bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Optimum Well Control Using Reinforcement Learning and Policy Transfer; Application to Production Optimization and Slugging Minimization
Authors: Poort Jonah , Van der Waa Jasper , Mannucci Tommaso , Shoeibi Omrani Pejman 
Published: September 2022

Abstract
Production optimization of oil, gas and geothermal wells suffering from unstable multiphase flow phenomena such as slugging is a challenging task due to their complexity and unpredictable dynamics. In this work, reinforcement learning which is a novel machine learning based control method was applied to find optimum well control strategies to maximize cumulative production while minimizing the negative impact of slugging on the system integrity, allowing for economical, safe, and reliable operation of wells and flowlines. Actor-critic reinforcement learning agents were trained to find the optimal settings for production valve opening and gas lift pressure in order to minimize slugging and maximize oil production. These agents were trained on a data-driven proxy models of two oil wells with different responses to the control actions. Use of such proxy models allowed for faster modelling of the environment while still accurately representing the system’s physical relations. In addition, to further increase the speed of optimization convergence, a policy transfer schem was developed in which a pre-trained agent on a different well was applied and finetuned on a new well. The reinforcement learning agents successfully managed to learn control strategies that improved oil production by up to 17% and reduced slugging effects by 6% when compared to baseline control settings. In addition, using policy transfer, agents converged up to 63% faster than when trained from a random initialization.
Best-In-Class Water Control Through the Application of Autonomous Inflow Control Valves in Villano Field, Ecuador: A Case Study
Authors: Atahualpa Gustavo , Astudillo Ricardo , Chango Mario , Borquez Carlos , Rauzi Roberto , Uzcategui Alberto A. , Fipke Steven , Molina Juan Luis , Mohd Ismail Ismarullizam 
Published: September 2022

Abstract
Water control in mature heavy-oil reservoirs is a well-known challenge in the Oil & Gas industry. Due to the mobility ratio, water tends to flow much easier compared to oil, leading to premature water breakthrough which pushes water cut values to over 95% or more within weeks of oil production. High volumes of water production negatively impact operations due to excessive electricity consumption (lifting and re-injection), overuse of water handling/treatment facilities and its associated impact to the environment. In some fields, high water-cut can limit the oil production if the water handling capacity is exceeded, driving operators to shut-in wells and lose recoverable oil.
Villano is a mature heavy-oil field located in a tropical rainforest area in the Pastaza province, east Ecuador (17–19 °API and 25 cP). The field has been mainly developed with horizontal wells, where several water-control completion strategies have been trialed (ICD/AICD) due to the presence of an infinite-acting, strong aquifer drive. Although some positive results had been observed in the field, none of these technologies have been able to provide effective water control in the sections with water breakthrough.
After a technical evaluation, the AICD-Valve technology was chosen, and the first installation was planned for mid-2021. Due to its ability to autonomously restrict water flow based on the fluid properties (viscosity and density), simulation results showed short- and long-term benefits in terms of oil recovery and water control for the field.
The AICD-Valve technology has shown superior water control compared to other technologies used in Villano field. The well began its production with 4% water cut (compared to &gt;50% with adjacent A/ICD completions) and approximately double the initial oil rate compared to modelling. The well eventually reached 80% water cut and stabilized at 80%–85%. Production rates have been very stable while the flowing bottomhole pressure has been dropping gradually, signaling that the AICD-Valves are autonomously choking the water zones while allowing production from oil zones. Water volumes produced from the AICD-Valve well are less than 1/3 of the neighboring A/ICD wells.
Relevance of Petroleum Engineering Under the Present Uncertainties
Authors: Farouq Ali S. M. , Soliman Mohamed Y. 
Published: September 2022

Abstract
Petroleum engineering will continue to have relevance and renewed importance in the emerging scenarios of Greenhouse Gas (GHG) emissions, and the forecasts of climate change, which are replete with uncertainties. The changing role of petroleum industry and academia in this framework over the next 100 years is outlined. The hurdles in reaching Net Zero – fossil fuel use with complete carbon capture and storage, and the use of renewables – are illustrated through a spreadsheet. Development of renewables is costly and has an environmental footprint 10 times that of oil and gas for the same amount of energy. Carbon capture and subsurface storage is a better option, and petroleum engineers are best suited to address that. They are also well positioned to develop energy using injection-production wells, and create storage space. Petroleum engineering, with its unique blend of skills and technologies is unmatched and needed for a long time.
Well Integrity in the Production Phase - Application of a New Quantitative Operational Risk Model
Authors: Oliveira Luiz Fernando , Domingues Joaquim , Colombo Danilo 
Published: September 2022

