bluuebunny/crossref_metadata_2025 huggingface dataset:
Mitigating Scale Deposition by Optimization of Completion Valves Geometry
Authors: Machado Patrick , Carneiro Giovanna , Leibsohn Andre , Bouamra Reda , Handerson Thiago , Franquiz Gabriela
Published: September 2021

The harsh conditions presented in Brazilian presalt, summed up with the complexity of its reservoir, generate a series of challenges to improve reservoir recovery. Routinely, we have used intelligent completion systems to address the major part of the challenges; however, with the new production rates new problems have arrived and the usual ones have turned more aggressive, generating risks even to the intelligent completion systems.

Inorganic scale is a critical challenge in presalt reservoirs production. Future plans for presalt production include more robust flow conditions and the use of an all-electrical completion system. Higher flow rates are likely to increase the risk of scale deposition and an optimum design is required.

To address the new challenges arising from the new perspective of exploration in the presalt fields, we developed the presented workflow to mitigate the scale deposition on completion valves. The method enables the optimization of choke geometry to reduce scale deposition on inflow control valves. The proposed workflow generates a criticalness parameter for geometry classification according to a scenario of mechanical failure (due to sleeve incapacity to move) or deviation of production design point. A computational fluid dynamics (CFD) simulation was developed and benchmarked by experimental data, thus CFD results for different scenarios and various choke geometries were used to build a risk analysis matrix, which allows the definition of the optimal choke design to mitigate scale on ICVs. The extracted criticalness parameter may be used as an evaluator to estimate the time to valve stuck due to scale deposition in a commercial 1D transient flow simulator, optimizing then valve cycling time.
Underbalanced Perforating with 800-ft Guns Completed in Single Trip with Fiber-Optic-Enabled Coiled Tubing: A Case Study from Jambaran Field, East Java, Indonesia
Authors: Maulana Ibnu , Purwanto Bambang , Makriva Doni Arief , Sugiarto Genie Ageng , Kuswardani Diah Setianti , Nuryadin Shakti , Jenie John Rizal , Arthur Parapat
Published: September 2021

Coiled tubing (CT) equipped with fiber optics and real-time downhole telemetry and a fit-for-purpose CT tower were used in underbalanced perforating operations in six wells in Indonesia; each operation involved 800 ft of perforating guns, and each was completed in a single trip. The reservoir is thick, with high permeability and characterized by high content of CO2 and H2S. The underbalanced perforating technique was deemed fundamental to minimize formation damage in the near-wellbore area, and the campaign was part of a national strategic project to develop a block's main reserve to supply gas to drive the national economy.

Each well had to be completed with minimum of an 800-ft perforation interval to deliver an average of 60 MMscf/D gas production for 16 years plateau with up to 34% CO2 content and 10,000-ppm H2S. The traditional method of e-line overbalanced perforating in such harsh environment became inefficient because of the number of runs required, which can be as high as 40 runs per well. CT-conveyed perforating guns and a completion insertion retrieval of equipment under pressure (CIRP) system were chosen to execute the task. The fiber-optic CT real-time telemetry system was selected to improve downhole depth accuracy, confirm the underbalance condition, and provide real-time confirmation when the 800 ft of guns detonated downhole. To execute the six-well campaign safely, a customized 100-ft CT tower was brought into the country.

Because this was the first in-country application for fiber-optic-enabled CT in single-trip with an 800-ft underbalanced perforation interval, thorough planning and preparation were critical for a successful campaign. Considering the high gas rate, high CO2, and H2S content, a downhole lubricator valve was added as additional barrier during undeployment, and an H2S and CO2 inhibitor was used to protect CT string integrity. Another risk mitigation plan was to utilize real-time CT inspection to monitor the CT integrity and condition throughout the job. Slickline deployment was used in first two wells to deploy multiple guns into the well, but this was deemed inefficient. The CT deployment method was used to complete the campaign. The project comprised a total of 2,200 operating hours, 29 CT runs, and 4,969 ft of guns in six trips with 917 ft as the longest interval. All six wells were completed with no HSE events, no automotive incidents, 98% operational efficiency, and 21% faster than planned duration.

