bluuebunny/crossref_metadata_2025_split huggingface dataset:
Commingled Production, a New Era in Mature Fields. Lessons Learned and Practices in ESP Lifted Wells Achieved 29 % Incremental Production During Initial Implementation in Shaya Project
Authors: Villalobos Jorge Luis , Andagoya Carrillo Kevin Ismael , Quinzo Maria Elena , Orozco Andres , Enriquez Luis Carlos , Reyes Carlos , Gonzalez Patricio , Torres Richard 
Published: October 2022

Abstract
For many years, commingled production has not been considered as a valid alternative to produce mature fields; actually, oil regulations in many countries do not allow this technique. This was the case in Ecuador until 2021. In 2021, Ecuadorian regulations allowed commingled production to increase the oil recovery. The main objective of this project is to present the artificial lift expertise applied in and the initial results, best practices and lessons learned of the first 13 wells of a commingled production campaign in the Shaya Project; the project focused on electrical submersible pumps (ESPs) and their operation. The aim was to enable a local best practice that established the well potential in commingled production model. This required the ESP design to lift at and beyond the expected target production, which was accomplished by the design of a robust enough system to cover the wide range of uncertainties presented by the multilayered production and related problems with mature fields, including fines production, increased viscosity, and free gas into the pump. An additional requirement was to handle both the current and higher rates associated with future waterflooding. Thirteen wells were completed with a commingled strategy for close to 1 year. The analysis of input data together with the ESP design criteria for pump model selection and production regime has successfully achieved optimum results, producing without issues two producing zones at the same time without any additional downhole tools. This resulted in an average incremental production of 29% compared to the historical single zone production, 92% of the artificial lift systems are operating inside the optimum operating range with high efficiencies (above 50%), and 62 % of the wells achieved maximum drawdown with a flowing intake pressure of approximately 250 psia. Even though the pressure is below the average bubblepoint pressure, the downhole flowing conditions remain stable, and hence there is a constant flow regime at the surface.
The statistical projection of the mean time between failures shows a 100% survival probability for the already reached 384 days of operation, thus giving to the project the confidence that it is on trend to accomplish the expected target run life of the field. This project aims to share with the technical community what has been learned in the Shaya Project, after more than a year evaluating the commingled wells following a clear journey through all the phases: reservoir evaluation, inflow consideration, production analysis, uncertain scenarios, combined fluid properties, artificial lift selection best practices, the surveillance, and performance evaluation.
Maximizing Asset Value Through Unified Gas Injection and Gas Export Management Via Development and Adoption of Integrated Well and Process Automation
Authors: Mohd Sahak Muhammad Zakwan , Myo Thant Maung Maung , Tuan Mat Tengku Amansyah , Harun Zalina , Castillano Eugene , Bhave Abhijeet 
Published: October 2022

Abstract
In oilfield with significant gas production, either from high associated gas production or non-associated gas (NAG) wells, gas injection is often prioritized due to the aim of oil production sustainability compared to gas export, with only the remaining gas flow not taken by the injection wells is exported as sales gas. However, with gas emerging as a cleaner energy source as compared to oil and instability in oil price, higher gas demand is expected in the future. Due to this, flexibility in managing the allocation between gas injection and gas export would be an advantage, especially with the cyclical demand peak due to winter and summer seasons. A case study for optimization for a unified management and automation of the gas export and gas injection is presented in this paper, which includes the flexibility in prioritizing either utilization options and managing the impact of changes in injection gas supply accordingly via process control and automation.
With the adoption of new controllers, operator would now be able to choose which priority mode would be given considering subsurface injection and gas export requirements. For example, when priority is given to the gas injection as per current operating mode, only the remaining gas balance will be used for export. However, when gas export is prioritized, operator would have the option to set the minimum gas export flow that is required, and the control system will automatically control the allocation for sales and injection, including automatically calculating and assigning the injection gas flow to each injector wells when the resulting gas injection supply is changed as a result of gas export prioritization. With the automation exercise, the operator would not need to conduct the manual adjustment of choke valves opening to regulate the gas injection and gas export flow, rather only the usage mode prioritization and the desired flow setpoints for both cases are required. The scheme allows the operator to take advantage on the opportunity of prioritizing gas export or injection depending on prevailing market demand and operational requirement needs for maximizing the value from the field.
Waterflooding Communication Analysis at Well and Layer Levels Using Energy Balance and Capacitance Resistance Methods
Authors: Kshirsagar Atul , Yu Huijuan , Cranfield Colin Bertrand , Green Steve , Feng Gui 
Published: October 2022

