bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of an Artificial Intelligence-Based Well Integrity Monitoring Solution
Authors: Aditama Prihandono , Koziol Tina , Dillen Dr. Meindert
Published: October 2022

The question of how to safeguard well integrity is one of the most important problems faced by oil and gas companies today. With the rise of Artificial Intelligence (AI) and Machine Learning (ML), many companies explore new technologies to improve well integrity and avoid catastrophic events.

This paper presents the Proof of Concept (PoC) of an AI-based well integrity monitoring solution for gas lift, natural flow, and water injector wells. AI model prototypes were built to detect annulus leakage as incident-relevant anomalies from time series sensor data.

The historical well annulus leakage incidents were classified based on well type and the incident relevant anomalies were categorized as short and long-term. The objective of the PoC is to build generalized AI models that could detect historical events and future events in unseen wells. The success criteria are discussed and agreed with the Subject Matter Experts (SMEs). Two statistical metrics were defined (Detected Event Rate – DER – and False Alarm Rate – FAR) to quantitively evaluate the model performance and decide if it could be used for the next phase.

The high frequency sensor data were retrieved from the production historian. The importance of the sensor was aligned with the SMEs and only a small number of sensors was used as input variable. The raw data was pre-processed and resampled to improve model performance and increase computational efficiency.

Throughout the PoC, the authors learnt that specific AI models needed to be implemented for different well types as generalization across well types could not be achieved. Depending on the number of available labels in the training dataset, either unsupervised or supervised ML models were developed. Deep learning models, based on LSTM (Long-Short Term Memory) autoencoder and classifier were used to detect complex anomalies. In cases where limited data were available and simplistic anomaly patterns were present, deterministic rules were implemented to detect well integrity-relevant incidents. The LIME (Local Interpretable Model-Agnostic Explanations) framework was used to derive the most important sensors causing the anomaly prediction to enable the users to critically validate the AI suggestion. The AI models for gas lift and natural flow wells achieved a sufficient level of performance with a minimum of 75% of historical events detected and less than one false positive per month per well.
Rapid NMR T2 Extraction from Micro-CT Images Using Machine Learning
Authors: Li Yiteng , He Xupeng , Alsinan Marwa , Kwak Hyung , Hoteit Hussein
Published: October 2022

Nuclear magnetic resonance (NMR) is an important tool for characterizing pore size distributions of reservoir rocks. Pore-scale simulations from digital rocks (micro-CT images) provide deep insights into the correlation between pore structures and NMR relaxation processes. Conventional NMR simulations using the random walk method could be computationally expensive at high image resolution and particle numbers. This work introduces a novel machine-learning-based approach as an alternative to conventional random walk simulation for rapid estimation of NMR magnetization signals.

This work aims to establish a "value-to-value" model using artificial neural networks to create a nonlinear mapping between the input of Minkowski functionals and surface relaxivity, and NMR magnetization signals as the output. The proposed workflow includes three main steps. The first step is to extract subvolumes from digital rock duplicates and characterize their pore geometry using Minkowski functionals. Then random walk simulations are performed to generate the output of the training dataset. An optimized artificial neural network is created using the Bayesian optimization algorithm.

Numerical results show that the proposed model, with fewer inputs and simpler network architecture than the referenced model, achieves an excellent prediction accuracy of 99.9% even for the testing dataset. Proper data preprocessing significantly improves training efficiency and accuracy. Moreover, the inputs of the proposed model are more pertinent to NMR relaxation than the referenced model that used twenty-one textural features as input. This works offers an accurate and efficient approach for the rapid estimation of NMR magnetization signals.
Fenja Digital Twin with Automated Advisory: A Solution for Operational Excellence
Authors: Forooghi Alireza , Trudvang Christian , Gupta Gaurav , Kjoerrefjord Gustav , Karimi Hassan
Published: October 2022

In this paper we describe the Fenja Digital-Twin solution, its automated advisory workflow, and how it enhances operational excellence and further strengthens the operational health, safety, and environment (HSE) vision of Neptune Energy. The Fenja development is a subsea tieback to the Njord-A platform located in the Norwegian Continental Shelf. Fenja wax and hydrate management strategies are based on active heating of the world's longest electrically traced heated pipe-in-pipe (ETH PIP) as the primary layer of protection.

The Fenja development demands a reliable and robust solution to address flow assurance challenges and support operational activities planning (production management, shutdown, startup, virtual metering, hydrate/wax formation preventions, ETH pipeline operation, and chemical tracking). A digital twin solution deployed for the Fenja development uses the integrated power of machine learning and data analytics with multiphase flow simulation, enabling enhanced efficiency and transforming operations.

