bluuebunny/crossref_metadata_2025 huggingface dataset:
Plug and Abandonment Excellence Journey in Malaysia from the Perspective of Malaysia Petroleum Management (MPM), Petronas
Authors: Omar M. , Xiong C. C. Yee , Idris F. R. , Zawawi A.
Published: October 2023

This paper demonstrates how to steer excellent well plug and abandonment (P&A) programs in Malaysia from the regulator's perspective through architecting P&A activities in Malaysian water by guiding operators to execute excellent P&A activities and adapting best practices from planning until execution based on a proven technical approach that's fit for purpose to deliver P&A with optimum cost and duration without compromising safety and technical requirements in Malaysia

Decommissioning and Abandonment (D&A) activities have become more prominent in Malaysia as more hydrocarbon fields are reaching their life span. There are more than 500 idle wells that need to be plugged and abandoned by 2030. Therefore, more than 70 wells per year need to be in the P&A commitment funnel for execution until 2030.

Based on PETRONAS Malaysia Petroleum Management's (MPM) observation as a regulator, inconsistency in well P&A approach by various operators resulted divergence in well P&A design, planning, and execution to meet PETRONAS Procedures and Guidelines for Upstream Activities (PPGUA). Among the two (2) main factors identified which led to a huge variance in P&A approaches across operators are lack of experiences in performing well P&A on a larger scale and gaps in communication with regulators, Realizing the communication gap between regulator and operators based on observation from 2016 until 2020, PETRONAS MPM, as shaper and enabler, embarked on an effective communication workflow based on a structured well abandonment activities cycle with the aim to close the gap and align the understanding among operators.

PETRONAS developed the well abandonment workflow cycle as a guide to operators, which covers five (5) distinct stages to ensure successful P&A campaign delivery from the initiation stage until well close-out & lesson learnt stage. Other supporting guidelines from PETRONAS MPM, for instance, are well P&A complexity benchmarking and well P&A campaign execution strategies, which assist operators in Malaysia from planning until execution stages.

It is mandatory to identify key factors to optimize the duration and minimize the cost. PETRONAS MPM emphasizes six (6) potential areas of optimization as key factors for operators to put their focus on when exploring cost and time reduction. Based on historical experiences, these six (6) areas will provide between 30% to 40% cost reduction opportunities in a well P&A campaign.

In summary, PETRONAS MPM, as a regulator, shaper, and enabler, will continue to take proactive measures to collaborate with all operators and business partners in Malaysia to continue promoting a safe, sustainable, and strong P&A ecosystem. PETRONAS believes a strong collaboration culture of sharing experiences will be essential for operators and contractors to work safely, stimulate creativity, and strive towards decommissioning cost compression.
Historical Cement Packer Case Study from Trinidad & Tobago Columbus Basin
Authors: Mammadli R. , Adilov R. , Bassie Y. , Rasmine M. , Hosein N. , Somai J. , Bruce T.
Published: October 2023

Historically, in the Columbus basin offshore Trinidad and Tobago small pool reserves are left behind the casing above the existing production packer. A low-cost alternative to an expensive rig workover was required to develop these trapped reserves. As a solution to this challenge, coiled tubing up-hole cement packer re-completion was developed and advanced during the last 10 years. Several well candidates were chosen to trial this method in the region. This paper will discuss the learnings and challenges faced during the execution and how the team applied these learnings for the next candidate selection.

Extensive data has been gathered from previous cement packer jobs and evaluated to establish the best practices and understand the key failure mechanisms. Based on the learnings, a candidate well was selected for up-hole recompletion. One of the key learnings from this exercise suggested the importance of well deviation to the success of cement packer jobs. Numerous failed well cement packers experienced contamination and channeling on 40 deg and higher deviation. It was identified that extending the top of the cement packer to the vertical section of the well was crucial for the success of the job. Extensive software modeling and lab testing related to the first-time use of a MgO-based expansive agent were performed to conduct the sensitivities around the height of cement in the annulus, and displacement rate to optimize the displacement efficiency. The analysis was performed to evaluate if the use of different cement retainer types and setting depth contributed to the success of the results.

The candidate well delivered planned objectives efficiently and within budget. The cement packer was placed above the zone of interest and logging was performed to confirm the quality of cement bonding. Cement displacement software modeling assisted in designing the pump rates to achieve the best results. Despite the operational challenges which resulted in setting the cement retainer shallower than the intended depth, ~500ft of uncontaminated cement with ~2200 psi compressive strength was attained. Even though the plan of bringing the cement to the vertical section was not achieved during the execution, the required cement packer height was not compromised. Perforations then were made, and ceramic sand screens were installed to prevent sand production.

