bluuebunny/crossref_metadata_2025_split huggingface dataset:
Channeling Identification: A Routine Surveillance Exercise for Successful Waterflooding Management in Casabe Alliance
Authors: Mora G. , Bonfanti B. , Porlles J. , Casas J. , Agudelo O. 
Published: June 2016

Abstract
The sedimentary environment in Casabe field is a complex continental-fluvial deposit conformed by numerous stacked sandstone reservoirs intercalated with shales with high lateral and vertical heterogeneity. In that conditions Casabe has been under Waterflooding for 30 years with successful results due to an efficient vertical and areal sweep achieved through selective injection.
The successful in production increment also bring us a huge increment in produced water in a ratio of 1 BOPD to 6 BWPD. But, we notice that there where patterns with more than 90% of BSW in between of patterns below than 70% of BSW. Considering additional arguments evidence lead us to rethink our vertical distribution.
With the water channeling identification in mind our reservoir surveillance process was adjust going further in layer by layer analysis from the production-injection balance and the pore volume displaced to get an indicator of where water is going in order to come with a general or localized solution. All the analysis required gather and integrate information from tools like inter well tracers, PLTs, swabbing by layers, saturation logs, time lapse resistivity logs, and cement logs where there was an opportunity to run the tools.
After the identification of water recirculation (Bad Water) in zones with high permeability the immediate action to stop water recirculation and reduce produced water was blocking zones in 1) Producers: Water shut off and/or 2) Injectors.
In the long term, a more comprehensive solution for water channeling will be Water Conformance as the saturation logs shows there is still oil in those layers.
The results of the work done in 21 production wells was the reduction of produced water up to 300 BWPD per well achieving water cuts lower than 80%. Additionally and more important was the increment in oil production observed in the same wells as a consequence of vertical swept efficiency improved.
Proppant Management: A New Challenge to Develop Unconventional Reservoirs in Argentina
Authors: Bonapace J. C. 
Published: June 2016

Abstract
Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs; it is well known that constructing an economic well in this type of formation is very challenging. In the last 15 years, exploration and development of unconventional reservoirs (tight gas) has been initiated. Over the past 5 years, the main target in Argentina has been located in the Vaca Muerta shale, which is one of the main source rocks in Argentina. Such a development challenge requires one to develop a fast learning curve to more quickly achieve economic wells. This type of completion and stimulation involves vast amounts of water, proppant, chemicals, and special equipment, coupled with continuous improvements in operations, quality, cost, time, and safety. Various alternatives in proppant management were explored and introduced. This paper describes several aspects related to stimulation of different tight formations and shales in Argentina, including proppant selection, supply chain, logistics, new storage systems, and laboratory studies performed on local white sand. The focus will be on these key aspects: Stimulation: information about proppant type, amount, and size for hydraulic fracturing performed in several tight and shale formations in Argentina with more details of the Vaca Muerta formation.Logistics and supply chain: improvements introduced from transportation, storage, and handling of proppant, including the evolution process over the last few years, from centralized storage sites to the wellsite.Laboratory: several samples of white sand procured from different parts of Argentina were evaluated to be used in hydraulic fracturing. API and ISO standards were used for qualifying tests including specific gravity (SG), bulk density, acid solubility, turbidity, sphericity, roundness, sieve analysis, and crush strength.
A Comprehensive Model for Performance Forecast of Multiple Fractured Horizontal Well in Unconventional Reservoirs: A Case Study
Authors: Chen Z. M. , Liao X. W. , Zhao X. L. , Liu H. M. , Tian J. , Zhu L. T. , Wang L. , Zhao H. J. 
Published: June 2016

Abstract
Performance forecast of multiple fractured horizontal well (MFHW) becomes a hotspot in the development of shale gas (SG) reservoirs. Due to geological and engineering factors, there exists complex mechanisms including stress-sensitivity effect, diffusion flow, gas desorption, finite fracture conductivity, and wellbore hydraulics. However, little work has been done to focus on these complex mechanisms simultaneously.
To comprehensively study this issue, a more comprehensive model was proposed in this paper. In this model, some aspects were all considered: (1) flow mechanisms of viscous flow, slip flow, transition flow, and Knudsen flow, (2) gas desorption and diffusion flow, (3) stress-sensitivity effect of permeability, and (4) wellbore hydraulics in the horizontal wellbore. The first part of this paper was model development and solution. During this process, model was developed based on the flow mechanisms of SG and its solution was obtained by applying a semi-analytical method. The second part involves model validation and case study. To verify the model, the results from the proposed model were compared with those from a commercial software, KAPPA Ecrin. After model validation, based on a real case from the Sichuan Basin, type-curve matching and parameter estimations were conducted using the proposed model.
This study further narrows the gap between theory and practice of performance predictions for MFHW in SG reservoirs.
Evaluation and Optimization of Oil Wells on Plunger Lift in the Main Soldado Field Offshore the Southwest Coast of Trinidad
Authors: Mohammed S. K. , Hosein R. 
Published: June 2016