Abstract
Reservoir surveillance and integration of geological and reservoir engineering studies are essential in optimising waterflooded oil field recovery. Maintaining calibration of dynamic models can be difficult as fields mature and watercuts increase, particularly where there is significant geological complexity. This can be even more challenging if the field is multi-layered with commingled production and injection. This paper describes how the energy method (EM) and capacitance resistance method (CRM) used for inter-well communication analysis were successfully employed to provide valuable insights in two such waterflood case studies and compares their results at well and layer levels.
In a preliminary step, classical waterflood surveillance and analytical techniques are combined with geological knowledge for a firm understanding of field performance. More detailed communication analysis is then performed to analyse inter-well and cross-fault communication.
In a first case study, the EM technique was used to examine waterflood effectiveness in six separate panels in the most faulted area of a mature, geologically highly complex oil field. In a second case study, both the EM and CRM techniques were used to assess and optimise the waterflood in the panel of another mature oil field.
The communication analyses provided a rapid route to understanding communication within complex, multi-layer fields using production data alone. In the first case study, results indicated significant communication between injectors and producers including across many of the faults separating reservoir compartments. Results identified areas of interest for infill drilling and possible workover targets. In the second case study, the combination of EM and CRM enhanced the overall understanding gained from the inter-well communication analysis.
Centrifugal Compressor Seal and Bearing Rubbing Due to a Destructive Repeatable Reverse Rotation
Authors: Ashour Mohammed , Shalabi Mustafa , Rengasamy S. G. 
Published: October 2022

Abstract
This case study is focused on the diagnostics of an abnormal event observed during each compressor train shutdown and led to a seal failure later through a detailed analysis of historical transient data collected using an online vibration online monitoring software during shutdown mode to identify the root cause of this abnormal behavior.
The unit consists of a centrifugal gas compressor (12440 RPM) driven by an induction electrical motor (3100 KW and 1790 RPM) through an increasing single stage double helical gearbox.
Machine train was running smoothly during steady state condition. Compressor bearings showed high vibration levels during each shutdown event close to alarm setpoints during last year, however no one took care as it was happening only during shutdown. The unit was compressing a hazardous gas, and any failure or leak could lead to a major safety incident.
Steady state data review showed good compressor rotor dynamics with acceptable vibration levels well below alarm set points, however during shutdown showed high vibration levels reaching alarm setpoints during shutdown. Review of the vibration and speed data through the online condition monitoring software showed symptoms of reverse rotation event repeating each shutdown after reaching zero speed.
After 3 month of operation and several shutdown events encountered, a gas leak took place from the compressor. During the internal inspection, severe rubbing marks found in the compressor seals and the rotor found damaged at these areas. Also, the compressor inboard bearing found totally damaged. Major overhaul took place changing the rotor and overhauling the compressor parts. The non-return valve installed on the discharge was dismantled and overhauled.
Compressor started up later and during the next shutdown the compressor bearings showed normal vibration behavior, and no reverse rotation events observed.
Unloading Liquid Loaded Wells- How Conventional Solutions Contribute to Sustainability Targets
Authors: Elabrashy Manar , Khan Zubair , Abbasi Haris Shakeel , Alsaeedi Ayesha , Al zeyoudi Mohammed , Grutters Marinus , Al Mheiri Eissa , Al Bairaq Ahmed , Ahmad Mubashir , Alsenaidi Shemaisa , Ahmad Zeeshan , Shaker Ashraf , Douglas Mahmood , Alblooshi Maryam , Siddiqui Muhammad , Albadi Mohamed Mubarak , Cristea Zaharia 
Published: October 2022