The Keep-Warm and Warm-Up advisory workflows help reduce carbon dioxide (CO2) emissions to the environment by optimizing the ETH pipeline power consumption and empowering the operational decision-making process for operations.

Leak detection advisory (LDA) uses data analytics, signatures analysis, and pattern recognition to rapidly detect potential leaks of fluids from hydrocarbon pipeline. Combining digital twin with data analytics makes detecting leaks more precise and avoids false alarms. A faster and highly precise LDA advisory can potentially minimize a great deal of hydrocarbon loss to the environment in a real leak event. In the test environment for the factory acceptance test, the LDA was able to produce an alarm within 1 hour after the onset of a small leak (1% of pipe diameter) and within 15 minutes for a moderate (>3% of pipe diameter) to large leaks.

A vast amount of real-time distributed temperature sensing data (at every 3-m distance, a total of 34,000 data points) along the entire length of the ETH pipeline and riser are continuously collected offshore and then fed into the advisory module. A customized automated workflow is developed to process this enormous amount of near real-time data to be used in calibration and to provide useful insights to the end user.

New methods, using machine learning and data clustering techniques, are used to develop specific automated advisories. The digital twin with automated advisory runs automatically and needs minimal to no intervention, providing operational awareness and actionable insights to decision-makers in real time. The integration of a "replay" functionality to rerun historical actions performed in the field and "look-ahead" functionality for future predictions in a collaborative environment makes the Fenja Digital-Twin solution an essential tool for operations.
Generation of Complex Emulsions During the Application of Improved Recovery Methods in Venezuelan Heavy and Extra-Heavy Oil Reservoirs: A Critical Review
Authors: Rodriguez Fernancelys , Belhaj Hadi , Rousseau David , AlDhuhoori Mohammed
Published: October 2022

The formation of emulsions during the production of highly viscous crude oils is one of the biggest issues observed both in cold production and after the application of IOR methods in Venezuelan heavy and extraheavy oil reservoirs, with impact on the lifting of crude oils, separation of phases, fouling, production costs, etc. For the cold production case, the presence of water with strong compositional and salinity variation, coupled with the presence of gas in the case of foamy oil, could generate very stable oil-water and gas-oil emulsions; hence complicating the phenomena after the application of thermal or chemical IOR methods.

This article presents a review of: 1) different types of emulsions found in cold production as well as thermal and chemical IOR methods, 2) factors that affect the stability of the emulsions (compositions of crude oil and formation and injection waters, type of injection fluid, temperature, etc.), 3) fluid characterization methods (gravimetric method, droplet size distribution, centrifugation, rheology, etc.), 4) recommended demulsifiers based on laboratory, and field experiences in Venezuela and internationally. These criteria will be reviewed in detail, establishing the main insights associated with the emulsion formation, providing related conclusions and perspectives for treatment and prevention measures.

Based on the results of this review, it can be highlighted that the presence of resins and asphaltenes in the crude oil has a fundamental role in the stability of the emulsions found during cold production in the Orinoco Oil Belt and that the composition of the formation water might increase the stability of the emulsions (Mg2+ and Ca2+). The application of thermal as well as diluent injection methods generates emulsions that involve precipitation of asphaltenes, which together with sand production in the process, leads to making phase separation processes more complex. Furthermore, the application of chemical methods could cause phase trapping (for the surfactant case) with impact on chemical losses, and water- in-oil emulsion with high viscosity after the addition of alkali in lab experiments. A worldwide review of field and laboratory remediation methods indicates that possible emulsion treatments include the use of silica nanoparticles, polyglycerol fumarate ester, heavy aromatic naphtha, electrical heaters, among others. This article presents the main insights related to the generation of emulsions in Venezuela and for developing strategies for emulsions breakers adapted to each IOR process. It also covers the effect of water chemistry, oil composition and type of IOR/EOR process on the characteristics of emulsion and emulsion stability, and consequently the impact on the technical and economic criteria of the process.
Vitamin C: An Environmentally Friendly Multifunctional Additive for Hydraulic Fracturing Fluids
Authors: Almubarak Tariq , Almubarak Majed , Almoajil Abdullah , Alotaibi Fares
Published: October 2022

There exists a need for high temperature fracturing fluids as we expand exploration into deeper, lower permeability, and hotter formations. Fracturing fluid stability depends on two main bonds: the crosslinker to polymer bond and the monomer to monomer bond. To preserve the crosslinker to polymer bond, a proper crosslinker with a suitable delay additive is typically utilized. On the other hand, the monomer to monomer bond is challenging to protect since it’s susceptible to a variety of factors with the main culprit being oxygen radical attacks. Consequently, the most common high temperature stabilizers used are oxygen scavengers such as sodium thiosulfate or sodium sulfite. Unfortunately, both additives create their own issues. Sodium thiosulfate is known to degrade at high temperature to generate H2S, while sulfites generate sulfates that end up causing inorganic scale precipitation or feeding sulfate reducing bacteria creating another source of H2S in the reservoir. Additionally, Sodium thiosulfate is a high pH additive which can cause formation damage through fines migration and precipitation of hydroxides.

