bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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.
Electric Submersible Pump Troubleshooting Guide, an Effective Way to Improve System Performance and Reduce Avoidable System Failures
Authors: Nunez Walter , Del Pino Jessica , Gomez Sebastian , Rosales Douglas , Puentes Juan , Rivera Hamilton
Published: July 2020

The Oil and Gas industry in recent years have been a great challenge for operators and aervice companies as well. This situation resulted in great opportunities to find efficiencies that can enhancement production, avoid down times and optimize operation in Electric Submersible Pump Systems (ESP). Keeping this on mind, one of the main drivers is implement procedures that can extent ESP run life, and one of the key challenges is to identify any trouble that can impact ESP performance timely so it can implement solutions to avoid failures.

The main objective was to develop a troubleshooting manual that could be used for any engineer to identify likely conditions that could be affecting negatively ESP performance and to implement solutions to minimize failure or damage beyond repair in ESP equipment.

A jointly team composed by the operator and the service company developed a troubleshooting manual to the proper identification of likely conditions that could be impacting the production and performance of ESP systems. This was achieved using monitoring information, tear down evidence, setting configuration and building a database with all the information in order to group similar cases to identify the best ways to respond to any anomaly in ESP behavior.

This procedure was implemented in the field that have an average of 450 active wells with 93% being ESP systems, by socializing it with all the parties that participate in ESP troubleshooting to guarantee a proper handling of any occurrence.

The main purpose of the creation of this procedure was to avoid failures associated with ESP operation conditions that could result in early failure; this is measured with the Failure Index (IF) that means the number of average interventions in an ESP field related to the average number of active wells in the same period.

The implementation resulted in awareness in all the personnel that when best practices are followed there are better chances of field KPI improvements and savings, in this case the Failure Index of the field was reduced from 0.4 to 0.18 attributed to technology and best practices implementation as well.

This paper aims to present the most relevant analyzed cases, the procedures implemented and the results in FI after implementation as well of recommendations to any party interested in implement similar projects in their operations.
Ensuring Zonal Isolation in Cementing Jobs of Gas Well
Authors: Jiménez Edgar , Vásquez Elvis , Velasquez Nelson , Vega Luis
Published: July 2020

One of the critical conditions in cementing operations of gas wells, is the underbalance that generates the entry of preflush in the annular space, especially with the use of in the fluid train, therefore, trying to ensure the pore Pressure control incorporating to the fluid system, only an extensive volume of Spacer.

In this way a possible gas inflow is avoided that would lead to enormous economic losses, however in terms of a good removal, just having a spacer in the preflush system would only be Fulfilling a single function that is the drag of suspended solids. in the annular space without being able to disperse and reduce its solid structures.

Our methodology has been proven in fields with high GOR and good petrophysical and reservoir conditions, which intend to add a volume of washes to the preflush system, thus Hydrostatic Balance with a low Rheological Spacer volume behind the mud.

The preflush system is by batch and pumped at 4.0 bpm continuous, considering a volume of 20 barrel máximum to generate a contact time greater than five minutes, thus improving the conditions of removal, diluting, dispersing and moisturizing the wellbore and casing external.

It evaluates Primary cement Using bond logs that was run three days after the cementing operation. The logging results indicate an average amplitude of around 5 mV, so the 5 ½" in. Casing cement job had 90% average bond index. Good zonal isolation was achieved.

In addition, Mechanical factors such as reciprocating the casing once carried to Depth, and casing centralization with Standoff greater than 80%, guarantee zonal Isolation in the área of productive.

The addition of a Surfactant to the formulation of the washes favors the water wettability of the wellbore in fron of cement.

The use of surfactants in preflushes entrain invading gas downhole and créate a stable foam. This foam then presents significant resistance to flow, thereby limiting upward migration (Marrast et al, 1975).

With regard to the properties of grouts dominate the rheologic behavior, with filtrations less than 50 cc /30 min, and compressive strength greater than 1,100 psi
Foam Cement Proven as Effective Solution for Zonal Isolation in Difficult Wellbores: A Success Field Case in Colombian Mature Fields
Authors: Vela Jose , Arias Henry , Sanchez Edwin , Garzon Juan Ramon
Published: July 2020

The objective of this paper is to present the improvement in zonal isolation and cement sheath properties using foam cement in heavy oil Chichimene Field in Colombia.