Abstract
Plunger lift is a well-known artificial lift technique originally developed for the de-liquefaction of gas wells. However its use has been extended to include high Gas – Oil Ratio (GOR) oil wells, those with low or no production due to paraffin and scale deposits and wells with high or fluctuating sales line pressures. It is an intermittent production technique that utilizes reservoir energy stored in the gas phase to lift oil from the bottom of the well to surface via the vertical cyclic action of a "pigging" device within the tubing. This action enhances the production performance of liquid loaded wells.
In this study, plunger lift systems on two wells were evaluated to determine well performance and to optimize production rates if plunger lift systems were to be installed on other wells. Casing and tubing pressure trends were used to identify operational deficiencies and causes. Vogel's model was used to model the inflow performance relationship using bottom-hole pressure data. The Foss and Gaul model for plunger lift operation was used to determine production rates and gas requirement for each well in order to optimize well performance. The mode of operation with the current settings (long after-flow periods and over-estimation of plunger fall back time) is representative of intermittent lift with the assistance of a plunger rather than gas assisted plunger lift operation. The GOR for both wells are too low for efficient operation and a model of the current settings indicates that a gas injection rate of 450 MSCF/D is required to obtain an optimum oil production rate of 103 bopd. These plunger lift systems also prevent paraffin accumulations in the production tubing of these two wells.
New plunger lift operating variables such as casing valve opening and closing time, gas injection rate, after flow time, plunger rise velocity and fallback time, flow-line motor valve cycle time and number of cycles per day were modeled to obtain an optimum oil production rate. The results showed that a gas injection rate of 173 MSCF/D is required to obtain an oil production rate of 195 BOPD for a plunger rise velocity between 800 to 1000 ft/min. For these new settings the gas requirement was reduced by 61 % and the oil production increased by 89 %. These results indicate that the modification of the operating variables can effectively optimize gas assisted plunger lift systems that are installed in the oil wells producing from the Cruse Formation in the Main Soldado field offshore the Southwest coast of Trinidad.
Effective Flare and Vent Management
Authors: Siu J. , Perseval A. 
Published: June 2016

Abstract
As the world reacts to a low commodity and oil price markets, energy companies are forced to seek more efficient ways of operating. This paper addresses the impacts of improperly managed gas disposal systems including lost revenue potential as well as the contribution to greenhouse gas emissions. It is tailored to the energy industry of Trinidad and Tobago which aims to achieve a reduction in overall emissions by 15% by 2030 from BAU (Business As Usual baseline) under the UN Framework Convention on Climate Change.
The study highlights and evaluates the major opportunities for emissions reduction including, but not limited to, conversion from cold vents to flares, implementation of hybrid flare-vent systems, conversion from natural gas to inert gas purge systems and proper monitoring and optimization of flaring rates. Supporting calculations and case studies are based on actual and theoretical data (from mass balances or otherwise) from local oil and gas operators.
The lack of reliable measurement data and trends for flare volumes was indicative of an industry that has grown callous to wastefulness. Findings revealed that significant value can be extracted through modest monitoring improvement projects, optimization of existing operations and increased operator conscientiousness.
A Model-Based Production Strategy Selection Considering Polymer Flooding in Heavy Oil Field Development
Authors: Botechia V. E. , Correia M. G. , Schiozer D. J. 
Published: June 2016

Abstract
Polymer flooding is a chemical EOR technique in which polymer is added to injection water, increasing its viscosity, decreasing water-oil mobility ratio and hence improving sweep efficiency. This recovery method create unique conditions that are absent in traditional water flooding, which makes an adequate production strategy essential to the success of the project. This work is part of a complete decision analysis process with polymer flooding and the objective here is to present a methodology for production strategy selection considering water and polymer flooding as recovery mechanism options in heavy oil reservoir, guiding the decision maker to have an accurate tool to compare water and polymer flooding strategies and decide which one is the best option in determined project, using numerical simulation and economic analysis. The methodology is divided in seven steps based on variable hierarchy. The optimization process aims the maximization of NPV and the variables optimized are: number and location of wells, production systems capabilities, schedule of well drilling, production and injection rates, economic water cut limit for well shutdown, polymer concentration and slug size. The application of the methodology is made in a model that represents an offshore heavy oil Brazilian field. For comparison purposes, the methodology is also applied considering water flooding as recovery mechanism. The results show the feasibility in applying polymer flooding in early heavy oil field development with better economic return than water flooding. Moreover, this work shows the importance of applying the process separately for water and polymer flooding, otherwise wrong decisions can be made if simple comparisons are performed.
Comprehensive Approach of Reservoir Characterization has Allowed Successful Stimulation of Sandstone Formations in Bachaquero Field-Lake Maracaibo, Venezuela
Authors: Schmid Werner , Martin Alberto , Palacios Jinna Marcela 
Published: June 2016

