bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Point on Wave Controlled Switching on High Voltage Systems for Weak Offshore Grids
Authors: Al Ammari Sara , Kotrappa Murugendrappa N. , Manna Malay , Abou El Makarem Mohamed
Published: November 2018

At offshore oil and gas islands, on site generators running independently are often utilized. These on site generators have their benefits but also pose their own drawbacks and may have their own problems. Due to the instability of those weak offshore grids, the grid disturbances may cause power outages, voltage fluctuations, changes in frequency, blackouts …etc. which are easily felt by the consumers and can also impact the performance and the service life of the electrical equipment.

A study has been performed to examine different methods to improve the reliability of the overall network. Circuit breakers are designed to react by opening or closing the circuit as soon as a command is received. While doing so, the circuit breakers go through tremendous high stresses which ultimately may cause it to produce an arc. This phenomenon can be mitigated and reduced using controlled switching. This technology involves pre-defined control strategy for opening and closing each circuit breaker pole independently. Controlled switching methodologies are used to minimize the stress on circuit breakers, prevent failure of electrical equipment and improve power quality without affecting the overall grid. This new cost effective technology helps in reducing disturbances while improving electrical reliability to the end consumer. High Voltage Shunt Reactors, Subsea Cables and Transformer Energization and De-energization cause high inrush current on the system. Power system study software has been utilized to identify which loads will provide the optimum benefit when implementing the Controlled Switching application.

This paper addresses the benefits of using controlled switching on high voltage circuit breakers on weak offshore grids. This paper also studies the applications and advantages of controlled switching of 132kV long subsea cable and transformer feeders wherein high inrush current is expected while showing the outcomes of research results and actual scenarios that have been implemented
Enhanced Solvent-Based Remediation of Waxy Deposits
Authors: Zadeh Kamran Akbar , Tatavalli-Mittadar Nirmal , Abd-Rahman A-Sukaimy , Jain Shekhar , Ashtekar Sunil , McGregor Stuart , Degaleesan Sujatha
Published: November 2018

Restriction or blockage of flow path due to waxy deposits is a global issue in the oil and gas production. This undesirable flow assurance issue leads to increase in production deferment and OPEX for mitigation and frequent intervention. It may also result in huge CAPEX for pipeline sections replacement due to untreatable blockages.

Despite the current prevention and mitigation strategies in place, wax deposition cannot be fully eliminated. Existing remediation technologies can be broadly classified to mechanical, thermal, and chemical-based treatments. These also have some limitations such as availability, cost, deferment and effectiveness. Today, most effective solutions are often a combination of mechanical and chemical which are expensive in terms of cost and may result in additional deferment time. As such, the development of more effective remediation strategies is of great importance.

Solvent-based cleaning can be relatively less expensive if it is a viable option. However, experience suggests that conventional solvents such as xylene are generally not that effective in dissolving and breaking wide range of waxy deposits with varying compositions.

Enhanced solvent-based remediation is a novel approach with the focus to balance performance, cost, and safety for field applications. Based on this approach, understanding the field deposit, optimizing solvent's performance in the lab under representative field conditions, selecting a solvent that balances performance with cost and safety, scaling up from lab to the field conditions based on the field's limitations, and proper deployment of the selected solvent in the field play important roles in effective remediation of deposits.

In this work, the enhanced solvent-based remediation approach and the lab procedure for primary screening of solvents are described. In addition, the procedure for cleaning a flowline that was restricted by wax deposit in an onshore field in South-East Asia is explained. The results of this successful field application that led to increase in net oil production and OPEX saving are also discussed.
Technology & Knowledge – Support for Learning Curve Implementation. An Experience in Off-Shore Oil Developme
Authors: Marchetti Pier Zaverio , Ezzaroug Adel , Fabro Gabriele , Parziale Sabino
Published: November 2018

The scope of this paper is to highlight, through the analysis of the technologies used and the specific knowledge of the operational team, that the combination of technologies and know-how of the operative people are the key factors for success in well operations.

Description of the different technologies applied during the development of an off-shore field in conventional water as adjustable well head, temporary P&A with mechanical bridge plug, LWD strategy and implementation of the design and procedure developed by the operative team during the activities, based on the real feedback, as light vs high casing profile, 21 ¼″ instead of 29 ½″ diverter using CP 20″ vs 30″, 4 ½″ mono-bore completion for horizontal wells, CT mill motor 2 7/8″, Plug&Perf® methodology, fracture operations material and methodology.

