bluuebunny/crossref_metadata_2025_split huggingface dataset:
An All-Inclusive Laboratory Workflow for the Development of Surfactant/Polymer Formulations for EOR in Harsh Carbonates
Authors: Dokhon Waleed , AlSofi Abdulkarim , Miralles Vincent , Rousseau David 
Published: September 2021

Abstract
Carbonate reservoirs are challenging for chemical EOR, particularly in selecting fine-tuned chemical formulations which combine high performance, stable behavior, and trouble-free operations. The design of suitable formulations requires substantial laboratory work and a solid methodology. In this paper, a systematic all-inclusive laboratory workflow to design a surfactant-polymer (SP) formulation for a carbonate reservoir is presented.
In this work, a complete process for development and evaluation of an SP formulation for high-salinity high-temperature conditions is proposed and adopted. For which, a high throughput robotic platform is used for efficient and robust formulation design. The process is illustrated on an actual case with harsh reservoir conditions (i.e. a high temperature of 100℃ and high connate salinity of 213,000 mg/L). The SP design methodology consisted of five steps: surfactant design, polymer selection, surfactant/polymer verification, topside assessment, and oil-displacement evaluation. The surfactant formulation design consisted of four substeps: solubility scans, phase-behavior scans (salinity scans), IFT measurements, and static adsorption tests. The sourced polymers were screened based on three key performance indicators: viscosity, filter ratio, and thermal stability. The selected surfactant formulations and polymers were then assessed as sloppy slugs in terms of compatibility and injectivity. Then, the unique topside assessment was conducted where it consisted of two components focusing on: separation kinetics and separated water quality. Finally, an oil displacement study was performed using a preserved composite plug, in which the SP formulation developed through the outlined process was used.
The results demonstrate the potential of a mixture of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES). The results also illustrate couple of polymers with stabilities suitable for high temperature conditions: an associative polymer, and an AM/AMPS copolymer. In addition, injectivity corefloods supported the SP slug transportability across the porous media. Corefloods also demonstrated the SP slug capacity to recover around 62% ROIC (remaining oil in core). Finally, SP in produced brines improved the separation kinetics but lead to a slight deterioration in separated water quality.
A key novelty of the adopted workflow is the integration of topside assessment. In addition, the experimental steps were clearly delineated including the preparation of representative oils. Beside a clear layout of the methodology, the work demonstrates that a surfactant-polymer formulation can successfully be designed for high temperature carbonate reservoirs and provide encouraging guidelines with respect to SP impact on topside facilities.
Assessment of Chemical Injection to Mitigate Wax Deposition in Unconventional Wells
Authors: M. D. Rosa Rafael , B. Soprana Arthur , Girardi Vinicius , M. Villagra Fernando 
Published: September 2021

Abstract
This work presents a numerical assessment of chemical inhibitor injection to mitigate wax deposition in unconventional wells. The goal of this study is to simulate the deposition of wax under several operational conditions and later optimize the chemical inhibitor injection position, using two different types of numerical simulations. A transient one-dimensional multiphase flow simulator - ALFAsim, with a dedicated wax model, was used to predict flow conditions such pressure, temperature, holdup and flow pattern profiles, as well the position and rates that wax accumulates. The results from the 1D simulation were then used as boundary conditions in a 3D CFD simulator, which aimed to assess how long it would take to a satisfactory homogenization of the inhibitor with the flow and what would be the minimum depth for the injector should be installed.
In this work, a 1D multiphase flow simulator with wax deposition model was used to identify on which operational conditions (flow rates and environmental temperatures) an unconventional well would start to present wax deposition on its tubing walls. After defining the susceptible region where the paraffin could deposit, it was important to verify if the inhibitor would be well homogenized with the stream when reaching this region. For that, a 3D CFD simulation was performed, using information obtained directly from the 1D simulator as boundary conditions. The CFD model was capable to show the mixing evolution of the inhibitor with the stream and it was possible to determine the minimum distance where the injector should be placed to guarantee such homogeneity. A real well was selected to provide comparisons between field observations and simulated data, in order to validate the model assumptions and accuracy.
Innovative Washpipe Free Circulating ICD Delivers Reduced Well Construction Costs
Authors: Wang Zhihua , Newton Daniel , Qureshi Aqib , Uchiyama Yoshito , Corona Georgina , Ashraf Hamza 
Published: September 2021