Achieving complete zonal isolation in the pay zone have become a major challenge in these fields, recently, given the complexity of the reservoirs: high permeability, low pressure, highly fractured, depleted, low fracture gradient, and cement column for well integrity. Despite advances in drilling technologies, such as MPD, massive losses still represent a major risk both drilling and cementing. Using commonly known cementing methods, like stage tool cementing and conventional slurries, have led to fair results. Foam cement technology emerged as an appropriate cementing method given its great properties both being pumped down, and once set

Foam cement has several advantages over conventional methods: it prevents losses, enhances displacement efficiency in the annulus, provides a unique feature of density/strength ratio, and has improved resilience and elastic properties once set.

Production liners in Chichimene and Castilla field have been cemented successfully with foam cement, even under severe well conditions as partial to severe losses. Full returns have been observed in all jobs while cementing, and cement has been seen at surface after circulating fluids out of top of liner. Good isolation has been obtained as per cement log evaluation. Foam cement has proved to be effective cement method to achieve proper isolation in difficult wellbores and has been of great benefit for cementing production zones in the mentioned fields.

Novelty of the cementing process, described herein, delivers unique engineered features that have proven a major benefit to ensure well integrity in the fields. Cementing under critical wellbore conditions, still account for many costly remedial works, and this novel approach for cementing showed its benefits to achieve excellent results. Content of this paper could benefit many operators dealing with critical wellbores.
Application of the Fast Marching Method in Heterogeneous Dual Porosity Reservoirs
Authors: Nakajima Kenta , Datta-Gupta Akhil , King Michael J.
Published: July 2020

For unconventional reservoirs, the role of accurate reservoir characterization is becoming increasingly important for optimization of field development. The Fast Marching Method (FMM) has provided a novel approach for rapid flow simulation for unconventional fields, as it reduces the depletion in a 3D heterogeneous reservoir model to that of an equivalent 1D model. In this paper, a practical approach to handle highly heterogeneous matrix properties for dual porosity FMM simulation is established. Various averaging methods for the heterogeneous matrix properties are examined through integrated case studies.

Current implementation of FMM simulation can directly account for fracture heterogeneity but requires averaging of the matrix property variations. In this study, we examine the error in the fluid production rate between the 3D heterogeneous reservoir model and the equivalent 1D averaged reservoir model. For some amount of matrix heterogeneity given by the standard deviation of the natural logarithm of permeability, 100 different realizations are created with a commercial geostatistical simulator. This paper evaluates the averaging approach in terms of the mean error and the distribution of errors for each value of the standard deviation.

The error shows significant dependence on averaging methods especially for the reservoirs with high heterogeneity. Geometric based averaging shows the smallest error from the viewpoint of the mean error for high heterogeneity. Also, its distribution of the errors is narrowest, which indicates that the geometric based averaging method demonstrates the most stable performance. In contrast, the harmonic based averaging method represents the biggest error in terms of the mean value and has the least stable error from the viewpoint of its distribution.

The work establishes an approach to consider the matrix heterogeneity in unconventional reservoirs with FMM. Through the integrated case studies, the most appropriate method for the different heterogeneities is evaluated. This study makes a significant contribution on the development of Fast Marching based reservoir characterization for more robust application for unconventional reservoirs.
Field Results of a Real Time Drilling Fluid Monitoring System
Authors: Magalhães Sérgio , Calçada Luís Américo , Scheid Cláudia , Paraíso Eduardo , Moraes Gabrielle , Valim Elias , Almeida Heraldo , Waldmann Alex , Leibsohn André , Marques de Sá Carlos Henrique
Published: July 2020

