bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economical and Technical Solution for Waterflooding Projects in a Mature Field: Modified Dump Flooding Well Completion Strategy
Authors: Meneses Sterling Alba , López Ruiz Yeniffer , Azancot Annalyn , Charry Lina , Correal Alvaro , Fuentes Llesica , Pastrana Wilmar , Silva Angel , Garcia Jose Norberto , Vasconez Nestor Danilo 
Published: July 2020

Abstract
It is a common practice to evaluate an injection pilot before a field-level implementation of waterflooding, but this requires early investment in facilities and construction time. An alternative solution is proposed as a modification of the dump flooding concept: Produce water from a low-salinity aquifer and inject it into an oil reservoir within the same well, using a closed system. The modification of the conventional dump flooding design consists of adding surface monitoring and control capabilities, which for this mature field is a local regulatory requirement
A comprehensive process for the completion design considered reservoir, well and operational conditions as both new and existing wells were considered as candidates for these completion systems. The design consists of a concentric completion with packers to isolate both the water aquifer and oil reservoir. Water is produced from a deeper low-salinity aquifer with excellent water quality through an Electric Submersible Pump (ESP) that also serves as an injection pump. At surface, the water rate is measured by a flowmeter and then injected into the same well through a concentric string to a shallower oil reservoir for secondary recovery. A simple closed-loop system at surface eliminates contact with oxygen, minimizing future corrosion problems. The high quality of the water (low salinity, without solids, O2, H2S or Fe) eliminated the need for water treatment.
Four wells have been successfully completed using this design, currently injecting at the required rates without presenting any functionality problem. Additional three wells are in schedule to be completed in order to accelerate waterflooding implementation in areas either remote or environmentally sensitive with no nearby water source. In these areas, implementing a waterflooding conventional pattern that requires connecting water producers and injector wells would require lengthy permission processes for long high-pressure lines and additional time for the construction of those water transport pipelines.
The completed modified dump flooding wells decreased the implementation time of the waterflooding pilot project from 2.5 years to 5 months. Additionally, the environmental footprint and facilities investment has been reduced by an estimated 90%. This is the estimated cost savings when comparing the investment in dump flooding well construction versus conversion of existing wells to water producers or injectors and the investment in facilities, including water treatment plants, to connect those wells.
This paper presents the main design and operational considerations before execution, deployment challenges, and lessons learned and recommendations from the execution of the first campaign
High Density Polyethylene Liner: Successful Alternative Against Corrosion and Wear Problems in Production Tubing of Mature Fields in Colombia
Authors: Duarte Poveda Gloria Isabel , Mateus Barragán Miguel , Estévez Lizarazo José Alexander , Doval Jorge Mario , Barragán Patricia 
Published: July 2020

Abstract
The production tubing in wells of mature fields in Ecopetrol located in the Middle Valley of Magdalena has shown a run life between 180 and 300 days. The main failures are due to corrosion and abrasive wear or friction mechanisms that, according to root cause analysis (RCA), could be the result of exposing the carbon steel to aggressive fluid, production sand and contact with sucker rod (beam pumping-BP or progressive cavity pumping-PCP).
Taking into account the positive experience previously obtained at field test and extended use of the HDPE liner in flow and collector lines with corrosion and abrasion problems, this work presents the results evidenced in laboratory evaluation and demonstration trial of the HDPE (High Density Polyethylene) liner to mitigate premature failures and prolong run life of production tubing.
Radio-Frequency Application for Oil Mobility Improvement in the Hollin Formation in Ip-15 Well. Pungarayacu Field
Authors: Llamuca Luis , Bonilla Andres , Mariño Rolando 
Published: July 2020

Abstract
In recent decades, oil producing countries have focused their efforts on incorporating new oil and gas reserves that support their long-term economic plans. An oil peak production in 2020 has been forecast by Belani (2006), and the challenge to find more reserves becomes greater as statistically the conventional to unconventional oil and gas resources ratio (2:8) may suggest that most conventional oil resources have been already found (Zou et al., 2015). This situation has risen concerns among oil dependent countries but have opened the gates for the development of unconventional oil resources in developed countries such as Canada, USA, China, etc (Belani, 2006). Crude bitumen is one kind of unconventional oil that poses a significant opportunity for development in Ecuador. According to a report by Gaffney, Cline & Associates (GCA) and Ivanhoe Energy in 2009, the Pungarayacu Field (Block 20) holds 6.4 billion barrels of oil initially in place (OIIP) and is considered the largest unconventional asset in the country. The challenge for its development consists of overcoming a low oil mobility associated to high oil density (ranging from 8 to 10 API) and viscosity values.
This work presents the application of Radio-Frequency (RF) for hydrocarbons thermal heating as an alternative for extra heavy oil recovery enhancement in the crude bitumen deposits of Pungarayacu Field in Ecuador. The activities conducted in this study include an approach to investigate, experiment and model the bahaviour of the reservoir temperature at a small scale under the influence of heat generated by microwaves. The study will demonstrate that hydrocarbon heating through the use of radio frequency represents a valid alternative for heavy oil extraction and discuss its feasibility based on an energy consumption analysis and some comparisons with upscaled projects using Steam Injection technology.
Subsea Systems Innovations and the Use of State of Art Subsea Technologies Help the Flow Assurance of Heavy Oil Production in Ultra-Deep Waters
Authors: Pedroso Carlos Alberto , Rosa Geraldo , Borges Priscilla , Nunes Kleber 
Published: July 2020

