bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Genetic Algorithm for Gas Lift Optimization with Compression Capacity Limitation
Authors: Garcia Artur Posenato , Rosa Vinícius Ramos 
Published: April 2012

Abstract
Gas Lift consists of gas injection into the tubing to reduce hydrostatic pressure loss. The oil produced from each well is a function of the gas injection rate. Some wells have unstable behavior by injecting low gas lift flow rates, on the other hand, excessive injection rates causes loss production due to its high friction pressure drop. Therefore the gas lift flow rate must be kept in a bounded interval. The objective of gas lift optimization is to allocate a limited amount of gas to a number of wells in order to maximize oil production or project revenue. Evolutionary algorithms were applied to achieve optimal production rates and decide which well must be closed when the compression capacity is severely reduced.
The FPSO considered in this study is equipped with three compressors to produce 16 wells with gas lift and export gas. Eventually, one or two compressors can have a downtime due to maintenance requirements or failures. In this case, at least one well has to be closed. The algorithm was developed to optimize the production when the platform compression capacity was reduced and decide which well should be shut-in. It takes into account not only the total amount of gas available but also the gas lift pressure, which can change along time.
The algorithm could solve a practical gas lift optimization problem and was able to determine automatically which wells had to be closed whenever the total available gas was not enough to operate all wells simultaneously. In case of total available gas be enough that all wells could produce, the results obtained by this genetic algorithm were equivalent to any ordinary optimization algorithm.
The production optimization is an important issue even during abnormal operational conditions. The water cut increases with the aging of wells and the gas lift flow rate demand also increases. Severe compression limitations are undesirable but they can eventually occur.
Uncertainty History Matching and Forecasting, a Field Case Application
Authors: Becerra G. G. , Modenesi A. P. , Lisboa E. F. 
Published: April 2012

Abstract
Geological, reservoir, economical and technological uncertainties have an effect on decision making and consequently on reserves development plans. Quantifying the impact of these uncertainties can make this process more reliable. A great difficulty to achieve this in practice is the variability and complexity of workflows available to manage uncertainty using numerical simulation.
The inaccuracy, high uncertainty or lack of reliable data yields risk to the forecasting process, making the calibration of the dynamical model with the field production data indispensable. History matching is an inverse problem and, in general, different combinations of reservoir attributes can lead to acceptable solutions, especially due to the high degree of uncertainty of these attributes. A set of solutions that respect the observed data may lead to different prediction scenarios.
The objective of this work is the integration of history matching with probabilistic analysis of representative scenarios. A methodology that allows the recognition of well-calibrated models within an acceptable deviation is used. This procedure helps to identify the critical uncertain parameters and their possible variation in order to estimate the representative reserve range. The goal is not to find the best deterministic match, but rather to show how the calibration process allows a mitigation of identified uncertainties.
A real case based on a reservoir from Campos Basin in Brazil was used. A 14 year historical period followed by a 12 year forecast period was considered, allowing verification and validation, at a global level, of the proposed procedure in a complex dynamic model. Two different commercial softwares were used, in order to demonstrate the advantages and restrictions of each approach. Distribution variations of the responses in time were evaluated by Latin Hypercube sampling and Monte Carlo propagation on validated proxy models.
The proposed methodology allows: (1) to reduce the range of possible models taking into account the observed data; (2) to identify the existent uncertainty as a function of observed data; (3) to reduce the uncertainty range of critical reservoir parameters; (4) to increase confidence in production forecast. One contribution of this work is to present a quantitative approach for increasing the reliability of reservoir simulation as an auxiliary tool in decision making processes in order to reduce the associates risk and to maximize development opportunities.
Recent Advances in Dynamic Modeling of Naturally Fractured Reservoirs
Authors: Camacho-Velázquez R. , Vásquez-Cruz M. , Fuentes-Cruz G. 
Published: April 2012

Abstract
Modeling of naturally fractured reservoirs (NFR) is a challenging problem which occurs frequently in reservoir engineering. Rock matrix, natural fractures, vugs, and also micro-fractures, constitute these NFR. Furthermore, it is well known that vugs effect on permeability is related to their connectivity. Likewise, in certain cases NFR exhibit fractures at different scales with poor fracture connectivity and disorderly spatial distribution of them. Thus, it is important to consider other alternatives for characterizing these heterogeneities in a more efficient way than traditional approaches. One of the reasons which drive to find solutions to these challenges is because these geological formations contain more than 60% of the world's remaining oil. Therefore, in order to exploit in a more efficient way the remaining hydrocarbons reserves, it is frequently necessary to face greater reservoir characterization and modeling challenges than those ones existing when these reservoirs started their productive life. This is even more relevant when a pressure maintenance project or an IOR/EOR process is planning to be implemented.
This work summarizes recent advances that address different dynamic modeling approaches, taking into account NFR's features like the presence of vugs and fractures at multi scales with a non-uniform spatial distribution. Thus, it is demonstrated the advantages of these continuum approaches to model anomalous behavior that cannot be reproduced by the conventional Warren and Root dual porosity model in order to obtain good-quality history matches for these systems. Also, the characterization challenges that the proposed models pose to the user are reviewed. Finally, some insights aimed to improve the proposed modeling techniques are provided.
New Artificial Lift System Using Coiled Tubing and Reciprocating Downhole Pumps for Heavy and Viscous Oil
Authors: Flores-Avila F. S. , Riaño J. M. , Javier-Martinez M. , Hammond T. , Cantu J. , Ramos J. 
Published: April 2012

