bluuebunny/crossref_metadata_2025 huggingface dataset:
Maximizing Reservoir Injectivity and Connectivity Through Synergistic Integration of Pressure While Drilling and 3D Seismic Data for Optimal Injection Well Placement and Completion in Geologically Complex Reservoirs
Authors: Abdullah Zulkiflie , Martinez Raul Leal , Al Hashem Hassan W. , Al Quaimi Bander
Published: October 2023

Optimizing injection placement and completion in multi-layered, heterogeneous sandstone reservoirs with long horizontal wells is a complex task that requires advanced measurement and modeling techniques. The proper placement of injectors is critical to ensure optimal transmissibility and facilitate pressure propagation within the reservoir. This task is however complicated by reservoir heterogeneity such as lateral discontinuity and geological barriers (e.g., faults and tight zones).

Standard triple combo logging tools are commonly used to geosteer horizontal wells in homogeneous reservoirs. However, in the presence of complex clastic reservoirs, such tools alone are insufficient to optimize well placement. To overcome this limitation, a novel approach is proposed to optimize well placement and completion for water injectors in complex reservoirs with long horizontal wells using a combination of formation pressure while drilling (FPWD) measurement and 3D seismic data. FPWD provides in-situ critical information on reservoir pressure, quality, and connectivity in complex geological barriers when integrated with 3D seismic for optimal reservoir connectivity and injectivity. Specifically, 3D seismic data is used to identify subsurface structures, such as faults and tight zones, and their impact on reservoir fluid flow. These structures can then be considered when placing injectors to ensure optimal reservoir connectivity and pressure propagation.

To test the efficacy of this approach, several critical wells in a challenging multi-layered heterogeneous reservoir were analyzed using FPWD coupled with 3D seismic data. The results demonstrate that the combination of these tools enabling optimized well placement and completion to maximize injectivity and pressure propagation. Moreover, the approach facilitates the identification of subsurface structures that may impede injectivity and allows for the implementation of mitigation measures.

This paper represents a significant advancement in reservoir engineering and well placement techniques. By providing a more comprehensive understanding of reservoir properties and dynamics, it offers a new paradigm for optimizing injectivity, facilitating pressure propagation, and in turn maximizing oil recovery in complex reservoirs.
An Artificial Intelligent Method to Optimize and Enhance Well Performance and Oil Production Wells by Approaching Well Behavior
Authors: Surya D. , Putra P. , Utomo G. , Ramadhan R. , Pratama M. B.
Published: October 2023

Monitoring oil production well is an essential part for Petroleum Engineer, who has responsibility to optimize, maintain and enhance well production performance. We have to obtain and know about any well behaviors. That can be so exhausting if we do to ± 100 oil production wells each and every day. Despite of that, each well has its own behavior that have to be obtained and analyzed further. We have to monitor properly from each production well so that human error does not occur which can cause miss analysis job we need proper and accurate analysis system. To maximize and optimize technology in industry digitization, the oil and gas industry has started to enter this revolution, by making various kind of tools that make it easy to monitor all oil and gas wells in order to serve accurate, fast, user-friendly and solution-oriented system. The purpose of this paper is to show how to maximize the utilization of digitalization and artificial intelligence to get fast and accurate optimization oil well performance.

Artificial Lift Rod Pump & ESP is a lifting method that is commonly used and makes a significant contribution to existing production, so it needs an easy, effective and precise monitoring pattern in its application. Quicklook Mapping Tools is an analysis tool based on Artificial Intelligence whose task is to categorize the performance of production wells based on the efficiency value of the pump to the thickness of the liquid. The results of Quicklook Mapping Tools aims to provide performance mapping of Rod Pump and ESP in the field and identify existing production optimization opportunities. Quicklook Mapping Tools requires input data, namely identification of well names, volumetric efficiency based on production tests, and operating parameters such as pump size, stroke length, SPM for rod pumps; pump capacity, pump curve, running frequency for ESP and data Pump setting depth - Dynamic Fluid Level. The data is inputted into the program to produce 4 quadrants, namely (1) High Submergence, Low Pump Efficiency (2) High Submergence, High Pump Eff (3) Low Submergence, High Pump Eff (4) Low Submergence, Low Pump Eff. By implementing Quicklook Mapping Tools, it gives extraordinary result. It is fast and accurate in giving information about well performance and behavior.

The artificial intelligence result of Quicklook Mapping Tools are described such as (1) increase the frequency of the existing artificial lift (2) increase pump capacity (3) ideal conditions for artificial lift (4) subsurface evaluation such as workover or well intervention program. It really gives easiness to Petroleum Engineer in observing well performance and taking decision and actions to the well.