This successful six-well campaign represents a first in-country application, which contributed to developing this main gas reserve. The campaign provides lessons for job planning and preparation, technology implementation, execution, and continuous improvement, which can be implemented in similar projects in Indonesia and around the region.
Mathematical Model for Rate Transient Analysis with Additional Interface Skin for Fractured Horizontal Well With Weak Fluid Supply
Authors: Zhang Jiali , Liao Xinwei , Cao Nai
Published: September 2021

This paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt "overlap". The results of the sensitivity study show that the abrupt "overlap" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.
Offshore Water Treatment KPIs Using Machine Learning Techniques
Authors: Flores Lauren , Morles Martin , Chen Cheng
Published: September 2021

New water treatment facilities in the Gulf of Mexico include a seawater Sulfate Removal Unit (SRU) to mitigate reservoir souring and scaling. The general industry sulfate target for offshore SRU is usually 20 mg/L or even 40 mg/L; however, some facilities may require <10 mg/L of sulfate in injection water, which makes water quality monitoring more critical and challenging. Current industrial practice relies on only pressure drop and a constant cleaning interval frequency to perform SRU maintenance which may result in reduced membrane life due to frequency cleaning or severe membrane fouling without the capability to predict fouling based on process conditions. The machine learning techniques applied will fill the gap and deliver a prediction model based on both simulation and real-time field data. This model will track and monitor the system key performance indicators (KPIs) including pressure, membrane fouling factor (FF), permeate sulfate concentration etc. The monitoring and prediction of these KPIs provide estimates on when the next maintenance procedure is required, track membrane system status for troubleshooting and actions, and optimize membrane performance by tuning operation conditions.
The Fall and Rise of Oilfield Ethics
Authors: Dahroug Ahmed , O’Connell Kevin
Published: September 2021

The oilfield is in many ways the backbone of the world economy. Historically economic recessions and booms were linked directly or indirectly to the oil price, itself governed by supply and demand. Since the start of this industry, it has experienced multiple scandals and major accidents that have affected its path to date.

In 2001 the Enron scandal of poor accounting practices shook the entire stock market, and it contributed to the complete recession in the same year. Not too long after, a supermajor revealed in 2004 a reserves accounting error that surprised the world. In 2010 the Deepwater Horizon blow out known as the "Macondo Incident" caused serious damage to the environment and significant fines to be paid in compensation due to poor engineering practice.

Incidents like these arise concurrent with times of high demand and are instructive as we study their causes and effects on the oil industry and therefore the global economy.

Areas of study for this paper include reserves/production estimation as well as ethical considerations for the oil industry at large.

Our study is based on the review of uncertainty in both the subsurface and surface parts of oil and gas production. We refer to the previous classifications of uncertainty for the subsurface part and focus on the uncertainty currently existing within the surface production system. Current surface production monitoring methods are discussed. We propose a more automated process to reduce the current uncertainty about hydrocarbon production. Artificial intelligence applicability in the surface production system is investigated.

Additionally, in this paper we review the previously mentioned poor practices and accidents briefly and use them to guide our suggestions about preventive actions to avoid future wrongdoing and incidents. We attempt to provide an objective for oilfield ethics and advocate for a unified oilfield industry code of ethics. However due to the large diversity that exists in the wide range of oilfield disciplines, a single code of ethics may not be applicable. Accordingly, we propose a guideline that may be used by different parts of the oilfield industry to develop an application-specific code of ethics. It is hoped that this guideline will guard against the gaps that may foster errors that affect the oilfield industry and global markets.
Stranger Things 3: Not All Temperature Simulators are Created Equal
Authors: Shine Joe , Heinold Thomas , Lawrence Don
Published: September 2021

The risk of improper temperature selection for the design and testing of cement slurries can be detrimental to well construction operations and could affect a well's integrity. The methods for temperature selection in API 10B-2 do not consistently reflect the representative bottomhole conditions for high temperature applications. More so, consider 10B-2 guidance valuable for proving benchmarks in the high temperature domain. Therefore, numerical temperature simulators help manage the risk by predicting the anticipated bottomhole cementing temperatures. Currently several temperature simulators are in use to predict, with better accuracy, cementing bottomhole temperatures. The manuscript investigates the strange differences in predictions between the simulators for a range of high temperature applications. The results of the work efforts should help end users understand the outputs allowing better judgement when selecting representative bottomhole cementing temperatures for a given application.
Improving Flow Assurance for a Waxy West African Crude Oil via Collaborative Development and Implementation of a Novel Pour Point Depressant Solution
Authors: Meister Claudia , Xu Liang , Muhammad Moin
Published: September 2021

An improved flow assurance solution based on a new additive with robust performance, low treat rate and versatile handling properties was developed successfully. It was applied in a waxy crude oil from West Africa with high pour point and a wax content of about 24%. Crucial for the project success was a close collaboration among all involved stakeholders from operator, service company and chemical supplier.

