bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Completion with Monobore Technology for Gas Production in the B6 LL 370 Reservoir in the Tia Juana Field, Lake Maracaibo, Venezuela
Authors: Mieres K. R. , Prieto V. , Banzer C. , Molina F. 
Published: November 2015

Abstract
The new opportunities of gas in western project (PNOGO for its acronym in spanish) is looking for new technologies to improve the efficiency of the exploration and production of gas reserves, in order to assure start-up and operational continuity of Ana Maria Campos Petrochemical Complex located in Zulia state. In view of this, it became necessary to evaluate the feasibility of building wells using monobore completion technology especially in the B6 LL 370 reservoir located in Tia Juana Field, Lake Maracaibo. Designing a monobore completion involves the construction of a wellbore whose internal diameter of the completion string is the same size from top to bottom. This type of completion has shown that this technique is feasible for the production of gas due to has yielded excellent results worldwide. The premises used for the selection of this completion were based on a review of geological, geophysical, petrophysical and reservoir characteristics, as porosity, permeability, well location in the structure of the reservoir, fluid production risk, among other features. Furthermore, production analysis and economic evaluations stablishing the new completion design. During this project, two wells have been drilled with this type of completion in this field whose diameter production casing was 5-1/2". The results indicate an average gas production of 5.6 million standard cubic feet per day (MMscfd) compared to conventional wells whose output is 1.7 MMscfd in the same reservoir. The decrease in the construction cost and operating time was 30% and 28%, respectively. The results show that using the technique of monobore completion is feasible and economically viable in the construction of wells in the B6 LL 370 reservoir.
Fast Wash Tank Design Algorithm for Early Production Facilities (EPF)
Authors: Reina E. , Vargas L. , Romo N. , Venegas H. , Delgado P. 
Published: November 2015

Abstract
An algorithm has been evaluated to offer a fast and simple design of a primary crude dehydration system consisting of a low capacity wash tank train, installed as Early Production Facilities (EPF) to achieve a crude oil specification not greater than 0.5% Basic Sediment and Water (BS&W) with average water cut at inlet of 30%.
The estimation method allows to perform routine calculations to determine the crude oil residence time available for water separation inside the equipment, water droplet diameter and water cut within the oil pad at different heights using a short-circuit factor (F) always greater than 1. As a result, short-circuit factor of 1.4 is verified to be a good value to ensure separation of phases in low-capacity tanks. In addition, tank dimensions are given based on API-12F specification for a nominal capacity of 500 bbl. for the 12 ft diameter and 25 ft height. Moreover, the designer must take into account different tank internal configurations to improve its efficiency.
Different dehydration configuration can be arranged using 500 bbl. low-capacity wash tanks installed in series. One (01) train consists of two (02) wash tanks, and as the required processing fluid capacity is higher, similar trains in parallel must be added to increase the dehydration system throughput.
Retention time and settling theory were used and applied to the system described above and determining that the oil quality is related to the maximum size of water drops carried-out over O/W interface and being smaller as the oil reaches the outlet connection which is close to the top of the tank. These sizing techniques allowed the BS&W and water droplet diameter being estimated as a function of the oil-column height, residence time and temperature.
Different effective heights through the wash tank oil pad are checked at various operational temperatures which allow the dispersed water droplets to settle out from the oil with different velocities and, hence, being able to evaluate several water cuts (%BS&W). EPF conformed by two trains of 4 low-capacity tanks each; working in parallel, provided a processing capacity of 12000 BFPD to meet a desired 0.5 %BS&W specification for given oil and water physical properties. Initial investment, operational costs and implementation time were favourably reduced during the early production stage until the permanent facilities were installed, thereby avoiding sophisticated technologies that could result in expensive and late industrial project deployments.
Well Production Performance in a Deviated ICD Completion: Case Study with Analogous Cased and Perforated Wells. Villano Field - Ecuador
Authors: Correa Ramon , Andrade Alejandro , Ippoliti Massimo 
Published: November 2015