Abstract
The use of coiled tubing as an artificial-lift mechanism has been very popular for lifting oil wells as velocity strings (siphon strings) and also removing water and condensate from gas wells. The effect of reducing the effective flowing area, increasing fluid velocity and therefore unloading the well is no longer the only lifting mechanism for this particular application. Reciprocating movement provided by a surface hydraulic operated unit is transmitted by the coiled tubing to a down-hole pump to assist in the lifting process. Therefore for low productivity wells in which the fluid velocity is significant below the minimum or critical velocity to prevent a well from loading up, the down-hole pump will achieve the flowing condition. Utilizing coiled tubing as the motion transmitter to the down-hole pump increases the benefits already explored by the use of continuous rod for SRP applications, by also providing a flow path from surface to bottom.
Through this flow path, chemical injection down the coiled tubing, and returning by the annular space between the coiled tubing and the 2 7/8" tubing string can be achieved while pumping the well. Chemicals pumped can be either viscosity reducers, corrosion inhibitors or any other needed to achieve optimum production. Also this flow path can be used to wash out sand or debris present inside the tubing string in an easy, fast and economical way. Also the potential use of pumping up through the inside of the coiled tubing or the back side (annular space between the coiled tubing and the production string) has been investigated with satisfactory results in this application.
The system has been successfully tested in four oil wells in North Mexico (two of them in the Chicontepec project) with densities up to 13.9 °API and viscosities up to 6464 centipoises. System components, selection criteria, design, execution, evaluation and lessons learned during this first time application are discussed in this paper. Based on the observed results, this technology is being considered as a technical and economical alternative to develop the heavy and viscous oil wells in the area.
Modeling Condensate Banking in Lean Gas Condensate Reservoirs
Authors: Huerta V. A. , Lanchimba A. , Porlles J. W. 
Published: April 2012

Abstract
Gas condensate reservoirs show a complex behavior when they are produced below dew point pressure under isothermal conditions, due to the presence of a two-phase system, and the appearance of a condensate banking phenomena. Recent gas condensate field discoveries in Peru exhibited initial reservoir pressures slightly higher than dew point; as PVT reports indicated that retrograde liquid saturation would not exceed 4%, condensate drop-out was not presumed to be a significant problem affecting well productivity and production performance, and indeed, strategies to face this problem have been currently delayed
Initial multirate tests run in the Peruvian gas condensate fields did show only a slightly indication of liquid drop-out in NIA formation (less than 5%), but some features of the existence of condensate banking were noticed in NOI and ENE reservoirs. As a consequence, it is worth to study the condensate drop-out phenomena as in many cases, it causes a permanent reduction in well productivity, and eventually, in recovery factor, even though is partially compensated by capillary number effects.
An integrated approach to model the condensate banking phenomena at well and fullfield scales, over the time, in Peruvian gas condensate fields is proposed by the combination of two powerful tools: well testing analysis and numerical compositional simulation; while the transient testing analysis, supported by a deconvolution algorithm, is used to evaluate "snapshots" of the three or four regions representing the various mobility zones around the wellbore, the compositional simulation allows predicting how the condensate banking will evolve in the future, and how this phenomena will affect production performance. Preliminary results predict a reduction of gas and oil production and recovery between 3% and 5%.
Measurement, Modeling, and Diagnostics of Flowing Gas Composition Changes in Shale Gas Wells
Authors: Freeman C. M. , Moridis G. J. , Michael G. E. , Blasingame T. A. 
Published: April 2012