Abstract
Flow assurance in ultra-deep waters oil production is always a major concern. Atlanta field, which produces heavy oil in ultra-deep waters, is one of the most challenging project offshore combining several difficulties: hydrates formation, emulsion tendency, scale formation, foaming, high viscosities that can achieve 100.000 cp at sea bed temperatures, etc.
To overcome these challenges, the best subsea system technologies has been used, together with some small, but ingenuous, innovations.
The use of a 6" unbonded flexible lines, with TEC 2 insulation layers minimize the risk high viscosities in case of the expected shut downs.
To cope with scales, foaming and emulsion, chemical additives can be deployed into the wells through the biggest and unique umbilical installed in Brazil, which accommodates 15 hoses, 2 MV Electrical Cables of 3X150mm2 and 2 Eletrical Cables with 4x6mm2 and 2 eletrical cable of 4x2,5mm2.
Hydrates can block the flowlines stopping the production. When it occurs, the remediation is normally long and expensive. For hydrates, the cliché "prevention is better than remediation" is true. Hydrates can be prevented with proper procedures and preventers. But in case of hydrate formation, a pioneer hydrate mitigation panel, operated by ROV was installed in the wet christmas tree (deployed by cables).
And finally, to guarantee the production flexibility for production and maintenance, an innovative and unique subsea lay out, consisting of two Electrical Submersible Pump (ESP), one in-well and other in mud line skid, was developed and installed.
All this innovations and best technologies used together made Atlanta a successful case of heavy oil production in ultra-deep waters, triggering huge resources around the world.
New Generation Formation Testing ORA Platform Used to Test and Sample Tight Naturally Fractured Carbonate Under HPHT Conditions
Authors: Gama Villegas Raul , Mendez de Leon Javier , Navedo Flores Victor Jesus , Dubost Francois-Xavier , Pfeiffer Thomas , Edmundson Simon , Partouche Ashers , Lavin Vizcaino Manuel , Hernandez Espinosa Hugo 
Published: July 2020

Abstract
Reservoir sampling and pressure (RS&P) testing acquisitions are fundamental in Exploration settings to evaluate reserves and/or well productivity. Wireline Formation Testing (WFT) is well known in our industry for conventional reservoirs. However, there has not been any available WFT technology to perform these acquisitions in Naturally Fractured Carbonate (NFR) formations under HPHT conditions. A new platform developed for all terrains of formations and environments was used for the first-time in in Mexico, allowing to conduct a full RS&P program to delineate reserves in a large gas condensate reservoir.
The new platform consists of a new focussed radial probe inlet, featuring a dual flowline with dual downhole pumps to allow focused sampling mode. Given the larger flow area of the new probe system, flow tests can be conducted in sub mD permeability zones, typical in NFR carbonates, and fluid identification can be performed in-situ while flowing thanks to a group of new sensors. Sampling for PVT analysis is achievable, and sample quality is ensured via the focused sampling system. Post sampling buildups provide pressure transient test data which allow characterizing the layer productivity.
The new technology was employed in two appraisal wells belonging to the Veracruz basin in Mexico. The reservoir facies are constituted by packestone and wackestone carbonates belonging to the mid Cretaceous, over very large thickness. Reservoir quality lies in vugular porosity and micro-fractures; however, the matrix porosity is low. The petroleum system originates from the Upper Jurassic source rocks which led to gas condensate hydrocarbons at the reservoir level today.
Preliminary simulations indicated that despite the low matrix quality, with the new platform, it would be possible to test and recover quality samples within 4-8 hours depending on the invasion depth scenario and with a drawdown below 300 psi. Four conclusive tests were made in the first well which helped the operator delineate reserves and two conclusive tests were made in the other well fulfilling objectives and following the designed test durations and outcomes, in temperature conditions up to 182 °C and pressure of 20kpsi. The lowest mobility flow test and fluid identification was conducted in 0.06 mD/cP.
The new platform test results compared very well with actual test results that were conducted.
These two cases highlight the possibility to test and sample fluids in HPHT conditions, NFR reservoirs with tight matrix properties with the new formation testing platform, in environments where previously formation testing was not possible. A significant amount of Mexican carbonate reservoirs faces this extreme environment.
Evaluation of Well Performance Using Data from Fiber Optics Sensors, in Wells of the Pilot Polymer Flooding Test. Orinoco Basin, Venezuela
Authors: Ramirez Andres , Vasquez Edgar , Quevedo Luis , Ulacio Ivon , Rojas Gonzalo , Rodriguez Oswaldo , Gamez Hector 
Published: July 2020