A transformation well performance and behavior analysis method using Artificial Intelligence helps petroleum engineers to increase the production in fast and accurate way
Integrated Performance Workflow to Optimize ESP Daily Operations
Authors: Al-Jazzaf Abdulla M. , Shehab Abdulaziz , Abdal Abdulaziz , Al-Askar Hamad
Published: October 2023

abstract

The Kuwait Oil Company’s (KOC) has significantly increased its dependence on Artificial Lift systems (AL) to reach their yearly production targets. Multiple AL systems are deployed however the major AL system used is the Electrical Submersible Pump where currently there are over 3,300 ESPs accounting for about 70% of the company’s production. Initial implementation of ESPs at the company started in the 1980s, throughout the next few decades only a handful of ESPs were installed. In 2008, ESP installations increased rapidly and currently these ESPs are producing most of the oil production within the company. Over the past 5 years, the ESP population has doubled with additional installations each month. Forecast shows that the ESP population would surpass 4,000 ESPs in 2024. The company’s ESP operations is divided into four main assets, North Kuwait, South Kuwait, East Kuwait, and West Kuwait. Each asset has their own staff that monitor the wells under their scope and aim to maximize production and operating life of these ESPs. Each asset is managed by a Team Leader that looks at the total asset’s operations, production, and performance. Each Team Leader has a number of Senior Engineers divided into well clusters that manage their own clusters, and each Senior Engineer has 2 – 4 Field Engineers that monitor both short term and long term performance on each individual well.
Onshore Electrified Rig, A Sustainable Strategy
Authors: Dumoulin Mélissa
Published: October 2023

TotalEnergies is a major global energy company with significant operations in oil, gas and renewable energy sources. The company Net Zero 2050 ambition sets a strategy to mitigate its carbon footprint and limit global warming. Reducing the carbon emissions across its value chain is a key aspect of reaching these ambitions. It involves adopting cleaner technologies and thus powering rigs with electricity instead of diesel engines for onshore drilling operations.

TotalEnergies is operating two electrified rigs in Tempa Rossa onshore field in south Italy. During the Gorgoglione-2 (GG-2) drilling project, multiple data have been collected to assess the potential of the rig electrification.

Thus, this paper presents the implementation and the benefits of an electrified drilling rig provided by a gas turbine on the nearby plant. The GG-2 drilling project’s data are used for the following purposes. To highlight the role of the different equipment and their articulation.To acknowledge the fuel gas consumption required to generate electricity and the cost associated.To calculate the GHG net saving and the cost saving applied to Gorgloglione-2 drilling project.To estimate the gain for future projects.

The objective is to give an overview of the rig electrification in this onshore context to provide guidance to other Oil and Gas (O&G) Operating affiliates willing to consider it.
Developing Mature Oil Rim Reservoirs with Large Gas Cap and Weak Aquifer: Key Decisions and Approach, Using A Mature Field in Oman as Case Study
Authors: Kumar G. , Khadhuri S. , Gharbi M. , van Neck H. , Hajri Y. , Yazidi R.
Published: October 2023

This paper describes key decisions and approaches that can be taken to help decision making for late life development of oil rim reservoirs with large gas cap and weak aquifer, with a case study from a mature field in Oman. The integrated approach evaluates different development options for economics, reserves addition and GHG emissions, and recommends the best one as per project value drivers.

Field X has been producing for more than 35 years, first 20 years on primary depletion, followed by produced gas re-injection which is continuing till now. The power and fuel requirements for compressing and re-injecting the gas makes production from this field very GHG intensive. Recently, production from the field has dropped significantly, even though current oil recovery factor is low. The asset team did a full analysis of recovery, GHG and economics to compare various development options, and recommended the optimum development plan based on project value drivers.

Field X currently produces relatively small amount of oil with large amount of associated gas at ~50% water cut and emits large amount of GHGs for a barrel of oil. Water flood development adds incremental oil reserves but requires drilling of additional water injectors and new horizontal producers, which adds to the project capex. Gas blowdown on the other hand erodes oil reserves, but it requires very little additional capital, and reduces lifecycle GHG emissions significantly. Start of gas blowdown timing has interesting impact on the project economics, which gets further complicated by trend of overall gas demand.

Overall, the trade-off exists between incremental oil reserves and NPV on one side and capex and GHG emissions on the other side, for different development options. The best development option in this case was to continue with water flood given promising pilot results. However, the full analysis must be done on case-by-case basis and will depend heavily on oil price and gas demand.

Usually, the development options are evaluated for reserves and economics. In this case study, the analysis was expanded to include lifecycle GHG emissions, while evaluating development options. It was quite a challenging piece of work, further complicated by gas demand forecast and supply forecast from other fields in overall demand supply balance. The analysis can be replicated by other projects, with modifications if required on case-by-case basis.
Increasing Electric Submersible Pumps Run Life: How to Mitigate the Impact of Sensor Data Loss?
Authors: Guillca L. N. , Enriquez L. , Batallas E. , Reyes C. , Tagarot G. , Campana D. , Segovia R. , Andagoya K. , Hidalgo M. , Naranjo R. , Villabos J.
Published: October 2023

Performing a health check on electrical submersible pumps (ESPs) is possible using measurements from the downhole and surface gauges. The downhole data lost significantly reduces the detection of operational issues (i.e., gas lock, recirculation, etc.), and shortens the life expectancy. This analysis summarizes the reasons and impact on the reliability when losing downhole sensor data in a mature field with 230 active ESPs exhibiting 1,580 days of mean time between failure (MTBF).

