bluuebunny/crossref_metadata_2025_split huggingface dataset:
EOR Screening and Early Production Forecasting in Heavy Oil Fields: A Machine Learning Approach
Authors: Muñoz Vélez Eduardo Andrés , Romero Consuegra Felipe , Berdugo Arias Carlos Andrés 
Published: July 2020

Abstract
A new mathematical model was proposed integrating the algorithms of neural networks and gradient boosting for the selection of the optimal EOR method in heavy and extra heavy oil fields as well as to predict the oil production of the field in the first five years of the project. The parameters were selected from genetic algorithms using the technique of auto-machine learning.
The model was developed with a database of 919 fields, from different public sources, and consists of three stages: 1) A dimensional reduction of the initial variables using t-SNE (t-Distributed Stochastic Neighbor Embedding), passing from 12 variables to 2 final variables. 2) An estimation of the optimal EOR method from an Artificial Neural Network. And 3) the integration of 1) and 2), serve as the input for a genetic algorithm in order to forecast the production of the first years of the field after the project started.
The obtained results show a correlation of 87% for the classification neural network, and 93% for the genetic algorithm in the test database. Therefore, an integrated workflow was also developed, which takes the generated production profile and performs cash flow analysis, leading to the calculation of key financial parameters for determining project feasibility from given reservoir, fluid, and economic conditions input by the user.
The developed model is presented as an opportunity to experience the possibilities that artificial intelligence has in the oil and gas industry, and how it can be of great help in the prediction of variables for process optimization. Employing the optimal EOR method from the beginning of field development can increase long-term profitability. In addition, the developed screening software eases decision making for operators in selecting, technically and economically, the most feasible thermal EOR method for the development of heavy and extra heavy oil fields, maximizing asset value and E&P portfolio.
Experimental Investigation on Mass Transfer Kinetics of Hydrocarbon Gas Influx for Enhanced Offshore Well Control
Authors: Ojedeji Damilola , Nielsen James , Perry Scott , Chen Yuanhang 
Published: July 2020

Abstract
This paper presents an experimental investigation of the time-dependent desorption of methane from non-aqueous base fluids, for a better understanding of mass transfer processes involved in riser gas events. A laboratory-scale experimental apparatus was developed and used to experimentally evaluate the rate of desorption of methane from Internal Olefin (IO) and Internal Olefin emulsions, which are commonly used as base fluids for offshore drilling in the Gulf of Mexico. The main test column of this apparatus consists of multiple sections that can be accessed separately. Methane was injected from the bottom of the test section to saturate the fluids at given starting pressures. Upon reaching complete saturation, the pressure was rapidly reduced and the methane that liberated out of solution was measured to determine the rate of degassing over time. The experimental tests were performed under various starting pressures and with different Oil/Water (O/W) ratios of Internal Olefin emulsions. Experimental results are discussed to comprehend how pressure and base fluids affect the desorption processes in the test column. This study discloses how methane evolves out of base drilling fluids commonly used in offshore drilling. The results can be used to improve well control simulators and help to better determine riser gas equilibrium through enhanced modeling of time-dependent degassing.
Review of Current Status of Reserves Estimation Standardization in Latin America; A Third-Party Auditor Opinion
Authors: Espinoza Rolmys , Siciliano Yoanna , Escobar Esther , Romero Maria 
Published: July 2020

Abstract
In recent years, internationally recognized reserves estimation and reporting standards have been adopted in Latin America by government regulators and national operators. This paper describes the current regional situation from the perspective of a third-party auditor.
Potential investors need a clear understanding of how a country and its oil and gas sector companies evaluate their petroleum resources to optimize asset portfolio management and value. To this end, the current reserves estimation and reporting practices of several major Latin American oil and gas producers were investigated to identify the level of standardization by country. This review includes the application of the main resource classification standards used by the government regulators in the region and how they have influenced the estimation of reserves in recent years. The role of the third-party reserve auditor is discussed, including the importance of intangible influences which must be taken into consideration. The process of reserve estimation is complex and involves multiple skills, knowledge and judgement while applying a variety of international reserves standards to provide a reliable independent audit for operators or regulators alike. Documented examples of inadequate reserves audit are presented.
The SPE PRMS is the reserve reporting standard used by most of the regulators and operators, but those companies that are listed on the USA or Canadian stock exchanges use SEC and COGEH, respectively. Annual independent reserves estimation from third-party auditors is mandatory for most of the Latin American countries reviewed, although some continue to use in-house reserves estimations. Examples are given to illustrate how some government regulators use their own internal guidelines with additional considerations for reserves estimation and reporting. The paper shows that those countries where reserves estimation and reporting have been standardized, and which are audited by third-parties, have given more confidence to the global investment community.
Standardization has been fundamental in helping to attract development funding for the oil and gas sector in Latin America, as it brings clarity to decision making based on reliable estimates of recoverable petroleum volumes. This paper provides a review of information regarding the status of standardization of reserve estimation and reporting in Latin America. Best practices are shared, and some necessary areas of improvement are proposed. Getting it right can result in improved transparency and increased international investment.
Integrated Digital Solution for Enhanced Oil Recovery Through Optimization of Injection and Production Networks
Authors: Mogollón Jose Luis , Franco Miguel , Querales Maiquel 
Published: July 2020

