bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methodology of Feasibility Study on Pilot Test for Dump Flood Completion System
Authors: Villarroel A. J. , Nieto Miño M. D. , Estrella K. I. , Perez J. A. 
Published: November 2015

Abstract
The "dump flood completion" (DFC) is a mechanism conceived to inject water from a reservoir with an active aquifer into a depleted reservoir using a drilled well with marginal production or closed due to low pressure. This innovative mechanism allows for saving the costs of drilling an injector well as well as expenses associated to building additional surface facilities, and water treatment procedures.
This study includes using dynamic models to evaluate scenarios linked to different DFC schemes, with the goal of increasing the net present value (NPV), while maintaining/increasing pressure in the reservoir.
A multidisciplinary team developed a detailed static model to better represent within the dynamic model, the sedimentary bodies dimensions, fluids flows, and the corresponding pressure changes.
The static model build used an exhaustive structural framework comprehensively coupled to the reservoir sedimentology model: facies and rock types, bodies' preferential directions, and bodies' dimensions. Before populating properties, sensitivitiess were performed to obtain an optimum grid and better represent facies lateral changes. The facies distribution model was created from the discrete curve of facies proportionality and using bodies dimensions defined in the sedimentology model. The netgross model was based on Vshale/porosity cutoffs. The porosity and NetGross characterizations were generated based on the facies modeling, and using the Sequential Gaussian Simulation (SGS) technique. The P50 of the stochastic simulations was used to establish the OOIP value.
The resulting static model was input into a black oil simulator to history match production and pressure, and obtaining a base case for prediction purposes. Subsequently, the sensitiy of the reservoir performance on most significant paramters, i.e. water injection rate, bottom-hole pressure, and number and location of injector wells, was analysed. The procedure was assisted by an optimization simulation tool to obtain optimum values of net present value (NPV). The final result was considered the most optimium injection pattern applicable to the current reservoir conditions.
Methodology and modeling techniques applied in this study can easily be extended to reservoirs in the basin with similar features.
Comments on Babu and Odeh's Model for Productivity Prediction of Partially Penetrated Horizontal Wells
Authors: Grassi E. , Zhu D. , Hasan R. 
Published: November 2015

Abstract
In this work, Babu and Odeh's model for estimating flow rate from partially penetrating systems is studied. A VBA code is written in order to simulate the model and its results are compared against simulations using Eclipse Software. Sensitivity to different parameters is analyzed.
The results obtained are compared against Eclipse runs, it is observed that the model is reasonably accurate.
It is concluded that the model is accurate within its simplistic assumptions, but it is in these same assumptions that it might yield very different results than reality itself.
Reservoir Compartmentalization in a Naturally Fractured Reservoir through Production-Pressure Performance and Compositional data
Authors: Paredes J. E. , Arana M. C. , Larez C. J. 
Published: November 2015

Abstract
Naturally fractured reservoirs (NFR) are generally subdivided into segments that behave as separate flow units due to the flow barriers (areal and vertical) generated by multiple fractures networks present in the reservoir.
This implies a challenge to predict the dynamic behavior of a reservoir when the degree of compartmentalization and blocks that form the reservoir is unknown. Generally, reservoir compartments are identified by geological events and not based on the dynamics.
This work proposes a methodology that attempts to describe and identify the compartments of a NFR through a dynamic analysis including:
– Production behavior (water, water-salinity, oil and GOR) – THP and BHP behavior (HPHT real time data) – Orientation and intensity of fractures – Analysis of the compositional variation of the fluid (vertical and areal) – Multi-tank model analysis (Material Balance) to identify faults transmissibility using in the simulation model
The proposed methodology was successfully applied to a NFR in the South of Mexico that presents problems in the History Matching process in its numerical simulation model.
ECD and Downhole Pressure Monitoring While Drilling at Ecuador Operations
Authors: Andagoya Carrillo K. I , Avellán F. J. , Camacho G. 
Published: November 2015

