bluuebunny/crossref_metadata_2025 huggingface dataset:
Computational Fluid Dynamic Modeling For Hazardous Gas Dispersion Analysis In Deepwater, Brazil
Authors: Franklin Gabriel , Barros Wagner , Ceciliano Marcos , Cunha Jeferson , da Rocha Aquiles , Fagundes Diego , Margotto Romulo
Published: November 2020

The production of hazardous gases such as CO2 and H2S impose high risks to offshore operations, with lethal impacts on personnel, along with special equipment required and environmental challenges. Hydrocarbon productions require that part of this gas could disperse on the atmosphere, so a comprehensive risk analysis is necessary to evaluate the gas disposal event. Computational Fluid Dynamic (CFD) can be used to effective study how the wind and environment can interfere with the gas dissipation in the air. In this work, a specific analysis was necessary to produce a gas well with up to 80% CO2 fluid composition. A CFD Gas Dispersion Analysis evaluated the turbulent airflow over and offshore drilling vessel perimeter to map the flammability levels and hazardous gases concentration zones, depending on winds speeds, wind directions, and well gas flowrates. Parallel processing was applied in order to reduce the computing time for simulation of 52 cases on gas release on burner booms and relief lines, and 56 cases for leak analysis on the process plant. The results permitted defining using 3D maps the concentration levels of hazardous gases on the rig expected on each scenario condition, as well as the coverage area outside the vessel affected by the gas release.
Planning and Challenges of Longest Complex 3D ERD Well Drilled in United Arab Emirates Onshore Field Artificial Island using Slim Casing Design
Authors: Hashmi M. Asef , Salem Gamal , Morales Annie , Banihammad Basma , Al Yamani Sultan Mohamed
Published: November 2020

This well was drilled with the objective to support the pressure sustainability of multiple producer wells across Lukhweir-2 formation based on ERD approach. This paper presents the challenges faced in planning and drilling of subject ERD well with a total measured depth of 27,352ft (8.34km) and having horizontal hole of 11,300ft (3.45 km reservoir contact) with directional difficulty index (DDI) of 7.208 using light/slim casing design.

Planning of this well started by meetings and collaboration with asset team to a common objective of delivering the longest well across Lukhweir-2 (LK-2) reservoir to support the multiple producers and mitigate all the associated risk by proper planning and drillability analysis such as trajectory design, collision risks, BHA, hydraulics and casing designing. This paper will explain the novel approach of mitigating the challenges faced while drilling this ERD well such as concerns about surface hole drilling (30 deg across interbedded shale formation), challenge in running 7" long liner (>8000ft across multiple reservoir) and overcoming surface pressure and torque limitations while drilling. Results, Observations,

This ERD WAG injector well is the first and longest to be drilled with 6" drainage across Lukhwair-2 reservoir from artificial island to have 11,300ft of 6" Geo-Steered Horizontal hole section using Slim Casing design which gives the total well measured depth of well 27,352ft MD / 10,101ft TVD (2.7 ERD H:V ratio) Results from this well have proven that ERD wells with longer reservoir contact have significantly improved well performance, enhanced reservoir management and reduced field development cost. This paper summarizes the practice and technology used to drill successfully the longest ERD / MRC well using slim design practice which includes the utilization of special dope for 4" DP to increase the torque limit, use of special surface equipment called chillers/coolers to over overcome high downhole temperature. This paper will also capture the drivers, selection criteria and lessons-learned over the entire well drilling.

The challenges/mitigation explained in this paper will stretch the ERD/MRC boundaries and support engineers to design the complex 3D wells with slim/light casing design and can achieve extended targets with 100% integrity.
The Operator's Eyes Downhole: Multiple Applications for a Novel Autonomous and Wireless Real-Time Integrated Monitoring System
Authors: Bezerra de Melo Ricardo Cesar , Eid Ramy N. , Tubel Paulo , Pasupathy Praveenkumar , Martinez Zuazo Iker
Published: November 2020

Nowadays wells are drilled deeper, hotter, and subjected to higher downhole pressures making it more complex for completion, deployment of production tools, and to maintain long term well integrity. It is evident that the utilization of downhole data is becoming more important, to optimize production, maximize the recoverable reserves, and to preserve the proper structure of the wells, facilitating their full life cycle until decommissioning. The Energy industry is relying on new technologies to reduce the cost of exploration, production, and maintaining the wellbore's structural integrity for the duration of the well-life as well as the reduction of their decommissioning cost.