Seventy-two cases of ESP strings with sensor data loss were analyzed during 6 years of operation using their failure reports, pulling reports, and failure analyses.

Using statistical methods and root-cause analysis tools, the average running time that an ESP survives without sensor data transmission in comparison with the systems with full data transmission was calculated and plotted.

In this paper, we identify the causes of sensor data loss, which are events related to data transmission system (40%), operational conditions (37%), mechanical events (19%), and electrical events (4%).
Innovative Analytical Approach to Eliminate Repetitive Unmanned Offshore Oil Platforms Interruptions
Authors: Ghanem Hashem H , Georgiou Ioannis , Mana Khaled A
Published: October 2023

More than 50% of the outages (trips) are attributed to malfunctioning Emergency Shutdown (ESD) systems. Therefore, it is deemed necessary to upgrade these aging and obsolete systems with the latest up to date technology. 39% of the offshore oil platforms outages are attributed to hydraulic system failures. This analytical approach can be applied to any offshore oil field for minimizing the undesirable trips and developing control methodology of the oil field outages. Part of the assessment methodology that needs to be considered is to study the repetitive outages seasons. This is to predict the timeline of the outages and identify the root causes to reach the proper solution. This analytical approach can be applied to any offshore oil field for minimizing the undesirable trips and developing control methodology of the outages.
Achieving Zero Routine Flaring from Block 60 Oil Production Facilities
Authors: Al Siyabi Manal , Al Ajmi Arwa
Published: October 2023

This paper illustrates the study undertaken by OQEP to comply with the goal of Zero Routine Flaring (ZRF) from oil producers by 2030 as mandated by the Ministry of Energy and Minerals (MEM). The ZRF goal is one of the numerous global initiatives toward achieving Net Zero Emissions by 2050 as per the Paris climate agreement. The study conducted by OQ Exploration and Production (OQEP) concept team is applied to flare recovery from Block 60 On-plot oil processing facilities. This article will focus on the methodology used to recommend the most optimal solution to recover an associated gas range of 0.5 MMSCFD to 3 MMSCFD.

The article describes the concept selection process carried out by the concept team at OQEP, to identify both the concept evaluation criteria and a divergent range of possible options to recover and utilize the flare gas. OQEP Opportunity management system policy was followed to conduct this study where the project was taken through an initiation stage to identify the challenge including identification of decisions and evaluation criteria, feasibility assessment where a wide array of options was explored and screened, and a final concept selection stage where the screened options were further optimized for final concept selection. To ensure an optimal concept was selected a wide array of technologies for recovering the associated gas from the existing on-plot facilities including conventional and novel technologies were explored.

The study noted the impact of the quantity of gas recovered on the final economic and environmental performance, in addition, the number of gas source points were also identified as an important decision as the gathering system can impact both the energy efficiency and the life cycle cost of the project. These decisions have been evaluated against the selection criteria and critical success factors.
Successful Implementation of Waterflood in Mature Oil Fields – A Case Study from South Oman
Authors: Borkent E. , Mufarji M. , Morianta M. , Busaidi I. , Mahrouqi I. , Al Badi M. , Ibrahim A. , Harthy M. , Al Kindi S.
Published: October 2023

Field A is one of the largest oil fields in the South of the Sultanate of Oman. The field was discovered in 1975 and has been in production since 1989 under depletion drive utilizing the aquifer support. The main producing reservoirs are part of the Haima Group, which are characterized by good quality and homogeneous sands, but the oil is viscous up to 1300 cP. After over 20 years of production, depletion levels in the field were getting high and a new development strategy was initiated by introducing water injection.

The waterflood development concept chosen for this mature field was injection deep into the aquifer at about 100 meters below the oil-water-contact. 38 vertical water injectors were drilled at regular spacing across the field area. As part of the waterflood development, 6 injector wells were completed just below the oil-water-contact as part of a shallow injection trial. These wells are fitted with fiber optics to allow regular temperature surveys and monitor fracture growth. Surveillance in all injectors is done on a regular basis to ensure conformance and prevent significant upwards fracture growth.

The water injection started in December 2014 and ramped up over the following years to the target level. The pressure response from the injection scheme was initially slower than expected especially in the crestal area of the field. A comprehensive water injection performance analysis was conducted, and several remedial actions were initiated by the team to improve waterflood performance. As water production from the field itself was below the forecasted rate, make up water was brought from nearby fields.