Vitamin C is renowned for its antioxidative and oxygen scavenging properties throughout many industries. It is commonly used as an extremely cheap supplement to boost the immune system and as a food preservative to increase shelf life. Moreover, it has an acidic pH and offers a chemical structure capable of delaying crosslinking reactions. For that reason, this work aims to study the influence of Vitamin C as a multifunctional additive in fracturing fluids.

The tests mainly utilized the high-pressure/high-temperature (HPHT) rheometer. The performance of Vitamin C was assessed with a guar derivative at temperatures between 250-300°F for 1.5 hours. Moreover, zeta potential and coreflood were used to evaluate the formation damage tendencies of using this additive.

The results showed that the use of Vitamin C was able to provide a pH reduction, crosslinking delay, and enhance the high temperature stability of fracturing fluids. Zeta potential and coreflood experiments showed that clays were more stable at lower pH conditions minimizing fines migration.

Vitamin C is a cheap and readily manufactured environmentally friendly additive that offers solutions to the use of fracturing fluids at high temperatures. Utilizing it not only offers oxygen scavenging ability, but also replaces additives that lower pH and provides crosslinking delaying properties.
Squeeze Deployed Sulfide Inhibitor Successfully Averts Challenging Sulfide Scale Deposition in Permian and Williston Unconventional Basins
Authors: Okocha Cyril , Thornton Alex , Wylde Jonathan
Published: October 2022

Sulfide scales (zinc, lead and iron sulfide) are currently causing considerable production challenges as mature fields are kept operational, and as deeper-hotter reservoirs are being developed. An effective way to combat conventional scaling is to inject "squeeze" scale inhibitors into the formation which are then lowly released as production resumes, providing scale protection. This option has not been the case for sulfide scales due to formation kinetics and lack of suitable products.

In this study we present two field cases where new generation squeezable sulfide inhibitors were deployed with clear success in inhibiting sulfide deposition and establishing stable production. Also presented are the development methods and chemical synthesis details for the development of a squeezable product. A novel fast screening technique is detailed as well as a new type of residual monitoring method for the polymeric species that inhibit the sulfide scales.

In the Permian Basin, newly completed long horizontal wells in the Sprayberry Formation were on a constant rotation of work overs (every 3 to 5 days) due to severe zinc and iron sulfide deposition. Early squeezes performed with known phosphonate/ester scale inhibitors, and end-capped polymer were unsuccessful. A new generation of squeezable sulfide inhibitor was deployed and stabilized production as well as the scaling ion data. A unique and fast residual analysis methodology (using a specialized HPLC column) was developed as part of the squeezable sulfide inhibitor development project capable of providing a unique selectivity in a high TDS brine without interferences increasing residual monitoring and squeeze confidence. In the Williston basin many fields are known for their troubled history with iron sulfide. To date, the preferred option has been continuous well cleanout that impacts production, next generation squeezable sulfide inhibitor was deployed and it successfully increased productivity and eliminated well clean outs for the trialed wells. This technology summarized in the paper offers a substantial step change in the ability to protect against sulfide scale via squeeze application.

These field treatments show that next generation squeezable inhibitors were successful in inhibiting sulfide scales with no observed formation damage, upset to process facilities during flow back, or decline in productivity.
Which Technology is Right for Your Field? – Quantifying Technology Significance
Authors: Mohammed Noureldien Darhim
Published: October 2022

Exploration and Production Professionals are always concerned with setting and optimizing field development plans (FDP). Setting field development plan is not an easy task; it usually requires full knowledge and integration between almost all technical disciplines to build a robust plan with optimum alternatives. Technology is a key, and it has a significant impact of reservoir development. Its impact was proved and identified in previous researches already but has never been quantified before. In this paper, a new methodology to quantify significance of technology is introduced using artificial neural network.

Significance of applied technology is well-proved on field development. Using reservoir-related technology (e.g. 4D seismic, Enhanced Oil Recovery (EOR), Conformance techniques… etc.) or well-related technology (e.g. smart wells, stimulations, artificial lifting… etc.) are believed to have significant impact on recovered hydrocarbon volumes and consequently the overall field development. However these factors cannot be evaluated directly for their impact on field development – there is a pattern but not recognized yet and that's why significance of technology on field development is not quantified till now.