In the initial lab screening by the chemical supplier, tests focused on pour point, viscosity and yield stress. This approach allowed to identify the most efficient type of additive chemistry for the specific crude oil and to meet target performance requirements.

Crude oil viscosity and yield stress under pipeline operation conditions could be reduced by more than 95% while reducing the required amount of additive by more than 75% compared to the incumbent solution. This resulted in significant cost savings for the operator and in a reduction of the Health, Safety and Environmental (HSE) exposure.
Mechanical and Geometrical Tortuosities: Vanishing and Appearing Tortuosities
Authors: Samuel Robello , Lightfoot Jonathan Dale , Turner William
Published: September 2021

Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs, and extended reach wells. This paper discusses the pitfalls of estimating tortuosity to quantify borehole quality and answers questions, such as whether the claimed benefits (i.e., enhanced drilling performance, improved hole cleaning, ease of running casing, and superior cement operations) can be fully attributed to reduced borehole tortuosity. Running casing may mask the tortuosity present in the as drilled open hole wellbore section. This vanishing tortuosity alters the apparent "wellbore quality" and the new tortuosity representative of the cased hole path may present new appearing tortuosity. Both vanishing and appearing tortuosity are generally neglected in engineering calculations.

Conventional methods to calculate tortuosity are based on the predetermined shape of the trajectory using the minimum curvature method. Wellbore undulation (geometrical tortuosity) is determined using geometrical measurements such as inclination, azimuth, and calculated displacement; however, much of this wellbore undulation vanishes after the casing is run, and thus the cased off wellpath appears smoother. This apparent change in wellbore tortuosity results from the flexural stiffness and rigidity of the casing pipes, and the compression and tension loads along the length of the casing string. Acquiring a subsequent survey along the cased well path yields new inclinations, azimuths, and displacements. This new survey records wellpath undulations resulting from the casings path through the original open hole wellbore geometry and what we call tubular undulation (mechanical tortuosity) which is specific to the path and position of the casing within the wellbore. The smoothing of the wellpath resulting from the casing masking original wellbore tortuosity results in the original geometrical tortuosity vanishing while the new undulations resulting from the mechanical tortuosity of the casing causes additional tortuosity to appear. The comparison between the geometrical and mechanical tortuosity provides a method of quantifying the vanishing and appearing tortuosity.
Performance Evaluation of a Density Measurement Tool for ESP Applications
Authors: Ejim Chidirim , Xiao Jinjiang
Published: September 2021

Knowledge of fluid densities in oilfield activities is vital during production operations. The information can be used to ascertain changes in the type of produced fluids, determine water cut, gauge equipment performance, etc. This study presents the evaluation of a measurement tool that can be installed with an electric submersible pump (ESP) to measure in-situ fluid densities during production operations. Such tools can also be configured for use in non-ESP applications.

The density measurement tool has a 5.62-inch outer diameter, typical of some ESP components, which may be installed in a 7-in, 26 lb/ft casing. The tool consists of two flow sections with a 5-degree deviation angle. Total flow rates from the analysis were varied from 2000 barrels per day (bpd) to 12,000 bpd with water as the operating fluid. Pressure drop data within each flow section of the tool were obtained and the fluid densities determined. The estimated densities were compared with the known densities for water.

The results indicate that the pressure drop measurements depend on the entry distance of fluid to the first measurement point within the tool. Other contributing factors include the distance between the measurement sensors and the deviation angle between the flow sections. These factors were optimized by incorporating flow symmetry into and out of the tool to ensure reduced variability of the pressure measurements and thus enable computation of the fluid densities. Overall, incorporating the two flow sections with known deviation angle was beneficial to reduce the complexity of estimating the fluid densities. Therefore, having a simple internal flow architecture in addition to optimized pressure measurement capabilities for each flow section has the potential to estimate fluid densities. Such a tool may be used as a means to measure in-situ and surface fluid densities from flows typical of oilfield production operations. The main benefit is to obtain instantaneous fluid density mesurements for more accurate production monitoring and faster decision-making during production with an ESP.