Abstract
This Extended Reach Drilling (ERD) field re-development of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals to reach the defined reservoir targets. However, certain areas of the field show permeability and / or pressure variations along the horizontal laterals. This heterogeneity requires an inflow control device (ICD) lower completion liner to deliver the required well performance that will adequately produce and sweep the reservoir. The ICD lower completion along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine.
To reduce the amount of rig time spent on the displacement portion of the completion phase, an innovative technology was developed to enable the ICDs to be run in hole in a closed position and enable circulating through the end of the liner. The technology uses a dissolvable material, which is installed in the ICD to temporarily plug it. The dissolvable material is inert to the RDF NAF while the ICDs are run into hole, and then dissolves in brine after the well is displaced from RDF NAF to completion brine, changing the ICDs from closed to an open position. The ability to circulate through the end of the liner, with the support of the plugged ICDs, when the lower completion is deployed and at total depth (TD), enables switching the well from RDF NAF drilling fluid to an aqueous completion brine without the associated rig time of the original displacement method. The technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving 4-5 days per well. An added bonus is that the unique design allowed for this feature to be retrofitted to existing standard ICDs providing improved inventory control.
In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification testing, field installations, and lessons learned that were required to take this solution from concept to successful performance improvement initiative.
Automated Well Production and Gas Lift System Diagnostics and Optimization Using Augmented AI Approach in a Complex Offshore Field
Authors: Elwan Mahmoud , Davani Ehsan , Ghedan Shawket G. , Mousa Hesham , Kansao Rami , Surendra Meher , Deng Lichi , Korish Mahmoud , Shahin Eman , Ibrahim Mohamed , Eid Tarek , Rouis Lamia 
Published: September 2021

Abstract
This paper presents the comprehensive analysis and optimization study of the gas lift system of 44 gas lifted wells in QQ Field in the Gulf of Suez. With the least amount of intervention, the optimized operational plan would yield an additional 7 to 10% oil gain over the current production rate, an improvement of gas utilization and operational efficiency, and operating cost reduction. This paper presents an Augmented AI approach, which is an efficient, repeatable and automated workflow to diagnose and optimize gas lift operations, reducing the time required for this process from weeks to hours. This study evaluates historical performance, identification of suboptimal performers using heuristic diagnostics, and subsequent optimization using well models coupled with advanced optimization algorithms.
The presented workflow implements a top-down approach beginning with field-level based analytics, then further delves into detailed engineering aspects of well production and individual gas lift operations. It builds from artificial intelligence and engineering-based workflows that compute smart metrics based on the historical well production and performance of gas lift systems. Heuristics and expert-based rules are also considered to perform a fast and smart diagnostics process. These analytics and diagnostics stages help build key metrics to evaluate well performance and monitor gas lift operations from both executive and asset management levels.
The study results identified suboptimal wells with inefficient gas lift performance that require detailed evaluation for improvement from both design and operational perspectives. During the optimization phase, reliable well model-based analysis coupled with physical constraints are used to provide remedial actions for the identified wells. The workflow allows automated well model construction and calibration, coupled with an unsupervised learning algorithm to detect and eliminate unreliable datasets. Afterward, specific well-level analysis is performed including gas lift performance curve while honoring existing well configuration, hypervolume-based multi-objective optimization and sensitivity analysis on key parameters for best gas lift performance.
Effects of Surfactant Partition Coefficient and Interfacial Tension on Oil Displacement in Low-Tension Polymer Flooding
Authors: Liu Mingyan , Baek Kwang Hoon , Argüelles-Vivas Fransisco J. , Abeykoon Gayan A. , Okuno Ryosuke 
Published: September 2021