Cement packers are not new to the industry. However, notable learnings were obtained from the Trinidad & Tobago region that integrates the combination of Gas lift mandrels, control lines, operational challenges and limitations. Incorporating previous learnings, cement lab testing, software simulation models, and the use of expanding agents, were the main contributors to the success of this job.
Wells and Facilities Instrumentation and Automation Towards Achieving Field Intelligence
Authors: Salim M. M. , Traboulay I. , Ahmed G. S. U. , Ibrahim E. , Al Wehaibi S. , Al Hammadi O. , Ballaith N. , Al Houqani M.
Published: October 2023

A well is a conduit that connects the hydrocarbon deposits in the subsurface to the facilities that transfers and processes it. Understanding the flow of oil or gas through the source rock can only be made possible from the wells itself. Aside from the flow conduits, wells are the only point of reference to understand the field wide behavior. This information is critical to manage the reservoir, ensuring sustainable production throughout the field life.

Traditionally, acquiring data from the subsurface to the wellhead relies on intervention, conveying instruments downhole with wireline or coiled tubing. Though effective, this activity incurs costs, logistically challenging and only sporadically available. Surface flow parameters such as rate and pressure are usually measured by analog gauges and Barton chart measurements, which are read manually by personnel to be tabulated later. In most cases, these data can be lost without a proper data management system in place.

With the advent of digital instruments, parameters such as pressure, temperature and flowrates; can now be measured automatically and transmitted to a DCS or SCADA system. Some downhole completions are now equipped with instruments that are robust and accurate to take measurements even in extreme conditions of heat and pressure.

With data at high availability, engineers are now able to conduct analysis faster, applying data analytics, collaboration and decision making. The main value for Digital Oilfield (DOF) is to save time in data retrieval, analysis and decision making and allow domain engineers to perform higher analytical function and decision making, taking them out from repetitive, manual work through automation.

This paper will describe the minimum instrumentations for all well types and major oil and as process facilities for real time data acquisition required to run DOF workflows. This covers subsurface wellbore to production manifold to custody transfer meters.
Managing Shift Workers Fatigue Using Psychomotor Vigilance Test and Biomathematical Modelling
Authors: Qureshi Farrukh , Karyum Hanafi , Al Mazrouei Shayma , Al Hammadi Nooh , Bametraf Rashed , Al Hammadi Saud , Saleh Ahmed
Published: October 2023

Shift work is a crucial aspect of modern industries, enabling round-the-clock operations. However, working outside conventional daylight hours can disturb the body's natural circadian rhythms, leading to increased fatigue, reduced vigilance, and impaired cognitive performance. This technical paper describes the use of the Impairment Detection Technology (IDT) i.e. Psychomotor Vigilance Test (PVT) and software based on the biomathematical modeling as an integrated approach to assess, predict, and manage shift workers' fatigue. By combining objective performance measurements and mathematical algorithms, employers can predict fatigue and proactively address fatigue-related risks, enhance worker safety, and optimize productivity in shift work environments.
High Conversion Refineries: An Approach to Reduce the Carbon Footprint by Hydrogen Network Optimization and Flexibility Enhancement
Authors: Campanelli Veronica , Magliulo Ciro , Albanese Claudio , Arces Ignazio
Published: October 2023

The momentum behind hydrogen as strategic vector to satisfy refining sector needs remains strong over the years. Indeed, hydrogen is a key feedstock in refining operations particularly for a complex conversion configuration such as that of Eni Sannazzaro Refinery, with one of the highest levels of complexity and capacity conversion in Europe, comprising of more than ten hydrogen consuming technologies out of which two hydrocracking, three diesel/kero hydrotreaters, three naphtha hydrotreaters, a FCC naphtha selective hydrogenation and other minor hydrogen consuming processes.

The Sannazzaro Refinery is a hydrogen self-sustaining hub thanks to a robust hydrogen producing system that includes technologies such as steam reforming, catalytic reforming and gasification that feed a hydrogen network structured in three hydrogen grids at different pressures and purities.

Targeting an excellent hydrogen network management and aiming at optimizing as possible the site energy consumption thus minimizing associated GHG emissions, the Sannazzaro Refinery has implemented a Dynamic Matrix Control (DMC) system monitoring the hydrogen network pressure to reduce the steam reforming throughput while maximizing the consumption of hydrogen produced by catalytic reforming units avoiding overpressures and hydrogen discharges towards the fuel gas network.

The project has resulted in an overall increased stability of hydrogen network, achieving a noteworthy hydrogen production saving of 900 ton/year with a reduction of 8500 ton/year of CO2 associated emissions towards an increase of site sustainability, parallel resulting in an enhanced stability of hydrocracker recycle gas purity (always maintained over 85%vol hydrogen content in order to preserve catalyst activity), determining a remarkable reduced standard deviation for controlled variables such as the high purity hydrogen grid pressure, succeeding in minimizing the hydrogen content into the fuel gas network, thus increasing relative fuel gas Wobbe index by 3 MJ/Nm3, hence positively impacting the site energy efficiency and enhancing its flexibility to closer tackle the variations on hydrogen refinery needs. All results have been achieved thanks to a fast controller run time (ca. 30 seconds) and an average service factor > 70%.

