bluuebunny/crossref_metadata_2025_split huggingface dataset:
Generating Synthetic Well Logs by Artificial Neural Networks (ANN) Using MISO-ARMAX Model in Cupiagua Field
Authors: Alzate G. A. , Arbeláez-Londoño Mastan , Agudelo A. Naranjo , Romero R. D. , Bolaños M. A. , Escalante D. L. , Quintero S. Gómez , Peláez C. A. 
Published: June 2014

Abstract
Well logs acquired directly in field have turned out to be one of the most key engineering elements to evaluate hydrocarbon formations. Nevertheless, the lack of information, some technical troubles related to the unfolding of tools, the operational states of the well and many other reasons may sharply limit the carrying out of an optimal formation characterization methodology along the entire productive or injective lifespan of a reservoir. Nowadays, artificial neural networks (ANN) are one of the strongest tools to supply such missing information in order to generate synthetic logs.
In this paper, we explain the putting into practice of an ANN methodology with the aim of provide useful input information in geomechanical modeling for the hydraulic fracturing simulator GIGAFRAC. More explicitly, the purpose of the schemes presented here is to provide transit-time curves for primary or compressional waves (DtP) and secondary or shear waves (DtS), based on full information measurements of Gamma Ray, Neutron-Porosity, Density, DtP and DtS logs; for some wells in the Cupiagua field located in Colombian Foothills, which break through some geologic formations such as Mirador, Barco, Guadalupe, and Los Cuevos.
A noteworthy amount of considerations were taken into account to ensure the success of the ANN estimation phases. A strong focus is done regarding to filtration and quality control of the input information to the network, relating to the control mechanism of outliers, as well as the splitting-up of logs in zones by using a geological criteria and spreading of data information in computationally convenient vectorial and matricial arrangements. Finally, good adjustments were obtained throughout the validation phases and they all were considered as successful outcomes, together with training phase and subsequent use of the same for estimating DtP and DtS curves.
Boscan Field_Highly Deviated Wells to Avoid Water Production in a Heavy-Oil Reservoir Influenced by an Active Aquifer
Authors: Plaza R. , Urdaneta L. , Valera N. , Bassano F. , Smith B. , Shannon C. , Izgec O. , Benson I. , Suman B. , Matheus L. , Molina A. 
Published: June 2014

Abstract
The Boscán field is a giant heavy oil reservoir (10° API) located in western Venezuela. The field is operated by the Empresa Mixta PetroBoscán. OOIP is estimated as high as 35 billion barrels. For over 60 years of production history, only ~5% of the OOIP has been recovered thereby considerable development opportunities remain at Boscán to increase recovery. Drilling highly deviated completions has proven to be a successful strategy to maximize oil recovery and mitigate ever increasing water production.
The southern part of the reservoir is in contact with an active aquifer where a high contrast in fluid viscosity is present between formation water and heavy oil (0.7 vs. 350 cP) generating large differences in the mobility ratio. This causes premature water breakthrough and sharp increases in water cuts over short periods of time. Water production during the last 10 years has exceeded the handling, separation and injection capabilities at Boscán leading to a significant number of wells being prematurely shut-in.
In the past, in order to control water production, shorter vertical wells were drilled and bottom water shut-off jobs were performed. However, these strategies have proven unattractive since overall net pay was reduced and coning tendencies were high. A new strategy was introduced of drilling highly deviated wells to maximize the reservoir exposed and mitigate water production by reducing pressure drawdown in the near wellbore region.
Recently, a ~5.5 million upscaled grid-block reservoir simulation model was developed and is being utilized to understand the aquifer impact and for optimal field development. Initial simulation results confirmed that highly deviated wells perform better and delay water conning.
This paper focuses on a deviated well strategy to increase recovery per well from a heavy oil reservoir with a strong aquifer influx. It shows how multi-disciplinary teamwork is being utilized to develop and execute the strategy and how Boscán may be used as an analogy for other fields having similar reservoir conditions.
Innovative Fiber-Based Proppant Flowback Control Technique Unlocks Reservoir Potential
Authors: Ramones M. , Rachid R. , Milne A. , Pelaez K. , Gutierrez L. , Madrid O. , Ponce G. , Ponce O. , Cruz S. 
Published: June 2014