In this research, more than 300 fields’ data have been used from many regions (US, Europe, Middle East and Africa) to give wide applicability of the model. Artificial Neural Network (ANN) has been used to recognize the pattern relating different "technology" to "field development". After the research, many key observations have been concluded; there were many fields’ types that were found very sensitive for specific technology more than others, other fields were found to have preferable technologies than others (i.e. well stimulation was more beneficial than other well technologies, in certain cases), and eventually statistical reviews, comparisons and conclusions for technologies had been deployed and its significance on field development for different regions.

This research introduces a new concept of quantifying technology and its impact on field development using a new application of ANN in petroleum industry. This paper is not only giving technical recommendations based on significance of each technology but also giving strategic insights for decision makers. E&P companies that are concerned with benchmarking technology should learn more about such approach, and follow guidelines provided so they can select the right technology for the right field.
FRP Materials in Oil and Gas Industry: New Challenge Highlighted
Authors: Herzallah Osama , Alsulaimani Mariam , Al Omari Ammar , Almarzouqi Abdulaziz , Braik Nouf
Published: October 2022

Lately, the oil and gas industry has been always exploring and examining new materials that has superior properties that work efficiently under severe conditions. Fiberglass Reinforced Plastic (FRP) is one of those materials that exhibit good corrosion resistance and possess powerful properties. However, FRP may encounter some substantial challenges through certain applications. This paper will highlight the failure of a unique FRP-made internal component in a condensate tank as part of a steam generation process. Some oil traces were reported in certain equipment downstream of a condensate return tank in a steam generation plant. The tank was taken out of service and inspected internally. The Corrugated Plates Interceptor (CPI) pack, one of the tank's essential internals that is made of an FRP material, was found to be covered with a dark sludge layer, partially distorted and becoming very crunchy. A root cause analysis was conducted to list all the possible sources of the CPI pack failure. All the equipment documents were reviewed and the properties of the FRP material of the CPI pack was studied.

The CPI pack in the condensate return tank was made from a cast Laminate Isophthalic Resin, which is an FRP material that is selected due to its chemical and mechanical properties. This CPI pack was found to be covered with dark sludge deposits. Some of the corrugated plates were either compressed or crumbled and the pack was distorted with a considerable angle from its original position. The review of the tank operating conditions showed that the temperature of the influent entering the tank was ranging from 70 – 95 °C. Simultaneously, after studying the FRP properties, it was noted that the maximum allowed heat distortion temperature of the CPI pack material is 100 °C, which is only 5 °C higher than the highest temperature of the inlet fluid. This marginal difference was found to be not enough for the FRP to withstand such service. Hence, the FRP material of the CPI pack was found to be inadequate for very high temperatures and shall be replaced with a more heat-resistant material. Moreover, the sludge layer on the CPI pack was attributed to the insufficient cleaning of the sludge inside the tank. This research sheds light on one of the challenges of using FRP materials in high temperature applications. This may grab the attention on a weakness of FRP materials that may need to be furtherly considered and improved in the future. In the case analyzed in this paper, it was recommended to use a CRA material with high heat resistance rather than an FRP material.
A New Fault Sealing Analysis Method Based on PSDM Seismic, Well Logging and Reservoir Performance and its Application in K Mature Oilfield
Authors: Xin Chen , Jianlin Li , Min Zhao , Qunli Qi , Xiaoliang Li , Dongyang Li , Wenwen Yu , Xiaohuan Yan , Junxian Chai , Dengyi Xiao , Shuangting Chen , Fuli An , Chen Yang , Bo Peng , Bo Wang , Weixiang Zhong
Published: October 2022

Accurate modelling of fault seal is crucial in understanding fluid flow and connectivity in mature fields. Numerous methods of modelling the sealing capacity of faults have been developed, such as lithological juxtapositions, SGR and PSSF. However, due to the uncertainty of structure, throw and lithology prediction, conventional methods are difficult to meet the needs of reservoir development. In order to improve the accuracy of fault seal analysis, a new method was proposed in this abstract. Integrated PSDM seismic data, well logging, and reservoir dynamic data, this new fault seal analysis method include 4 steps: 1) Horizons and faults update based on PSDM seismic data. In this step, more accurate structure model would be generated; 2) Integrated well logging and seismic motion inversion (SMI) for reservoir lithology modelling. In this step, the accuracy of lithology prediction results on both sides of the fault will be improved; 3) Fault seal analysis was ran efficiently in 3D geological model by lithology juxtaposition and SGR. 4) Fault seal analysis QC and optimization by using reservoir dynamic data.