Abstract
For the period different drilling campaigns took place at the Tapi and Auca Fields, Ecuador. A downhole monitoring pressure tool helped identify some important pressure behaviors and scenarios.
The ECD monitoring led to better wellbore cleaning, drop of mud weight detection not detected on surface and improvement of drilling operation times by deciding whether it was necessary to make short trips or not, based on the acquired data. All the gathered data allowed the creation of a database that will become the baseline to improve future drilling projects in those fields.
The tool uses a quartz crystal type transducer that grants high resolution and accurate readings in real time and memory of annular pressures and bore pressures. Additionally, ECD (Equivalent Circulating Density) and ESD (Equivalent Static Density) measurements are calculated and this last one also defines an inherent value of the EMW (Equivalent Mud Weight). The tracing of these values show the performance of the drilling fluid and an ECD working frame could be defined to ensure effective cleaning of the well.
In order to understand ECD, external factors affecting its behavior need to be denoted such as flow patterns, ROP or drilling fluid properties. Additionally, the applications of pressure records when performing FIT, CIT or LOT are explained.
Different scenarios of how the data was analyzed, interpreted and the decisions taken during the operations are shown in this paper.
Integration of Formation Evaluation Domains for an Optimized Perforating Design
Authors: Morales O. , Bravo J. L. , Lomas J. , Madruñero C. , Vallejo R. , Rabanal J. C. , Pastrana W. 
Published: November 2015

Abstract
Petroamazonas EP is the national oil company in Ecuador. It holds most of the oil concessions Onshore and Offshore in the country. The oil and gas production targets require implementing advanced analysis that provides effective results on production.
In order to analyze and predict the well Productivity, it is necessary to perform an appropriate perforating analysis; this can be achieved integrating Petrophysics, Geomechanics, Reservoir and Production Domains. For an advanced Perforating design a clear understanding of rock characteristic, depth of damaged zone and reservoir behavior is used in the Perforating simulation. This enhances the right selection of charges and ensures they will overpass the altered zone. Step by step procedure is described:
Petrophysical evaluation and rock strength of the formation of interest. Quantification of alteration depth. Display the penetration profile. All this previous steps are used in order to obtain a detailed Flow Profile. To identify and select with the Flow Profile the better zones to produce. A sensitivity analysis is performed to select the best scenario for a technical and economic decision.
This methodology was implemented in two of the key Petroamazonas EP assets, which are Amistad Offshore Gas Field, and Apaika Onshore Oilfiled. This helped to optimize and predict the productivity of the wells.
The following conclusions were obtained once the wells were on production:
Selection of the better intervals to produce Low Uncertainty of well productivity prediction Confirmed effective communication between borehole and reservoir Skin reduction due to a better perforating selection and design Optimized completion design Making proper decisions when analyzing project cost versus production.
New Techniques Aimed at Facilitating Application of Directional Casing Drilling in Ecuador
Authors: Ramírez H. , Breton M. , Lougon A. P. , Rodriguez R. , Barreto M. , Chancay J. 
Published: November 2015

Abstract
Directional Casing while Drilling (DCwD) in Ecuador has been technically evaluated as a well construction technique to reduce or mitigate operational problems associate with: 1) constructing wells that could not be drilled efficiently using conventional techniques in partial and total lost circulation scenarios, through swelling shale or with hole instability issues, tight hole or stuck-pipe applications; 2) or to reduce total operational costs by eliminating casing runs, short/wiper trips and increase ROP.
At last count there have been over 200 worldwide directional casing drilling runs both onshore and offshore. These runs have been successfully executed in some of the most challenging drilling theaters making DCwD a viable and cost reducing alternative which helps operators solve the previously mentioned problems. To support the introduction of DCwD in Ecuador, rigorous engineering analysis has been performed which involves both the economic and technical aspects to help determine what kind of casing drilling system and BHA configuration is most suitable to ensure a successful run.
Modeling sofwares have been used to evaluate drilling dynamics and hydraulic requirements enabling engineers to select a drillstring that is capable of performing the specified job and obtain the required performance improvement with DCwD. The digital analysis helps to accurately predict if the application is suitable and determine which parameters could be applied to efficiently and safely execute the DCwD application.
There are some factors or parameters that can be taken as benchmarks when analyzing both static and dynamic simulation results. Torque determines if the rig has the capacity to drive the system. Fatigue and buckling analysis provide inferences into casing pipe selection and connection type. Realistic friction factors used during the simulations will avoid obtaining erroneous results which could lead to serious drawbacks. Scenarios like magnetic interference, presence of conglomerates or boulders could limit the tools' used for a specific application. The recommended BHAs will be supported by the specific regional analysis in addition to successes in other similar worldwide applications.
Once the engineering analysis has been completed, economics are then considered. The directional casing drilling service cost versus the amount of saving obtained by applying this technology has to be thoroughly evaluated. Savings will be couched as either time and/or money. Both have to be evaluated in the short and long term to determine which applications would benefit from DCwD and which environments should be avoided. The authors will explain how this analysis is performed to obtain an adequate feasibility study to meet the client's objectives. They will also discuss the key performance objectives that must be considered during each step of the analysis.
A Real Case Study: Field Development Plan Evaluations for Oso Field
Authors: Sierra F. , Monge A. , Leon S. , Vasquez F. , Garcia J. , Llerena G. , Borjas J. 
Published: November 2015