In conclusion, the overall project demonstrates how the implementation of a Dynamic Matrix Control system interestingly contributes to reduce a high conversion refinery carbon footprint and its hydrogen production cost via a fast-track and a low-cost project, being the site characterized by a complex hydrogen network with multiple hydrogen grids and steam reforming units to modulate the hydrogen production.
Paving the Road for Wireless Gauge Installation in Onshore Field
Authors: Almadani Amr H. , Eissa Mohammad A. , Winarno Mulad B. , Mutairi Khaled M.
Published: October 2023

Observation wells become very essential to provide an update of reservoir performance. Monitoring reservoir pressure is very crucial in reservoir and production’s enhancement process. Collecting pressure data using slickline method is not favorable in high production’s high demand period. One of the conventional techniques to collect downhole pressure data is by installing Permanent Downhole Pressure System (PDHMS). These PDHMS are powered by electric cable which is subjected to failure in case of rush current or short circuit. Once failed, workover rig is required to replace the failed PDHMS which is considered as non-economical solution.

An innovative approach was developed to continue monitor the reservoir data for wells that have failed PDHMS without the need of workover rig. This approach is by installing wireless gauges. The system is powered by batteries, can be deployed by wireline, and installed inside production tubing.

Pressure and temperature data are transmitted wirelessly through metal from tubular to wellhead. Surface panel system can display, store and provide port to download the data. However, the data transmission of the wireless gauges is interrupted by overhead powerline, cathodic protection, intelligent field equipment and other existing electric devices. Therefore, first of its kind noise filter cancelation was added into the system to ensure the accuracy and continuity of data transmission.

An integrated process for wireless gauges installation was developed starting with the designing process to receiving the data at engineers’ desktop. This process plays a vital role in planning future production optimization, reservoir management and injection strategies.

This paper is sharing the best practice and procedure that should be followed during the surface panel work preparation up to downhole gauge installation
Management of Facilities Services Across ADNOC Group Companies
Authors: AlMazrouei Mouza , Ahmed Reda Hashem , Muckattu Joseph
Published: October 2023

ADNOC Group B&S managing its facilities across ADNOC Group Companies by planning, executing, and monitoring all facility services involved in building maintenance services, office space management, building asset management, and soft services by using Computer Aided Facility Management (CAFM) system.

CAFM system is a specific type of facility management system that allows users to optimize a lot of customer-oriented services in an organization, such as facilities services, office space management, building assets management, and so on. Additionally, CAFM system allows for planning, executing, and monitoring of various activities within facilities once the building is ready after construction handover.

ADNOC Group B&S is adding Service Provider contracts in the system and managing Service Providers operational scope of work such as Assets, Buildings, Resources, Maintenance Schedules, Spare-parts, Service Level Agreement (SLA) and Key Performance Indicator (KPI).

Also, CAFM System h a s mobile solution which enabled ADNOC Group B&S to facilitate the Service Provider to perform real-time maintenance activities and allow business owners to monitor the Service Provider work-orders/service requests.

One of the important tools that enable ADNOC Group B&S to have a visualization of information is by utilizing the Data Analytics and Business Intelligence dashboards.
Improving Process Control Performance in Project Delivery
Authors: Al Mawali S. , Al-Sibani O. , Moosawi M. , Alawi A.
Published: October 2023

This paper discusses the challenges of ensuring effective process control performance in new projects in the oil and gas industry. It also presents Petroleum Development Oman's (PDO) approach to incorporating process control into project delivery to address these challenges. PDO has improved process control performance in new projects by adopting a comprehensive approach. This approach includes introducing KPIs, establishing a process control discipline, and updating the company's quality assurance framework. The results of these changes have been significant, with two mega projects achieving a higher process control performance than previous projects of comparable complexity. These improvements ensure that the value of a project is reaped as early as possible in the operate phase directly after commissioning and handover and thereby maximizing the return on investment for automation.
Challenges and Mitigations in Geosteering the Longest 6 1/8 Inch Horizontal Reservoir Section in Adnoc Onshore History
Authors: Chikhi Zoheir , Abdulla Al Hosani Fatima , Yousif Al Blooshi Mariam
Published: October 2023

This paper is about the Geosteering challenges and mitigations in drilling the longest MRC well in Adnoc Onshore history. The well was drilled as Horizontal Oil Producer with the objective to maintain current sustainable production in Habshan-9 (R1_B) formation based on the new ADNOC approach to drill MRCs (Maximum Reservoir Contact) in Abu Dhabi fields. The MRC philosophy has been implemented in Adnoc Onshore for many reasons, mainly to deal with the surface congestion and the anti-collision in the subsurface. This paper presents the challenges faced in planning and drilling of the subject MRC well with a total measured depth of 28,200ft (8.5km) and having horizontal hole of 17,148ft (5.23 km reservoir contact).