Abstract
Almost all O&G companies have a well integrity management system based on a well failure model. Until now, they are mostly based on qualitative risk models with only very few claiming to use quantitative risk methods. The objective of this paper is to present a production well integrity managementsystem based on a different type of quantitative risk model. Traditional risk assessment methods were developed to be used in design stage. Therefore, they are not really adequate to manage operational risks during the production phase because they cannot take into account the operational history and the true current asset conditions during operation. Unlike such models, our quantitative risk/reliability model has been developed to be specifically used during the operational phase of a well. Therefore, it can accurately calculate the risk of an uncontrolled leak today and provide good estimates for the future evolution of this risk.This quantitative model has been served as the basis for the development of a web-based computational system which is now implemented in Petrobras and is an important part of the well integrity management system of that company. A descriptionis presented in this paper together with a simplified application to a subsea well.
Maintain Long-Term Production Rates by Unique Environment Friendly Asphaltene Solvent
Authors: Omer Mohammed , Busteed John E. , Fragachan Francisco E. 
Published: September 2022

Abstract
Heavy oil production often results in the deposition of organic solids, like waxes or asphaltene. These asphaltene deposits pose a serious problem to the operator, negatively affecting the productivity of the reservoir, by reducing the permeability and altering wettability. Its deposition in production and tubing facilities can cause operational and economic issues. Various chemical and mechanical methods used for treating deposition are partially effective. Traditionally xylene has been used to remove these organic deposits, however, because of its low flash point (~80 °F) it poses a great risk of ignition. In addition, xylene does not change the wettability of the rock surface, resulting in short-lived effectiveness.
This paper outlines the development of an optimized environmentally friendly Asphaltene Solvent. Suitable for surface and bottom hole conditions. The paper discusses the production results and flow assurance observed from long-term production results from field trials performed in the Middle East. The optimized asphaltene solvent was designed and evaluated by dissolution, wettability and stability tests, and its results were benchmarked against actual xylene treatments, demonstrating and excellent flow assurance beyond standard xylene systems.
The laboratory testing demonstrated that the system was capable of dissolving Asphaltenes and Paraffins up to 99% -after 4 hours in a water bath at 194 °F (90 °C)- and leaving the rock water-wet.
A unique environment friendly asphaltene remover system has been developed capable of maintaining long-term production rates and by leaving the rock in a water-wet condition. Flash point of this system is higher (&gt; 145° F or 62.7° C) than the traditional solvent systems, allowing to perform pumping operations in a safer and environmentally friendlier way.
Effects of Pipe Rotation on the Performance of Fibrous Fluids in Horizontal Well Cleanout
Authors: Garcia Sergio , Mendez Michael , Ahmed Ramadan , Karami Hamidreza , Nasser Mustafa , Hussein Ibnelwaleed 
Published: September 2022

Abstract
The deposition of rock cuttings is a problem commonly faced during drilling, completion, and intervention operations. Using polymer-based fluids is a common technique to improve horizontal downhole cleaning. However, these fluids cannot always guarantee an efficient wellbore cleanout. One way to enhance cleanout efficiency is by rotating the drill pipe to mitigate the settling of solids and facilitate their removal. However, drill string rotation often increases equivalent circulating density (ECD). Therefore, this study explores how the impact of rotation on hole cleaning can be synergized by using fibrous fluids to perform cleanout at reduced rotational speeds with limited impact on ECD.
The flow loop utilized for this study consists of a 48-ft long eccentric annular (5" × 2.375") test section. Each experiment began by forming a stationary bed of natural sand (average diameter of 1.2 mm) in the test section. High-viscosity and low-viscosity polymer-based suspensions with and without fibers were used. Drill pipe rotation speed was varied from 0 to 150 rpm. In each experiment, the flow rate was increased from 35 to 195 gpm stepwise. The equilibrium bed perimeter was measured at every test flowrate until a complete bed cleanout was achieved. As part of the test, flow rate, pressure gradient, and equilibrium bed height were measured. Rotational viscometers were used to measure fluid rheology before and after each test.
Fiber particles improve the carrying capacity of the fluid by reducing the settling of solids and minimizing the re-deposition of particles. The results demonstrate the effectiveness of fiber in synergizing the effect of pipe rotation on hole cleanout performance in horizontal wellbores. The impact of fiber is more pronounced when used with low viscosity fluid. The cleanout performance of the low-viscosity fluid amplified significantly with rotation, almost entirely cleaning the bed at 75 gpm and a rotational speed of 50 RPM, compared to more than 195 gpm without rotation. Even more improvement could be achieved by adding a small amount of fiber (0.04% wt/wt). Furthermore, the fiber improved the cleanout performance of the high-viscosity fluid. The enhancement, however, was not as noticeable as with the low-viscosity fluid. In general, rotation combined with low-viscosity fibrous fluid exhibits the most effective sand cleaning performance. Rotating the pipe re-suspends the settled solids, which are then carried away by the fluids. Fiber particles enhance the fluid's ability to carry solids.
Pros and Cons of Saline Aquifers Against Depleted Hydrocarbon Reservoirs for Hydrogen Energy Storage
Authors: Delshad Mojdeh , Alhotan Muhammad , Batista Fernandes Bruno Ramon , Umurzakov Yelnur , Sepehrnoori Kamy 
Published: September 2022