Abstract
Few attempts have been made to model shale gas reservoirs on a compositional basis. Multiple distinct micro-scale physical phenomena influence the transport and storage of reservoir fluids in shale, including differential desorption, preferential Knudsen diffusion, and capillary critical effects. Concerted, these phenomena cause a measureable compositional change in the produced gas over time.
We developed a compositional numerical model capable of describing the coupled processes of diffusion and desorption in ultra-tight rocks as a function of pore size. The model captures the various fracture configurations believed to be induced by shale gas fracture stimulations. By combining the macro-scale (reservoir-scale fractures) and micro-scale (diffusion through nanopores) physics, we show how gas composition changes spatially and temporally during production.
We compare our numerical model against measured gas composition data obtained at regular intervals from shale gas wells. We utilize the characteristic behavior illustrated in the model results to identify and to define features in the measured data. We present a workflow for the integration of measured gas composition data into production data analysis tools in order to develop a more complete well performance diagnostic process.
The onset of fracture interference in horizontal wells with multiple transverse hydraulic fractures is shown to be uniquely identified by distinct fluctuations in the flowing gas composition. Using these measured composition data, the timescale and durations of the transitional flow regimes in shales are quantified, even for high levels of noise in the rate and pressure data. Reservoir properties are inferred from the integration of the compositional shift analysis of this work with modern production analysis.
This work expands the current understanding of well performance for shale gas to include physical phenomena that lead to compositional change. This may be used to optimize fracture and completion design, improve well performance analysis and provide more accurate reserves estimation.
This work demonstrates a numerical model which captures multicomponent desorption, diffusion, and phase behavior in ultra-tight rocks. We identify and validate diagnostic trends via high-resolution composition, saturation and pressure maps. We provide a workflow for incorporating measured gas composition data into modern production analysis.
Sizing of Pipelines for Gas-Condensate by Multiphase Dynamic Simulation, Based in Minimum, Medium and Maximums Flowrates
Authors: Martinez-Ortiz V. 
Published: April 2012

Abstract
In this paper a methodology based in multiphase dynamic simulation to size gas-condensate pipelines is presented. This method considers minimum, medium and maximum forecasted field flowrates. Sizing the pipeline considering only the maximum flowrate can result in oversizing the pipeline diameter. An oversized pipeline can cause operational problems when the field's production declines. The multiphase dynamic simulation allows evaluating the flow stability for minimum and medium forecasted flowrates, where the steady state condition may not be defined.
In this paper, this methodology was applied to size a pipeline in South America's gas condensate fields. Previously, these pipelines were oversized using only steady-state tools.
Geomechanics Characterization of the Clastics and Carbonates Formation of Southern Fields of Mexico (2005 – 2009)
Authors: Tellez C. P. , Elisabeth F. , Bentosa E. , Munoz D. , Cortes C. 
Published: April 2012

Abstract
The geological structures to drill and reach the producing reservoir of the South region of Mexico are very complex. They can vary from deep fractured carbonates reservoir at more than 7000 m true vertical depth, anticline uplifted by salt or/and shale dome themselves inducing abnormal pressure up to 2.2 gr/cc of equivalent density in the overlying formation. The geological complexity of the south region is reflected also in its geo-pressures, geo-stresses and geomechanical properties.
Since early 2000 Petrόleos Mexicanos (PEMEX) has considered the Geomechanics discipline as a key component for their future economic success. With the urgent need to improve recovery, more complex wells are being drilled and PEMEX has taken the challenge to have geomechanics analysis for any well that will cost more than 10 Million of dollars. This strategy has been translated with training of key personnel, geomechanical core campaign and geomechanics studies included into their drilling program. Since 2006, more than fifty geomechanics studies (analytical and numerical) have been carried out in the south region of Mexico and have been incorporated to mitigate drilling risk and optimize well design. Velocity analysis, Geomechanics core test interpretation, caving interpretation, breakouts and induced fracture analysis from image logs, direct pressure measurements, leak off test and mini-frac interpretation are some of the different information used to calibrate the geomechanics studies.
This paper refers to the regional compilation, findings and results of the 50 geomechanics studies conducted in the different fields of the south region between 2006 and 2010 and its impact on the well design of exploratory and development locations. The paper presents to the industry, the methodology used for their construction, illustrated by the data used for their calibration and how they were successfully used for well design and real time decision with selected post mortem analysis for some well. Finally the results of the geomechanical studies (Strength, overpressure and stress anisotropy) have been mapped regionally to forecast the geomechanics behavior in the entire south region of Mexico to optimize the drilling of future well locations.
Methodology to Quantify the Value of Information Incorporating Operational Flexibility
Authors: Bovolenta Humberto D. , Munerato Fernando P. , Schiozer Denis J. 
Published: April 2012