Application of these technologies and knowledge of the integrated team gave a sensible reduction of operative time (40% for vertical wells and 50% horizontal wells in comparison to the initial development well drilled) and relevant cost. The paper will analyze the evolution of the drilling and completion programs and the technologies applied in order to improve efficiency in operating time with reduction in drilling and completion cost. The main topics that will be presented are: ➢Light casing profile (13 3/8″ – 9 5/8″ – 7″ – 4 ½″) vs Heavy (20″- 13 3/8″ – 9 5/8″- 7″- 4 ½″)○20″ CP drilled vs 30″ CP hammered○9 5/8″ casing middle alt depth vs 9 5/8″ below bottom salt➢Optimized LWD strategy - wire line only as back-up➢CP hammering (WHP4) - off line hammering in parallel with other operation with JU➢CP 20″ vs 30″ - smaller hole and material stock optimization (WHP3)➢21 ¼″ instead of 29 ½″ diverter (WHP3)➢OBS II adjustable well head for 9 5/8″ casing (WHP3)➢P&A with Bridge Plug (Archer plug) instead of cement plug (WHP3) for temporary abandonment➢Use 4 ½″ mono-bore completion for horizontal wells➢Bigger CT mill motor 2 7/8″ on 1 ¾″ coil tubing.➢Plug&Perf® methodology used for selective fracture operations.

The paper gives a real experience on how a combination of technology and human experience of the integrated team gives excellent results on learning curve with good impact on Operating Time and relevant cost associated.
What Happened During Normalization?
Authors: Ramachandran Karthik Nataraj , Al Hammadi Ayesha , Al Hosani Khalil
Published: November 2018

Building a performance driving culture is often analyzed from the viewed from the perspective of standardization of the performance appraisal process. What is often ignored is the assessment of the behavioral change required to ensure that all the employees are aligned to the desired culture. The organization under review has introduced the concept of "Normalization" to bring fairness, transparency and alignment of the required culture. Using the concept of sensegiving and sensemaking, this paper explores if the Normalization process has achieved the desired objective of reducing the gaps between the desired and actual culture orientation. This is done though the analysis of the feedback on the employee's performance by the line manager and the normalization committee. This textual analysis is then compared against the desired scheme of the rating descriptors to analyze the gaps in the culture building process. According to the authors this may be the first time observational and textural analysis is used for this kind of research.
Optimizing the Completion Design of a Maximum Reservoir Contact Well for Enhanced Deliverability, Monitoring and Accessibility
Authors: Gharbawi Shihabeldin , Saqib Talha , Kaouche Salim , Sabri Abdul Moez , AL-Mehairi Omar , Mutairi Ali Al
Published: November 2018

The Maximum Reservoir Contact (MRC) concept was developed to improve well productivity and sustainability by maximizing the contact area with target reservoirs. MRC is a proven technology for the development of tight/non-economical reservoirs. Completion design for MRC wells plays a vital role in enhancing well deliverability, monitoring and accessibility.

MRC technology was put into application to appraise a tight and thin heterogeneous carbonate reservoir in a giant offshore field in Abu Dhabi. Different completion scenarios were simulated to select the best suited completion to achieve enhanced well deliverability, monitoring and accessibility.

Heavy casing design with liner and tie-back system was finalized to maximize accessibility and achieve proper isolation behind casing. A special pre-perforated liner was also designed to eliminate the pressure drop across the wellbore. The MRC drain was divided mainly into two sections, blank pipe and pre-perforated liner equipped with swell packers for isolation. Pre-perforated liner was subdivided into compartments for proper flow distribution, accessibility and monitoring.

The blank pipe was utilized to isolate the potential gas zone. Fractures and faults presented a major challenge in achieving the well objective. Special logging requirements were also considered for proper characterization of the suspected faults/fractures as well as to confirm and locate the source of gas risk for compartmentalization.

For proper accessibility, monitoring, stimulation and sustainable production, tapered upper completion was designed and equipped with permanent downhole gauge for continuous monitoring.