Abstract
Most of the reservoirs in Ecuador are in mature fields with subhydrostatic pressure. To produce from these reservoirs, an artificial lift system must be included as part of the completion, and stimulation treatments are frequently required to produce economically.
Hydraulic fracturing is commonly applied today to remove formation damage, since the penetration of the matrix treatments sometimes is not enough to fully bypass the damage zone because of the depletion. However, in the U formation, after performing fracturing treatments, the maximum drawdown is limited to ensure proppant pack stability. Proppant flowback has been an issue in the first wells hydraulically fractured. Apart from the production limitations, the consequences of proppant flowback may include: decreasing of fracture conductivity, damage to surface and downhole equipment, additional operational cost, and loss of workover efficiency, one of the main factors affecting the Ecuador oil industry scenario.
All these consequences have created the need for a new approach to be able to produce these well economically without the mentioned issues. An innovative fiber-based technology for proppant flowback control (FBPFC) was proposed. At surface, low concentrations of short fibers are easily dispersed into the fracturing slurry. Meanwhile, at downhole conditions, the fibers are activated by temperature, becoming sticky and bonding with each other to create a continuous web that consolidates the proppant pack. The fiber web has negligible effect on conductivity, creating a stable proppant pack that is resistant to cyclic stress loading. This translates into higher drawdown and productivity.
The novel FBPFC technique has been successfully implemented in Ecuador, after determining the associated risk of proppant flowback, based on the geomechanical reservoir properties. More than 30 stages have been pumped with this technique without proppant flowback despite optimizing the drawdown after the treatments. This resulted in a four- to five-fold increase in production compared with a two- to three-fold increase in wells where the bottomhole flowing pressure was limited by the risk of proppant flow back. The use of FBPFC enabled the full potential of the reservoir to be realized.
Use of Emulator Methodology for Uncertainty Reduction Quantification
Authors: Ferreira C. , Vernon I. , Schiozer D. J. , Goldstein M. 
Published: June 2014

Abstract
In petroleum engineering, simulation models are used in the reservoir performance prediction and in the decision making process. These models are complex systems, typically characterized by a vast number of input parameters. Usually the physical state of the reservoir is highly uncertain, and thus the appropriate parameters of the input choices. The uncertainty analysis often proceeds by first calibrating the simulator against observed production history and then using the calibrated model to forecast future well production. Most models go through a series of iterations before being judged to give an adequate representation of the physical system. This can be a difficult task since the input space to be searched may be high dimensional, the collection of outputs to be matched may be very large, and each single evaluation may take a long time. As the uncertainty analysis is complex and time consuming; in this paper, a stochastic representation of the computer model was constructed, called an emulator, to quantify the reduction in the parameter input space due to production data over different production periods. The emulator methodology used represents a powerful and general tool in the analysis of complex physical models such as reservoir simulators. Such emulation techniques have been successfully applied across a large number of scientific disciplines. The emulator methodology was applied to evaluate the production data capacity to identify uncertain reservoir physical features over the production period for a synthetic reservoir simulation model. The synthetic model was built to represent a region of an injector and related producers. In the case studied; thousands of realizations were required to identify certain physical reservoir features. This justifies the use of emulation and shows the importance of this technique for the identification of regions of feasible input parameters. Moreover, the impact on the input space reduction due to different production periods was determined. The emulator methodology used assists in carrying out tasks that require computationally expensive objective function evaluation, such as identifying regions of feasible input parameters; making predictions for future behavior of the physical system and investigating the reservoir behavior.
Effect of Dissolved Solids on Reuse of Produced Water in Hydraulic Fracturing Jobs
Authors: Haghshenas A. , Nasr-El-Din H. A. 
Published: June 2014

Abstract
Multiple-stage hydraulic fracturing jobs are usually needed to produce economically from tight sand gas reservoirs. High costs of water acquisition and waste water disposal, and the lack of available water resources near operation sites, make the reuse of produced water an unavoidable option. Applications of produced water in hydraulic fracturing jobs result in low quality fracturing fluids, which usually have high levels of hardness and salinity. This is especially true for flowback fluids, which contain high polymer loading. The viscosity and rheological properties of fracturing fluid, significantly affect leak-off rate, proppant placement, length and width of fractures, fracture conductivity, and consequently, the success of the treatment. The objective of this study is to determine the acceptable dissolved solid contents for flowback fluids to prepare fracturing fluids.
Analyses of 36 flowback fluid samples from the West Texas region have been collected, and experimental studies were conducted on the analysis of the dissolved solid contents of produced water, which affect the application of flowback fluids and the capability of prepared fluids in proppant transport and handling. A high-pH borate crosslinked guar-based polymer has been picked to determine the ranges of acceptable salt contents. Dynamic viscosity and rheology tests, static proppant settling, and small-amplitude oscillation rheology, were the methods used to evaluate prepared samples at room temperature and medium temperature (225°F).
The results show that some divalent cations such as calcium and magnesium have severe negative effects on the prepared polymers. Calcium is the controlling ion and about 60% of flowback fluids need to be treated to meet the maximum acceptable concentration criteria for these ions. Although monovalent cations such as sodium and potassium were tolerable at higher concentrations and the potassium contents in almost all flowback fluids meet the determined acceptable value, more than 70% of samples need to be treated for high sodium ion concentration. Although the presence of other ions like iron, show no significant variation in fracturing fluid properties, they can affect treatment jobs in special cases. The results comply with the extracted outcomes in SPE 168614 and show that adjusting the concentration of the polymer, buffer, and crosslinker can minimize the effect of temperature and salts. The fluids prepared with the determined ranges of dissolved solids showed reasonable rheological stability and proppant transport characteristics. This paper introduces the practical operating range for produced water content and defines the factors that can adversely impact borate-crosslinked fracturing fluid characteristics at low and medium temperature applications.
Unlocking the Potential of Mexican Offshore Fields through Real-Time Optimized Placement of Carbonate Acidizing Treatments
Authors: Inda Lopez A. , Inda Herrera L. A. , Soto Lopez E. O. , Ramondenc P. , Murillo Vallejo A. L. , Rosado Rivero I. , Worden S. 
Published: June 2014