Abstract
At the beginning of field development, many questions regarding the reservoir structural model still remain and it is necessary to mitigate this uncertainty and associated risk before the final field development plan proposition. Mitigation of risks and uncertainties can be done in two ways: through additional information acquisition and operational flexibility, but both have limitations. Information has value within a project up to the point where the benefits obtained do not outweigh its acquisition cost. Flexibility may not be viable due to the impossibility of practical changes in the production strategies or in the facilities when these are already in operation. The value of information (VOI) and value of flexibility (VOF) are resources capable of quantifying the relevance of information and flexibilities in reducing project risk, as demonstrated by the methodology proposed by Xavier (2004). However, this methodology considers fixed production strategies, which may significantly impact the value of information, overestimating it because it does not incorporate future flexibility. Thus, the objective of this paper is to improve this methodology through the implementation of an assisted automated process for strategy selection and optimization, incorporating operational flexibility to the project by reducing the number of dry wells and through a more accurate dimensioning of the production strategies and facilities. The methodology is applied to one simple case, where the only uncertain attribute is the structural model, aimed at the validation of the automated methodology. The results indicate that, in the initial phase of development, the more accurate design of the production strategies and facilities has a direct impact on the expected monetary value of the project, which is reflected in the VOI and in the decision analysis, increasing the accuracy and the value of these tools in projects with a high degree of associated uncertainty.
Evaluation of Multifractures Through Unconventional Log Using Gamma Functions, Mineralogy and Fracture Migration in Laminated Sandstone of Chicontepec's Formation, Chicontepec Channel, Mexico
Authors: Garcia S. Gomez , Estrada E. , Rodriguez L. , Vargas A. , Gomez G. , Picon O. , Estrada J. , Zarate Heriberto , Salazar A. , Tineo F. , Quediman B. 
Published: April 2012

Abstract
Chicontepec Basin has more than 80% of reserves in the North of Mexico; however, due to the complexity of the site, only contributes 25% of total production in the region. Considering the complexity of lithology, variation and discontinuity of facies and petrophysical conventional evaluation that do not identify: effective porosity, quantification irreducible water saturation, water moving, type of oil, identification of facies, it is proposed to use a methodology which, in addition to conventional calculations, must achieve the quantification of the fractions of porosity, movable fluid differentiate the irreducible, identify areas of low resistivity but hydrocarbon storing and integrating the results of the analysis with the sedimentary facies, gamma functions, determination the volume of shale and identification of areas of least resistance to fracturing identified through descriptions of cores, and extrapolate to other wells with less information through neural networks.
Implementation of these unconventional logs (NMR, Mineralogy and cross dipole acoustic) aims to characterize in detail the site, minimizing the uncertainty associated with the results obtained with conventional petrophysical evaluations made only from basic logs. The generation of Gamma functions (inversion of T2 spectrum with gamma functions), Laminar Disperse and Structural Clays and Fracture Analysis of Migration allows us to optimize the selection of intervals allowing for greater accuracy when shooting, fracturing and finish well. Additionally, allows more accurate to estimate reserves to define areas containing oil and which could not be identified with conventional logs.
Have fractured more than 20 wells following this methodology with an average of between 300 to 600 bpd and 4 wells surpassed the 800 bpd
Using Neural Networks for Determining Hydrocarbons Presence from Well Logs: A Case Study for Alagoas Basin
Authors: Fernandes M. A. 
Published: April 2012

Abstract
This work proposes a method to determine oil, gas and water presence in reservoirs directly from commonly measured well log parameters, such as resistivity, gamma-ray, density and neutron, by using Artificial Neural Networks (ANN). The wells from the oil field approached in this case study require frequent workover jobs to put their multiple zones in production one after another as soon as they become depleted. Once this oil field is segmented in hundreds of hydraulically isolated reservoirs containing small oil volumes, a procedure for identification of the fluids contained in the reservoirs crossed by a well can be of great value to make routine decisions (regarding evaluations and perforations) faster and more accurate.
The work started based on the observation that zones with different fluids (or the absence of fluids) show characteristics sufficiently particular in the cited logs that make possible their classification by an artificial intelligence algorithm. The ANN approach is chosen considering its capability of working with a non-linear problem in which some uncertainties are also present, based on algorithms with relatively simple implementation.
A characteristic of this method is that the ANN can be trained with data points of a specific zone, block or area, which means adjusting itself to this specific data set, learning its particularities, what leads to more accurate results when used to classify other zones with similar characteristics. The method's applicability increases in mature fields presenting a large number of logged wells with perforated and tested zones allowing validation of the information used in the supervised learning of the ANN.
For the training and validation of a Multi Layer Perceptron (MLP) Neural Network, 160 data points were used with depth information and the corresponding Gamma Ray, Resistivity, Density and Neutron log values, along with fluid identifications based on the results of logs and perforations. These data points came from two wells of Alagoas Basin, Brazil.
In the tests performed in this work, the ANN presented a generalization capability after extracting information from the training data, leading to a good confidence in the classification results for a testing data set.