This study presents a tool with a different internal architecture and a method that can be used to estimate fluid densities from flows typical of oilfield production operations. The tool architecture and measurement technique are simple and have the benefit of easy integration into a flow monitoring system. Such systems are of value to oilfield operators and stakeholders to optimize hydrocarbon flow and implement effective production management of field assets.
Data Driven Gas Well Performance Model Hands Back Control to Engineers
Authors: Veeken Cornelis
Published: September 2021

This paper presents a fit-for-purpose gas well performance model that utilizes a minimum set of inflow and outflow performance parameters, and demonstrates the use of this model to describe real-time well performance, to compare well performance over time and between wells, and to generate production forecasts in support of well interventions. The inflow and outflow parameters are directly related to well-known reservoir and well properties, and can be calibrated against common well surveillance and production data. By adopting this approach, engineers develop a better appreciation of the magnitude and uncertainty of gas well and reservoir performance parameters.
Data-Driven Optimization of Intermittent Gas Production in Mature Fields Assisted by Deep Learning and a Population-Based Global Optimizer
Authors: Gómez Javier Fatou , Omrani Pejman Shoeibi , Belfroid Stefan Philip Christian
Published: September 2021

In gas wells, decreased/unstable production can occur due to difficult-to-predict dynamic effects resulted from late-life phenomena, such as liquid loading and flooding. To minimize the negative impact of these effects, maximize production and extend the wells’ lifetime, wells are often operated in an intermittent production regime. The goal of this work is to find the optimum production and shut-in cycles to maximize intermittent gas production as a decision support to operators.

A framework suitable for single and multiple wells was developed by coupling a Deep Learning forward model trained on historical data with a population-based global optimizer, Particle Swarm Optimization (PSO). The forward model predicts the production rates and wellhead pressure during production and shut-in conditions, respectively. The PSO algorithm optimizes the operational criteria given operational and environmental objectives, such as maximizing production, minimizing start-up/shut-in actions, penalizing emissions under several constraints such as planned maintenances and meeting a contract production value.

The accuracy of the Deep Learning models was tested on synthetic and field data. On synthetic data, mature wells were tested under different reservoir conditions such as initial water saturation, permeability and flow regimes. The relative errors in the predicted total cumulative production ranged between 0.5 and 4.6% for synthetic data and 0.9% for field data. The mean errors for pressure prediction were of 2-3 bar. The optimization framework was benchmarked for production optimization and contract value matching for a single-well (on field data) and a cluster of wells (synthetic data). Single-well production optimization of a North Sea well achieved a 3% production increase, including planned maintenances. Production optimization for six wells resulted in a 21% production increase for a horizon of 30 days, while contract value matching yielded 29/30 values within 3% of the target. The most optimum, repeatable and computationally efficient results were obtained using critical pressure/gas flowrates as operational criteria. This could enable real-time gas production optimization and operational decision-making in a wide range of well conditions and operational requirements.
A Well-Testing Approach for Diagnostics of Fracture Complexity with Well Interference
Authors: Chen Zhiming , Liao Xinwei , Zhao Pengfei , Zhou Biao , Chen Duo , Sepehrnoori Kamy
Published: September 2021

Owing to well interference, the fracture geometries of child wells are sometimes more complex than initially expected. Some approaches or methodologies have been developed to evaluate the complex fracture geometries, however, the fracture geometries are still poorly understood. This work uses the boundary element method to propose a new well testing approach to determine the complex fracture geometries of child wells with inter-well interference.