The well was successfully drilled and completed with production performance exceeding expectation which will indeed pave the way to apply MRC technology to unlock the all-out potential from undeveloped tight heterogeneous reservoirs within the field.
Application of Underbalanced Coiled Tubing Drilling Technology to Enhance Gas Production in Deep Carbonate Reservoirs
Authors: Guizada Pablo , Rahim Zillur , Aliraani Bodour
Published: November 2018

Heterogeneus deep carbonate reservoirs require enhanced development strategies to maximize reservoir contact and ultimately to increase the recovery factor. In some complex carbonate reservoirs, conventional strategies for reservoir development are not always the best choice and new technologies have to be applied to optimize the reservoir development. In such cases, underbalanced coiled tubing drilling (UBCTD) has proven to be a suitable approach to exploit more complex reservoir areas, where conventional drilling and stimulation techniques no always meet well productivity expectations.

The UBCTD technology consists of drilling a well with a drilling fluid pressure lower than the reservoir pressure, which tends to minimize the formation damage. Due to the underbalanced condition imposed in the wellbore, the well is allowed to flow naturally during drilling, while its productivity is measured. Another technique that accompanies this strategy is called bio-steering, in which cuttings are inspected while drilling to detect micro-fossils from the reservoir. Based on the real-time well productivity and the micro-fossils appearance, the well trajectory can be adjusted and corrected during drilling to chase the good wellbore productivity layers.

A number of wells has been drilled using this strategy with encouraging results so far, which opens a great window to continue exploiting the reservoirs under development. With this technology, multilateral placement is possible with a high degree of accuracy across thin reservoir layers, which maximize the reservoir contact and increases the well productivity. This work presents a general description of this technology as well as present a successful field case including all stages from well planning to well execution and testing.
Drilling Optimization in Action - Delivering 125 Field Records in 6 Quarters
Authors: El Hawy Ahmed , Al Busaidi Adil , Vasquez Bautista Ramiro Oswaldo , Awadallah Muhannad , R. Heidari Mohammad , Saidi Khaled , Escamilla Barton , Al Abri Zahran , deBoehmler Guy , Al Harthi Said , Haeser Patrick , Al Riyami Khaleel , Picha Mahesh
Published: November 2018

As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success.

While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons. Drilling optimization in action was then introduced with its’ comprehensive drilling optimization package, where all historical norms, failures, lessons, and designs were analyzed thoroughly. New objectives and revised designs were proposed accompanied with a whole new process that ensured success.

From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones.

Drilling optimization in action project was successfully introduced and executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits models, adequate technology utilization and effective real-time performance reporting and monitoring.

While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.
Multistage Fracturing Completion in Vertical Wells - Is it Applicable? Yes
Authors: Ibrahim Ehab , Sayapov Ernest , Hinai Rashid , Qarni Sulaiman , Kristanto Royke
Published: November 2018

In low-permeability formations such as tight gas reservoirs, a well would be economic only if an effective hydraulic fracturing technique is selected. In central part of Sultanate of Oman a deep tight gas field is developed with hydraulic fracture stimulation. Normally, between 7 and 13 frac stages are done per well. Majority of wells are vertical with pay zones separated with shale layers that prevent fracture growth. Plug & perf is a common technique used in this field, therefore there are multiple well interventions during Hydraulic Fracture operations that consume time and delay the well delivery. By deploying multistage frac completion with the objective of producing, enhancing and cost/time savings, the effectiveness of the fracturing operations was expected to increase. Equipment selection, design and development was performed based on well conditions, casing design, operational parameters and production gas composition.

Multistage frac completion allows the frac operation to be continuously performed without the need to conduct intervention activities such as running/setting frac plugs, perforating, milling and clean-out between intervals. The intervention activities can be conducted at the end of the frac operation in single-trip deployment if desired. The success in North America in horizontal tight gas wells has opened a door for implementation of this system in vertical wells in Sultanate of Oman. The main challenge in deployment of this system in vertical wells is the accurate positioning of the sleeves. The shale layers between the pay zones could be as narrow as 5 m or less and a small pay zone might be easily missed. Besides, deployment and cementing operations are equally essential as proper zonal isolation is a must with water zones embedded in between.