Abstract
This paper aims to show the behavior of a 66° deviated well completed with Inflow Control Devices (ICD) after 5 years of production, making a comparison with two analogous wells that have a standard Casing and Perforated completion (C&P). At that time, this type of installation (2011) was the first case in Latin-America. The study is complemented with the performance of two ICD installed in parallel with two horizontal wells.
The analysis describes the ICDs completion for a deviated well, the reasons why the well was completed in this manner and the production results obtained for three wells (1 ICD and 2 C&P) using elapsed time comparisons. The analysis considered the historical Water Cut (WC), the Productivity Index (PI), and Fluid Performance (Oil and Water). Furthermore the use of diagnostic plots to identify the water production mechanism taking into accounts the main facility (water treatment) constraints during the production of the wells.
The deviated ICD completion allowed a Water Cut reduction of at least 10% after 5 years of production, delaying the premature water channeling with an positive reserve impact compared with analogous C&P wells. Moreover this type of completion provides a new way to complete deviated wells, with more than a 45° angle, where the quality of the initial cementation job is doubtful.
Unlocking a Mature Field Reservoir Potential through Optimized Fit-for-Purpose Hydraulic Fracturing
Authors: Ramones M. , Gutierrez L. , Moran M. 
Published: November 2015

Abstract
Production and recoverable reserves of mature oilfields can be increased through the application of Production enhancement and optimization techniques. In the Napo reservoir, where an important percentage of the total production comes from highly depleted sands with moderate permeability and high clay contents, the implementation of hydraulic fracturing stimulation, with the simple objective of skin by-pass is generally accepted, however the production performance and decline after these conventional treatments is not optimal, due to subsequent fracture conductivity impairment caused by clay and fines migration issues, which is the primary formation damage mechanism. For this reservoir, with a clearly identified damage mechanism combined with moderate permeability and significantly low reservoir pressure gradients (down to 0.1 psi/ft) a fit-for-purpose strategy to successfully stimulate and obtain sustained production was required.
A xthorough multidisciplinary study and well screening was carried out to identify the best candidates. This task incorporated petro-physical, stratigraphic, completion and production history analysis, as well as enhanced Hydraulic Fracturing modeling for dedicated optimum fracture geometry and treating fluid selection. The study presented on this paper shows the workflow followed of the candidate selection, treatment design, execution and the post-job evaluation and validation methodology implemented on the campaign. Also, well testing before and after stimulation treatments had enabled the validation of the strategy, followed by production monitoring.
After 14 months of production it has been proven that this production enhancement strategy has achieved sustained production, with an average production increase of 350% and average post-frac skin values of -3. The post stimulation production conditions have had a positive effect on the run life of electro submergible pumps and the reduction of workover operations.
On Parahuacu and Guanta fields the achievement of a sustained production optimization through the application of a fit-for-purpose hydraulic fracturing strategy has unlocked the reservoir potential, quantifying an incremental production in excess of 390,000 bopd during 14 months after the hydraulic fracturing campaign. After 14 months of the campaign start-up, 990 bopd of incremental production associated to the Hydraulic Fracturing activity, Represents on average 30% the total field production, proving the effectiveness of this technique which is now part of the asset's production optimization strategy.
A Finite Horizontal-Well-Conductivity Model for Pressure Transient Analysis in Multiple Fractured Horizontal Wells
Authors: Chen Z. , Liao X. , Zhao X. , Dou X. , Huang C. , Chen Y. , Li L. , Guo X. 
Published: November 2015