This method has been successfully applied to the K mature oilfield in Central Asia. The detailed faults interpretation was done based on new PSDM seismic data. The number of faults increased from 18 to 44, and the new structural model was improved obviously. The reservoir model based on the combination of well logging interpretation and seismic motion inversion (SMI) is not only consistent with drilled well, but also consistent with seismic inversion trend, which improves the accuracy of lithology prediction. Automatic fault seal analysis algorithm based on 3D geological model can efficiently generate the fault seal analysis results, and find potential areas. Fault seal analysis results can be validated and optimized by dynamic data from drilled wells. 6 potential faulted seal traps below conventional oil-water contract (OWC) were found in the slope area of oilfield. 3 wells have been drilled and confirmed 3 fault seal reservoirs with high oil production and much lower water-cut (6%) than conventional water-cut (96%) in the slope of K mature oilfield. It is proved that the method is beneficial for development in mature oil field.

This new fault seal analysis method integrated the information from PSDM seismic data, well logging, and reservoir performance data to improve the accuracy of faults model and lithology model, and generated a more reasonable fault seal analysis result. This allows more confidence in estimating the sealing or leaking capacity of faults and reduces risk of re-exploration and development in mature oil field.
Block-61 Rigless Method for Efficient Permanent Abandonment
Authors: Al Abri Sultan , Abbas Aala , Jaboob Musallam , Al Abri Muna , Najwani Mohamed , Al Harrasi Sultan , Al Fadhli Khalid , Al Shidhani Taimur , Al Darai Asma
Published: October 2022

Well Abandonment is an important stage in the life of any well and in the field development plan in general. Tight regulatory requirements along with high cost made it apparent to search for more innovative methods to design and execute well abandonments more efficiently.

Conventionally, well abandonment operations are performed by cementing the wellbore utilizing a drilling rig and its facilities, which is the main driver for the relatively high P&A cost. Here is where the method/initiative of "Rigless abandonment" came into play. This technique replaces the use of drilling rig with other intervention conveyance packages, resulting in a more efficient and cheaper plug and abandonment while satisfying all the regulatory isolation requirements.

For a non-standard abandonment operation, the rigless abandonment initiative was a great success. All the abandonment objectives have been met and required barriers have been established while spending 73% of the planned cost only. Despite the challenges faced during the operation, the well abandonment only took 1 day longer than planned. In addition, many lessons learned have been captured to avoid recurrence in the upcoming similar jobs.

In the year of 2019, a well in the northern part of bp's block 61 concession was deemed for abandonment due to poor reservoir performance. An opportunity was fore sought by the intervention team to design and execute the required abandonment in a "rigless" style. The planned process considered the use of coiled tubing unit to kill the well and place cement across the targeted Amin formation. Subsequently, utilizing the wireline service to place a plug across the packer before perforating above it. This step was to create a pathway for the cement to communicate between the A-Annulus and the tubing in the wellbore. Then, using the cement unit, the cement was reverse circulate down the annulus and up the tubing. To ensure the placement of the cement, a slickline drift run was conducted after the cement has cured, which indicated TOC at 480 m. Finally, the X-tree was removed, and the tubing and wellhead was cut at surface before performing a top-fill job to cement the remaining void up to surface.

The implementation of this abandonment operation also adhered to strict safety standards. The rigid bp safety process guidelines ensured that all challenges and optimization opportunities were fulfilled in a safe manner.

The purpose of this paper is to detail how the team pushed the technical envelope to introduce this methodology and share the journey of implementing a cheaper and safer well abandonment alternative.
Maximum Reservoir Contact (MRC) Water Injector Well Performance in ADNOC Onshore Carbonate Reservoir Equipped with Limited Entry Liner (LEL) Smart Completion
Authors: Al Shkeili Sara Abdulla , Javid Khalid , Benourkhou Noureddine , Al Sayari Saleh Ali , Al Dhuhoori Moza Saeed , Utama Indra , Rachapudi Venkata Subba Ramarao , Chang Ernisto Lenin , Jimenez Alvaro , Chaudhry Muhammad Zubair Tanvir , Mogensen Kristian , Hosani Fahad Mustafa
Published: October 2022

Developing mature reservoirs is associated with challenges and limitations both in surface and subsurface. In This paper we will tackle the area of developing reservoirs with Maximum Reservoir Contact (MRC) wells by introducing our experience in combining it with LEL completion and introduce initial results in unlocking the potential of our reservoir with reduced capital expenditure (CAPEX).

Conventional wells with 3000 ft open hole length become more challenging as development of the field progresses and especially with drilling new wells. Congestion and anti-collision at surface and subsurface limitations arise more often let alone the cost, manpower and environmental issues. We are going to introduce Maximum reservoir contact MRC wells with extended open hole length of around 10,000 ft. which allow to maximize gain from this well while optimizing other parameters (well spacing, cost…etc.). Measurement of rate and pressure, pre and post acid stimulation controlled by LEL completion as well as comparison with conventional water injectors in the vicinity were performed before to evaluate the performance of the MRC well.