This paper is discussing the lessons learned from utilization of multistage frac completion in vertical deep wells (around 5000 m) covering the completion and Hydraulic fracturing stimulation operations. This technique has proven significant cost & time reduction and production increase as well as reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country.
Use Metaheuristics to Improve the Quality of Drilling Real-Time Data for Advance Artificial Intelligent and Machine Learning Modeling. Case Study: Cleanse Hook-Load Real-Time Data
Authors: Al Gharbi Salem , Ahmed Moataz , ElKatatny SalahEldin
Published: November 2018

The drilling engineers are overmild with huge amount of data-points, argue the need to develop Artificial Intelligent (AI) and Machine Learning (ML) models to crunch these huge amount of data generating decision-like information. There are a lot of challenges developing such approach, varying from computational power, lack of subject matter experts, and develop the optimum algorithm. But the main bottleneck is the quality of the data. Regardless of how advance AI/ML model, if the data is bad, the model will generate bad result; garbage-in garbage-out. The scope of this paper is to use metaheuristics models to improve the data quality. The process start by extracting Hook-Load drilling real-time data. And explore the raw data quality using visualization and statistical methods. Then apply several Metaheuristics models to generate functional approximation equation that identify/ follow the trend of the good-quality data. This will be by employ multiple scenarios with different degree of randomness that lead to the highest matching which generate the high quality level. The process will cover different technique including Greedy, Hill-Climbing, Random Search, and Simulated Annealing. During this process hundreds of thousands of scenarios will be conducted to simulate the Hook-Load data, to identify the optimum functional approximation equation that match the best data quality. Which can then safely integrated into the advance Artificial Intelligent and Machine Learning models. Running such process require an expensive computational cost, since it includes huge amount of real-time data need to be process under complex advance models. Moreover it require a deep understanding of the internal process of each models to ensure finest manipulating them to get the optimum data quality result. Running these scenarios, lead successfully to functional approximation that spill the data behavior, with Mean Absolute Error (MAE) equal to 10.5. It is worth height that functional approximation is very expensive in term of time and complexity, but it generate the highest quality result, leading to better AI/ML model. Moreover it is the most dynamic approach allowing it to be applied in other drilling real-time parameters as well. Utilizing Metaheuristics approach to improve the data quality is new to the upstream domain in general, with almost no application in drilling in specific. The novelty is to introduce this advance technique into the drilling real-time data domain, it will sharply improve the data quality leading to higher Artificial Intelligent and Machine Learning prediction/ analytical models. It worth mentioning that such approach will run all those simulation/ scenarios and adjust itself automatically with almost no manual interference. Leading to self-data-driven data-quality model.
Operationalization of a New Systematic Work Process at PETRONAS Carigali Sdn Bhd
Authors: Choudhuri Amit , Jainal M Saifunazim , Adenan Mustafa , Takei Jamaludin B , Ali Toslan B , Janor M Nazori
Published: November 2018

An innovative work process for integrated and collaborative way of working has been developed and is being operationalized throughout all PETRONAS Carigali operating blocks, within Malaysia and also, in all International Countries wherein PETRONAS Carigali is the operating partner. This process is inline to the Company's vision for a phenomenal shift in the way that the company's workforce accomplishes its tasks, employing latest digital technologies and efficient work processes. Through this work process, the intention is to integrate all systems and tools, adopt collaboration between various work disciplines and come up with a novel work process that is lean with the prime objective of maximizing production and improving the production efficiency.

This integrated and collaborative work process is being named as Reservoir Well Facility Management (RWFM), encompassing all the six production lenses and is thus an end-to-end business process. The geographical areas of operation of the Company are vast and scattered across the world. Thus, a need has been felt to standardize the work practices across all operating blocks in order to ensure that there is a standardized and integrated way of working at every work location. Also, there have been a number of digital solutions deployed over the last couple of years and the immediate need is to integrate all these solutions as well as to enhance their utilization. This RWFM work process will facilitate increased utilization of the tools as well as integrate all the current solutions.

The new work process has been deployed as a program at most of the Assets of the Company. The process will take some time to be fully practiced and the program team will be looking at a stabilization period before the Assets actively implement it in their daily routine. There is a Change Management effort ongoing in parallel to assist the operationalization team and to bring in the mind set change to inculcate the new way of working. This paper will entail a detailed discussion on the work process and the operationalization activity undertaken by the focused team.
New Techniques Developed to Safely Unload and Test High Rate Offshore Sour Gas Well With 7-in Monobore Completions-Lessons Learned Gas Wells Offshore Sarawak Malaysia
Authors: Azraii Azraii Fikrie , Adhi Adhi Naharindra , Hui Chie Thian Hui , Claire Claire Chang , Ridzuan Ridzuan Shaedin , Roh Cheol Hwan , Zarir M. Zarir , Firdaus Firdaus Bidi
Published: November 2018

Sarawak, Malaysia first offshore high rate dry gas field has an over pressured reservoir. Successful pressure control during drilling required the use of barite in the water based drilling mud in PMCD mode inside carbonate. Barite is very abrasive and is insoluble in any acid or solvent. Any barite left in the reservoir due to mud losses has to be produced back to surface after completing the wells. This cleanup is crucial for the safety and longevity of permanent facilities, especially when high rate gas wells are involved; due to the high rate of impact of any solids that may be produced with the gas. It is also critical to design the cleanup job carefully to ensure proper equipment and safety measures are taken to avoid washouts and related safety hazards.