The planning phase was crucial to align all stakeholders (reservoir management team, subsurface operations, drilling, material, fluids, completion and directional) on the common objective of delivering safely and as per the objectives the longest 6 1/8-inch horizontal reservoir section in Adnoc Onshore history. The meetings were meant as well to mitigate all the associated risks by proper planning of the drillability analysis, the agreed trajectory, collision risks if any, BHA choice, hydraulics, logging tools and choice of the lower completions. The well was more challenging as it is drilled up dip the thin (2-4 ft) Habshan-9 (Habshan-1) formation.

This paper will explain the way the landing inside the thin Habshan-9 reservoir was achieved and how we maintained a very smooth hole with a DLS (Dogleg Severity) < 1 deg/100 ft. indispensable to run a +17k LEL (Limited Entry Liner) lower completion.

This Oil Producer MRC well is the longest 6 1/8-inch horizontal reservoir section in Adnoc Onshore history unlocked the potential to drill even longer wells which will significantly improve well performance, enhance the reservoir management, reduce the field development cost and reduce the field congestion.

This paper summarizes the challenges encountered during the geosteering and the mitigations that allowed successfully complete and deliver the longest 6 1/8-inch horizontal reservoir section in Adnoc Onshore history.
Comparison of Cement Evaluation Utilizing Different Logging Tools and Cementing Best Practices: A Case Study in Middle East
Authors: Nathan Kumar , Kamarudin Muhamad Aizat , Devadass Lingges , Mohammed Mustafa Jawad , Yen Kok Kwi , Amat Hadi , Choon Tan Boon
Published: October 2023

Cement Evaluation Tools are usually deployed to evaluate the cement bond behind the casing or liner prior to well test or produce the well. Since oil and gas spillage can be hazardous to environment and impose great HSE risk, the cement evaluation is often given a special priority especially after the Macondo incident. Hence, in many countries the regulatory authorities have imposed a strict requirement on having good hydraulic isolation before letting the well to be tested, produced, or abandoned. Thereby, cement evaluation logs become the necessity to be run in all the wells to analyze the cement bond behind the casing.

The basic cement evaluation log which is cement bond log (CBL) is being around and well understood by the industry and still being used as a basic log concurrently with other advanced logs. High demand on the cement evaluation logs makes the cement evaluation tools to undergo tremendous development and with better understanding on the physics of the measurement, industry players have developed various tools. The cement evaluation tools can be categorized into broad category of acoustic based, ultrasonic based, radioactive based and electromagnetic based logging tools. Among all these cement evaluation tools, ultrasonic based tools are the mostly used tools in the industry. In line with the advancement of the tool, the efficacy of cement evaluation will only be maximized when the cement evaluation procedure and technique are simultaneously improved. Additionally, the improvement on the cementing procedure and cement recipe shall also be performed from time to time based on the actual cement bond evaluation result for optimum cement bond behind the casing.

Hence, this paper will give a comprehensive view on the cement bond assessment done in Field G from basic to advance cement evaluation tools. This includes the factors that affecting cement quality which includes both the logging operation, and cementing procedures. The interpretation technique and guideline that were developed to evaluate the cement bond behind the casing will also be discussed. The cement evaluation data analysis from 120 wells from Field G will not only aid industries in selecting appropriate logging tools and cementing procedures for cement evaluation, but wit will also serve as an avenue to give new perspective in logging and cementing operation.
India's 1st Polymer Flood Scheme Implementation from Laboratory to Field in Heavy Oil Having Strong Aquifer
Authors: Sharma Ajay Kumar , upadhyay Sandeep , Mitra Sujit , Meena Rakesh , Mavoori Ravi. S.
Published: October 2023

The case studies for Polymer flood globally in heavy oil are few and far between. The low primary recovery of this field warranted an EOR scheme. The present paper discuss the challenges in designing & implementing a polymer flood project in a heavy oil field in a strong aquifer drive with vertical well configuration. The paper covers a complete EOR cycle from screening, laboratory studies, simulation studies, pilot execution and further full field implementation.

EOR screening was carried out through established screening methods to find a suitable EOR technique. Post screening, polymer flooding was tested in the laboratory and based on the encouraging laboratory findings, it was recommended for simulation studies. Sector modelling with fine grid scale of 16*16m carried out for pilot simulation study. Polymer Pilot scheme was designed and successfully implemented in the field in May-2019. After Successful pilot execution, history match of the polymer pilot was carried out. Learning's from the pilot study were incorporated in the model and full field scheme was implemented in the field in Oct-2022.