Abstract
Mexico has long based its strength on the exploitation of its offshore fields to become one of the largest oil producers in the world. Although still yielding most of its production today, those mature fields have entered a downward trend for the past few years, with a gradual decline of their hydrocarbon output. This trend coincided with an increase in work over operations, most of them involving matrix acidizing interventions in carbonate formations for damage removal and stimulation purposes.
Matrix stimulation of offshore Mexico fields presents several challenges, starting with the very nature of the carbonate rocks composing the reservoirs, whose properties can greatly vary within a short distance. In addition, the well conditions are also at times not well understood, with perforated intervals heterogeneously producing, and the increasing occurrence of water production. Finally, due to the location offshore, time-efficiency and operational simplicity became important workover requirements that have a direct impact on the chosen stimulation procedure, often achieved using a simple bullheading sequence, which unfortunately leaves the much needed control of zonal coverage out of the equation.
This paper presents a carbonate acidizing workflow and interpretation method that have been developed and successfully implemented in offshore Mexico over the past couple of years. This technique constitutes the cornerstone to assessing and controlling matrix acidizing treatment coverage while it is pumped, in real-time, to ensure optimum treatment performance and maximum return on costs. The workflow relies on the use of a fiber-optic line enclosed inside a coiled tubing (CT) string to acquire distributed temperature sensing data, which are analyzed and translated into a zonal coverage profile using a fast interpretation algorithm. This information then allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence.
As the case studies presented in this study will show, there is a lot to gain from this improved methodology. In particular, they show that the long-standing blind bullheading practice results in some shortcomings that may be detrimental to truly unlocking the full potential of those offshore fields.
Application of Elastomer More Resistant to Gas in Progressive Cavity Pumps in Boscan Field to Improve Run Life
Authors: Marchan L. , Socorro D. , Concalves E. 
Published: June 2014

Abstract
The Boscán Field, a giant heavy oil field located on land 45 km SW of Maracaibo, Venezuela, was discovered in 1947. It has been operated by a joint venture company called Petroboscan since 2006. It covers an area of approximately 660 km2 with 890 drilled wells and 426 active wells with 10.5 API oil. Since 2001, Progressive Cavity Pumps (PCP's) have proven to be a viable, cost-effective means of production in the Boscan Field. It contributes 23% of the total field production through 134 active PCP wells. PCP systems are the second artificial lift method most used in Boscan field, and include both insert and tubular PCPs. From the beginning of the project, two types of elastomer compounds (NBRA & HNBR) were selected and successfully applied for several years. However, the reservoir pressures in some areas of the field have declined significantly, generating higher GORs, which have resulted in the reduction of PCP run life.
A new challenge was established to improve pump run life by changing the elastomer composition to be more resistant to explosive decompression during well shut-in events. A total of 13 wells with repetitive pump failures due to gas were selected. Crude samples were taken and elastomer compatibility tests were performed. The following step consisted of installing and testing the elastomer in candidate wells. Elastomer #1 was installed in two different wells and showed an improvement in run life from an average of 83 days up to 500 days. Improvement of the run life with elastomer #2 was also significant, from an average run life of 162 days up to 345 days. Based on this experience, the elastomer # 2 was considered to be the most optimal to be used in the field and has been installed on 8 wells with a current run life of 368 days.
This paper will contain the details of the field trial of gas resistant elastomer, and the optimization philosophy used in Boscan, to improve PCP run life in high GOR environments.
Conceptual Study and Evaluation of the DTS-Fiber-Optic System as Monitoring System of Injection-Production Profiles in Conventional Reservoirs: A Colombian Field Application
Authors: Jaimes M. G. , Prada J. A. , Dorado R. , Cornejo E. 
Published: June 2014