An automated system was developed to determine some physical properties of the drilling fluid in real time during drilling operations. Rheology, density, electrical stability, total solids suspended and water in oil ratio were determined in real time during onshore drilling operation. This work presented the results obtained using the system, comparing it with data obtained by standard offline methods according to API. The first stage of the development was performed in laboratory where the monitoring container was connected to a fluid flow loop was built. Rheology was determined using an inline modified concentric cylinder viscometer. The device was capable of determining shear stress at different shear rates. Density was determined by a Coriolis device, electrical stability was calculated by a self-designed device built under API technical design, water in oil ratio was provided by electromagnetic means of a commercial device and total solids suspended was calculated using a developed material balance equation, which uses real time data of density and water in oil ratio as inputs. The entire system was assembled into a skid, fully automated and controlled by in house developed software, adequate to be transported and installed at rig sites. The second stage was to test the system in onshore rig sites in northeast of Brazil. With automatic control of flow rate and pressure, the system performed measurements in the rig site drilling fluid, pumping the fluid in and out of the system, operating as a bypass of the main pressurized drilling fluid flow line. The system reported data locally on a screen and transmitted to a remote operations center. Density, electrical conductivity, total solids suspended and water in oil ratio were provided at every second. Viscosity profile was provided every 30 min with calculation at 6 different shear rates, in accordance to API. Electrical stability tests were performed every 30 min with 1 min of duration. The developed system performed measurements properly in the onshore rig sites. All technical requirements for operational safety were met, as well as environmental and electrical hazard managed. Overall statistical deviations calculated between online and offline reference data reported were considered satisfactory. The system constitutes the most complete project for real time fluid monitoring properties in real time. Several fluid properties (electrical stability, water oil ratios) were measured online for the first time. These properties are a requirement for real time diagnosis software and an essential input for autonomous drilling projects.
Improving CSS Performance with Preformed Foam: Teca - Cocorna Field Case
Authors: Perez Romel , Rodriguez Hector , Barbosa Carolina , Manrique Eduardo , Garcia Luis , Rendon Gabriel
Published: July 2020

Cyclic Steam Stimulation (CSS), is the most applied thermal enhanced oil recovery (EOR) method worldwide. However, despite the vast experience gained over the last few decades CSS still has its challenges including but not limited to energy efficiency and operational costs. CSS has been evaluated for several years in Colombian heavy oil reservoirs. As CCS approaches its maturity, new alternatives and injection strategies are required to potentially extend the technical-economic limit of this recovery process.

This work is focused on the procedure implemented during the design, execution and monitoring of the hybrid technology of steam plus foam as a strategy to improve the performance of a mature CSS process. The strategy developed for experimental tests, numerical simulations and pilot test is described. The evaluation of well head configuration, injection facilities and schedules to assure a good quality and stability of the preformed foam is also discussed.

The CSS-foam injection pilot was performed in Teca - Cocorna field. The cumulative surfactant injection was between 3 to 5 tons distributed between two mature wells under CSS at a concentration of approximately 2500 ppm. The facilities used for the foam generation with nitrogen at surface conditions and well injectivity performance will be discussed.

Early incremental production due to foam injection has been positive. The first CSS-foam pilot tests allowed the assimilation of lessons learned to incorporate best practices for the continuous improvement in the operation of CSS processes. The performance of CSS-Foam will be updated based on the pilot results due to the level of uncertainties associated with the scaling of laboratory results. According to the performance of the pilot, Ecopetrol will continue evaluating this hybrid CSS technology to improve oil recovery and energy efficiency in fields with steam injection.
Downhole Steam Quality and Flow Rate Estimation in Selective Steam Well Injection Completions
Authors: Rodriguez-Prada Hector A , Delgado-Delgado Patricia
Published: July 2020

Objectives/Scope: To determine quality, mass and volumetric flows in each sands where steam has been injected using well completions with selectivity elements under critical regime. From pressuretemperature logs and ILT run in wells, were used to estimate density, volumetric and mass flow of steam, and heat injected at each distributor element which wells are completed.

Methods, Procedures, Process: When steam is injected into a well, the quality and mass flow at the well head is usually known. With the logs of pressure and temperature, together with the ILT and flow control devices in critical regime, it is possible to know the conditions of the steam (saturated, sub-saturated and over-saturated), and speed of flow, it is possible to determine in function of the completion of the well, diameter of tubing for injection and diameter of the throat, the following variables or properties, like volumetric flow, mass flow, quality and density of the steam, in each point or element for distribution of the well.