Abstract
In the normal life of an oil or gas well, sometimes the well produce water in conjunction with the desired hydrocarbons. In the initial stage of life of the wells, the wells have sufficient energy to carry undesired water through the well bore and out of well to the surface. With the passage of time, the reservoir pressure depletes, and it leads to a decrease in well production. When this occurs the flowing pressure decrease and have an adverse effect on the well to carry and remove the undesired water being produced by the well. When the well can't carry said water out of the well bore it builds up in the production tubing and the well shuts off flow to the surface. Soap sticks are deployed on the wells to generate foam and to overcome the liquid loading, thereby reducing the surface tension and lowering the fluid density.
The customer was experiencing liquid loading in many of its older gas wells which has a considerable impact on production targets. The liquid loading was a major challenge for the customer. The customer was using coil tubing and nitrogen kick off to offload the liquid loaded wells. The cost associated with nitrogen kick off was vey high. The customer was looking for a cost-effective solution to offload liquid loaded wells. This paper describes the application of Soap Sticks on liquid loaded wells and demonstrates that the use of Soap Sticks is cost effective and sustainable alternative to unloading by coil tubing. Initially, two liquid loaded wells were selected for Soap Sticks treatment. The data for two wells, Well X-1 and Well X-2 was used for analysis and to prepare best treatment plan. The Well X-1 was a deviated well with 4-1/2-inch single string completion. The well was producing 4944Mscf/d and 39 bbl/day liquids. The well was loaded up with water and was unable to deliver the desired production rates. As per the analysis, the Soap sticks were launched, and the well was unloaded successfully.
The Well X-2 located in the same field and was a vertical well with 4-1/2" single string completion. Based on historical data, this well was producing around 4310 Mscf/day. The production from this well dropped to 1704Mscf/day and it was kept dropping continusly. Prior to the field trial the liquid column height was determined, and the required number of Soap Sticks was calculated for the candidate well. Commencing the field trial, Soap Sticks were dropped in the well and wellhead pressure was building up. After several hours of pressure build up the well was opened whilst monitoring the flow rate and wellhead pressure.
Production Excellence Program Enhances Operation Efficiency
Authors: Florez Fabian , Calderon Diego , Kartoatmodjo Gayatri , Fendt Andrew , Wilson Gregor 
Published: October 2022

Abstract
Many IOC and NOC organizations have and continue to be face with the challenge of establishing a corporate standard for measuring production performance across their producing assets. The difficulty with this challgenge comes from reporting localized production, managing production shortfalls, and identifying opportunities to increase production. These are three critical elements of production excellence or production performance programs.
This paper presents a solution for this challenge. This novel solution uses the choke model or limit diagram to integrate existing portions of the production performance framework; i. e., shortfall production management, opportunity identification workshops, and well potential calculations. The challenge is to duplicate these elements in a standard way across 12 active producing assets at different geographical locations, with diverse operating cultures, hydrocarbon types, contractual frameworks, and engineering criteria.
Within three years all assets were sharing the same basis for Production Excellence program (Px) with strict reporting discipling enabled by common corporate system. During the same period the overall production efficiency increase by 3% adding 1.1 MMBOE into the tanks.
In addition to the production baseline sustainability, other major benefits included the standardization of oil production loss classification and production opportunities identification workshop to keep the discipline of identifying production potential to reflect the everchanging field conditions.
This paper will present the integration of the Px program as the main endevoar to make it a portion of the operating culture and the proposed method to capture and share the performance gains. Additionally, a tremendous effort was made to build some of the elements directly into the production data management systems in the local operating assets to enable the corporate reporting system to read any source of data. These data are then used as a business intelligence application reporting accessible via smart and interactive dashboards.
Composite Materials for Cheaper Oil and Gas Production. Experience in Application.
Authors: Ablaev Anton , Ruban Konstantin , Zozulya Andrey , Kozlov Vladimir 
Published: October 2022

Abstract
The global composite market has been developing dynamically in recent years. The main goal of introducing composite materials as a replacement for metal - is to reduce the capital and operating costs of the enterprise. This paper describes Volga Gas's experience in developing four areas of composite materials application: well loops, tubing, petroleum product storage tanks, and process pipelines.
The main goal of this project was to replace metal well plumes with composite ones. As a composite material, the company "Volga Gas" suggested using fiberglass pipes, the installation of which is carried out in an easier way due to the absence of the need for welding operations and electrochemical protection. The last stage of this test is non-destructive testing. The technology of application of tubing is also offered (НКТ) made of composite materials. Despite the fact that the technology of launching composite tubing is similar to metal tubing, it has a number of advantages during further operation. It is important to note the technology of manufacturing tanks from composite materials. This technology is quite popular in remote fields, and the company "Volga Gas" successfully implements projects for the use of composite reservoirs in these conditions. The main advantage of replacing a metal tank with composite ones is a sharp reduction in the complexity of installation, and as a result, its terms. This paper also describes the technology of using pipes made of low-pressure poly-ethylene (GYL). These pipes can be widely used as process pipelines for corrosive liquids.
Virtual Tour (4.0) for Adnoc Offshore Assets
Authors: Mullick Partho , Almenhali Lateefa , AlAmry Mohamed , AlJaberi Manea 
Published: October 2022