Abstract
The asset Oso-Yuralpa has 7 fields and 323 completions, located in the Blocks 7 & 21 of Ecuador. The oil cumulative production reaches 168.5 MMSTB. The active wells produce using electric submergible pump, hydraulic jet pumps and natural flow, mainly from 3 production zones. In surface, the production is processed in two flow stations, with high capacity processing.
This project was focused on Oso Field, located in the asset north area. Due the aggressive drilling campaign and the consequent increase in the daily production activities, has created the need to evaluate the impact on the surface facilities.
The scope of this study is evaluating different field development plans, integrating reservoir to surface facilities, that includes reservoir description, well models configuration, fluids gathering network, process facilities and economic indicators, with the objective of visualize and optimize field production, better decision making and operational planning considering long term life cycle.
Working in four scenarios was evaluated, as follow: Base Case: Operations at current situation.Drilling New Wells: Execution of drilling campaign to create 35 new wells using four rigs.Drilling Campaign with Delays: Considering delays in drilling schedule.Drilling Campaign with one rig less: This scenario considers one rig less.
The results in terms of cumulative production and recovery factor, estimates a maximum recovery factor of 4.2%, with and an additional cumulative production of 87.52 MMSTB with an increase of 1023 MMUSD in the Net Present Value (NPV). The Operating costs increase in 30% due investments in drilling campaign and fluid processing in surface.
As conclusion, the fourth scenario (Drilling Campaign with one rig less) gives the highest profitability index with the lower operational costs, which represent the recommended development plan.
The implementation of and integrated asset study, permit evaluate the project profitability in different scenarios, identify bottlenecks in surface network and measure the investment and costs uncertainty.
The present study allows the knowledge sharing between disciplines, making possible evaluate and visualize the asset development with sustainable technical and financial indicators.
The continuous evaluation of integrated models, serve as base for further production optimization and risk analysis studies, and could be applied in other assets.
Integrated Characterization Workflow Enables Ecuador NOC to Increase Oil Production from Very Thin Sand Reservoirs
Authors: Izurieta A. J. , Pastrana W. , Pazos J. , Davila E. , Chavez J. C. , Vallejo R. , Bastidas D. V. , Luzuriaga A. , Hernandez A. Diaz 
Published: November 2015

Abstract
The objective of this paper is to describe a comprehensive approach integrating static and dynamic well characterization to optimize well completion and subsequent improving oil production in thin sand reservoirs.
The following procedure was used to estimate and optimize the production potential of 3 feet sand reservoir located in Limoncocha Field: Accurate well logging program to identify thin sands. (Vertical Resolution, Static Data)Open Hole Mini DST program to estimate permeability, skin effect, and reservoir pressure and productivity index. (Dynamic Data)Anchored guns with 800 psi of static underbalance to avoid control fluid invasion.Well completion done with drilling rig; No well test is required using this methodology.PVT sample taken in cased hole for further characterization and continuous improvement.
Traditional workflows created by operators companies in the Ecuadorian Oriente Basin usually work very well in formations over 20 ft. thick. When such workflows are applied to thin reservoirs, frequently leads to bypassed zones with under estimated production potential. In order to offset this typical scenario, the G&G team working at Limoncocha field developed an integrated workflow to properly perform dynamic and static characterization of this type of zones to determine well productivity and the best completion method at an early stage while the well is still open hole. For this particular case study by a proper analysis the G&G team was able to characterize and predict oil production from 3 feet thin sand located at 11200 ft depth.
Mini DST technique played a vital role in the process, becoming the optimum link between static and dynamic data that allowed the proper workflow integration. The application of an early integrated well characterization allowed to set an optimum completion system design including state of the art perforating and optimized ESP design with no prior well test resulting in an improving oil rate of 850 stb/day from 3 feet thick sand overcoming the idea that it is a low productive or no pay zone regarding its current cumulative oil production of 126 MMSTB. This methodology truly predicted the production potential opening a new scenario where deep thin sands are now considered economical
Considering that the "easy" oil almost gone in the Oriente Basin, this paper describes an innovative workflow that allows proper planning to produce successfully thin reservoirs which in the past were considered low or non-productive.
Rock Typing Mapping Methodology Based on Indexed and Probabilistic Self-Organized Map in Shushufindi Field
Authors: Leon M. A. , Lafournere J. P. , Bourge J. P. , Bolanos M. J. , Bringer F. , Navarrete J. , Hurtado J. , Gozalbo E. , Suter A. , Henson R. , Rodriguez J. C. , Castillo F. , Ochoa J. 
Published: November 2015