Results, Observations, Conclusions: The methodology developed has allowed to determine the steam mass flow and injected energy that flows in each distributing element and how much is injected in each selected sand, obtaining that the highest mass flows are obtained where the lower qualities of the steam exist and vice versa, as well as the total energy injected in each sand looks almost independent of the steam quality in a range of 15% to 90%. This is due to the behavior of the mass flow and the latent heat of vaporization and their relation to the quality of the steam in throat under critical regime. As the steam quality increases, the mass flow through the throat decreases, and by the contrary the latent heat of vaporization increases. So the combination of both generates a total heat injection is almost independent of the quality of the steam, and the total amount of heat injected being a direct function of the diameter of the throat and the number of devices used for steam distribution.

Novel/Additive Information: The novel combination of flow equations in pipes, critical flow in throat and flow through the spinner used in the ILT, allowed to estimate the mass flow and the energy injected into the reservoir with wells using selective completions in critical flow conditions. It was determined the existing differences in the conditions used during the design of the well completion and those existing during the steam injection. With this new methodology, the steam injector well completion is optimally designed, as well as obtaining the efficiency of the steam injection by sand, through a better estimation of the SOR and the oil incremental recovery during the continuous steam injection process.
A Systematic Volcanic Intrusive Characterization Model for Exploration and Production of Vaca Muerta Formation
Authors: Utge Silvana , D’Angiola Marta , Dominguez Fabián , García Daniel , Ruiz Ronyl , Rodríguez Jesús , Pérez Gustavo
Published: July 2020

This paper presents a new approach based on a systematic workflow that diminish the uncertainties regarding heterogeneities and other geological factors that dramatically impact the unconventional reservoir performance in Vaca Muerta. In addition to the natural heterogeneities caused by marine depositional sub-environments that formed rock configuration variability, both vertically and horizontally, some areas of Vaca Muerta are affected by subsequent volcanic activity that creates complex characteristics for drilling and completions.

A detailed geological, mineralogical and petrophysical characterization from the pilot well is performed to precisely determine landing points as well as the identification of traversed volcanic intrusive bodies. Pilot hole characterization added comprehensive knowledge to the horizontal drilling operations using Geosteering by decreasing geological uncertainty and allowing full control of drilling through the LWD azimuthal information in real time, and therefore making decisions to obtain optimal well placement. Critical information about elemental gamma ray spectroscopy (U / Th/ K, e.g.), that revealed specific reservoir characteristics of the depositional environment, supported the hypothesis of the heterogeneity of Vaca Muerta Formation and helped to identify the intrusive bodies.

The workflow is completed with a complete structural evaluation, identification of natural fractures and textures from electrical borehole images logged in Oil-based mud environment. This analysis defined precisely the intrusive (dikes and sills) configurations. Textural and mineralogical characteristics, as well as information about their location, spatial and relative geometric development are included in the evaluation. The analysis provided critical inputs for completion decisions as well. Operational and evaluation results are used as the platform for future developments of new exploratory non-conventional areas.
Building A Production Analysis Tool for Analog Field Analysis Brazil and Mexico
Authors: Pederson John M. , Eburi Simeon , Boyarko Devin C.
Published: July 2020

This paper showcases how public data was integrated using data visualization software to develop appropriate analog information for new prospects and field evaluations in Brazilian Campos and Santos and Mexican Gulf of Mexico deepwater plays. The data visualization software was selected for its ability to integrate geologic map files (.shp files) and digital production data. This work was extended to evaluate Mexican opportunities since similar production data is available from the government.

In the exploration workflow, analog field data is used to develop potential prospect estimated ultimate recovery ("EUR"), recovery factors, the appropriate EUR per well and initial production rates. This information is then used in a conceptual development plan that allows potential economic scenarios to be assessed. Both in Brazil and Mexico, substantial well data is available from the respective governments. The team successfully used this information to develop appropriate low, mid, and high oil production forecasts.
Machine Learning Models To Automatically Validate Petroleum Production Tests
Authors: Machado de Almeida Duque Maria Clara , Souza Chaves Gabriela , de Oliveira Monteiro Danielle , Velasco Medani Luciana , Martins Ferreira Filho Virgílio José
Published: July 2020