Abstract
This abstract outlines the implementation of Virtual Tour (4.0) facilitating maintaining the dynamic changes to ADNOC OFFSHORE assets because of continuous ongoing Plant Modifications / Projects, thus resulting in the Engineering Drawings and 3D Models being overwhelmingly out of date, which impacts safety, operation and maintenance. Site visit becomes mandatory for decision making both by Company & Contractor personnel due to delay in availability of as-built drawings and 3D intelligent Models for a given facility.
Capitalizing on the advancement of Virtual Reality technology by creating an interactive Virtual Reality environment for all ADNOC Offshore operational sites is the need of the hour. Authorized and secured Business Users across ADNOC Offshore will have instantaneous visualization of offshore sites which optimizes the requirement for site visits meant for engineering, tendering activities and familiarization programs by more than 80%.
The output will be a user-friendly web portal easily deployed on the desktop or on a mobile device, the format following the spirit of "Street View" navigation that entails utilizing the latest 3D high-resolution laser scan technology output of point cloud & 360° high resolution photographs superimposed on each other.
A virtual tour environment/solutions aims to provide the below listed benefits, which is believed to be a future road map in terms of Return on Investment
➣ Site visits were reduced by almost 80%, so less overhead Logistic cost and direct man-days saving. ➣ Contractor's multiple site visits are avoided which is 2 to 4 Weeks Savings per Project/PMRs. ➣ Minimize Contract Variations due to site conditions with clear photos and sizing capabilities; variations any show stopper or risks are identified during the early stage of engineering. ➣ Provide visual support for Operations and HSE related induction/ training with the aid of 360° high resolution Images and Remote site measurement (up to ±3mm accuracy) ➣ Improve work preparation and facilitate the risk assessment process by identifying the equipment located in the area with Tag viewing feature. ➣ Visualize the event location and surroundings during emergency situations and drills. ➣ Facilitating visual inspection/coating inspection which reduces inspection & maintenance costs. ➣ Reduces dependency on the as-built layout drawings and intelligent 3D Model related to site conditions. ➣ Superimposing of 3D intelligent and non-intelligent model with laser scan true view point cloud. ➣ Facilitate up-to-date development of 3D e-Learning training modules. ➣ Facilitate to complement in the development of Digital Twin ➣ Less travelling to site will reduce Greenhouse emission and fuel consumption. ➣ Reducing the issuance of Permit to work.
Stochastic Optimization Workflow for Non-Uniform Coarsening of Simulation Grids and Location and Sequencing of Wells
Authors: Verma Santosh Kumar , Xu Yifei , He Shuai , Sanai Alireza 
Published: October 2022

AbstractAn adaptive differential evolution (DE) optimization algorithm and workflow are presented for non-uniform coarsening (NUC) of simulation grids resulting in smaller and faster models that maintain the key physics of the original model. The workflow presented here fully automates the grid generation process and results in a better NUC grid. The algorithm presented can handle discrete and continuous NUC grid generation parameters. We also use the DE optimization method for location and sequencing of wells.A typical NUC grid generation process splits the reservoir into several regions: property preservation, near-well, far-well, etc. Several techniques for region splitting, e.g. time-of-flight (TOF), distance from wells, mixture of the two, etc. are used. The coarsening process has several types of parameters: continuous, binary, and integer. The resultant optimization problem is a mixed-integer nonlinear optimization problem which is solved using the modified adaptive differential evolution method.Two methods are used to evaluate coarse grid quality. They are flow diagnostics, based on single-phase steady-state flow, and multiphase flow simulation. Well allocation factor differences computed from flow diagnostics and three phase production data differences computed from multiphase simulation are used in the objective function. These two objective functions are used in a two-stage optimization - in the first stage flow diagnostic differences drive the coarse grid generation process. A technique to prescreen NUC grids is presented for the second stage. It significantly reduced the time used in getting optimal NUC grids for all the cases that were studied. The NUC grid results clearly show the convergence of coarse grid results towards the fine grid results. Preserving fluid contacts in the coarse grid is found to be critical in getting an optimal NUC grid. A real field example with dozens of wells are presented that show the effectiveness of the adaptive differential evolution optimization workflow in achieving an optimal drilling schedule. Another set of examples demonstrate how the ability to move well locations within a user defined region helps us to further maximize the objective function.The novelty of this adaptive differential evolution optimization workflow is the ability to automate the NUC grid parameter selection and the grid generation process; thus saving several days for a practicing engineer. Another novelty of the optimization algorithm is the ability to fully automate the process of scenario generation and simulation, thus saving time from manual exploration of the range of parameters.