour. The computational analysis of this large volume of data requires a previous processing for the removal of noise and outliers and for the reduction of the filtered data. The Discrete Wavelet Transform (DWT) and the Multiresolution analysis were used successfully for this purpose. In the Multiresolution analysis, the DWT is used to decompose a signal in approximation and detail coefficients through low pass and high pass filters, respectively. The coefficients are modified, according to a thresholding method, to remove the noise and outliers before the reconstruction of the original signal. The final result depends on the kind of wavelet and resolution level used for the decomposition process, the method used to estimate the noise level and the rules used to modify the coefficients. In this work, the performance of different wavelet decomposition, noise threshold estimators and thresholding methods was investigated. Several combinations were tested on synthetic and actual data to establish a procedure that efficiently removes the noise and preserves the sharp features, characteristic of changes in production or injection rates, with minimum user intervention.
Visualization Process Approach to Identify Scenarios to Improve Recovery in a Mature and Stratigraphically Complex Reservoir: El Cordon Field
Authors: Santisteban M. , Altamiranda E. , Rodriguez M. I. , De Pellacani M. B. , Alvarez R. 
Published: May 2009

Abstract
The El Cordon Field is located in the prolific San Jorge Basin in Argentina. The El Cordon Field has produced from multiple fluvial volcano-clastic sandstones of Cretaceous age for more than 50 years. Production is primarily from the Cañadon Seco and Caleta Olivia members of the Cañadon Seco formation, and to a lesser degree from the Mina El Carmen formation. The field is characterized by a complex sedimentary environment and mineralogy which affects the quality of the reservoir and makes reservoir characterization and development of exploitation strategies difficult. The field is considered to be in a mature stage of development with over 630 wells under primary production and water injection projects on-going in selected areas of the field.
A Visualization Process Approach was developed in 2007 to identify scenarios to improve recovery and add economic value to the field. After a quick-look reservoir characterization, five scenarios were evaluated for maximizing reserves recovery. Historical and statistical data was analyzed to evaluate various development scenarios and the associated reserves. The various cases evaluated included: 1) a base case; 2) reactivation of existing wells; 3) drilling of wells at normal spacing; 4) infill drilling; and 5) water injection. Application of all cases indicates a potential increase of the field recovery factor from 9.4% to 14.2%. A technical screening for polymer injection feasibility was also analyzed. A second "Conceptualization" phase would include a detailed reservoir characterization study to help reduce uncertainty and support the definition and implementation of the best scenario for further field exploitation.
Upper Completion Design Methodologies for Deepwater Subsea and Dry Tree Applications
Authors: Arrazola A. , McAnally Y. 
Published: May 2009

Abstract
Deepwater fields are one of the largest growth segments of the industry. The technologies that enable this growth economically are those that provide improvements in operational reliability, flexibility, and cost, and which mitigated risks. With offshore rig rates often hitting $500K US per day, special considerations must be taken into account when specifying or designing an upper deepwater completion at depths greater than 1,000 ft (305 m). When selecting a completion scenario, an accurate assessment of risk versus reward must be analyzed in order to design a cost-effective, yet flexible completion. In this paper, the authors outline the proper methodologies in selecting existing technology for each completion approach in subsea and dry tree applications.
Design methodologies for deepwater completions vary when compared to conventional type completions. The basis of design in a conventional type completion includes: 1) a production packer to isolate pressure and fluids from the producing zone and manage production tubing movement and loads; 2) a surface-controlled subsurface safety valve (SCSSV), whose objective is to isolate the tubing and well head from well fluids in an emergency or planned shutdown; and 3) flow control equipment, such as landing nipples, chemical injection nipples, and sliding sleeves. Deepwater subsea or dry tree completions have similar basic requirements as that of conventional completions. However, critical to deepwater are the completion design, planning, quality assurance and quality control, reliability, execution/deployment, and longevity of the completion.
Drivers for completion methodologies in subsea and dry tree applications will be discussed. Issues such as tubing space-out, packer-setting methods, SCSSV operating parameters, sub-mudline tubing and packoff hangers will be reviewed. Temporary well suspension methods will also be discussed where applicable and different completion options will be outlined for each case.
Unified PTA and PDA Approach Enhances Well and Reservoir Characterization
Authors: Ehlig-Economides C. A. , Martinez Barron H. , Okunola D. 
Published: May 2009

Abstract
As permanent downhole gauges have become more reliable, increasingly operators are installing them on injection/production wells. Each time the well is shut in, often solely for operational reasons, pressure transient analysis (PTA) can be performed on the resulting falloff/buildup transient lasting from a few hours to a few days. When the well is flowing, the permanent gauge provides a long term record of pressure behavior during injection/production. Usually the well rate is also determined on a continuous basis, daily or monthly, although often at a much lower data rate than the pressures recorded by the permanent gauge. Recorded pressure and flow rate data are typically used for production data analysis (PDA). Due to the difference in data collection between PTA and PDA, these analyses are performed independently, yielding multiple interpretations from a diverse group of people and software programs. At times the results may conflict, and creating one consistent well and reservoir characterization can be quite challenging and time consuming. A unified interpretation of both analyses would reduce analysis time and increase confidence in the results.
In this study, relatively short-duration PTA data and long-term PDA data are combined to provide a more complete analysis than either PTA or PDA alone can provide. The unified analysis is displayed on a combined plot of pressure change and its derivative from a single transient flow period (preferably a falloff/buildup), and rate normalized pressure (RNP) and its derivative based on injection/production data. Data processing techniques follow a stepwise procedure to construct the combined plot. The result is a virtual drawdown response that can be diagnosed like pressure and pressure derivative and matched with an appropriate model for the well and its drainage area. The method is most effective when flow remains single phase or at least segregated in the reservoir.
Apart from the unified PTA and PDA approach, this study also offers significant improvements in the RNP data processing that leads to a much more conclusive PDA. Synthetic examples illustrate the effectiveness of the technique for known models. Then two field examples show its practical application.