After overcoming the initial challenges, the field is now injecting as per the target rate. And a clear response to the waterflood has been observed through an increase in reservoir pressure. The estimated recoverable volumes increased by about 10%, a very significant addition. The increase in reservoir pressure has also helped to conduct many WRM optimizations like well bean up, artificial lift optimizations and well stimulations. The increase in reservoir pressure has also opened the door to significantly increase field offtake rates through a dedicated conversion campaign by replacing Beam Pumps and Progressive Cavity Pumps by Electric Submersible Pumps. This allowed increased gross offtake and higher net oil production. As a result, Field A achieved record production over 2022, the highest level in 5 years.

Changing the field development of such a mature field has come with numerous challenges, but the success also proves that late field-life waterflood can add significant value. This is replicable to many other oil fields in the South of the Sultanate of Oman and beyond.
Achievement on Automatically Simulation Model Calibration to Provide Fit-For Basin 4D Fea Dynamic Drilling Analysis
Authors: Liu B. , Ma J. , Xu Y. P. , Huang Y. S. , Feng F. , Xu G.
Published: October 2023

After years of using 4D simulation for drilling product design and service event root cause analysis, there is a growing demand for an automated workflow that can provide a standardized and efficient model calibration process. This workflow aims to reduce the dependency on manual adjustments, improve the accuracy of simulation inputs, establish a strong correlation between simulation results and field measurements, and enhance drilling performance prediction. To achieve these goals, the auto calibration workflow incorporates various optimization techniques based on the physics and attributes of drilling simulation engines. For instance, grid search is employed to optimize discrete formation descriptions using a library of test rock files, while gradient descent is utilized for the optimization of continuous model parameters. Furthermore, the optimization of certain model parameters is simplified by leveraging special drill state data, thereby reducing the complexity of the overall optimization process. These approaches have significantly improved the performance of optimization, even when dealing with computationally intensive simulations. This paper provides a comprehensive review of the newly developed automated calibration workflow, including the algorithm development and field results. It also discusses the lessons learned from this work and outlines future directions for research and development.
Sand Clean Out With Coiled Tubing and the Use of a Special Sand Clean Out Tool: A Case Study in Depleted Wells in Colombia
Authors: Cortés Caterin Barrera , Sanchez Miguel , Hampson Richard
Published: October 2023

Cleaning sand effectively from horizontal wells with slotted liner, low formation pressure, and lost circulation can be very challenging. This paper begins by examining all the relevant factors to develop a suitable job design and applying it to the given conditions for successfully removing sand from depleted wells in Colombia using Coiled Tubing (CT) and a Special Sand Clean Out tool (SSCOT).

The main considerations for the cleanout of depleted wells will be examined, and the steps required to carry out the correct execution of the well cleaning will be shown, considering the main risks that can occur while carrying out the operation. Post-job evaluation is performed to ensure a successful sand cleanout was achieved.

During cleanout of these types of wells, it is necessary to use tools that create turbulence in conjunction with gelled and foamed fluids to keep the particles suspended without affecting the well's productivity and allowing full access to the target depth. Once the cleanout is complete, placement of screen liners in the producing zones can be carried out successfully, reducing future sand production and recovering the production of these wells that have been shut down for many months, even years, due to sand plugging, affecting productivity of the entire field.

Foamed fluids were used for efficient and effective sand cleanout due to the resulting low hydrostatic pressure that reduces the possibility of lost circulation, its high solids transport capability, and compatibility with the formation fluids. This was combined with carrying out the operation using a Special Sand Clean Out Tool (SSCOT), effectively reducing the probability of sticking the CT and achieving efficient sweep results.
CO2 as a Service (CO2aaS) Advisory and Optimization Contractual Models for Critical Production Assets
Authors: Porciani Daniele , Parrella Ilaria , Lauriola Michele
Published: October 2023

Based on the existing knowledge and capabilities of rotating equipment and critical energy systems, industry players are developing and implementing solutions for Emissions Monitoring and Optimization ("EM&O") solutions, aiming advanced monitoring and advisory as well as emissions reduction targets within their Environmental, Social and Governance ("ESG") policies (e.g. Oil & Gas Methane Partnership 2.0 – "OGMP 2.0" or the United States Environmental Protection Agency GreenHouse Gas Reporting Program – "GHGRP").

By 2021, compliance markets had an annual trading value of more than $900bn, with the European Union ("EU") Emission Trading System ("ETS") by far the biggest, accounting for about 90 per cent of trading volume and value that year (LSEG Market Research, 2023). Much smaller, voluntary carbon markets, for their part, have seen the value of transactions rise sharply from $520mn in 2020 to $2bn in 2021 (Ecosystem Marketplace, 2023). However, growth has come with implementation challenges with waivers, trade-offs and policy postponements, raising questions over the extent to which these markets are reducing global emissions.