Well production in oil fields is a dynamic and complex activity. The patterns and characteristics inherent to the well, such as pressures and flow rates, are changing based on production time and the fluid composition – a complex multiphase mixture composed of oil, water, and gas. Thus, it is necessary to evaluate well behavior with periodic production tests. This paper proposes an automatic tool based on machine learning models to assist the production tests validation process in a quick manner. The developed methodology was applied to 13 representative wells of a Brazilian offshore oil field. For each examined well, a dataset is created with operation variables obtained from valid and invalid production tests. Six classification algorithms are analyzed, Logistic Regression, Naïve Bayes classifier, K-Nearest Neighbor, Decision Tree, Random Forest and Support Vector Machine (SVM) in reason to automatically label a new production test as valid or invalid, according to production historical data for the well. The dataset was divided into training and validation sets. The training set was used to perform feature selection, to calibrate and choose the proper model. The validation set was then used at the end of the procedure to evaluate obtained results, by comparing the model’s output with real test labels. From the results obtained in the case study, it was possible to identify that IGLR (Injection Gas/Liquid Ratio), oil flow rate and the pressure loss between wellhead and platform were representatives for most of the wells, which implies that these variables have a huge influence at the production well test validation. Furthermore, the validation set indicates that SVM and logistic regression were the models with the best performance. Besides that, accurate results were achieved, since the model correctly classified at least 5 of the 6 tests in 70% of wells analyzed, and for the remaining wells, 4 of 6 production tests.
Workflow for Optimization of Waterflood Performance: Field Example from El Furrial Field - East Venezuela Basin
Authors: Perez Amaro Iris , Chek-Yan Chelhod Nellys , Laprea-Bigott Marcelo
Published: July 2020

This paper presents a workflow for the analysis and diagnosis of the water injection project and the evaluation of chemicals treatments for water control using laboratory data and numerical modeling for field performance analysis, oil recovery and sweep efficiency optimization in the East Area of SJN FUL 2 reservoir / El Furrial field - Venezuela.

A description of applied chemical technologies and considerations for selecting well candidates to workover based on root-cause analysis of water production, along with reservoir modeling of feasible production scenarios and its effect on the hydrocarbon recovery, are shown on the second part of this study.

The optimization process on the production and injection profiles and the impact on the recovery of the remaining oil reserves using the proposed workflow are demonstrated with El Furrial field and SJN FUL 2 reservoir information. The results show that reservoir management is the main driver behind the well performance control in this high heterogeneity water flood system. The use of proper production surveillance management techniques, allows selecting technologies which will bring a project to success when heterogeneities play a fundamental role.
Corrosion-Fatigue Assessment of Martensitic Stainless Steel and High Strength Low Alloy Steel Sucker Rod Materials in Harsh Environments
Authors: Barreto Rodrigo , Martinez Oscar , Shakhmatov Aleksey , Stachowiak John , Howie William , Badrak Robert
Published: July 2020

The cyclic nature of the operations with sucker rods makes the fatigue life one of the most desired characteristics for these products. Production in aggressive service environments with higher acid gas concentrations associated with increased levels of hydrogen sulfide (H2S) and carbon dioxide (CO2) requires good fatigue life with the potential for corrosion. This combination makes corrosion-fatigue the primary mechanism responsible for sucker rod failures in reciprocating artificial lift applications.

High Strength Low Alloy (HSLA) steels have been widely used in decades to provide fatigue resistance, however the corrosion resistance of such steels is of concern. High-chromium steels have recently been utilized to improve performance, but their corrosion resistance is limited along with their fatigue performance.

The development of a new martensitic stainless-steel grade aims to improve corrosion resistance, extend fatigue life of sucker rods and reduce overall operating costs. The combination of selected chemistry with well-defined process variables and heat treatment parameters is key to provide a product with optimum properties that includes fatigue life with needed mechanical properties, toughness and grain structure.

This paper presents the results of different high strength low alloy steels compared to a targeted stainless steel in corrosive environments.
A Sustainable Future Under Energy Intensity Scenarios-Peru's Compliance with COP24 in an Energy Trilemma Environment
Authors: Cervantes Bravo Reynaldo José , Jimenez Nieves Edgar , Valqui Ordoñez Brayam , Canto Espinoza Daniel , Hinostroza Cairo Anderson
Published: July 2020

The most important transition of the energy matrix in Peru was characterized by an economic bonanza between the years 2009 - 2011 and, whose energy intensity (I.E) was reflected by the accelerated growth of the GDP; which, caused an exponential increase in the energy demand of Peru and, whose multiplying effect was produced by the energy exchange of the predominance of Hydroelectric Energy towards the development of Natural Gas with the Camisea Gas Megaproject, however, it was not considered the impact of other factors.