Abstract
In the case of this pilot test using polymer flood, evaluating the performance of injector wells was one of the main priorities. Losing injectivity is recognized as one possible cause of poor performance in the case of enhanced oil recovery processes, so estimation of the length of the well that contributes with injection, the identification of by passed zones, the diagnostics of the well behavior, and recommending solutions for a future project, were part of the objectives stablished at design of the project. For those reasons, we chose to complete the wells using a distributed temperature sensor (DTS).
After installation of fiber optic sensors system in the wells associated with the project, the acquired data was analyzed using different techniques: Comparison of the effective length obtained from the static model with the one obtained from fiber optic sensors, and also pressure test analysis, later the distribution of the injection rate in each case was obtained. Initially it was necessary to establish a base behavior: Real-time measurements of pressure and temperature, characteristics of the injected fluid, and petrophysical evaluation of the completed intervals, which was used as departure point for studies performed.
Maintaining a good injectivity in polymer injection projects normally is a major concern, in this case we present a real case of a polymer injection project in an extra heavy oil reservoir, which is producing oil with an average viscosity of 4150 cP at reservoir conditions. Polymer solution with a concentration of 1600 ppm was injected since 2017 and the injection is maintained so far without important reduction in the injectivity index. An estimated of the injection interval was established, and also estimation of the injection distribution in the horizontal section. The estimation was then validated with the results of the measured surface rate, and pressure transient test analysis. In average 30 % of the horizontal section of the well were receiving polymer solution, and then thanks to this new information zones not receiving polymer solution were identified. The results were used to improve the reservoir simulation models, and as diagnostic tool for pilot test.
This paper describes how a better understanding of the connection between the well and the reservoir, can improve the reservoir simulation models, decision making process, and well performance evaluation. Also the importance of determine the possible not swept areas in the reservoir, which could result in low volumetric swept efficiency, and as a consequence low recovery factor. Finally the results presented here could be useful to the general interest of engineers dedicated to polymer flooding projects.
The Use of Drilling with Casing to Set a New Standard for Drilling Operations in Argentina
Authors: Espinosa C. M. , Watts R. D. , Rebasa N. , Lojk C. I. , Roldan C. , Codega D. , Castiñeiras T. 
Published: July 2020

Abstract
During the last 7 years the number of projects and operators using drilling with casing has increased steadily in both the Vaca Muerta shale play and in the Golfo San Jorge mature projects.
The following paper summarizes the evolution of the use of this technology and the benefits it has brought to operations in Argentina. Additionally, as some premature failures occurred, the paper identifies some limitations of the technology and the lessons learned from those failures.
Within this paper, detail will be presented for the current use of Drilling with Casing (DWC) technology in shale operations and mature fields in Argentina. A summary the drivers and benefits of the technology along with its limitations will be presented. In particular, the paper will include the analysis of some premature failures with a set of recommendations to minimize the risk of failure.
Several operators are using DWC in their operations in unconventionals fields in Vaca Muerta and in mature fields in the Golfo San Jorge Basin. The highest percentage of the strings installed is for surface casing where the main target is to reduce Non-Productive Time (NPT) during drilling. The use of DWC has extended to almost all projects in Vaca Muerta, making it a standard technology for the surface casing section in one of the most important shale plays outside of North America. In the Golfo San Jorge basin, the DWC technology has been used to overcome drilling challenges of mature fields with extensive water flooding, wellbore instability, inflow control and differential sticking. The results have helped operators to reduce NPT. The technology has proven its reliability with more than 1200 strings installed in the last 7 seven years. However, some premature failures have occurred and resulted in an intensive investigation by the casing manufacturer. The failure analysis showed that fatigue was the most common mode of most of these failures. The challenge rose when the available fatigue modes could not predict or replicate the failures. Within the paper we detail the probable sources of loads that provoked the failures and some recommendations that will help to minimize the risks for the future.
The use of DWC and its benefits in Argentina could be replicated elsewhere reducing costs and improving efficiency. The set of reccomendations of the paper could help to reduce the risk of future operations.
Implementation of Extended Range Pump as a Solution for Low-Input Wells. Success Story in Llanos Norte
Authors: Nunez Walter , Del Pino Jessica , Garzon David , Pinto Duvan , Gonzalez Camilo , Pinilla Jaime , Gomez Alvaro 
Published: July 2020