It was confirmed that MRC well injectivity surpasses the conventional injectors with shorter open hole length in relatively tight areas of the reservoir which have low permeability especially if equipped with LEL completion. Initial results show Injectivity improvement compared with nearby water injectors plus additional gain in injectivity noticed after acid stimulation with the LEL completion. The MRC well performance after stimulation showed well head injection pressure decreased drastically after the acid stimulation with increased injected volumes of water. This shows that smart completion solutions well help to improve performance and optimize acid stimulation which highlights the importance of combining MRC with LEL to maximize gain and enhance performance to take the maximum benefit.

Through our success with MRC well with LEL completion the community of petroleum engineering will be able to take decisions regarding implementing this method and technology to optimize their drilling which will have positive impact in cost, planning and environment.
Say No to Carryovers
Authors: Yadav Sudhanshu Kumar , Al Muhairi Mohammad Ahmad , Obaid Ahmed , Hosani Rasha Al
Published: October 2022

Carryovers are infrequent incidents in process industry. Cause of these events is poorly understood. Carryover cannot be prevented using current configuration of instrumentation and control systems. Prior to the event operators are caught completely off-guard as the process parameters continue to stay in normal operating range. Realization of abnormal situation comes a bit late when carryover fluid reaches in downstream subsystems. Operators need help to stop these events from occurring by taking some informed decisions. This is achieved by introducing a new Operator Warning and Advisory Layer of protection.
Transformation in Well Delivery Commissioning Cycle Time Using Kaizen Methodology-Sultanate of Oman
Authors: Al-Azkawi Hafidh Said , Al-Naabi Omar Sulieman , Al-Hadhrami Abdullah Khalifa , Al-Musharafi Salim Mohamed
Published: October 2022

Petroleum Development Oman LLC (PDO) is the leading exploration and production company in the Sultanate of Oman. The company drills around 650 wells a year most of the well are in the South asset where the highest oil production. Currently, the South directorate drills an average of 400 wells a year varying from sweet, thermal, and critical sour/high-pressure free flow wells. In addition, 200 wells undergo conversion process. Commissioning of these big numbers of wells has imposed a great challenge to the team due to the high number of stakeholders involved to commission one well. Based on the records of 2018, in average, the critical sour high-pressure wells took 300 days to commission from well pad release. While sweet conventional wells took 22 days from rig release and high-pressure free flow wells took 80 days from rig off to commissioning. Because of these long durations, the new oil production was impacted and therefore impacted the overall production targets.

The objective of this paper is to illustrate the improvement on the well delivery process in the south directorate. The team has followed a kaizen methodology for the root cause analysis and has come up with key improvements to minimize the Hook-up and commissioning of all types of wells drilled, followed by PDCA process.

After applying the improvements revealed from the different kaizens for each type of wells, the team managed to reduce the duration for the critical sour high-pressure wells from 300 days to 45 days in 2020 until reached to 17 days in 2021. For the sweet conventional wells, the duration was reduced from 22 days to 10 days in 2019 until it reached to an average of 3 days in 2022. On the high-pressure free flow wells, the duration was reduced from 80 days to currently averaging at 17 days. As a result, the Oil South Directorate realized a benefit from acceleration of the new oil production hence it increased the company revenues ahead of the plan.

The successful implementation of well hookup process of all the mentioned types can be replicated in other fields in Oman and worldwide. The improvement was already recognized internally within PDO by winning two awards which are oil south directory silver award and PDO CI award for the best kaizen in 2021. The methodology has been cascaded to other directorates within PDO for their replication.
Electroless Nickel Plating Applications to Enhance Corrosion Protection, Equipment Reliability and Cost Effectiveness in Centrifugal Compressors
Authors: Pranzetti Alice , Bellacci Michelangelo , Cappuccini Filippo , Rizzo Emanuele
Published: October 2022