Abstract
Hydrogen (H2) is an attractive energy carrier and its true potential is in decarbonizing industries such as providing heat for buildings and being a reliable fuel for trains, buses, and heavy trucks. Industry is already making tremendous progress in cutting costs and improving efficiency of hydrogen infrastructure. Currently heating is primarily provided by using natural gas and transportation by gasoline with a large carbon footprint. Hydrogen has a similarly high energy density but there are technical challenges preventing its large-scale use as an energy carrier. Among these include the difficulty of developing large storage capacities.
Underground geologic storage of hydrogen could offer substantial storage capacity at low cost as well as buffer capacity to meet changing seasonal demands or possible disruptions in supply. There are several options for large-scale hydrogen underground storage: lined caverns, salt domes, saline aquifers, and depleted oil/gas reservoirs where large quantities of gaseous hydrogen can be safely and cost-effectively stored and withdrawn as needed. Underground geologic storage must have adequate capacity, ability to inject/extract high volumes with a reliable caprock. A thorough study is essential for a large number of site surveys to locate and fully characterize the subsurface geological storage sites both onshore and offshore.
A non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs was evaluated. The phase behavior, fluid properties, and petrophysical models were all calibrated against published laboratory data of density, viscosity, relative permeability, and capillary pressure for a given site. History-matched dynamic models of two CO2 injection field projects in saline aquifers and one natural gas storage in depleted oil reservoir were considered as hypothetical hydrogen seasonal storage sites. The results revealed the need to contain the stored working gas volume because of high mobility of gaseous H2 with an integrated approach of site selection and its geological features, well locations, and the need for pump wells to maximize the capacity and deliverability.
Implementation of Autonomous Inflow Control and the Effect on Carbon Intensity
Authors: Elseth Geir , Martiniussen Ingvild Berg , Halvorsen Martin , Årland Kristine , Wesenberg Margrete Hånes , Nogueira Elysio Mendes , Erlandsen Sigurd Myge 
Published: September 2022

Abstract
A lean approach for qualification of inflow control is presented, involving full-scale experimental tests. The experimental data are converted into optimized well design by a simple and robust workflow, incorporating internally developed software tools for pressure-drop modelling and for well modelling with inflow control. Production data from several Equinor operated fields are analyzed, and the increased oil recovery, as well as the impact on CO2 intensity, is discussed.
Results from a full-scale qualification test campaign including five different autonomous inflow control devices (AICD) are presented. The intended application is a special case with high expected production and high pressure, in nearly vertical wells, which is unlike any of the more than 175 wells with AICDs in Equinor. The ability to choke gas and allow high oil production, as well as other selected qualification criteria, were examined for the five, already commercially available, technologies in a benchmarking study.
Coupled Flow and Geomechanics in Reservoirs with Complex Fractures Using Embedded Meshes
Authors: Chen Jungang , Wu Kan , Killough John 
Published: September 2022

Abstract
Conventional modeling of coupled flow and geomechanics in fractured reservoirs requires computation meshes conforming to the fracture geometry, which not only needs complicated gridding techniques but consumes a huge amount of computing resources. The objective of this paper is to present a numerical model that is able to efficiently model coupled porous flow and poroelastic effect in fractured reservoirs with complex fracture distributions. In this paper, embedded discrete fracture modeling (EDFM) is used to model fluid flow in fractured porous media and an extended finite element method (XFEM) is utilized to model displacement discontinuities arising from fractures. To model fracture aperture changes during depletion, a proppant model with linear elasticity is assumed. Moreover, to cope with complex fractures, we consider two basic types of fracture junctions, one is the ‘X’ type junction where two fractures intersect each other, the other is the ‘T’ type fracture where one fracture is captured at the fracture tip by the other without crossing it. Special treatment is performed to preprocess two types of fracture junctions and any combination of these two. The model is validated by analytical solutions as well as cases from other publications. We also present horizontal well production cases where hydraulic fractures intersecting with natural fractures.
Intelligent Application of Computer Vision and Data Analytics to Optimize the Separators Cleaning for Unconventional Reservoirs
Authors: Parizek Jason , Popa Andrei , Tam Soong Hay 
Published: September 2022