Abstract
About 70% of the oil produced today comes from mature fields, which focuses the interest of the industry on these fields, especially when the recovery factor is low (under 30%).
To increase the recovery factor, techniques as water injection can be implemented which also helps to mitigate the environment impact, transforming the water produced from an unwanted to a resource.
Having permanent control over the reservoir when is going through a secondary recovery, requires optimize the processes of displacement and recovery. The monitoring has the power to set the behavior of operational parameters for the optimization of the injection-production operations and to diagnose potential problems, which allow having a specific and a general vision of the process.
The continous monitoring process should be considered from the planning of injection-production system. The technology that provides constant monitoring is the DTS-Fiber Optics System, which allows the generation in real-time of production profiles and come across with more frequently the injection distribution. With the proper interpretation of these logs the following can be achieved: the injection rate optimization, injectivity leak detection, leak control in wells, cross-flow detection, the contribution of each zone in a stratified reservoir, and detection of the water breakthrough in the producer well.
This paper contains a conceptual level study, which presents the working principle, applications worldwide, Benchmarking, benefits, advantages, best technical setup and the correct procedure for implementing the DTS-Fiber Optic system for both a producer and an injector well. Additionally an economic evaluation which compares the DTS-Fiber optic System with conventional monitoring systems currently implemented to generate injection and production profiles in the Yariguí-Cantagallo field in Colombia are presented.
Finally, the main findings, conclusions and recommendations obtained in this study are shown.
Design and Validation of an Improved Shunt Tube System
Authors: Bonner A. , Hailey T. , Veit J. 
Published: June 2014

Abstract
Shunt tube technology to mitigate premature bridging in the annulus while pumping slurry has been used successfully in the oilfield for over two decades to assure complete gravel placement. The systems have been applied in a variety of scenarios including single and multizone completions, cased and openhole completions, and both gravel and frac-pac applications. By deploying a screen system empowered with the slurry bypass mechanisms of a shunt system, an operator usually experienced greater job reliability, a reduced possibility of pack failure, and maximized production.
This paper discusses an improved version of the traditional shunt tube system that has recently been developed by a major engineering and service company to enhance sand screens for gravel packing in long production intervals. The system was designed primarily for gravel packing in horizontal wells and is a system with two larger transport tubes and two smaller packing tubes, all mounted to standard sand screens in an eccentric design. A new seal design improves sealing capability between the joints of screen. By the optimization of the attachment of the tubes to each other, to the rings mounting the system to the screen, and to the sealing fittings at the transport tube ends, the design significantly enhances system capabilities.
Computer flow modeling was used to improve erosion resistance and lower pressure loss by reducing friction at tube connection flow transitions. Extensive test programs to ensure equipment integrity, including torque, tension, and compression capability of major components were used. The system can be assembled more quickly due to the shroud covering the joint connection being an integral component of the screen with no bulky clamshell hinges or pins to be assembled.
The improved pressure sealing, erosion resistance, ruggedness, improved rig assembly times, and system qualification will be presented in the paper.
A Method To Size Gas-Liquid Horizontal Separators Handling Nonstable Multiphase Streams
Authors: Hernandez-Martinez J. L. , Martinez-Ortiz V. 
Published: June 2014

Abstract
The sizing procedures of all the process equipment in oil and gas industry share a common assumption: the stream flowrate measured at the inlet is always constant or stable. This principle works fine for plants where the process conditions are controlled, but it does not apply to primary production facilities where the streams come from multiphase flowlines or wells. In a real horizontal gas-liquid separator, the inlet stream flowrate is not constant and the liquid fraction fluctuates as a function of time. This fact must be considered in the design procedure applied to these units.
The sizing procedure described here allows to size horizontal gas-liquid separators, considering non-stable flowrate at the inlet, or fluctuations in the liquid fraction on the same stream. The method looks for the best unit design to address these variations and also gets the smallest possible horizontal gas-liquid separator.
The proposed method consists of two parts. The first one is solved by a dynamic multiphase flow simulator which allows modeling the multiphase flow in the pipeline and predicting flowrate and liquid fraction fluctuations at the separator inlet. In the second part, the horizontal separator sizing is solved following a modified Svcek and Monnery (1993) method. It is adapted to take into account a non-stable stream at the inlet, using the surge volume calculated by dynamic multiphase simulation. Other well-known methods are also reviewed, such as Arnold (1986). Relationships between the Svcek and Monnery approach and other methods are depicted.
The method is illustrated sizing a gas-light oil separator located in an offshore production facility where the feed stream is identified as non-stable. This behavior is taken into account, and the effect in the vessel volume is numerically evaluated. This approach allows obtaining the smallest separator volume based on dynamic simulation results; as compared to the sizing based on overdesign rules.
The approach depicted here can be applied for sizing horizontal gas-liquid separators in which the dynamic nature of the multiphase flow must be taken into account and the smallest possible volume is desired.