Abstract
The Shushufindi field is located in the Oriente basin of Ecuador. The field was discovered in 1972 and widely developed with about 247 wells covering an area of approximately 400 km2. The implementation of lithofacies characterization in 98% of the existing wells has given a reliable description in about 92% of the wells in the current geomodel, which demonstrates, the validity of the deterministic method.
A robust petrophysical rock type (PRT) classification can significantly improve the chances of success for all wells, focusing on layered reservoir rocks recognized as the major energy resource in recent years. The vertical and lateral classification of rock heterogeneity in the form of rock types is critical to understand the flow dynamics of the reservoirs. Well logs are the best option for formation evaluation as they provide high vertical resolution measurements. However, rock type's classification using only well logs interpretation techniques, has its limits.
In this paper, we introduce a rock type neural network technique based on Indexed and Probabilistic Self-Organized Mapping (IPSOM) which was designed for the geological interpretation of well log data, facies prediction and optimal derivation of petrophysical parameters. The rock typing was based on cored wells in a 3-step approach. Preliminary rock type identification was based on sedimentology description and routine core analysis. In parallel, it was refined with high pressure mercury injection data to describe accurately the porous media. The porosity and permeability ranges were established to elaborate a sand facies classification represented by Petrophysical Rock Type through Winland method. The neural network was first trained on cored reservoirs, and then propagated to uncored wells using the classification model relationship with electrical logs. Finally using the IPSOM classification model, a permeability-porosity relationship for each rock type was obtained, providing input to the dynamic model to predict and validate permeability.
This paper present a reservoir characterization enhancement technique using neural network, which has proven its utility in refining the dynamic model of the Shushufindi field and directly contributing to the operator by improving production from layered reservoirs.
Pipeline Integrity Management in High Environmental Consequence Areas
Authors: F. Eguiguren G. 
Published: November 2015

Abstract
In 2009 Repsol Ecuador developed several root cause analysis in order to define the strategy for threats control as corrosion or third party damage. In conclusion it was defined the need to develop a pipeline integrity management plan based on international standards which ensure threats control and reduces leaks rate.
In 2010, a pipeline integrity management system based on the standard API 1160 "Managing System Integrity for Hazardous Liquid Pipelines" has implemented in order to ensure reliability and availability of the pipelines.
It starts with an external audit in compliance with criteria of standards API 1160 and ASME B31.8S as well as the requirements of CFR 195. The audit showed that Repsol Ecuador was meeting 37% of these requirements and provided an opportunity to identify where to should improve.
The plan developed by Repsol Ecuador for pipeline integrity management consists of the following parts: Determination of High Consequence Areas "HCA" in case of leakage or total failureStructured methodology for risk analysisDetermination of baseline of mechanical integrityDevelopment of Risk Mitigation and Control plansRe-evaluation of riskAudit Plan and KPI
As a result of the implementation of pipeline integrity management plan it can be mentioned the following:
To identify high consequence areas it was necessary to develop a new definition based on the API 1160 criteria but modifying them to accomplish the Ecuadorian reality and precisely the zones of influence of Blocks 16 and 67. It was determined that all Repsol Ecuador operation is been developed into a HCA.
A methodology for risk analysis based on the criteria of Pipeline Risk Management Manual by Kent Mulbahuer and following the criteria of the Repsol's corporate standard for risk analysis. The result of this analysis was the clear evidence that the greatest threats to the pipelines are internal & external corrosion and third party damage.
Based on the risk analysis, the baseline was determined by In Line Inspection and methodologies as ECDA. From the results mitigation plans were executed.
Currently and by using a software tool called Pipeline Integrity Data Tool, Repsol Ecuador integrates all information from daily operations, maintenance, inspection, etc., and defines the distribution of resources to prevent spills. As main results, the leakage rate has decreased from 23 leaks/ 500Km – year in 2009 to 4 leaks/ 500Km-year in 2014 in piggable pipelines.