Coating technology is an efficient and cost-effective solution to protect equipment from aggressive environments. Corrosion and particles erosion are the most important material degradation phenomena in process centrifugal compressors leading to loss of performances, increase of vibrations and potentially safety concerns, especially for compressors operating with toxic gases. Among the today available coatings, Electroless Nickel High-Phosphorous plating (ENP) is one of the most robust and reliable solution. In this paper, the ENP corrosion resistance in continuous wet harsh environments was investigated through customized autoclave tests. The campaign assessed the corrosion resistance of both proprietary standard ENP (10-13%P) and proprietary modified-ENP, respectively with PTFE and SiC particles, ("doped-ENP"), in a single (SL) and double-layers (DL) fashion. All DL-ENP samples (standard and doped), showed an excellent corrosion resistance in harsh environment up to 10 bar H2S, 150 bar CO2 and 100000 ppm of chlorides. Among the SL samples, standard ENP showed the best results compared to the doped options. The samples characterization highlighted that the standard ENP is an effective barrier against the ingress of the corrosive gas mixture. On the other hand, the "doped" SL samples showed a reduced corrosion resistance. This reduction seems to be caused by the disruption of the ENP dense and amorphous film, resultant from the dopant particles inclusion. In this same study, the electroless in situ repair of locally damaged ENP was also investigated. As a result of the restoration process fine-tuning, a seamless ENP patch repair was obtained, thus ensuring the complete refurbishment of the original coating.
Working the Agile Way to Fast Track the Hydrocarbon Maturation Process
Authors: Singh Jasbindra , Borbajo Renato , Bashokooh Behrooz , Sariri Aisha , Riyami Said , Haddad Bahjat , Al Breiki Al Anood , Radwan Mohamed , Rajhi Mohammed , Sulaimani Al Zaina , Hillgartner Heiko , Khusaibi Mohammed , Mahruqi Issa , Azri Nasser
Published: October 2022

The "Agile Development" process utilises fast track evaluation of discovered hydrocarbon reservoirs and fields using the analogue based evaluation, capitalizing on existing organizational know-how in development of existing assets. It provides flexibility in the process to be able to adapt any changes happening during the span of the evaluation. The scope of the process covers the technical evaluation and the assurance events leading to a decision-based roadmap forming the basis of final investment decisions.

The fast-tracking "Agile Development" process has been designed to evaluate opportunities from appraisal to development phase based on the analogue data and the concepts. The process is utilised to characterize several different steps, starting from framing the opportunity to the delivery of the field development plan. Analogue assessment typically involves identifying the analogue[s], understanding the development concepts and utilising them for the estimating the production from the project development and the associated costs to evaluate the economic attractiveness. The assurance of the evaluation process has also been adapted to specific needs in project evaluation process. There are different tools - all developed in-house within the organisation - available for screening the analogues and then finally, selecting the analogue suitable for the evaluation of the project development planning. The outcome is also benchmarked on several parameters to ensure the project robustness.

The process has been implemented in several projects involving depletion and waterflood flood recovery mechanisms. The approach has resulted in reducing the time saving by over 50% as compared to normal process of opportunity evaluation. The quality of the product is similar to the FDPs delivered using the standard processes. The process may bring in additional value as it accelerates the delivery of the FDP in a much shorter time while providing flexibility to adapt to any changes experienced during the evaluation process.

This is a fast-tracking approach of evaluating the attractiveness of the discovered opportunities by implementing the experience and learnings from the development of similar reservoirs.

The process is still maturing and has the potential to reduce the evaluation time further by additional 50% for the projects using similar recovery mechanisms. The approach can further be extended for testing and/or implementing in EOR process specifically polymer flooding methods.
OPEX Optimisation for Un-Piggable Vent Line/Low Flow Pipeline Inspection via Self-Propelling Robotic ILI Tool
Authors: Abdullah Mohamed Ali , Supian Aishah Mastura , Ahmad M Nazri , M Ali Napiah M Nazmi , Mat Tuselim Ahmad Sirwan , Zakaria Muzdalifah , Hassan Hendra Luthfi , Mohamed Abd Salam Mohamed Ridzuan , Denis Gurin , Mikhail Lebedev , Elena Fertikova , Vitaly Romanovich
Published: October 2022

This paper is to share the development of Self-Propelling Robotic In-Line Inspection technology that PETRONAS embark as OPEX optimization for un-piggable pipeline. Lack of conventional inspection methods to inspect un-piggable pipelines such as vent pipelines without pig traps facility and low flow pipelines, has prompted PETRONAS to embark on technology development journey for Self-Propelling Robotic ILI.

The development of the Self-Propelling Robotic In-Line technology consists enhancement of robotic tethered crawler tool to a wireless robotic tool, testing and validation using actual full scale fabrication test loop. Fabricated test loop includes horizontal and vertical section with bends of 1.5D to simulate the inspection tool travel as per actual site condition representing vent line.

The enhancement consists of wireless connection range, optimum speed and distance, movement of slippery surface which grease was applied on the vertical section and emergency extraction of inspection robot.

Robotic ILI qualification test which was successfully met PETRONAS requirement based on full scale factory acceptance test. The test was focused and able to meet below success criteria: -

Robotic ILI tool able to self-propel on vertical test spool. Robotic ILI tool able to move with wireless connection for the intended travel length. Emergency retrieval tool procedure and mechanism in the event of faulty robotic ILI or loss of connection. Sensor detection capability at POD 90% and POI 80%.