Meanwhile, the EU ETS's policy of giving free allowances to heavy industries as long with other policymakers postponing or providing "carbon waivers", along with what until recently were low and volatile prices, carbon pollution credits and/or taxes have been considered too cheap to incentivise large-scale investments in clean technology and/or to oblige users in adopting "green" technology.
Techno-Economic Assessment of Crude Oil/WaterEmulsion Separation Efficiency
Authors: Aljabrine Mashhor , Fairweather Neil
Published: October 2023

The objective of this study is to conduct a techno-economic assessment to identify the necessary investment for maximizing profitability in existing oil processing facilities. As oil reservoirs transition from primary to end of secondary recovery, many processing facilities face challenges due to an increasing water cut. Despite advancements in oil and gas production separation equipment, these facilities must maintain production at the forecasted capacity, leading to potential capital expenditure.

When the water cut surpasses the typical dehydrator's operating envelope (around 30-40%), additional measures are required to reduce the water content and bring the dehydrator inlet water cut back within its operational range. Typically, the conventional approach involves debottlenecking the wet crude handling system by introducing additional process equipment to decrease the water cut into the dehydrator.

However, this assessment explores an alternative solution by maximizing the utilization of existing production separation traps, such as three-phase separators. The study calculates the actual water separation efficiency and considers installing dual frequency desalting technology to replace the standard dehydrator.

The results of this techno-economic assessment indicate that by optimizing the crude oil separation efficiency, the need for immediate capital expenditure can be deferred. This approach allows existing oil processing facilities to efficiently manage the increasing water cut and maintain profitability without significant upfront investment.
Successful Reduction of GHG Flaring Emissions in South Oman Cluster Using Simple CI Tools
Authors: Mandhari A. , Ramakrishnan P. , Maskari M. , Hadhrami A. , Mihajlov R. , Shukaili A. , Tobi Y.
Published: October 2023

Controlling oil and gas stations effectively to reduce GHG emissions is a crucial step in mitigating the effects of climate change. This study focuses on identifying and applying the strategies available for reducing GHG emissions from the South Oman Sour Cluster. Minimizing flaring attributed to facilities instabilities, leads to flaring, as well as flaring on planned shutdowns and start-ups using six sigma approach and cut down the average flaring by 35% through operational excellence.

Controlled flaring during Shutdowns, start-ups and partial trips of production units, a novel thought of a simple Six-Sigma CI approach. Back pressure control in the chokes of each well, which directly balances/controls the flow line pressure, controls bubbling effect in the TH and NAG and results in better GOR. This phenomenon occurs in many natural and engineered systems. HP separators in Station-H operate at 85 BarG. Well chokes control NAG release. Back pressure control technique is applied to wells in a unique way, which maintains constant pressure in the flow line and optimizes flow of oil and gas from the reservoir.

Project Benefits (During the pilot period from 01/05/2022 to 05/05/2022) lead to Flare reductions in Station-H which reduced flaring during start-ups of the station by 35% taken on an average of 5 days and reduced flaring during any unit trip by 55% with Yearly reduction. Deferment savings of 0.8M $ in each start-up and S/D. back pressure controls applied using chokes, enabled flow optimizations to each well to reduce annual GHG emission by 13 k tone/year of CO2. Compressed sour gas from LP/IP compressors diverted to Gas sweetening units converted in to sweetened gas. If any compressor trips, or S/D well chokes in back pressure control reduce gas feed/ cutoff feed to HP Separators. Back pressure controls abnormal fluid behavior is controlled in tubing head. Under controlled pressure more oil flow occurs, reducing NAG gas flow. This prevents undesired situations like producing more injected gas than crude oil from the oil reservoir. Back pressure control applications directly reduced flaring of NAG and yielded better GOR without major changes in the process. Flaring control and reducing GHG emissions to ZERO is the long-term objective of our team by effective application of CI, six sigma and operation excellence. Flare Gas Recovery projects deploy new technologies to recover gas such as energy transformation and waste heat regeneration in the aim of achieving GOAL ZERO.
Title- Planning and Contract Management Strategies for Successful EPC Project Execution
Authors: Mahajan Aniruddha , Baride Milind
Published: October 2023

EPC Project execution is always a complex task requiring amalgamation of multiple engineering and technical skills along with Project Management excellence. Projects cannot be successfully executed only by the Owner, PMC, and EPC Contractor alone but require vendors, subcontractors, and service providers whose role and performance are key to project success. Successful EPC project execution requires the strategy to onboard the right stakeholders onto the project at the right time in a planned manner during the various execution stages of the project and ensure that they promptly deliver on time, safely as per the technical specifications, within budget as per plan and Contract. Thus, ensuring that every stakeholder delivers as per the plan and the Contract will ensure that an EPC project is successful.

The strategy for Project execution depends on several factors which include amongst others scale and complexity of the project, the business environment, location of project site, general market conditions, availability of skilled engineering and construction resources. Too often the focus is on getting the Project execution right with strategies focused on the above drivers without focusing on the underlying people constituting the project team who are going to execute the strategy and the project.