Abstract
In this paper, a novel model was proposed for pressure transient analysis in multiple fractured horizontal wells (MFHW) with consideration of pressure loss within the wellbore. To facilitate solution of this problem, the whole system was divided into (1) reservoir subsystem, (2) fracture subsystem, and (3) wellbore subsystem. Incorporating with frictional and acceleration pressure drops, a mathematical model with finite horizontal well conductivity (HWC) was established. Employing Laplace transform, the mathematical model was solved. Transient pressure solutions of MFHW were acquired using Stehfest numerical inversion. Model validation was carried out by comparing with simplified cases in literatures. Case study and sensitivity analysis were conducted based on a real case from the Ordos Basin.
The case study strongly shows that when ignoring the wellbore hydraulics, errors could be caused during the performance forecast. Results of sensitivity analysis show that, the dimensionless wellbore pressure of MFHW increases with the increase of Reynolds number; it decreases with the increase of reservoir-wellbore constant. The effect of pressure loss on pressure performance of MFHW will be exaggerated by increasing Reynolds number, or decreasing reservoir-wellbore constant.
Assessment of Different Artificial Lift Methods To Optimize Production Within the Paraiso Oilfield in Ecuador
Authors: Fructuoso T. N. , Suarez-Bastidas S. , Cueva D. 
Published: November 2015

Abstract
Assessment of the original artificial lift systems installed in place to determine better means to produce the existing assets and thus looking for ways to optimize and reduce lifting costs for the operator. Reciprocating rod lift systems with ultra long stroke mechanical pumping units were recommended and implemented to help achieve the desired flow rates.
The existing artificial lift equipment was evaluated to determine if a more suitable alternative could be designed for the flow rates and depth encountered at the assets. This alternative included the use of reciprocating rod lift systems with an ultra-long stroke pumping unit, high strength sucker rods, custom tailored rod pump for the application, and automation equipment to match well inflow to displacement capacity throughout the pumping cycle.
Three wells were converted from previous installations with hydraulic lift systems to ultra-long stroke reciprocating rod lift systems. Among the observed results upon the conversions were completed were: Reduced power consumption therefore a minor lifting cost per barrel, reduced work over costs due to nature of the interventions, and reduced surveillance expense with the use of automation equipment allowing the operator to monitor the wells remotely.
The ultra-long stroke reciprocating rod lift systems increased the lifting efficiency, reduced production costs, and provided the operator with more flexibility for producing their asset.
Oglan 2 Dir Well: A Successful Exploratory Project With Heli-Portable Logistics – The Role of Integration in Reaching the Goals
Authors: Atahualpa G. , Venturino G. , Zerpa E. , Correa R. , Guleryuzlu M. T. , Telles J. , Morán S. 
Published: November 2015

Abstract
Drilling an exploratory well in highly sensitive environments imposes a number of challenges for an Oil Company. One of these challenges is to provide Heli-portable logistic coordination to achieve a successful drilled well in the most cost/time effective manner keeping in mind that hundreds of people, equipment, supplies and fuel have to be transported to and from the rig in the safest way1. The solution implemented is based on the proven concept of integration of services. In this case, the methodology was adapted to the condition of the remote location with heli-portable logistics, in which the key factors are Logistics, managed by the Operator and Service Companies, shared Drilling Engineering, Risk Management, identification and selection of new technologies and pre-defined communication and responsibilities flowchart among Operator, Service Companies and Rig Contractor.
The initial time planned for the exploratory Oglan 2 Dir well was P-10: 32.7 days, P-50: 37.4 days and P-90: 49 days with an initial estimated NPT &lt; 15%. The total duration of the well was 38.1 days, with an NPT of 15% due to operational difficulties encountered while acquiring downhole data and other operational events; however, 0% NPT was related to heli-portable logistics. Pre-established communication and responsibilities flowchart together with risk management allowed the achievement of goals and targets: coring 220 feet of Hollín Formation (main well target), acquire LWD on all the section and WL open hole logs in 81/2" section and, the most relevant goal, take fluid samples from Hollin and Napo Formations using a Saturn Tool.
This methodology and concepts can be used as a guide for any heli-portable and/or remote operations with a pre- defined management and communication workflow among Operator, Service Companies and Rig Contractor reaching the main goal to meet AFE time and cost.
Re-grading Proven Reserves with PRMS
Authors: Harrison Bob , Senergy LR , Falcone Gioia 
Published: November 2015