Abstract
Complex surfactant formulations have been applied to induce ultra-low interfacial tension (IFT) (e.g., 10−3 mN/m) between the displacing water phase and the displaced oil phase in chemical enhanced oil recovery (CEOR), where the residual oil after waterflooding can be largely recovered as an oil bank. This paper is concerned with a simpler, lower-cost CEOR, in which a sole additive of surface active solvent (SAS) makes low-tension displacement fronts in polymer flooding (e.g., 10−2 mN/m) without involving ultra-low IFT microemulsion phase behavior. The envisioned application of SAS in this research is to displace a continuous oil phase with low-IFT displacement fronts with mobility control by polymer.
Previous research found that 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO, or "7-15") as SAS was able to reduce the IFT between polymer solution and the reservoir oil from 15.8 mN/m to 0.025 mN/m. In this research, the effect of SAS partition coefficient on the low-tension polymer (LTP) flooding was studied as an additional factor for SAS optimization. In particular, the comparison between two SAS species, 2-EH-4PO-15EO (4-15) and 2-EH-7PO-25EO (7-25), was important, because they had similar IFT values, but markedly different partition coefficients. The IFT was 0.20 mN/m with 4-15 and 0.18 mN/m with 7-25; and the partition coefficients were 1.61 with 4-15 and 0.68 with 7-25 at the experimental temperature, 61°C.
These two SAS species were compared in the secondary-mode LTP flooding with a slug of 0.5 wt% SAS for 0.5 pore-volumes injected (PVI). Although these two SAS species gave comparable IFT values, their oil-displacement characteristics were quite different. The oil recovery factor at 1.0 PVI was 65% with 4-15 and 67% with 7-25. At 5.0 PVI, it was 74% with 4-15 and 84% with 7-25. The SAS recovery at the effluent was 67% for the 4-15 SAS and 86% for the 7-25 SAS. With a similar IFT reduction, the SAS with a smaller partition coefficient (i.e., 7-25) resulted in less SAS retention and more oil production for a given amount of injection.
In comparison to the previous research with 7-15, the oil recovery factor with 7-25 was smaller at 5.0 PVI, but similar at early times up to 1.5 PVI. When the SAS concentration was reduced to 0.1 wt% SAS for 0.5 PVI, the oil recovery factors with 7-25 and 7-15 were close to each other at both early and final stages. In these smaller slug sizes, the SAS recovery was detected only for the 7-25 case, which means 7-25 went through the sandpack whereas 7-15 did not. That is, the optimization of SAS likely requires taking a balance between lowering the partition coefficient and lowering the IFT.
First Ever Offshore Deployment of an Inflatable Packer Anchoring System for Rigless Installation of an Insertable Progressive Cavity Pump: A Case Study
Authors: Osorio Alejandro , Ford Francis 
Published: September 2021

Abstract
An offshore well located in Indonesia required rigless installation of an insertable progressive cavity pump (I-PCP) as a cost-effective solution to restore production while eliminating the need to retrieve the upper completion for extensive maintenance. The well had been previously completed with a conventional progressive cavity pump (PCP) as an integral part of the completion and was placed offline for approximately one year due to mechanical failure of downhole components. Typical I-PCP anchoring methods were not feasible alternatives for this application. A pump-seating nipple (PSN) insertable seal stack could not be used due to the lack of a PSN at the required I-PCP setting depth, and a mechanical J-slot anchoring device could not be deployed because rod conveyance from an offshore barge is subject to constant heave, which results in fluctuating axial loads and rod position, which would pose the risk of prematurely activating a mechanical J-slot anchor during deployment.
An inflatable packer anchoring system was selected as a solution to the operational challenges encountered in this application. The system comprises inflatable packer technology, a hydraulically-actuated anchoring slip mechanism, seal cups, and a shearable intake sub. Conveyed on sucker rods, the system provides the required pressure competence to confirm tubing integrity and enable a complete hydraulic setting sequence.
The first ever offshore installation of this system proved its optimal functionality by successfully anchoring an I-PCP inside 3-1/2" production tubing riglessly from an offshore barge. The system was set by applying pressure via the tubing-rod annulus, and the well was immediately placed into production. After being shut-in for more than one year, this unique solution provided the well operator with a safe and low-cost alternative to reestablish production while eliminating the need for a workover rig.
The objective of this paper is to provide a case study analysis of the first offshore deployment of this technology, discuss its potential for optimizing PCP/I-PCP completion designs, and explain the economic and operational benefits of associated rigless well intervention operations in comparison to current alternative methods.
Social Risk Management as a Response to Increasing International Pressure for Social Performance
Authors: Borbor J. D. , Van Cranenburgh Katinka C. , Luca Christiaan W. F. 
Published: September 2021