To ensure solids free production from day one, a procedure was implemented and successfully executed during the development of this first offshore high rate high-pressure sour gas field. This was achieved by using the tender rig as a main support and complementing the safety with the incorporation of the selected well testing equipment management system. In addition to the proper equipment, a detailed cleanup procedure, which covered systematic production ramp up and defined solids free criteria, was implemented from well owner or asset. So far, this well cleanup setup and program has been implemented on several wells on platforms with minor erosion and no safety issues.

One platform with several wells is already producing and is flowing trouble free. This paper will describe the details of the setup of the rig facilities to clean these barite fluids from the wells, and the solids control equipment used and the cleanup procedure.
Specific Analyses for the Reassessment of Existing Offshore Platforms Under New Seismic Conditions
Authors: Brocherie Jérome , Bounhoure François , Barbier Frédéric
Published: November 2018

The recent major seismic events in South East Asia have led the Oil & Gas Companies to reevaluate the design of their offshore platforms with sometimes more stringent seismic conditions than original ones. The Yadana offshore platforms located in a high seismic activity area in the Andaman Sea, operated by TOTAL E&P MYANMAR, were part of this important work. DORIS Engineering and GDS have developed specific seismic analyses to validate the design under new conditions.

This paper will present the different engineering challenges which were faced to revalidate the structural integrity of the different jacket type platforms under new seismic conditions. It will describe the methodology specifically developed for this project and how were identified and defined the necessary site modifications. These analyses were developed to assess more accurately the maximum relative displacements of jacket type platforms connected by bridges and to validate the stresses in foundation piles. It will also address the offshore works performed on the platforms with a maximization of SIMOPS works and limited shut down periods.

Insufficiencies in the conventional design approach required to develop specific methods to validate the integrity of the jacket foundations and the platforms displacement (bridges). This paper will address, in particular, the design methodology used to verify the integrity of the jacket foundations and to define the required topsides and jacket reinforcements. A time domain approach, based on the "ASN" guidance used for nuclear facilities, was developed to verify the pile stresses and assess more accurately the maximum relative displacement of the platforms connected by bridges. The offshore works were afterwards performed in a timely and cost-effective manner. The detail engineering and the operation offshore had to include risky and unconventional operation such as bridges pot bearings replacement or piping modifications on bridges. SIMOPS works were maximized allowing the shutdown to be limited to the shortest duration.

This paper presents the different engineering challenges which were faced to revalidate the design of existing platforms. It presents the specific methods which have been successfully developed by engineering to validate the design. This project is a good example of a "brownfield" project, from a challenging situation through development of a reliable and efficient engineering solution to successful completion of offshore works.
A Novel Strategy to Identify Potential Savings in Digitized Oilfields Through Automated Drilling Data Analysis
Authors: Ansari Arsalan , Watfa Mohamed
Published: November 2018

Digital oil fields implementation is ongoing in various oil fields around the world since the last few years. There are many research initiatives focusing on performance improvements trying to eliminate Non-productive time (NPT) caused by equipment failures or drilling conditions but the Invisible Lost Time (ILT), which accumulates when common drilling operations such as drill pipe connections are not carried out efficiently, is neglected. This makes it difficult to compare well delivery time and performance discrepancies for each activity across a field. The main challenge in optimizing drilling performance is deciphering the rich data streams in real time to make informed business decisions. This study focuses on the integration and analysis of real-time drilling data in order to evaluate the drilling performance via Invisible Lost time.

The methodology starts with analysing the effectiveness of the Remote Monitoring (the backbone of Digital Oil Field) of critical drilling operations as the actual performance is compared with predefined operation practices in terms of Rig Performance, Individual Crew Performance and Section Performance over four unknown drilling wells located within Field-X in the North Sea. The Invisible Lost Time is quantified from selected drilling activities such as tripping, drilling, running casing and flat time operations that can result in significant potential savings other than the main drilling operations.