Thermal stability tests for various polymers were carried out in laboratory and thermally stable polymers were shortlisted. Similarly, test for adsorption and screen factor was carried out and suitable polymer was shortlisted for core flood experiments. Core flood experiments carried out on sand pack made from native sand of the reservoir. Based on the mobility ratio and shear thinning properties of selected polymer, polymer viscosity was taken as 25cp. Polymer flood linear core displacement efficiency was found 61.4%. Incremental displacement efficiency was 17% over water flood.

After laboratory experiments simulation study was performed for polymer pilot. Sensitivity carried out for number & type of patterns, pilot site, injection/production rates, residual resistance factor (RRF) and pore volume injection. Based on simulation results a normal 5 spot pattern was proposed for field execution. Envisaged incremental recovery over base case was ~12% of target oil. Expected oil recovery was achieved in pilot and water cut reduced from 80% to 60%. History match of pilot was carried out in the black oil simulator. After pilot history match full field scheme was prepared and implemented in the field in Oct-2022.Incremental recovery envisaged in full field scheme over base is ~ 5%.

This study has proved that polymer EOR can enhance oil production in heavy oil with strong water drive. This project paved way forward for other analogous fields. A standard methodology was adopted to implement polymer flood in all analogous fields of the company with low recovery. The experience and expertise gathered from this study has given courage to implement full field polymer EOR in analogous fields without pilot study.
Chemical Tracer Evaluation of First Horizontal Multistage Fracturing Treatment Well in the Telisa Formation, Indonesia
Authors: Yudhanto G. , Pramadana A , Akbari A. , Gani E. E. , Koseluk D. , Harjaya B. , Makmun A. , Swarnanto A.
Published: October 2023

Efficient hydraulic fracturing is one of the most important parts of Telisa formation development strategy. Historically, the Telisa formation was developed with single-stage vertical wells, stimulated with conventional propped hydraulic fracturing technique. To promote field development, operators looked for drilling horizontal wells completed with multistage hydraulic fracturing treatments. Aiming to evaluate the effectiveness of new well completion method, non-invasive and cost-effective diagnostic evaluation tool was needed.

Chemical tracers have been used for many years to understand the effectiveness of hydraulic fracturing operations by utilizing unique chemical tracers in each stage (or stage grouping) to provide an understanding of relative tracer flowback contribution. Tracer contribution can be affected by several variables, including reservoir quality, effectiveness of the hydraulic fracturing treatment, and areas of pressure depletion from existing offset vertical or horizontal wells. Liquid-water chemical tracers provide an understanding of far-field, hydraulic-fluid movement, while solid particulate oil and water chemical tracers provide an understanding of near-wellbore connectivity with created hydraulic fracture. When using both tracer types in combination, a more comprehensive understanding of the hydraulic stimulation can be attained.

This paper will discuss the general characteristics of the Telisa formation and how the design of hydraulic fracturing treatment was implemented. The chemical tracer design will also be discussed, and the chemical tracer results will show how the unique characteristics of both solid particulate and liquid chemical tracers were used to provide a detailed understanding of stage performance after the successful implementation of the first multistage horizontal well in this field.

The data from the solid particulate chemical tracer recoveries were used to show the effectiveness of each stage in the hydraulic fracturing treatment. The liquid water chemical tracer recoveries helped to identify stages in the well where pressure depletion from nearby vertical wells might have affected far-field fracture fluid movement. All the data gathered during this study will be valuable in the future development of the field as more horizontal and multistage wells are drilled and completed.
Reducing Embodied Carbon by Using Fibre Reinforced Polymers (FRP) Rather Than Steel
Authors: Eves S. , Lye N. , Herbert B. , Chiu A. , Friedrich R.
Published: October 2023

In recent years embodied carbon has become an important consideration when designing and specifying new builds and refurbishments in the oil and gas industry. Fibre Reinforced Polymer (FRP) structural products and Glass Reinforced Epoxy (GRE) pipes have been used for a number of years due to their light weight and corrosion resistant properties, but these properties also have the effect of reducing the embodied carbon of the products over their life span. Reduced transport weight, reduced maintenance and longer lifespan are all contributing factors. By taking the examples of traditionally steel products and their FRP equivalents this paper aims to quantify the potential savings.

The comparison for structural products focuses on Multi-Angle Rapid Railing System (MARRS™) offshore handrails manufactured with FRP profiles and fittings (MARRS FRP handrails) vs. Galvanized Steel Handrails. For GRE pipes, a typical 12-in. pipe is compared against steel alternatives. This study uses baseline scenarios to calculate the main life cycle impacts and scenario-based analysis to account for the maintenance and repair opportunities that the products allow for. Global warming potential is the impact category analyzed in the study.