Abstract
Oil exploitation in the Bachaquero field in east Maracaibo Lake has been occurring for more than 50 years. Sandstone is the primary formation type, and nonconsolidated and poorly consolidated sands are common in this field. Complex mineralogy and fines migration have become root causes of production decline and formation damage. This paper describes a comprehensive approach to reservoir characterization that has contributed to the successful stimulation of the sandstone formations in the field.
Chemical stimulation, specifically matrix acidizing with hydrofluoric (HF) acid systems that are customized and tailored to reservoir characteristics, has proven to be effective at enhancing production in this field. The types of clays that are present include kaolinite, illite, smectite, chlorite, and mixed-layer clays; feldspars are also present. An adequate analysis of each well helps to ensure that HF acid dissolves the clays to restore permeability without promoting nonsoluble fluorosilicates precipitation through reactions with aluminosilicates. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The high presence of feldspars requires more conservative treatments to avoid undesirable precipitations.
Reservoir characterization and fluid tailoring has helped ensure treatment success, but other good practices also have been applied to help achieve production goals. The stimulation treatment design includes pumping formation-conditioning fluids before and after the main acid; using different types of organic solvents to dissolve asphaltene deposits in the well; performing near-wellbore (NWB), hydrochloric (HCl) acid, and HCl/organic acid blend preflushes and post-flushes to treat calcium carbonate and control the pH and iron precipitation in the reservoir; achieving short-term clay inhibition and long-term clay stabilization; and using other fluids, such as relative permeability modifiers (RPMs) for water-control applications and diversion of treatment in laminar reservoirs with petrophysical heterogeneities. All of these combined practices have resulted in successful stimulation of the field.
This paper discusses in detail this comprehensive approach to reservoir characterization applied successfully in wells in the Bachaquero field. The workflow includes candidate analysis, from reservoir description and mineralogy and formation damage mechanism identification to stimulation treatment design, laboratory fluid systems tailoring, placement and diversion techniques, pretreatment operational task fulfillment, field execution, quality control, and post-job evaluation through analysis of records and statistics.
Comparison of Primary, Secondary and Tertiary Polymer Flood in Heavy Oil - Field Results
Authors: Delamaide Eric 
Published: June 2016

Abstract
Polymer flooding is an Enhanced Oil Recovery process usually employed in tertiary mode, after a waterflood. However, in heavy oil reservoirs the process is also commonly employed either in primary or secondary conditions because waterflooding is not considered to be economic. For new projects the question often arises as to whether it is better to start by injecting water or to go straight to polymer injection. Injecting water first provides a baseline for comparison with the polymer flood and in some cases allows an earlier start-up of the project due to the construction and commissioning of polymer mixing facilities. On the other hand, the risk is that water channeling could occur and could be irreversible, thus reducing the potential recovery during polymer injection.
Some authors have reported laboratory studies comparing the different methods but so far there has been no field results published that could be used for validation or guidance. Although several polymer flood projects in heavy oil have been reported in the past few years they are still relatively few and no detailed field results have been reported to date on that issue.
The largest polymer flood in heavy oil is currently being implemented in the Pelican Lake field in Canada, with several hundreds of horizontal wells injecting polymer. All the methods - primary, secondary and tertiary - have been tested and as a result the field provides a large database that allows to compare recovery and other parameters for each method.
Although such a comparison is mostly focused on a single field and is thus inherently biased, it should provide useful guidelines for companies looking to start new pilots or field projects. Relevant literature on this topic will also be reviewed to present a complete review of the issue.
Conceptualizing an Improved Oil Recovery Master Plan for Trinidad & Tobago
Authors: Sinanan B. , Evans D. , Budri M. 
Published: June 2016