Histograms were utilized to improve rig performance which indicated that the Connection time can lead to significant days’ savings as Tripping time contributes to approximately 60% of the Invisible Lost Time (ILT). Additionally, the effect of various factors such as hole sections and well depth on potential savings was also studied. This strategy may be developed as a cost-effective technology for any drilling or workover wells, as it results in improving drilling key performance indicators (KPI's) leading to performance improvement, risk mitigation and cost efficiency in real-time drilling activities.
Optimization of Models for Rapid Identification of Oil and Water Layers During Drilling - A Win-Win Strategy Based on Machine Learning
Authors: Sun Jian , Li Qi , Chen Mingqiang , Ren Long , Sun Fengrui , Ai Yong , Tang Kang
Published: November 2018

The identification of oil and water layers (OWL) from well log data is an important task in petroleum exploration and engineering. At present, the commonly used methods for OWL identification are time-consuming, low accuracy or need better experience of researchers. Therefore, some machine learning methods have been developed to identify the lithology and OWL. Based on logging while drilling data, this paper optimizes machine learning methods to identify OWL while drilling.

Recently, several computational algorithms have been used for OWL identification to improve the prediction accuracy. In this paper, we evaluate three popular machine learning methods, namely the one-against-rest support vector machine, one-against-one support vector machine, and random forest. First, we choose apposite training set data as a sample for model training. Then, GridSearch method was used to find the approximate range of reasonable parameters' value. And then using k-fold cross validation to optimize the final parameters and to avoid overfitting. Finally, choosing apposite test set data to verify the model.

The method of using machine learning method to identify OWL while drilling has been successfully applied in Weibei oilfield. We select 1934 groups of well logging response data for 31 production wells. Among them, 198 groups of LWD data were selected as the test set data. Natural gamma, shale content, acoustic time difference, and deep-sensing logs were selected as input feature parameters. After GridSearch and 10-fold cross validation, the results suggest that random forest method is the best algorithm for supervised classification of OWL using well log data. The accuracy of the three classifiers after the calculation of the training set is greater than 90%, but their differences are relative large. For the test set, the calculated accuracy of the three classifiers is about 90%, with a small difference. The one-against-rest support vector machine classifier spends much more time than other methods. The one-against-one support vector machine classifier is the classifier which training set accuracy and test set accuracy are the lowest in three methods.

Although all the calculation results have diffierences in accuracy of OWL identification, their accuracy is relatively high. For different reservoirs, taking into account the time cost and model calculation accuracy, we can use random forest and one-against-one support vector machine models to identify OWL in real time during drilling.
Standardizing the Data Structure and Formats to Meet the Business User Requirement
Authors: Kumar Pranav
Published: November 2018

Data Management concept is well understood now a days, in Oil and Gas industry. General workflow of data management starts with data generation, its processing (if required), followed by data loading into specific datastore, database or location (on file system), with the aim of for sharing it with the end user. A lot of integration happens with different systems and the corporate database, to perform various studies. This is all done under defined data governance rules and Service level agreement. This paper focusses on standardizing the data structure and formats, so that end users have to spend less time in getting the data for their daily use and interpretation. Additionally, the proposed work shows the ability to fix the data quality issues at the source. At the later stage, no one has to run the data quality checks, tools or scripts for fixing any data quality issues, separately.

The below steps can optimize the data quality and format issues: Data management team to coordinate and meet the end users to know the subsurface software used, data type used, problem while loading the data in the applications.Make listing and categorization of the data format required by the subsurface applications.Make listing of the units, coordinate system, and reference datum of data type as a standardCoordinate with contract administrators, vendor, contractors, data loaders to setup guidelines and instructions to deliver the data in the required formats.Create automated workflows for loading the data

The vendor or contractors have been generating data as per defined parameters in the service contracts. It is suggested to modify the contracts, so that the data is received as per the end user requirement. The benefit of using the method will aid the following: Each stakeholders involved in the data flow will gain knowledge about the dataData Quality and completeness checks will be improved.The end users of the data who are actually working on the data will find it easier to load or do interpretation.Data Standard will be implemented with much easier way.Issues related to data loading will be resolved in a better way.It will be easier to automate the process of receiving the data.
Dare to Change: PETRONAS New Approach to Implement Artificial Intelligence of Wells Activity Performance and Benchmarking Tool
Authors: Mohamad Azlan , Radzlan Raihana , Wan Hassan Wan Helmi
Published: November 2018

PETRONAS Carigali Sdn. Bhd. (PCSB) Wells Department (formerly known as Drilling Division) has long realized the importance of drilling and delivering most cost-effective Wells for the Exploration and Development segment, by establishing the PETRONAS Digital Collaboration Centre (PDCC), which serves as a decision support platform for stakeholders to monitor, reduce, and eliminate operational and safety problems during drilling, but a piece of the puzzle is still missing - to measure the well activity performance.