A typical MARRS handrails installation could be 4,000 linear meters, meaning the embodied carbon for the steel handrail could be as high as 5,500 tonnes of CO2e, while the MARRS equivalent will be less than 200 tonnes of CO2e, a saving of over 96%.

The use of GRE pipes in place of traditional CS pipes produces at least 60% savings over 20 years, with further savings from the embodied carbon used in work required to install replacement pipes due to corrosion.
Predicting EOR Polymer Viscosity with Varying Molecular Weight and Chemistry Using Machine Learning
Authors: Maillon Rémi , Ghosh Pinaki , Wilson Clayton
Published: October 2023

Polyacrylamide polymer flooding is an established EOR technique to reduce the water/oil mobility ratio and improve sweep efficiency. Polyacrylamide polymers are non-Newtonian fluids whose viscosity depends significantly on shear rate in addition to several other parameters, such as brine salinity and hardness, temperature, polymer concentration, chemical composition, and molecular weight. Each oil reservoir has unique brine compositions, expected shear, and temperature conditions. Estimating the polymer solution's in situ viscosity under these conditions can be quite challenging, requiring expensive and time-consuming rheological lab experiments.

Machine learning has recently gained popularity and has been applied successfully in many sectors, including the oil & gas industry, to develop predictive models and forecasting tools. With more than 30 years of experience in polymer EOR projects globally, SNF has compiled a large rheological dataset, including approximately 75,000 lab experiments measuring the viscosity of its synthetic polymers under different reservoir conditions. In this study, different machine learning algorithms have been tested on SNF's rheological dataset to predict polymer viscosity for any given polymer type and concentration under certain reservoir conditions. The best results were achieved using a Random Forest algorithm, the results of which have been presented here. The model predictions are based on the following eight input features: active polymer concentration, shear rates, brine total dissolved solids (TDS), hardness, temperature, polymer molecular weight, and chemistry (ATBS percentage and Acrylamide percentage). Based on preliminary investigations, the results obtained are promising, with an R-Squared regression score of 89.6 % and a mean absolute percentage error of 35.8%.

The model's results have helped SNF better understand the impact of these different parameters on polymer viscosity and can be used for improved quality control of lab measurements generated across the globe. This tool aims to aid product development by providing in silico data in concurrence with in situ experiments, driving a robust development process.
Matrix Stimulation in Heterogenous Carbonate Reservoir: A Case Study from the UAE using Custom Acidizing and Self-Diverting Acid Treatment as an Alternative to Conventional 15% HCl Treatment
Authors: Tuoyo Ella , Ambrosi Giuseppe , Hernandez-Solana Leticia , AlKamali Mathayl , Ottolina Renny , Akl Osama G. , Alshehhi Hajer
Published: October 2023

This paper aims to highlight how important it is to apply the matrix acidizing engineering approach to achieve the best results for any well, which includes the custom chemistry selection and execution procedure to enhance well productivity in argillaceous limestone reservoirs. This study showcases the complexity of interaction between the various layers of the reservoir and the self-diverting agent, and how this optimized placement leads to increased treatment effectiveness.

Using 15% Hydrochloric Acid (HCl) on carbonate reservoirs is challenging due to the speed and aggressiveness of the reaction. In addition, there is no doubt that in matrix stimulation the diversion and coverage of the treatment fluid plays a key role in driving the efficiency and final result of the operation. For this case study a customized acidizing blend combines primary and secondary reactions that provide longer reaction time and better etching. In addition, a pH-activated self-diverting acid was pumped in stages to provide dynamic diversion of the treatment fluid while being pumped.

The well is a newly drilled, open-hole, single gas producer in a green field. Apart from the already listed benefits, other considerations were the natural fractures in the reservoir, the high percentage of swelling and migrating clays in some zones, and the long treatment interval.

The original treatment was designed considering four (4) stages (2 acid and 2 self-diverting acid system stages) and 20 gal/ft of reservoir. After the 3rd stage, the well recorded a peak of 12 MMscfd of gas (the objective was 8 MMscfd), and the Wellhead Pressure (WHP) surpassed 4,500 psi, which created some operational concerns since the wellhead was only rated to 5,000 psi. Based on this, a decision was made to cancel the 4th stage of the treatment and open the well to reduce the pressure quickly. However, as the horizontal section is open hole and was recently treated with acid, this abrupt change in reservoir mechanics led to a suspected collapse of the formation.

The stimulation approach proved successful during the operation as post-job analysis of the wellhead pressure response indicates a significant skin reduction. The results, however, brought conditions never seen before in the area, and the contingency steps taken proved detrimental to the reservoir.