Abstract
The reliability of the production operations depends not only on the well performance but also on the effectiveness of the surface facilities to transport and separate the produced fluids. In the case of the unconventional reservoirs, the completion treatments placed to stimulate the long horizontal wells require large volumes of proppant and water. During flowback and even later in the life of the well, fractions of the proppant makes its way to the surface and into the separators. Large accumulations of sand reduce the ability of the separators to perform as designed, impacting production, and requiring complete shut-down for cleaning to restore their original capability.
The work introduces an intelligent end-to-end workflow integrating computer vision and data analytics to automatically interpret thermographic images, identifying when a production separator needs condition-based maintenance. The new approach leverages infrared thermography pictures taken from hundreds of separators in an unconventional asset and automates a labor-intensive process to make objective maintenance decisions. Contrasted to the manual method, where vessels were taken offline, visually inspected, and cleaned out on time-based maintenance schedules, this work provides an accurate visualization of the sand level using computer vision.
The study demonstrates who how integration of digital technologies such as computer vision and data analytics enable optimization of maintenance work. The application showcases the business impact not only through cycle time reduction and effort, by also enables better decision making and optimization of resources.
A Passive Flow Control Nozzle for Water Choking Application
Authors: Zhu Da , Soroush Mohammad , Rosi Giuseppe , Scott Ryan 
Published: September 2022

Abstract
Reducing water production is the primary problem in the oil and gas industry. There are a few flow control technologies with moving parts available on the market to choke back water. However, the main issue with those technologies is the potential of plugging and scaling. In this paper, we will introduce a novel passive flow control nozzle, which has no moving part inside. All the choking is implemented through its internal geometry. Therefore, the risk of plugging and scaling will be significantly mitigated.
In this paper, a passive flow control nozzle designed specifically for water choking will be presented. Design philosophy in fluid mechanics will be introduced in detail. The results of Computational Fluid Dynamics (CFD) and physical flow loop testing will be shown to evaluate the performance of the technology. It is shown that a passive choking nozzle can choke back more than 40% of water compared to an orifice while maintaining oil production rates. We will also perform simulation case studies to compare conventional slotted liner completions with the completions equipped with a passive choking nozzle (PCN). We will show that the nozzle can effectively choke back water and promote oil production in a long horizontal well. Finally, we will briefly discuss how the passive nozzle can mitigate well-known issues such as scaling and plugging.
Numerical RTA Extended to Complex Fracture Systems: Part 2
Authors: Lia Carlsen Mathias , Curtis Hays Whitson 
Published: September 2022

Abstract
This paper is a continuation of the work presented in URTeC 3718584 (Carlsen & Whitson, 2022), and focuses on practical usage of ‘fractional RTA’ theory when applied to both simulated data and field data from the SPE data repository. Most of the theory presented in Part 1 is kept for completeness.
An inherent assumption in most industry RTA is equally spaced fractures. However, as shown in several field studies (Raterman 2017, Gale 2018), the distance between individual fractures tends to be unevenly spaced along the wellbore (e.g., "fracture swarms"). In this paper, we extend the original numerical RTA workflow proposed by Bowie and Ewert (2020) to account for uneven fracture spacing.
Acuna's (2016, 2020) heterogeneity parameter, delta (δ), is introduced to generalize the linear flow parameter (LFP) to account for complex fracture systems (LFP’ = Akδϕ1-δ = 4nfhxfkδϕ1-δ). For evenly spaced fractures, δ = 0.5, simplifying LFP’ to the familiar LFP = A√k = 4nfhxf√k. For uneven fracture systems, 0 ≤ δ ≤ 0.5.
With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFP' and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, also wells with complex fracture systems. Namely, that wells: (1) with the same value of LFP', the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFP'/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFP' and OOIP, rate performance of gas, oil, and water will be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model.
The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities. This paper extends the approach to complex fracture systems that can be described by the Acuna parameter δ.
Numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k, δ), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells. Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fracture spacing. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.