Projects are temporary endeavors with a definite beginning and end to achieve specific goals. Projects assemble large groups of highly skilled cross functional resources on a temporary basis to deliver project goals and the outcome of the project will depend on how this temporary team functions, collaborates and delivers. This is the biggest internal challenge of the Project team, one which can make or break the project success.
Wells Around Formation Issues WAFI Tool-Machine Learning Tool to Extract Field Issues from Daily Reports
Authors: Al-Taha Ahmad , Al-Sulaimani Tariq , Al-Bahri AL-Salt
Published: October 2023

The objective of this paper is to share and introduce the Wells Around Formation Issues [WAFI] tool, which was developed by Petroleum Development Oman LLC [PDO] - collaboration between Well Engineering and Data Science teams. This tool's function is to extract Formation Issues from the Daily Drilling Operation Reports [DDOR\ & Other Reports entered by Drilling Site team and display them per formation per field. WAFI is a cutting-edge Well Engineering solution that employs Text Mining techniques to automatically provide offset well information, significantly enhancing efficiency and reducing manual labor spent on data extraction from disparate databases and analysis in Excel.This advanced solution facilitates a deeper understanding of complex relationships between neighboring wells and the well to be drilled. By optimizing this process, our approach aims to effectively pinpoint potential challenge areas, thereby augmenting drilling operations and sustaining overall project success.The tool was trialed in 3 fields in PDO, and it managed to pick up most of the drilling and formation issues identified and expected in each field and in offset wells, based on the Trained Machine Learning Model.The tool picks up the Depth at which the issue occurred, and it links it to the Formation being drilled. The results are viewed in a formation level view or at a Well level view, so it will give an overview of the field issues in offset wells. This will help Team for better planning and preparing for the upcoming wells, and of understanding of the Fields issues.The tool picks up the following Issues: Tight spots, Over Pulls, Reaming and Back Reaming, Vibrations, Stick & Slip, Bit Balling, Fish, Lost Circulation, Fluid Influx, Stuck Pipe & Drill String Failure.The parameters being picked by the model are: Loss Rate range, Flow Rate, Torque, RPM, Overpull and ROP [Rate of Penetration].This is Phase One of the Tool development, and next plan for Phase Two will include more functionalities and more features, Parameters and enhancements to the tool. Both phases will be discussed in this paper.
Rigless Thru-Tubing Gas Lift Retrofit System Optimizes Production in Shut-In Well by Deepening Injection Point Below Production Packer
Authors: Suhaimin F. , Sabri D. , Gutleber S.
Published: October 2023

Well A, a Brownfield offshore oil producer in Brunei, was shut in due to multiple leaks in the tubing. The well was drilled in 2000, so was facing common issues associated with depletion prior to shut-in. Production from the well was restored by installing an innovative thru-tubing retrofit gas lift system, allowing for injection of lift gas below the production packer, while simultaneously restoring tubing integrity by isolating the leaks.

The goal of the rigless intervention was to restore tubing integrity by installing an ISO 14310 V0-validated gas-tight straddle across the leaks. The straddle also serves as a retrofit gas lift system, enabling delivery of lift gas below the production packer, just above the horizontal open hole gravel pack section. The straddle directs lift gas down an inner string hung from the lower packer with an installed gas lift mandrel on the bottom of the tail pipe, delivering lift gas below the production packer. The straddle features internal flow paths, allowing produced fluid to flow through the straddle back towards surface.

Once installation was complete, the new gas lift valve was installed 200 m TVD (true vertical depth) deeper than the lowermost side pocket mandrel. During the initial well test, lift gas was injected down the casing and entered the production tubing through the leak points and SPM, which were contained within the straddle assembly. The upper and lower packing elements in the straddle directed all gas through the crossflow sub and into the inner string suspended from the lower packer. A slim gas lift valve was connected to the downhole end of the tail pipe. By injecting lift gas in the lower completion, hydrocarbon was unloaded from a deeper depth than would have been possible using conventional gas lift. Within four hours of starting lift gas injection, Well A was flowing steadily with 900 kPa of flowing wellhead pressure (FWHP). The well was then shut in, pending a full well test.

This novel approach helped avoid an expensive workover and minimized runs in hole by incorporating the gas lift retrofit system into the straddle isolating the tubing leaks. This installation was the first in Brunei that placed the lift gas injection point beyond the production tubing in a horizontal well. As a result, a well that had been shut in for five years was re-instated and production was further optimized by deepening the lift gas injection point 200 m TVD below the lowermost side pocket mandrel.
Leveraging IoT, Machine Learning and Cloud to Deploy at Scale Remote Monitoring Capabilities in Coal Seam Gas (CSG) Well Pads
Authors: Shekhawat D. , Shannon C. , Grover R.
Published: October 2023

Coal seam gas (CSG) is a naturally occurring methane gas found in most coal seams and is similar to conventional natural gas. CSG is a major source of energy, accounting for about 15% of Australia's electricity generation. Also, CSG is an integral part of the gas industry in eastern Australia, particularly in Queensland. Origin Energy is the upstream operator for a leading joint venture in Australia and is responsible for the development of its CSG fields in the Surat and Bowen basins as well as the main transmission pipeline that transports the gas to the LNG facility on Curtis Island near Gladstone, Queensland.