Abstract
In the Llanos Norte area, ESP systems represent 92% of the installed artificial lift systems. According to the current production strategy in this field, there is a need for intervention in low quality sand. The design of the artificial lift system is affected by the uncertainty of the productivity index and expected flow rates. 25% of the completions designed for low flows have had deviations greater than or equal to 50% between the design parameters and the actual parameters. This condition has led to the search for alternatives for intervention and completion of this type of wells, this because the conventional technology of the pumps used historically in the field does not allow producing efficiently in such a wide uncertainty production ranges.
Service Provider, from the hand of the Operator implemented a pump called FLEX-ER (extended range pump). This solution allows extending the range of the efficiency cone of the pump from 50BFPD and up to 2900BFPD, this feature helps to mitigate the uncertainty in the available design parameters, keep the pump in the optimal ranges of operation, avoid the up and down wear of the stages, thus increasing the lifetime of the electrosubmersible system.
The implementation of this technology has allowed having an ESP equipment available to cover the production needs of the wells in low quality sands of northern plains. The wide range of operation of this stage allows to be protected against uncertainty in productivity and facing the changes that the well may have during its production stage. Additionally, the implementation evaluation model for 8 wells resulted in a projected saving of USD 1.4 million, as a consequence of the reduction in intervention costs, energy consumption and NPT reduction. According to these results, it is expected for the next well drilling and reconditioning campaigns, including the standardization of the technology in order to optimize the production processes of Occidental.
This paper aims to present the most important technology implementations, follow up and results as well as the impact in field performance KPI.
Pressure Transient Analysis PTA Diagnostics and Screening Criteria
Authors: Alcantara Ricardo , Ham Juan Manuel , Paredes Jorge Enrique , Petriz Jose Maria , Sanchez Guillermo , Briones Mario , Fuentes Gorgonio 
Published: July 2020

Abstract
The objective of this work is to generate a selection matrix that contributes to the decision making, contemplating all the necessary technical criteria to ensure that the information gathering is adequate and the Pressure Transient Analysis (PTA) could be advantageous for the reservoir characterization and the determination of well productivity parameters.
For this scrutiny we analyzed more than 500 well tests from 100 fields in Mexico and other parts of the world, onshore and offshore, carbonates and terrigenous, and different types of fluids (black oil – extra heavy, heavy, intermediate and light, volatile oil, retrograde gas and condensates, wet gas and dry gas), from which all the pressure responses obtained were compared in order to identify every associated problem and the causes that originated them from the design, execution and finally, during the interpretation of the PTA.
The importance of this work lies in improving the PTA through the allocation of different numerical values for each of the controlling factors involved at reservoir, well and at surface level, depending on its own impact on the results, so we classify them in Well Evaluation Conditions (WEC) and Reservoir Evaluation Conditions (REC).
Redefining Technical Limit – Managed Pressure Directional Drilling Solution in Mexico Zaap Field
Authors: Lopez Infante Jose Luis , Vizcarra Marin Hector Hugo , Fernandez Mendez Jorge Armando , Ngan Alex , Acosta Javier , Garcia Edgar 
Published: July 2020

Abstract
This paper will discuss the Managed Pressure Directional Drilling fit for purpose solution deployed to meet the drilling challenges in Mexico offshore Zaap field. This innovative solution integrates a new state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as total losses, wellbore instability and stuck pipe were mitigated, and an improved drilling performance with reduction of NPT as compared to other directional drilling systems.
The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling (DD). Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication plan are crucial for the effective execution. The solution is based on a rigorous Drilling Engineering process; including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the operator to tackle drilling hazards without compromising the directional drilling requirements.
The paper will also discuss the effective communication plan between the directional drilling services, MPD services and rig contractors to ensure safe operational alignment. Also, the paper includes a planning and operational blueprint to reduce NPT related to total losses, stuck pipe & wellbore instability, increase drilling performance (ROP improvement) and quality wellbore for liner run afterwards in the Middle Cretaceous formation.
Drilling challenges in the Zaap field requires the utilization of both Directional Drilling technology and MPD techniques to improve drilling performance and reduce NPT respectively. Through processes, best practices and lesson learned, this paper hope to serve as the bellwether for the combined solution to achieve technical limit drilling performance in the Zaap field, offshore Mexico.