Abstract
This study objective was to design a functionally integrated digital enhanced oil recovery (ID-EOR) solution enabling pseudo-real-time optimization of injection and production networks to help improve asset performance and maximize net present value.
ID-EOR indicators for each business process (e.g., injected fluid-to-oil ratio, productivity index, and recovery factor), automation opportunities, workflow logic and characteristics, flow diagrams, and mathematical models were identified and mapped for injection and production processes. A swim lane- based approach was selected to structure the various automated workflows. The swim lanes are (i) injector well short-term diagnoses and network regular update, (ii) reservoir model, (iii) production network regular update, and production well short-term diagnoses. A set of engineered workflows would perform a series of tasks delivering outputs that ultimately provide the users with diagnosis and/or recommendations. Workflows can be run individually or in tandem, and goals can be met by making decisions at the well, network, and reservoir levels, or with all the levels integrated.
One of the challenges to further advance ID-EOR solutions is the lack of quantitative data. Based on proprietary information, literature research, and stochastic analysis, 20 to 60% cost or resource reduction in fuel, power, maintenance and operations can be realized using digital workflows and automation. Stochastic analysis pointed to positive P50 present value of hundreds of millions of dollars, and negligible risk of unprofitability. In other words, the results obtained provided realistic expectations of benefits from digitalization and automation in the short, medium, and long terms.
ID-EOR solutions offer a path to increased profitability while reducing economic and operational project risks. The sensors, data transmission, processing, and storage technologies necessary are available, and most methods have been tested individually and/or partially integrated. The next step is a full integration trial in the field.
While almost fully integrated digital solutions have been previously implemented for waterflooding, this new concept design introduces a novel integrated digital solution to gather and diagnose data and make timely operational and engineering decisions to meet planned injection and production targets in EOR projects, and maximize the economic benefits.
Case Study: Implementing Continuous Circulation and Managed Pressure Drilling Techniques to Drill in the Challenging Perla Gas Field in Offshore Venezuela
Authors: Arellano Juan Jose , Pozzo Huerta Javier Enrique , Johnson Rachel , Poletzky Isabel , Kumar Bikram 
Published: July 2020

Abstract
The Perla Gas Field is a naturally-fractured carbonate formation in offshore Venezuela that often requires advanced technology to complete and optimize drilling operations while also minimizing nonproductive time (NPT). To overcome the challenges and reduce NPT demonstrated on a well drilled in 2010 in the Perla field, continuous circulation and managed pressure drilling (MPD) technologies were used to drill two subsequent wells in 2016.
Drilling in the Perla field is a challenge because of its narrow pore pressure and fracture pressure window, which increases the potential for issues such as lost circulation, kicks, wellbore instability, and connection gas. To overcome challenges encountered in 2010 while also decreasing NPT, a combination of MPD and continuous circulation technologies were selected to drill the wells. To navigate the tight drilling windows, MPD was selected for this campaign, with continuous circulation implemented to supplement the MPD process by removing any transient time or pump cycling effects during connections.
Continuous circulation allows the operator to circulate fluid downhole during the drill pipe connections. The system includes a manifold connected into the standpipe that performs the diversion, and subs installed onto the top of each stand of drill pipe, creating two independent flow paths for drilling an open hole section. MPD creates a closed loop system and allows the operator to safely add or remove backpressure at the surface in order to control bottom hole pressure (BHP).
In Perla, a well was drilled in 2010 with significant losses as a result of an unexpectedly narrow drilling window of 0.5 ppg equivalent mud weight between pore and fracture pressures (9.8 to 10.3 ppg, respectively). In 2016, the new combined solution enabled drilling of the lateral in both wells by maintaining a constant BHP during all phases, mitigating influxes or losses, removing static mud pressure spikes (breaking gels), reducing connection gas, and improving hole cleaning. A statically underbalanced 9 ppg fluid was used while targeting a 10.2 ppg equivalent mud weight throughout the length of the 8½ in lateral on more than 150 drill pipe connections to decrease tripping time, get liner to depth, and improve the estimated time to total depth, decreasing overall risk, NPT, and cost.
In exploratory and development wells, risks increase when different than expected well conditions are encountered during drilling. This case study provides an example of the viability of combining MPD and continuous circulation, a solution which is highly applicable in offshore Latin America, including but not limited to Venezuela.
The Water Shut Off Technique Extends the Productive Life Cycle of the Cretaceous U Sandstone: The Iro Field Case in Ecuador
Authors: Bailón Luis Roberto , Orellana Ney Holger , Villegas Santiago , Martinez Edsson , Román Servio , Espín Jorge , Gaibor Andrés , Tamayo Telmo 
Published: July 2020