Origin Energy has been exploring ways to leverage modern technology solutions to increase field staff productivity, reduce operating costs per well, and improve asset reliability while also bringing more wells into production to meet growing customer demands. Field operators drive up to 100km per day and may have up to 20 well visits per day as part of a routine inspection that involves visual checks of the site to gain situational awareness.

In recent years, with advancements in technologies such as edge compute (IoT), modern network connectivity options (satellite, narrow-band LTE) and Machine learning (no-code/low-code solutions) leveraging Cloud infrastructure early experiments are suggesting the implementation of safe, reliable, low-cost remote monitoring capabilities at scale is a possibility.

This paper discusses how Amazon Web Services (AWS) collaborated with Origin Energy to deploy a trial focusing on remote monitoring of well pads using a camera solution. This trial captures images from the well pad at regular intervals, which when scaled out will help reduce the need for routine inspection of well pads by field operator at the current interval. This trial has also developed a data repository of all the images in the AWS Cloud and is designing a data processing pipeline to label images and use low-code/no-code ML to detect visual anomalies.

In addition to the Origin Energy use cases (described in use case section 2.1 and 2.2) AWS has also helped an operator in North America (use case section 2.3) with building Machine learning models using Amazon SageMaker for anomaly detection. Hence, based on these projects it has become evident that using IoT, Machine Learning, and Cloud computing can accelerate innovation that drives down cost and increase operational safety of managing Oil & Gas assets remotely.
Decommissioning a Lightweight Marginal Field Platform: Challenges and Journey to Successful Execution
Authors: Yee Teh See , Badrol Raja Sharifuddin Ahmad B. Raja , Shaharuddin Noor Hidayah , Zakaria Amirah Bt C. , Alifah M. Norfisyah B. , Azali M. Syaifullah B. M. , Kasah M. Aziehan Mat
Published: October 2023

As reserves of some of the oil and gas field start to deplete, and in addition, certain platforms have reached their end of design/producing life, it comes the time for the relevant platforms to be removed and disposed or widely known as decommissioning. Topsides decommissioning includes complete removal while the substructure removal options include total removal for onshore disposal, reefing (in-situ or ex-situ) and leave in-place. This paper will discuss the recent Malaysia offshore decommissioning project which had been completed in June 2023. This project was distinctive from other decommissioning projects as the decommissioned topside would be re-used and refurbished by other operator for a new oil and gas development project.

The decommissioned platform was designed as a three (3) legged conductor-supported platform which was installed by jack-up rig. Located at only 3.3 Nautical Miles (circa 6.1km) offshore Kuala Baram, Sarawak Malaysia, its soft soil condition makes it too risky to remove the platform using the jack-up rig based on the challenges/complications encountered during post-installation. The shallow water depth of 10 meters limits the lifting vessel selection as well as its associated marine spreads. These had contributed many challenges in planning the wells P&A and the overall facilities removal. Furthermore, the concept and removal methodologies for this ‘conductor supported platform’ would be different from any other typical wellhead platforms.

This paper will elaborate the entire decommissioning process and its challenges in all the phases, including wells abandonment, pre-abandonment survey and data gathering, engineering, decommissioning, structural removal and transfer, disposal, and final site clearance. The engineering study, cutting tools selection, removal sequences and vessel selections played important roles in succeeding the entire campaign.

In addition to the technical challenges, this paper will also discuss the schedule and cost optimisation that the Project Management Team had put an effort into.

This paper should be an interest to those who are exploring platform and facilities abandonment and decommissioning, and we will walk the reader through the whole journey of the platform facilities decommissioning and removal.
Unlocking Potentials of Big Data: A Method for Enhancing H2S Specification in NGL Product From Condensate Stripper Column
Authors: Bajuaifer Hatem A. , Khan Ashiff– , Hawsawi Ahmad M. , Otaibi Majed M.
Published: October 2023

This paper covers an optimization study in Saudi Aramco Khurais Facility through data analytics and modeling to enhance NGL Quality and maximize C3+ Yield through Process Modeling and big data statistical modeling of correlations. The paper objective is to:

Share the optimization approach and how it can be replicated. Presents the results and outcomes of this optimizations along with utilized big data approaches.

The main concept of this study is to utilize a big data approach to analyze +5 million data point to discover unknown relations between various parameters that cannot be explained from process point of view. Moreover, the discovered relations and other parameters were further investigated through statistical models of correlations. The generated results were evaluated from process point of view to be utilized in enhancing NGL quality and maximize the yield through developing new process schemes and system modifications via HYSYS simulations followed by a field trials prior actual deployment on plant level.