Based on the evaluated technology, Robotic ILI solution is feasible in ascertaining the un-piggable pipeline integrity and recommended solution to tackle high operational costs that upstream operators face when inspecting their pipelines using current available methods. Deployment of this technology is estimated to provide up to 30% OPEX optimization. The technology has been evaluated to be technically ready and tested which currently in the stage of pilot testing.

Current approach to inspect un-piggable vent or low flow pipeline is Crawler ILI type technology which propelled by umbilical cable whereby the pipeline requires to be in shutdown mode. While inspection using Self-Propelling Robotic ILI can be applied for un-piggable pipeline i.e. low flow pipeline and vent line with short duration or no requirement of shutdown.
Driving Operational Excellence and Energy Reduction via End-To-End Production & Energy Loss Accounting at an Oil&Gas Client
Authors: Fien Gert-Jan A. F. , Semaan Samar M.
Published: October 2022

This paper will cover the recent implementation of a new end-to-end Production & Energy Loss Accounting (PELA) system at three separate sites of a major refining and petrochemicals company in the Middle East. It describes the development of practical tools, governance structure, training of relevant staff, embedding and evolving of the associated Management Operating System (MOS) and some of the early benefits achieved.

The new system includes customized software tools providing shift operators in each process with real-time information about production and energy losses in the main value drivers: asset utilization, product quality, reprocessing, equipment efficiencies, flaring, etc. The tools allow immediate assignment of standardized "cause categories" for later aggregation and analysis. A separate data compilation and visualization tool was also developed, along with work processes to support deviation analysis and decision making. More than a hundred technical staff across the three sites received training and a weekly meeting cadence was established for maximum leverage from this initiative.

This PELA system successfully covers 21 separate process areas. It led to confirmed savings of 7.9 MMUS$ in the first year alone, by wiring the organization for continuous improvement and providing greater transparency for staff and management alike.

PELA serves as a vehicle for change by driving awareness of the front-line staff and ensuring better cooperation between them, process engineers, maintenance, and production planning. The success of such a program relies on lean skills, analytical capabilities, expertise in change management, and strong leadership within the line.
Technology for Assuring Integrity of Uninspectable Small Diameter Pipeline Systems
Authors: Phipps James Alexander
Published: October 2022

The inspection of large diameter pipelines using intelligent pigs is commonplace and subject to continuous development.

Increasingly onerous is the inspection and thus integrity void associated with ‘unpiggable’ pipelines, caused by a variety of factors including diameter, geometry, access and economics.

The traditional inspection of pipework is onerous, expensive and can expose the operator and contractor to increased levels of risk, typically associated with access and logistics challenges.

The development and deployment of small and ultra small intelligent pigs can increasingly enable the inspection of pipeline and pipework inventory which could not previously be exploited.

The increasing momentum to embrace alternative energy sources involves new and often smaller diameter systems, as well as the opportunity to re-purpose part of the existing energy network.

The ability to deploy such technologies can significantly increase the speed of inspection survey, offer full coverage, whilst lowering the risk associated with complex and extensive access arrangements.
Enhancing Plant Reliability Through Risk Management of Single Point of Failures (SPoF) in Sour Gas Facility
Authors: Jain Nitish Kumar , Narsapur Sameer Surendra
Published: October 2022

ADNOC Sour Gas has experienced plant trips in the past, production loss as a result of avoidable actions resulting from component failures. These trips, in many instances were a result of a single point of failure. Single point of failures (SPoF) are specific common sections of piping and equipment which if failed or leaked in service can immediately shutdown the entire operating unit or the production facility as a direct impact or cascaded effect without giving the operator adequate time to respond and control the situation.

Large size gas processing plants such as ADNOC Sour Gas Facility with two gas trains operating simultaneously are designed to run uninterrupted for 4 to 5 years between 2 planned major turnaround cycles. By design and per specification, there are number of sections in the plant that have no stand by or any redundancy available in design. Due to this design of common sections or often defined as single components, it is not feasible to repair equipment, piping or instrumentation due to integrity issues while they are in operation. Any rectification work on these common systems (mechanical, electrical, instrumentation or structural) can lead to shutting down the entire gas plant & facilities. This planned or unplanned shutdown can lead to enormous production loss. To alleviate or minimize the consequences from these single common plant section events and improve the reliability and availability of the overall facility, management of these common sections is paramount for the business. ADNOC Sour Gas has successfully utilized the lesson learnt and identified all potential SPoF in the facility and developed SPoF management plan.

In order to ensure higher reliability of Operations, it is important that SPoFs are minimized or managed to avoid downtime. The concept of SPoF is very effectively utilized in IT industries, Networking and supply chain. Sour gas has successfully applied the concept for Oil & Gas Operations.