The earlier arrangement heavily relied on human factors such as the time-consuming logs that were completed manually by the PDCC personnel within 7 days after each completed well section. The analysis was done manually using excel spreadsheets, only focusing on major well activities, for example running the casing/liner and connection time. However, no pro-active action was taken during the operations to improve the performance. Furthermore, there is no ability to intervene with the rig performance in real time and adapt a technical limit approach. The Operational Excellence coach has limited experience and no tools to measure the technical limit, which also leads to a knowledge gap in wells performance and benchmarking areas of the drilling engineer's portfolio.

The implementation of the new artificial intelligent tool, presents revolutionary management challenges for people, process, and technology within the PCSB, aligning with Well's House vision to be "World Class Well Delivery – Preferred Solutions Partner".

This paper presents the business requirements and implementation of the PETRONAS Wells Performance Tool, and also describes the comparison between the previous approach and the challenges faced with implementing the new solution.
Field Trial Results for New Sand Control Technology for Water Injectors
Authors: Fipke Steven , Charles J. E. , Green Annabel
Published: November 2018

In 2014, an R&D project was intitiated to develop an innovative technological solution to improve the performance and reliability of Deepwater Gulf of Mexico assets. The objective was to increase the life expectancy of Miocene and Lower Tertiary water injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion.

Before scoping out the project, an internal study was conducted to compile and analyse the available data. The root problem was identified as an accumulation of formation solids inside the lower completion; principally fine matrix sand that had been pulled in from the reservoir. These formation solids are normally stationary during steady injection, but can be mobilized during shut-ins (maintenance, pump problems, environmental conditions, etc.) due to powerful transient flow effects such as back-flow, cross-flow and even water-hammer. Eventually, enough solid fill can accumulate inside the lower completion as to diminish the injection rates. At this point the operator must consider some very expensive options such as to sidetrack or re-drill a new injector well.

The obvious solution to this problem was to find a way to prevent the fine material from getting inside the completion. The challenge was to do so while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. Therefore, the goal of the project was to find a practical, efficient method of stopping the formation material from entering the lower completion during a shut-in cycle. To achieve this, a new flow control device (FCD) and completion system was developed with intrinsic non-return valves (NRV) that are designed to prevent any back-flow or cross-flow during the shut-ins. Also, depending on well conditions, the system will minimize the damaging effects of water-hammer: rapid, high-amplitude pressure cycles that can occur during a sudden stoppage of flow.
Improving Field Development Through Successful Installation of Intelligent Completion on Water Injector Well
Authors: Yanez Eglier , Uijttenhout Mattheus , Zidan Maher , Salimov Rail , Al-Jaberi Salem , Al-Shamsi Al Anoud , Al-Sereidi Amnah , Amer Mohamed Mostafa , Al-Hammadi Yousef , Abdul-Halim Abdullah , Caletti Giovani , Adli Mustapha , Al-Hammadi Yousif Hasan , Al-Hosani Fahad Mustafa
Published: November 2018

Including "smartness" in your field does not necessarily add additional expenditures. ADNOC Offshore piloted a new well completion design combining Interval Control Valves (ICVs) in the shallow reservoir and Inflow Control Devices (ICDs) in the deeper reservoir, both deployed in a water injector well for the first time in the company. The objectives were to improve reservoir management, reduce well construction complexity and achieve one of the main business targets of cost optimization. This paper covers the subsurface study, detailed well construction design, completion deployment, well intervention and overall well performance in commingled injection mode.

A multi-disciplinary study was conducted based on updated reservoir data available after the first two years of production in a heterogeneous multi reservoir field. This study showed the possibility of replacing the upper horizontal drain by a deviated perforated section. The authors identified the need of completion compartmentalization to overcome challenges such as high reservoir heterogeneity and uneven pressure depletion enforced by non selective acid stimulation. As part of the evaluation, a simulation was performed to evaluate the expected injection performance across the four zones with different combinations of ICVs and ICDs in order to cater for different injection scenarios.