Abstract
The water shut off technique is applied in some wells as a remediation plan to restore their production after an early water breakthrough from U reservoir in the Iro field of the Oriente Basin, Ecuador. The production historical data, workovers and sandbodies correlation are compared among wells to understand the reservoir behavior, the shale baffle sealing continuity, the existence of different sand units and the impact on their production.
Few years of heavy oil production with abrupt water increase conducted to squeeze perforations in the lower part of pay zones. Production behavior before and after water shut off is analyzed regarding water cut, formation water salinity, fluid provenance from the reservoir and its zone perforations setting during completions. The stratigraphic well correlation, reservoir properties and sealing shale layers explain the well production outcomes and geological patterns. Well intervention lessons learned and recent pulse neutron logs support additional water shut off proposals at current Iro producer wells.
The U sandstone reservoir development was focused on the Lower U sequence while hydrocarbon potential was identified in Upper U sequence. Nevertheless, the geoscientist kept the main interest in Lower U reservoir development because of their oil in place volume. The strong water drive aquifer caused mostly a fast water cut increase achieving 90% in around three months and well’s production continued for few years until economical cut. In order to keep wells in active status, squeeze jobs were planned and executed, dropping the water cut to less than 10% followed by a gradual ramp up during many years of production. The fluid rates were reduced drastically from average 10000 bfpd to less than 1500 bfpd. The formation water salinity increased from 18000 ppm to 60000 ppm. These evidences advice of two different production behavior in the Lower U sandstone reservoir. The re-perforations were done above a shale layer seal which separates sandstone units. This seal is controlling the water breakthrough in many wells. However, there is evidence of sandstone units connection to the western area of the field, because of salinity decrease and pressure increase.
After many years of production, pulse neutron logging was run showing flushed zone from former producing perforations as well as remaining hydrocarbons at thin sandstone layers deposited in the upper unit of Lower U sandstone reservoir. In addition, this document will allow reservoir engineers to forecast production behavior, to plan water shut off in analog fields, accordingly.
Practical Aspects of Foam-Assisted SAGD
Authors: Delamaide Eric , Batôt Guillaume , Ayache Simon Victor 
Published: July 2020

Abstract
Steam-foam has been used extensively in field trials to improve steam conformance, both for cyclic steam injection and steam flood. It is a proven process and very useful lessons can be drawn from these field trials to plan new projects. However, foam has not yet been used to improve SAGD (Steam-Assisted Gravity Drainage) performances. The aim of this paper is to examine the reasons for this situation and discuss the practical aspects of Foam-Assisted SAGD (FA-SAGD).
After a thorough description of the main mechanisms involved in these processes (steam-foam for cyclic steam injection and steam flood, as well as foam for SAGD), this paper proposes to review the differences between the various processes and their implications for the design and implementation of FA-SAGD. Finally, based on the lessons drawn from all the documented steam-foam trials, potential and drawbacks of FA-SAGD are presented together with suggested roadmaps to address these remaining and newly identified challenges to make this technology come true.
By definition, the driving mechanism of SAGD relies on gravity and involves the use of a pair of horizontal wells drilled a few meters apart, one on top of the other. This is completely different from foam applications with both cyclic steam injection and steam flood, which are typically conducted with vertical wells; in addition, cyclic steam relies on single wells only whereas steam flood is essentially a lateral displacement process. Steam quality, injection velocity, proximity of the injection and production wells and the risks associated with the formation of emulsions in the surface facilities are some of the issues that are typically not problematic for foam with conventional steam processes, but which need to be considered before FA-SAGD can be implemented in the field. This work concludes that FA-SAGD is feasible but that ignoring any of these aspects would very likely cause the process to fail in the field.
This study will provide useful physical considerations on the steam-foam process along with detailed guidelines for the implementation of the Foam-Assisted SAGD process in the field. It will be useful for engineers that are considering foam to improve the performances of SAGD by targeting a reduction of the steam consumption or the Steam Oil Ratio.
Impacts of Natural Fractures on Non-Planar Hydraulic Fracture Propagation in Storage-Viscous and Storage-Toughness Dominated Regimes
Authors: Rueda Cordero Julio Alberto , Sanchez Cristian Mejia , Quevedo Roberto , Roehl Deane 
Published: July 2020