Following the correct matrix stimulation engineering approach helped to select a custom solution for the well that considered the proper reaction time of the treatment chemical systems with the reservoir. This improved the creation of the wormholes and determined the diversion technique to consider maximizing reservoir coverage over the length of the open hole section.
Well Hookup Surface Completion Optimization
Authors: Al-Mawali M. , Al-Hasni R. , Al-Abri A. , Al-Barwani M.
Published: October 2023

In the Oil & Gas upstream industry, the efficient and timely installation of well hook-up surface equipment's holds a vital importance for ensuring safe and productive operations to ensure an immediate return on investment. It is crucial to minimize the time and risks associated with bringing the well hook-up surface scope into production after a rig move off location. This paper introduces an integrated approach that focuses on achieving a safer design, cost optimization and minimizing installation time as well as the flexibility of the designed system, ultimately aiming to expedite the production of the first drop of oil.

The petroleum industry operates in a highly competitive and fast-paced environment, where every minute counts. Following the rig move, the installation process of the well hook-up surface scope must be completed promptly to resume production activities and avoid potential financial losses. Consequently, exploring innovative approaches that streamline the installation process and mitigate associated risks becomes crucial.

The integrated approach proposed in this paper represents a comprehensive and strategic solution to address the challenges encountered during the installation of well hook-up surface scopes. By incorporating advanced technologies, meticulous planning, and optimized procedures, this approach aims to maximize operational efficiency and minimize costly delays.
Berri Increment Project Approach to Improve Hydrocarbon Condensate Quality
Authors: Al-Zahrani Talal A. , Al-Hajri Ali M. , Al-Ghanem Hashem H. , Salu Samusideen A. , Al-Otaibi Fahad M.
Published: October 2023

As part of Berri Crude Increment Project, 40 MBD of Hydrocarbons (HC) Condensate will be separated in the new associated gas gathering system of Abu Ali oil producing facility. The condensate will be collected and exported via a 70 km pipeline. The extent and impact of water presence in the condensate was thoroughly evaluated during the FEED stage of the project, as it is common among similar oil and gas processing plants, and contributed to difficulties — for downstream pipelines and receiving facilities, especially at turndown operations — with such problems as corrosion, solids deposition, sludging and hydrate formation. The objective is to develop a robust and cost-effective process designed to tackle this challenge and ensure production reliability.

The team evaluated several options to resolve this design challenge, including the following mitigations: Chemical injection of hydrates and corrosion inhibitors in the export condensate pipelineInstallation of liquid/liquid coalescers to filter the export condensatesInstallation of a condensate stripping system at Abu Ali to boil waterRelocating the TEG system to upstream all condensate removal drums in the gas plant to ensure collecting only "dry" condensate to the export condensate drum.Installation of a liquid dehydration package for the export condensates. The package mainly includes a molecular sieve and solid desiccant adsorption beds.

A combination of three options were selected for the design of the Abu Ali export condensate system. Free water removal by liquid/liquid coalescer with full redundancy to improve the efficiency of the molecular sieve.Dissolved water removal by liquid dehydration package.Backup methanol injection and corrosion inhibitor for emergency operations.

This new process design has some unique aspects that are worth of highlighting, such as: The first installation of its kind in Saudi Aramco upstream facilities for raw hydrocarbon condensate.The first installation of a molecular sieve dehydration process for sour condensate in Saudi Aramco.
Assuring the Structural Integrity of a Fleet of 119 Offshore Platforms in the Egyptian Gulf of Suez by Applying RBI Methodology and Adopting a Qualitative and Semi Quantitative Approach.
Authors: Amer M.
Published: October 2023

This paper is about Assuring the Structural Integrity of a Fleet of 119 Offshore Platforms in the Egyptian Gulf Of Suez by Applying RBI (Risk Based Inspection) Methodology and Adopting a Qualitative and Semi Quantitative Approach with one purpose of determining the Probability Of Failure (POF) as well as the Consequnce Of Failure (COF) of each platform and decide if the platform meets the company acceptance criteria (survive the 10,000 years event storm).

The work done has been performed in 2 phases:

Phase I : involved selection of critical and representative platforms for ultimate strength assessment and seismic assessment. The platform selection has been performed based on platform generic grouping followed by risk ranking using a qualitative approach to determine the POF of the fleet based on factors such as water depth, degree of damages reported on a platform, extent of load increase, foundations, anodes depletion …etc. In addition, API seismic zoning has been considered as well in selecting platforms for seismic assessment.

The platforms were selected to represent the fleet, the purpose was to allow the selection of platforms which were most representative or critical among generic groups of similar platforms to perform push-over analysis and determine the actual (quantitative) POF.