This optimization approach resulted in discovering three new process schemes to enhance NGL quality and maximizing product yield including:

External vapor propane injection to stripper column to artificially increase the traffic in the column and maximize the yield where a portion of the propane will be condensed in the column and generate more liquid volume of the higher product value (i.e liquid NGL) Vaporizing a slip strip from generated NGL to increase the traffic in the column artificially to increase the confidence level in maintaining the product quality to 99.7% (i.e 3 standard deviation). Vaporizing a slip stream of OFF-SPEC product to artificially increase the traffic in the column and maximize the yield.

The main outputs of this optimization are:

Developing 3 novel process schemes for hydrocarbon condensate processing. Increasing the confidence level of maintaining product quality to 99.7%. Generating additional value of additional NGLrecovery.

The novelty in this paper is the approach to utilize big data and multivariate analysis along with process modelling to identify hidden relations and factors impacting yield and product quality that resulted in developing new process schemes to increase NGL yield and the confidence in achieving quality specifications to 99.7%. This process along with developed process schemes can be replicated and add benefits to any gas plant that utilize stripper columns for NGL sweeting process resulting in multiple circular economy initiatives and ideas such as reducing reprocessing time, reducing feed stock and reuse of off spec products in better applications.
PDO Waterflood Gap to Potential Focus Area and Key deliverables from Central Waterflood Team
Authors: Al Balushi F. I. , Hadfield N. S. , Al Brashdi D. K. , Al Shaaili M. M. , Al Hinai K. M.
Published: October 2023

PDO waterfloods over 70 fields in both North & South Directorates with full range of geology and developments concepts like: carbonate & clastic, light & heavy oil (1cP - +3000 cP), five spots, peripheral, line drive, Horizontal & Vertical. Waterflooded fields anticipate wide range of challenges which are related to pattern size, well count, Water quality & Injectivity decline, Vertical & Horizontal Conformance, Metering & Surveillance, Integrity & Facility constraints, and lack of well & reservoir management models that used for quick optimization. 50% of PDO Production & Reserves is delivered through Water flood Projects.

Around 90% of waterfloods were not using baseline or models in which to compare their performance to help driving opportunity and threat management (e.g., Top Quartile Recovery factor, Tube model, Field Development plan models, external benchmark). In PDO Many fields were having low throughputs leading to slow recoveries from Waterflood, and injection decrease as BSW increases. Also, effective sweep optimization was not stablished in both how to achieve it and how to demonstrate the benefits. Finally integrated optimization of both surface and subsurface opportunities is lacking in many projects.

In 2019 PDO established the definition of the Waterflood gap to potential in terms of throughput and sweep, and this will be used to identify individual fields with Gap to Potential and opportunities to close the gap above those currently captured Program Build Cycle. Additionally, Waterflood Improvement plan was developed based on deep dive exercise which aim to improve production by reducing Field decline rate as result of optimisation

Getting the right amount of water, of the correct Quality Improve sweep oil in the most effective way Reduce the opex cost of water flooding
Deployment of Automated Dynamic Kill System to Manage Well Control Activities in High Risk Shallow Gas Cap Wells
Authors: Al Salmi Ammar Hamed , Al Makhmari Nasser Issa , Al Naamani Noaman Hilal
Published: October 2023

One of the greatest dilemmas in Petroleum Development Oman in workover operation is incidents related to gas cap wells where primary well control barrier is maintained by dynamic kill methodology which is the use of fluid velocity to prevent gas evacuation to surface. This paper discusses the well control method in oil wells associated with gas cap by automation and innovation of Dynamic-kill equipment and procedures. Gas cap wells which are located in the north of Sultanate of Oman are considered as high-risk wells from well control prospective. For long period of time, conventional killing manifold has been used to establish the filling rate to maintain the primary well control barrier. Multiple failures occurred related to the reliability of the conventional system which inspire the need of new methodology. Statistical analysis study was carried out to identify the well process safety incidents related to workover activities in gas cap wells. Moreover, route causes analysis took place to identify the main challenges using the conventional kill manifold system.

This paper highlights the use of [Automated Dynamic kill system, Rotating control device (RCD)] which was implemented for the first time and resulted in a significant reduction in Well Process Safety risk exposure, people exposure and environment exposure.

This paper will give an overview about the old system and its related operational challenges that created an opportunity to innovate and design a new system. The new system went through a unique design process to fulfil and overcome the associated challenges of the conventional system. Commissioning phase for the new system carried over to identify the limitation and confirm the reliability of the new dynamic kill system by performing several tests including extended function test, flow test and logarithm accuracy test. Several enhancements were added based on field trails and requirements to meet the optimum system delivery as final product. In addition to the final approved system, RCD (Rotating Control Device) was utilized as a fail-safe system to provide sealing mechanism around the pipe and to act as an additional barrier in case of primary barrier loss. The combined systems led to improvement in HSE by reduction in human dependency by 70% as well as significant reduction in WPS incidents related to gas cap wells. Finalizing the paper by visual comparison between the conventional and automated systems in terms of HSE and operational aspects.