In this sense, the present study requires contextualizing the Energy Trilemma: 1) the country's energy security; through an energy efficiency policy in response to meeting demand in line with GDP growth, 2) energy equity, for the access of quality energy and accessible prices to more vulnerable populations with a diversified energy matrix; 3) environmental sustainability, to describe the Environmental Commitments of Peru with the COP24.

The methodology is based on a macroeconomic-energetic model, whose architecture begins with historical information between the years 1970-2016 with respect to GDP vs. primary energy consumption; to then calculate the annual energy intensity of Peru and its CO2 emission according to the polluting factor of each primary matter. Followed, using projections of the GDP from 2017 to the year 2035 (3.8% per year - Conservative case with information from the World Bank) and 3 scenarios of decrease in energy intensity of 1%, 1.5% and 2% per year, may increase energy efficiency and reduce the emission of CO2 in the proportion of 10.4%, 15.2% and 19.6% respectively between 2017-2035.

As a result, the total energy consumption will be estimated up to the year 2035 in Millions of TOE, according to each scenario of variation in energy intensity (ΔI. E). and with the forecasts in the distribution of the energy matrix of the years 2025 and 2035 through the BAU methodology, its forecasts of each primary material will be known (Natural Gas, Oil, Coal, Hydroelectric, Renewable Energy, others) until the year 2035 This will allow us to know the forecast of CO2 emissions based on each pollution factor of the primary sources and energy intensity levels predicted with respect to the base case (Δ IE = 0).

Finally, Peru's commitment to COP24 will be evaluated based on the per capita correlation of the country / world population in the estimation of the cumulative maximum emission limit of 2.13 GtCO2 between 2017-2035 for Peru, if the temperature is not increased more than 2 ° C for the year 2100 and guarantee the demand of Peru under an optimized Energy Trilemma.
Using Machine Learning for Building Multivariate IPR Models From High Frequency Streaming Data
Authors: del Pino Fiorillo Mario Antonio
Published: July 2020

Over the last years, we have seen how the volume of data being generated at the field has grown exponentially. Dealing with this amount of information has become increasingly challenging, as conventional computational tools are not suited for dealing with such high-frequency data. This is more noticeable on modern assets where SCADA systems are the norm and several gigabytes, or even terabytes, of data are generated each year. On this work, we explore an innovative way to address this issues when trying to build productivity models for an asset. We compare this with conventional workflows and explore the benefits from it.

The objective of this work was to develop an algorithm capable of building IPR-like models with high-frequency data generated from producing wells. The code handles data retrieval, filtering, model fitting and results presentation. It accounts for depletion driven changes and is able to accurately predict short and medium term evolutions in productivity. This would allow integrating the developed code with a global optimization model intended to be developed. The Multivariable approach allows including effects of other variables if necessary, such as ambient conditions, depletion rates, sensors re-calibration, among others.

This technique was tested on a gas condensate field constrained to a daily nominal rate of around 200MMscfd of dry gas. The market constraint forces the operations team to carefully manage producing wells to maximize cash flow. Production strategy focusses mostly on condensate maximization, prioritizing wells with the highest liquid yield. This usually results in having three wells on stream of all six available. Because of this, those wells with low liquid yield have limited production data. It is on these wells were conventional IPR regression workflows suffer from representativeness issues. This would result in being unable to properly run a global optimization model taking into account all available wells.

Machine learning techniques were used to create multiple models. Metrics were computed to quantify model accuracy and select the best fit model. The resulting code successfully built IPR curves with great prediction capabilities. This was validated by creating different models for each month from March 2018 to July 2019 using data corresponding to their previous months.