Abstract
The Petroleum Resources Management System (PRMS) is a project based framework that classifies and categorizes a project's resources based on their likely commerciality and recoverability. The path from prospective resource to reserves is inferred to be ‘one way’, as re-grading proven reserves is considered a "rare event", but evidence suggests reclassification decisions are more commonplace.
According to PRMS, reserves should only be downgraded if there is "an unforeseeable event that is beyond the control of the company … that causes development activities to be delayed beyond a reasonable time frame". This rather loose definition allows companies to interpret the meaning quite differently. Some choose to leave ‘under threat’ reserves as booked, by claiming the projects are subject to force majeure that might adversely affect their commerciality. Others downgrade such reserves to contingent resources, at least until the critical contingency is removed and the volumes return to the higher class.
Two case studies involving reserves re-grading are given to highlight the applicability (or not) of PRMS to politically unstable areas and mature provinces, respectively. The first example from the Middle East tells how continued civil conflict and international sanctions has led shareholders to invest elsewhere, so that some operators have reclassified reserves. The second example tells how a North Sea operator, responding to pressure from government and partners, initiated a remedial program to get an asset back on stream, and in so doing allowed reserves to remain booked.
Decisions over whether or not to re-grade proven reserves are more prevalent than implied in the PRMS. Consideration should be given to amending the PRMS guidelines to reflect this observation.
Implementation and Performance of a Heavy Oil Pilot in Atacapi Field, Ecuador
Authors: Ramirez J. , Hoffmann M. , Izurieta C. , Podeley M. , Carrera O. , Lasluiza H. 
Published: November 2015

Abstract
A methodology was implemented to produce and transport heavy oil (12° API) from Basal Tena Formation in Libertador and Atacapi Fields, in a profitable way.
Before implementing the pilot project in January 2015, not a single well was producing from Basal Tena Formation in the southern part of Libertador and Atacapi Fields. Furthermore, commingled production is not allowed by the authorities unless reliable production allocation is guaranteed. The pilot project consists in mixing oil from two formations with different fluid characteristics in the wellbore. The heavier oil is combined with lighter oil, which works as a diluent; this process renders a blend suitable for production by submersible pump system and transport through pipelines. Both formations were tested and their fluids were characterized independently before starting commingled production.
Oil from Basal Tena Formation has an API gravity of 12° and a viscosity of 260 cP at reservoir conditions. The pilot shows that it is possible to produce, transport and quantify it after dilution; in this case 35° API oil diluent is produced from Napo T formation. Almost seven months after implementing the pilot, oil from both formations is still being produced, despite the fact that diluent contribution rate is not constant, as the production of the Napo T formation is declining because of water breakthrough. The key variable observed to quantify the production from each formation is the specific gravity of the produced blend.
Because of its success, this pilot is the first step towards the future development of these accumulations of oil in the Basal Tena Formation, not feasible without implementing a more expensive method, until now. This simple approach can be repeated in other areas in Oriente Basin.
Use of Banana Peel Based Filters to Reduce Heavy Metals in Wastewater
Authors: Palacios Adrian 
Published: November 2015

Abstract
Determine the filtration levels of banana peel to reduce heavy metals in wastewater —coming from drill pipe washing— including barium, cadmium, chromium, lead, nickel, and vanadium. The water used for this study was intentionally contaminated with high concentrations of the metals in a laboratory accredited by the Ecuadorian Accreditation Organization (OAE).
The moisture of the banana peel was determined through a compositional analysis. Then three methods were used to dehydrate them (sterilizer, sun radiation and ovens) to identify the most effective one to pulverize the peel and place them inside the filter, since the objective was to obtain a porous medium (filter) through which the contaminated water could circulate smoothly.
The peel of an average size banana weighs about 50 g. After being dehydrated at a temperature of 60° C, using a sterilizer (Autoclave), it was possible to obtain around 10 g of micropulverized shell, which can decontaminate 0.5 liters of water. By using 10 ml of micropulverized shell to filter a liter of contaminated water with heavy metals, it was possible to observe a 70% reduction in Barium, 93.62% in Cadmium, 90.99% in Lead, 93.82% in Nickel, and 65.52 % in Vanadium.
The implementation of a banana peel based filter on treatment systems for industrial wastewater can effectively reduce heavy metals and even exceed the results of conventional filter methods, such as activated carbon, which reduces the levels of these metals by approximately 65%.
Computed Tomography for Petrophysical Characterization of Highly Heterogeneous Reservoir Rock
Authors: Skinner James T. , Tovar Francisco D. , Schechter David S. 
Published: November 2015