It is found that the well interferences from Parent well on Child well mainly happen on the late stage, which can be physically expected. The flow regimes of Child well can be divided into: wellbore storage & skin effects, fracture bilinear flow, "fluid supply", formation linear flow, pseudo-boundary dominated flow, "well interferences", pseudo-radial flow, and boundary-dominated flow. The stage of "well interferences" occurs later with the increase in well spacing. The boundary-dominated flow is affected by the reservoir size and shape. When the reservoir size is fixed, the pressure curves in final stage of different-shape reservoirs overlap, which provides a tool to diagnose the reservoir size. While the reservoir size are variable, the occurrences of boundary-dominated flow are quite different. The smaller the reservoir, the quicker the boundary-dominated flow, which is in line with actual situations. It is also found that Parent-well rate mainly affects the flow regimes after pseudo-boundary dominated flow. That to say, after that flow regime, the performance of Child well is interfered by Parent well. The impact is more obvious with the increase in Parent-well rate, especially in pseudo-radial flow. In that flow stage, the horizontal value of pressure derivative also satisfies 0.5(qchd,D+qpar,D). In addition, when the Parent-well rate is negative, namely an injection well, the pressure derivatives of Child well decrease sharply, which means that the pressure depletion of Child well decreases and it is helpful to production of Child well. When the Parent-well rate is a positive and large value, the pressure depletion of Child well increase sharply and its production is harmed by the Parent well. Thus, there should be an optimized production strategies between Parent well and Child well. Finally, the model application on diagnostics of fracture complexity of an actual well is performed. This study provides a new way to identify the fracture geometries of child wells in unconventional plays.
Quantifying the Effect of Stress Hysteresis on the Drilling Window: How Mud Weight Variations Can Affect Wellbore Strength
Authors: AlBahrani Hussain , Morita Nobuo , Alqam Mohammad
Published: September 2021

The estimation of the drilling window limits ensures that lost circulation and wellbore instability events are minimized. These limits are conventionally defined during the pre-drilling phase based on offset wells data. As drilling commences, mud weights are selected to fit within these limits and they can be adjusted to react to different drilling scenarios as long as they don't violate the defined limits. This process fails to consider the effect of the initial mud weight and its subsequent adjustments on the strength of the wellbore. The concept of stress hysteresis dictates that when a body is subjected to a certain load, such as the one exerted by the hydrostatic pressure of the mud, its state will be altered in a manner that can shift its strength limits. This work presents a model that quantifies the changes in the drilling window due to variations in mud weight. The objective is to ensure that any subsequent mud weight changes will fall within the updated drilling window limits.

The analysis is carried out using a novel process of a 3D poro-elasto-plastic finite element model (FEM) that is integrated with a machine learning (ML) algorithm. The integrated FEM-ML model uses offset wells data along with the best fitting failure criterion to estimate the initial limits of the drilling window. The offset wells data used consist of wireline logs, drilling reports, and mechanical testing lab results belonging to the formation of interest. The integrated model uses this data to estimate the stress distribution and learn the failure patterns. The model is then used to run different scenarios of mud weight variations while drilling a specific hole section to quantify their effect on the drilling window. The end result of each scenario is an update of the drilling window, which reflects the effect of stress hysteresis.

When examining the initial estimations of the drilling window against those reflecting the stress path effect, a significant discrepancy in the window size is quantified. This examination is carried out for an offset well, which experienced multiple mud weight changes as a response to various drilling events. Subsequently, the changes in the drilling window and the actual mud weights used are analyzed in view of the drilling difficulties experienced in that specific offset well for the purpose of providing a form of validation. The model results show that the drilling window had shrunk significantly enough for the mud weight to violate the wellbore stability limit. Failure to consider the stress hysteresis effect in this well led major wellbore instability, tight hole, and overpull.

The modelling effort presented in this work allows for a new aspect of dynamic responses to drilling events as they occur.
Wettability Characterization from Pore-Scale Images Using Topology and Energy Balance with Implications for Recovery and Storage
Authors: Blunt Martin , Kearney Luke , Alhosani Abdulla , Lin Qingyang , Bijeljic Branko
Published: September 2021

We present two methods to measure contact angles inside porous media using high-resolution images. The direct determination of contact angle at the three-phase contact line is often ambiguous due to uncertainties with image segmentation. Instead, we propose two alternative approaches that provide an averaged assessment of wettability. The first uses fundamental principles in topology to relate the contact angle to the integral of the Gaussian curvature over the fluid-fluid meniscus. The advantage of this approach is that it replaces the uncertain determination of an angle at a point with a more accurate determination of an integral over a surface. However, in mixed-wet porous media, many interfaces are pinned with a hinging contact angle. For predictive pore-scale models, we need to determine the contact angle at which displacement occurs when the interfaces move. To address this problem we apply an energy balance, ignoring viscous dissipation, to estimate the contact angle from the meniscus curvature and changes in interfacial areas and saturation. We apply these methods to characterize wettability on pore-scale images of two- and three-phase flow. We also discuss the implications of the results for recovery and storage applications.
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

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

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

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

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

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

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

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

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.