Abstract
Trinidad and Tobago has been an oil producer for over a hundred years. The land based production has historically been the spine of the energy sector. Many changes in reservoir management philosophies, with respect to improved oil recovery techniques (IOR), in the past, can be pegged to economic ramifications, global market issues and technological practicality. What is for certain is that these issues will always have a cyclical presence, but should not be a deterrent in planning the role-out of IOR projects when the market conditions are right. During periods of low oil prices, when capital spending is usually at its lowest, is an opportune time to reassess how to treat with IOR projects. This paper provides an insight into the planning process which can be used as an instigating tool to create an IOR master plan for the land based acreage of Trinidad.
Adding reserves is the ultimate objective but this can be only realized with fit-for-purpose planning and a multidisciplinary coordination of data. The first phase, which this paper addresses, will consider a local historical IOR review, candidate selection with reservoir and technology commentary. These activities would form the basis to drive the first phase action items and spur a second phase of study which would address costs, procurement, execution, KPI monitoring, safety and environment, logistics, risks, contracts, success definitions, approvals, fiscal allowances, technology providers and team building requirements.
Conceptualizing the first phase of a master plan was conducted through data mining, report reviews, interviews and simulation modeling. This paper answers, in brief explanations, the experiences of the past and the methods of the future. Technology identification and application seems to be the principle guide that the reservoir management process needs to consider in developing an IOR master plan for Trinidad's onshore oil fields. An onshore IOR master plan would eventually serve as a manual that strives for an effective and structured manner of exploiting mature fields, regardless of changes in management or management philosophies. The guidance offered within should form the basis or foundation of an eventual master plan.
Effect of Confinement on Gas and Oil Relative Permeability During CO2 Flooding in Tight Oil Reservoirs
Authors: Zhang Kai , Seetahal Steve , Alexander David , Lv Jiateng , Hu Yi , Lu Xueying , Zhang Dingbang , Wu Keliu , Chen Zhangxin 
Published: June 2016

Abstract
For Cardium tight sandstone reservoir and Monteny liquid rich shale reservoir, horizontal well with multi-stage hydraulic fracturing is applied to develop the oil underground. However, Primary recovery of tight oil reservoirs is still low even with horizontal wells and massive hydraulic fracturing. A CO2 flooding process is regarded as a promising technique for improving tight oil recovery. However, the gas-oil relative permeability during CO2 injection is not fully understood because the nanoscale pore confinement in tight oil reservoirs alters phase behavior of the reservoir fluid.
In this paper, the effect of confinement on gas and oil phase behavior is investigated. Afterwards, the gas-oil interfacial tension and solubility parameter are analyzed, resulting in an alteration in relative permeability during CO2 injection without and with hysteresis. Results show that the relative permeability of oil and gas can be further increased by the confinement effect during CO2 flooding as the interfacial tension of gas-oil can be further decreased in a nanoscale pore. Furthermore, miscibility is enhanced by the confinement effect as the solubility parameters difference between oil and gas decreases. It is consistent with the reduction in gas-oil interfacial tension. In addition, the gas phase trapping caused by hysteresis effect is weakened by the confinement effect, resulting in a lower critical gas saturation and a better oil production during CO2 injection.
Impact of the Use of Intelligent Wells on the Evaluation of Oilfield Development and Production Strategy
Authors: Barreto C. E. , Gaspar A. T. , Schiozer D. J. 
Published: June 2016

Abstract
Intelligent wells are widely used around the world and they have the potential to significantly improve oil production or control water production of wells and fields. However, in many cases, the definition of the number and position of valves is still made considering only the well without evaluating if the decision to use them can change other important aspects of the production strategy. This article presents a study to evaluate some relevant aspects of the inclusion of intelligent wells in a more global study of production strategy selection. Such inclusion is an important step in the precise evaluation of the benefits of intelligent valves. The methodology comprises the economic optimization of a production strategy under different limits of platform flow capacity, the optimization of the number and position of valves (intelligent wells), including and excluding conventional well operation. This study was applied to the UNISIM-I-D benchmark case, starting with a previously optimized production strategy, regarding type, number and position of wells, well-opening sequence and platform flow capacity in 9 different geological scenarios. The optimization methodology uses a complex workflow to test different strategy alternatives using a genetic algorithm and a methodology to optimize the number and position of valves. We showed that the use of intelligent wells can significantly alter the water flow capacity and the operational design of wells. However, for this specific case, the use of intelligent wells was not able to modify oil production and water injection flow capacity. Intelligent well application was viable for 7 out of 9 geological scenarios with the number of valves varying from 1 to 14. The intelligent-well application improved the total NPV from 0% to 1.5%. The platform water flow capacity could be reduced by at least 30% if intelligent valves were implemented. These results are quite different when a less precise optimization methodology is applied, yielding an overestimation of an intelligent well. To conclude, the application of intelligent wells was viable for most of the scenarios. Although intelligent wells present low impact on NPV, they can modify the design of platform capacity significantly. This fact suggests that the optimization of intelligent wells must be combined with the optimization of the platform water flow capacity and the conventional well operation optimization. This work provides important information for reservoir engineers who use reservoir simulation to optimize production strategy. Currently, in many cases, intelligent wells are only evaluated after the selection of the platform design. We have proved that the combined optimization can yield a different production strategy design. In addition, we have also proved that the evaluation of intelligent wells viability without an adequate optimization of conventional well operation overestimated the number and the value of valves.