Abstract
In the past decades, financial institutions have led the way for companies to adhere to international standards for social performance. The journey began in the Industrial Revolution, when negative societal business impacts rapidly escalated, which led people to demand for their management. Initially focused on working conditions, impacts on the environment soon started to gain notice. Halfway through the 20th century, a combination of oil spills and mass media attention generated enough public pressure for the United States to sign the first piece of legislation requiring the environmental impact assessment. With this law and its replication abroad, however, came the concern with social impacts as well. Both environmental and social performance expectations soon spread internationally and, by the 1980s, multilateral financial institutions, most prominently the World Bank, incorporated such considerations into their investment and lending practices, which is the source of all such international standards today. These standards require the establishment of a social management system to integrate risk and impact management processes and stakeholder engagement activities. Given the challenge of implementing these requirements, a social risk management development framework is proposed to bring together the extensive and multidisciplinary demands of effective social performance. Five development areas are proposed: governance, social policy, tools, resourcing and capacity, and knowledge sharing. This is an important step to take today as it is expected that the next decades will see these international demands increase, possibly by ever increasing governmental regulation.
Well Cleanup Utilizing Smart Well Completion and Zero Flaring Technology
Authors: Alkhalifah Mohammed , Younes Rabih 
Published: September 2021

Abstract
In an oil field, openhole multilateral maximum reservoir contact (MRC) wells are drilled. These wells are typically equipped with smart well completion technologies consisting of inflow control valves and permanent downhole monitoring systems. Conventional flowback techniques consisted of flowing back the well to atmosphere while burning the hydrocarbon and drilling fluids brought to surface. In an age of economic, environmental and safety consciousness, all practices in the petroleum industry are being examined closely. As such, the conventional method of flowing back wells is frowned upon from all aspects. This gives rise to the challenge of flowing back wells in an economic manner without compromising safety and the environment; all the while ensuring excellent well deliverability.
By utilizing subsurface smart well completion inflow control valves, individual laterals are flowed to a separator system whereby solid drill cuttings are captured and discharged using a solids management system. Hydrocarbons are separated using a separation vessel and measured before being sent to the production line toward the field separation facility. Permanent downhole monitoring systems are used to monitor pressure drawdown and subsequently control the rate of flow to surface to ensure reservoir integrity. Following the completion of the solids and drilling fluid flowback from the wellbore, comprehensive multi-rate measurements at different choke settings are obtained to quantify the well performance.
This paper looks at the economic and environmental improvements of the adopted zero flaring cleanup technology and smart well completions flowback techniques in comparison to conventional flowback methods. This ensures that oil is being recovered during well flowback and lateral contribution to overall flow in multilateral wells. In addition, it highlights the lessons learned and key best practices implemented during the cleanup operation to complete the job in a safe and efficient manner.
This technique tends to set a roadmap for a better well flowback that fulfills economic constrains and protects the environment.
Application of Digital Well Construction Planning Tool During Well Conceptualization Phase
Authors: Hugo Costeno , Rajeswary Kandasamy , Jose Telles , Jacob Camacho , Diego Medina , Freddy Gori , Hector Garcia , Omar Vilchez 
Published: September 2021

Abstract
Digital well construction tools are becoming more widely considered today for well design planning, enabling automated engineering and simultaneous team collaboration under a single solution. This paper shows the results of using a digital well construction planning solution during a project’s conceptual planning stage. This method shortens the time needed to estimate the well times and risk profile for a drilling campaign by applying smart engines to quickly and accurately perform critical offset analysis for defined well types that is required for project sanction.
With this solution, the Offset Well Analysis (OWA) process is done automatically based on the location of the planned well, trajectory and well architecture. Various information and reports (both subsurface and surface data) from neighboring wells is stored in cloud solutions, enabling ease of access and data reliability for both large or smaller scale data storage. The software selects the most relevant offset wells, displays the risk analysis and generates the stick chart. For a conceptual design, the risk levels can be manually set higher due to potential unknowns in surface and subsurface risks which can later be refined. Quick validation of the well design allows the engineer to design a conceptual drilling campaign quickly and more efficiently.
The solution minimizes the time to perform probabilistic time and risk estimations. It reduces the risk of biased decision making due to manual input and design. This allows for better-informed decisions on project feasibility, alignment of stakeholders, increased design reliability as well as reducing the amount of time and resources invested in OWA.
The work presented here is aimed at sharing the experience of applying a digital well construction planning solution specifically on the conceptual project stage and discuss the value it adds to the well design process.