As a result of the integrated analysis, a new well completion design was deployed to optimize a Dual Horizontal Water Injector into a Single Smart Completion with 3 Inflow Control Valves (ICVs) covering the upper perforated zones and 14 Inflow Control Devices (ICDs) with sliding sleeves across lower lateral reservoir. Cost savings and reduction of rig time was achieved with this new completion design demonstrating very pro-active participation from all involved teams, ADNOC Offshore and Service Companies.

The requirements to complete high and low permeability zones in one single well can be successfully accomplished. Firstly, mitigation of early water breakthrough is achieved by incorporating surface water injection control in high permeable zones and secondly, the injection target for the low permeable reservoir is also delivered.

Building on the successful results and captured lesson learnt, this new well completion design provided the capabilities to optimize the water injection plan while reducing costs. Therefore, the project has passed the trial phase and the team proposed its implementation.
How Targetless Local Position Reference Sensors will Change and Improve the Experience of DP Operators
Authors: McKnight David
Published: November 2018

Position reference sensors (PRS) in dynamic positioning systems have either been global systems, such as GNSS, or targeted local PRS, such as laser, radar, or taut-wire. Local PRS operate by placing an artifact into the environment and tracking that. For a laser or radar local PRS that artifact is a reflector or a responder. For a taut wire that artifact is a heavy weight. Once this artifact is in position then the sensor tracks where it is relative to the artifact.

This method of operation, where an artifact is tracked, is understood throughout the DP industry. Targetless local PRS disrupt this as the system no longer relies on targets placed within the nearby environment, but on the environment itself. They may rely on self-mapping technologies or they may be looking for specific structures or features in the environment. These both result in a method of operation which may hold surprises for one trained in traditional DP sensors.

This paper discusses the nature of the changes and what a DPO should be aware of as they approach the use of these sensors. We will also look at particular scenarios where this new operating paradigm will convey particular advantages to the user.
Update in Development of Advanced Plasma-Based Technology for Rigless Well Intervention
Authors: Kristofic Tomas , Kocis Igor , Gajdos Matus , Horvath Gabriel
Published: November 2018

Plasma-based technology for various upstream applications has been under development for a couple of years. The first commercial application is for wellbore tubular removal or "milling" for Well Plug and Abandonment the main focus being the North Sea and Gulf of Mexico. In parallel to this process, the technology can be applied also for other well intervention applications E.G. Slot Recovery, Fishing and Re-entry, where removal of long tubulars sections is required.

The initial presentation of this novel idea for the Middle East was at ADIPEC 2015 where the development team presented the paper titled Non-contact Approach in Milling Operations for Well Intervention Operations. The main objective of the paper was to present the possibility of non-contact approach, based on electrical plasma in downhole milling or cutting operations. The present paper follows this paper from 2015 and summarizes recent achievements in progressing the development and commercialisation. It focuses mainly on successful milling tests of long tubing sections.
A Cost-Effective Dual-Element Metering System for Wet Gas Flowrate Measurement
Authors: Halilah Sami , Mokhtari Kahila
Published: November 2018

A wet gas flowmeter based on field-proven flowmeters and flow computers has been developed. The flowmeter is engineered by integrating the well-established SmartCone meter, a Pitot tube meter and filed mounted Flow Computer technologies in one wet gas metering solution. This combination exploits the characteristics of these two flow metering elements in wet gas flowrate measurement; The Cone measurement in wet gas is characterized by its relatively large gas measurement over-read with increasing liquid-loading, whereas this has a significantly lower impact on the gas flowrate measured by the Pitot tube.

The DynaCone wet gas flowmeter has been in development over the past several years with particular emphasis being placed on developing a flexible flowmeter for broad operating conditions and applications including high turndown ratio, minimal pressure loss, measurement quality diagnostic, and performance characterization in industry-recognized wet gas flow loop.

The wet gas performance has been demonstrated at CEESI wet gas flow loop yielding gas flowrates better than ±3% in Type I wet gas range, and better than ±5% in Type II without the input of liquid flowrate to correct for over-reading. Furthermore, uncertainties better than 2% and 3% for Type I & II respectively can be achieved if periodic liquid flowrate information is available for input.