Abstract
A correlation between Computed Tomography (CT) number, matrix porosity, and permeability is presented that enables the petrophysical characterization of highly heterogeneous reservoir rocks with a level of detail that is not achievable by direct laboratory measurements. A total of 143 ft. of 4 in. diameter reservoir core from the North Burbank Unit (NBU) in Oklahoma were imaged using a state of the art medical computed tomography scanner. The CT number, which is a function of the density and composition of the rock was observed to correlate with both porosity and permeability values that were measured discretely along the core using conventional laboratory techniques. A mathematical expression was fit to the data that allows the prediction of the porosity and the permeability of the core within the 350 µm isotropic resolution that the CT scanning unit is capable of.
We also show that in the case of reservoirs with high vertical heterogeneity, where permeability variations of hundreds of millidarcies occur within one foot, the selection by visual inspection of core plugs for laboratory measurement of petrophysical properties leads to a flawed characterization of the stratigraphic column as some of the plugs are taken along bedding planes, and therefore are comprised of more than one rock type. We propose the use of CT-scan imaging to identify different rock types and take core plugs that are representative of unique rock types as a better practice for rock characterization.
Our work has greatly improved the knowledge of the stratigraphic column of the NBU and has provided a better understanding of the degree of vertical heterogeneity in the area. The detailed knowledge of permeability and porosity obtained from the CT numbers of the cored well can be used for the adjustment of petrophysical models based on well logs to enable the extrapolation of the detailed petrophysical characterization of the cored well to other NBU wells that have not been cored but have log data. The implementation of the proposed technique will help optimize well completion, sand perforation, water and gas shut off treatments, and EOR schemes implementation among other activities.
Reliability Reduction of the General Electric Turbines Due to Incompatibility Issues Between the Fuel and the Biocide
Authors: Ibujés-Flores P. M. , Eguiguren-Gutierrez F. 
Published: November 2015

Abstract
In 2013, there were situations that altered the normal operation of the turbines, attributed mainly to the fuel used (diesel) that is produced in the "Topping" atmospheric distillation plant located in the Northern Production Facility (NPF).
There is evidence that there is a continuous presence of significant amounts of highly viscous substances throughout the diesel system that feeds the General Electric turbines located in the oil separation plants of the NPF and the oil re-pumping station of Shushufindi.
Diesel from the "Topping" plant receives a monthly biocide chemical treatment against fungi and bacteria in storage tanks. However, agents such as moisture and oxygen have interacted with minority compounds (0.024% S and 0.015% P) of the biocide, producing highly viscous substances.
High viscosity substances resulting from oxidation and polymerization reactions in the aqueous phase formed from sulfur and phosphorus compounds cause clogging of the control valves of fuel entrance to the injectors, thus, reducing the reliability and availability of the turbine.
Based on the analysis performed, it was determined that the cause of the generation of highly viscous substances was the monthly dosages of biocide in the storage tanks of diesel (300 and 476 mg/l). To solve this problem, the dosage of biocide has a conditional restriction, i.e., whenever the proliferation of fungi and bacteria reach 103 and 104 col/ml, respectively, in the tanks, the biocide is added.
As a result, the availability of the turbines in NPF (General Electric) and Shushufindi (Solar) increased from 96.51% and 97.98% to 100.00% and 99.53% respectively.