This approach gives a tool to automate the creation of mathematical models for data-rich assets. It shows how data analytics techniques allow building versatile programs that can be rapidly deployed in the field. There are numerous potential applications; real-time production strategy updates, integrated interpretation of asset development, better design and scheduling of surface facilities, among many others.
Improving Oil Recovery in the Mature La Cira Infantas Oilfield Using Multiphase Flow Simulation
Authors: Yao Calvin C. , Blanco William F. , Alvarez Argenis J.
Published: July 2020

La Cira Infantas (LCI) is the oldest oilfield in Colombia, with 100 years of oil production history spanning three periods: primary depletion, the first waterflood (WF) period, and the second WF period. After the first WF period, the field had neared its economic limit and an abandonment program was underway from 2003 to 2005.

Partners Ecopetrol and Occidental made the decision to implement a waterflood redevelopment project in 2005 that included reconfiguration of the old WF areas and WF expansion into new areas. The partners formed integrated reservoir development and management teams (RDT and RMT) that have combined workovers, infill drilling, WF optimization, and other IOR/EOR methods. The oil production has increased from approximately 5,000 to over 43,000 bopd, which is above the predicted 40,000 bopd.

One of the key components was WF conformance controls to improve sweep efficiency and to improve injection profiles across multiple stacked-sand layers. The selective injection method was implemented using multiple packers and side-pocket mandrels/valves. The design of selective injection strings involved complex engineering calculations and left some room for improvement.

This paper describes a new workflow used to optimize the selective injection design using multiphase flow simulation based on actual WF patterns. A field pilot test used an inverted 5-spot WF pattern to demonstrate this new workflow. The simulation results predicted a 45% incremental oil production above the base case. The simulation optimization process reduced the number of mandrels/valves from nine to six, which saves about 30% of the associated completion costs compared with the initial completion proposal for this case study.
Risk Mitigation in Overpressured Wells Through Geomechanical Approach
Authors: Carvajal Olga , Sierra Camilo
Published: July 2020

The geological evolution of the northern region of Colombia has resulted in lateral/oblique compressional stresses leading to the development of tilted faulted blocks and associated subsidence, followed by intense folding/uplift that has impacted the stress regime and the pore pressure evolution. Previous pore pressure prediction approaches often considered a shallow overpressure associated with a high fracture gradient (FG), and thereby allowing an assumption for a wide operational mud window. Drilling experiences however, indicated a contrasting scenario and thereby a better understanding and a more accurate estimation of overpressure and FG became necessary.

With the aim of optimizing drilling operations, a geomechanics analysis was conducted, based on existing information incorporating local geological inputs and production well data, in order to better predict wellbore stability, pore pressure, fracture gradient and to identify related drilling risks for the planned wells.

The resultant geomechanical model confirmed the presence of shallow overpressure development, the occurrence of which, along with its distribution and magnitude, is mainly controlled by the geological events (especially uplifting) that shaped the basin. Subsequent updates of the model managed to explain the frequent occurrences of water inflows, gas kicks, high volume of losses (a gain-loss situation) and instability recorded in previous wells. It also predicted a feasible but conservative mud weight window for the wells in this field. Understanding the geological evolution allowed for a better comprehension of the stress regime changes over time. Through an enhanced understanding of the geological and geomechanical influences, a risk mitigation strategy was developed to proactively reduce pore pressure and wellbore instability related drilling effects encountered in the earlier wells.

So far, well schematics and mud weight windows have been optimized in five wells through utilizing this geomechanics approach to deal with the challenges imposed by a narrow mud window. The planned wells have been successfully drilled in record time with no major drilling problems by using the recommended mud pressures and optimized drilling practices.
RTA Assisted History Matching with a Combined Hydraulic Fracturing and Reservoir Simulator
Authors: Fowler Garrett , McClure Mark , Allen Jeff
Published: July 2020

History matching is a critical part of the simulation workflow. History matching in shale is unique because it involves data from both hydraulic fracturing and from production. This paper presents a step by step workflow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. We perform sensitivity analysis simulations using a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop ‘motifs’ that inform the history matching process. Using intuition from these simulations, we show how to expedite history matching by changing matrix permeability, fracture conductivity, matrix pressure dependent permeability, boundary effects, and relative permeability. Finally, a worked example, using two Eagle Ford hydraulically fractured wells, is presented to demonstrate the workflow.