Abstract
Hydraulic stimulation is a technique in which a mixture of viscous fluids is pumped through an injector well in order to initiate and/or propagate fractures in the rock formation to enhance well-reservoir connectivity. Analytical and numerical methods have been proposed in the literature for predicting the evolution of the induced hydraulic fractures. Most of those studies are limited to some assumptions, such as fracture propagation through intact materials that follow a linear elastic behavior. However, those assumptions do not apply in naturally fractured porous media. The presence of geological discontinuities such as faults, joints, and natural fractures increases the complexity of the hydraulic fracturing treatment, affecting the final configuration of the hydraulic fracture network. This work investigates the effect of natural fractures on hydraulic fracture propagation in two limiting propagation regimes: toughness-fracture storage and viscosity-fracture storage dominated.
The model fully couples permeable rock deformation and fluid flow inside and across the fractures. The hydromechanical triple-nodded zero thickness interface element has been combined with a cohesive zone model to simulate hydraulic fracture propagation. Mohr-Coulomb criterion and a contact model represent frictional and closure behavior of natural fractures, respectively. The longitudinal flow within the fracture is governed by Reynold's lubrication theory through smooth narrow parallel plates (i.e., Poiseuille flow). An innovated intrinsic mesh fragmentation technique is used to simulate complex crack patterns during hydraulic crack propagation.
The results of the new approach are compared with analytical solutions. Moreover, the influence of parameters such as rock permeability, fluid viscosity, initial stress state, and natural fracture orientation on the hydraulic fracture propagation is analyzed.
Intelligent and Automated Workflow for Identification of Behind Pipe Recompletions and New Infill Locations Opportunities for an Onshore Middle East Field
Authors: Kansao Rami , Benhallam Wassim , Aronovitz Alexander , Ravuri Meher , Maqui Agustin , Suicmez Vural , Castineira David , Darabi Hamed 
Published: July 2020

Abstract
An integral aspect of field development planning is the process of identifying remaining, feasible, and actionable field development opportunities (FDOs) such as recompletions and new drills. In mature brown fields, this process is extremely difficult to undertake in a reasonable timeframe due to the sheer size of the available datasets (e.g., thousands of wells, decades of production history), geologic complexity (e.g., dozens of layers, faulting, folding, fractures, pinchouts), and engineering challenges (e.g., commingled production and injection, field compartmentalization) unique to each reservoir.
The automated framework is a fully streamlined framework that aims at building a comprehensive opportunity inventory consisting of behind-pipe recompletion opportunities, vertical new drill locations, sidetrack opportunities, and optimal deviated/horizontal targets. In addition to opportunity identification, it can generate additional deliverables for vetting purposes including a well book report and a standardized Petrel project. The main objective of this process includes: 1) fast, data-driven, and consistent approach for evaluating and identifying field development opportunities, 2) fast execution time, accelerating processes from months to days, 3) integration of multi-disciplinary data, 4) consistency and repeatability, minimizing subjectivity, and 5) streamlined visuals for opportunity vetting.
This framework has been successfully applied to a mature field in the Middle East with more than 1,000 producers and 55 years of production history. Hundreds of recompletion opportunities were initially identified for the field. A final list of opportunities is then generated by running the opportunities through a series of user-provided attribute filters such as minimum initial rate, minimum oil thickness, maximum acceptable uncertainty, and so on. The process is then typically finalized with manual vetting of the opportunities by subject matter experts including geologists, reservoir engineers, and production engineers that ensure the opportunities are geologically sound, mechanically feasible, and meet various validation criteria that are discussed in this document. A final list identified 116 recompletion opportunities in 116 wells with a total potential production upside of around 63,000 B/D.