Phase II : Upon finalization of platform selection in Phase I, detailed ultimate strength (progressive collapse pushover) and seismic assessment was performed in Phase II for selected platforms, after that all generic POF's estimated in Phase 1 were revisited & updated based on the outcomes of pushover calculated RSR's and POF's. The pushover analysis outcome based on these selected platforms (from Phase II) would be deemed as reasonably sufficient to infer the current robustness of all the structures.
Literature Study and Model Example of Machine Learning Application for Plugging Prediction at Hydrate Inhibitor Regeneration System: Study Case
Authors: Hamidiy M. I. , Suryodipuro A. D. , Sommeng A. N. , Nengkoda A. , Amir M. F.
Published: October 2023

Gas hydrate is one of five solids that commonly cause flow assurance issues, resulting in loss of production opportunity (LPO). As a common problem in the upstream oil and gas industry, gas hydrate formation prevention and mitigation should be considered during the production lifetime. The most popular method is to inject hydrocarbon fluids with antifreeze chemicals called thermodynamic inhibitors such as methanol and ethylene glycol. Compared to other mitigation strategies, this method is often used instead of heating and pigging methods that contribute to non-productive time. Mono ethylene glycol (MEG) is generally chosen as a hydrate inhibitor in gas pipeline transportation due to its capability to be regenerated and reused to reduce operating costs. However, in one of the Indonesian subsea systems, actual problems arise from MEG Regeneration Unit (MRU) such as scaling and fouling which cause plugging in the lean MEG injection system. This paper aims to show a method to predict the possibility of plugging using supervised machine learning by observing the correlation between the total dissolved solids of lean MEG and other process parameters. This discusses several previous studies showing that process parameters in the field may affect the quality of lean MEG injection. Some classification algorithms are compared to evaluate the performance of plugging possibility prediction. The result of this study shows that by applying a Random Forest algorithm, the highest accuracy among other algorithms, to field process parameters, the cleanliness can be determined whether on-spec or off-spec with an average accuracy of 79-92%. Therefore, some benefits might be gained by deploying machine learning to the MRU system and can be used to optimize MRU's operation, monitoring, and maintenance strategy.
Machine Learning Models for Predicting Relative Permeability of Two-Phase Flow in Porous Media
Authors: AlGannas Sulaiman M. , AlTurki Ali A. , Sudirman Sharizan B.
Published: October 2023

Relative permeabilities are fundamental quantities for reservoir engineering that govern production/injection and displacement (i.e. natural depletion, water or gas-cap drive, waterflood). The relative permeability (kr) of a phase is a dimensionless quantity that measures the effective permeability of that phase in the coexistence of the other phases, which is represented as the ratio of the effective permeability of that phase to the absolute permeability (keff/kabs). These curves are dependent on fluid saturation, saturation history, fluid distribution within the pores, capillary, wettability, viscosity, pore geometry.

A displacement of a two-phase system of oil and water on a core (Fig. 1) will cause resistance to the movement under pressure. The race to reach the other end of the core depends on the permeability (the ability to be penetrated or passed through) of the rock and the fluid properties (i.e. density, viscosity).
Identification and Mitigating Risk in Deepwater Surface Casing Strings with a Cradle to Grave Approach
Authors: Angelle Jeremy R. , Thibodeaux Robert L. , Norma Roger A. , Fadaol Seth J. , Snell Taylor D. , Smith Logan E.
Published: October 2023

As deepwater well designs have progressed toward deeper targets, the well integrity risk of surface casing strings has increased. Surface casing strings utilized in deepwater environments are installed before the drilling riser is installed allowing them to be subjected to metocean conditions and difficult to handle and install. Additionally, the exposure from the well has increased the need for advanced connector designs and complex manufacturing processes to ensure well integrity is maintained.

To ensure the casing string is fit for duty, a "cradle to grave" approach is utilized to identify and classify the risks created by loads induced on the casing string. Beginning with the handling process, all handling loads, environmental loads resulting from handling, and metocean conditions are identified. Once installed, the well loads resulting from potential well exposure and structural loads resulting from the rig are identified. Finally, the connector and fabrication design process is analyzed to identify requirements needed to satisfy the load conditions and mitigate risk to well integrity.

Introducing advanced mechanized tubular running technologies resulted in up to 20% reduction in exposure of the surface casing string to dangerous sea states and ocean currents and a 41% reduction in red zone entries. Exposure of the surface casing string to environmental loads was further reduced by 7% with the use of an innovative hands-free anti-rotation key, which requires no installation on the rig floor during tubular handling operations and lowers red zone entries beyond current mechanized handling solutions.

Once set in place, surface casing strings are subjected to a higher classification of well service as structural and well loads increase in severity. To address this, a new weld-on connector qualified to connection assessment level I+ for gas tight service with elevated temperature per API RP 5C5 / ISO 13679 was installed, allowing deeper wells in deeper waters to be achieved.