This paper addresses various new opportunities created by an "integrated" casing/tubing/microsensor technology, and real-time data communication from downhole to the surface. This manuscript will highlight some of the main components of this Novel Autonomous and Wireless Real-time Integrated Monitoring System, which consists of: A smart casing-collar module with an array of various sensors, to monitor casing/cement for the initial state of stress, formation creeping, open annuli and near-wellbore reservoir properties. This information is processed through a short-hop, two-way wireless communication system, for data and command transfer from the casing module to the tubing module, and a wireless power transfer system, to provide power from the tubing-module to the casing-module.An intelligent tubing module deployed near the smart casing-collar module that contains another set of smart sensors for production and annulus monitoring. Interfacing with the casing module is done via the short-hop wireless power transfer and communications system. Included here is a downhole power generator and a real-time wireless communication for data transfer to surface. This provides the end user, the ability of in-situ power generation and real-time wireless data.

The abovementioned integrated system is aimed at addressing the entire well-life planning needs, as it can feed the asset management system for production optimization, zonal isolation, P&A placement, casing integrity, formation creeping, reservoir evaluation, and potential decommissioning requirements. Custom-specified systems can quickly adapt and incrporate new features that are of potential benefit to other "industries".
Artificial Intelligence Based Optimization of Gathering System
Authors: Lakshmanan Charan , Muralidhara Srikanth , Karajagi Nachiket , Chakraborty Somdatta
Published: November 2020

Gathering system optimization is no longer an option for any operator, it is a necessity. The primary objective for an operator is to match the demand at the sales point to avoid penalties due to minimum volume commitment (MVC) agreement.

With time, operators face challenges to adhere to this demand due to inefficient production surveillance, production optimization & capital project evaluation. Also, with oil & gas price at its lowest, operators are now facing increased cost pressures leading to less personnel for field operations.

Operators are now collecting & managing a lot of data than ever from their operations as part of their digital journey, which enables them to improve the network performance using machine learning. Insights or details missed by operators or conventional first principle-based models can be derived & explained using these models.

The paper talks about this novel approach of machine learning-based collaborative platform called ‘Digital Twin’. Digital Twin is based on automated data flow from ingesting data from SCADA system, pushing required data to the steady-state simulator, receiving simulated results, & finally viewing the machine learning augmented simulation results on the platform.

In this solution, the Bayesian Changepoint model is trained on wellhead flowrate & line pressure to identify critical wellpads & pipeline sections needing intervention, in real-time.

Deep learning-based neural network algorithm is then integrated as part of the digital twin to accurately predict the scenario of field changes. This neural network algorithm is trained on the actual field data along with steady-state simulation results. The model output helps the operator to identify the deviation of the simulation results from actual field data, then improving the simulation results for certain scenarios of field changes.

The improvement in accuracy by about 15% was realised with the neural network structure of 5 layers (3 hidden layers + input layer + output layer) through its machine learning augmented simulation results. With improved accuracy, operators are accepting the solution to make real-time operational decisions through the automated architecture resulting in a 95% reduction in time for simulating scenarios.

This paper aims to provide a blueprint of the digital twin solution & explaining its potential for easy scalability across different gathering networks.
Using Data Science to Enable Condition Based Maintenance and Classification for Offshore Assets
Authors: Subrat Nanda
Published: November 2020

Recent advancements in the field of data science, digital technologies and their applications are presenting new opportunities for marine and offshore fleet operators to adopt a more effective asset management strategy that combines advanced data analytics with maintenance and operational experience to reduce unplanned downtime. Advanced data science and analytics enable timely detection of deteriorating equipment behavior, which in turn optimizes the scope of maintenance activities and planning based on asset condition. When used within a reliability-based maintenance program, they further provide the foundational elements for building an enhanced platform for efficient risk-based decision making and better understanding of asset health and performance. This information can be useful for classification societies to be able to make better class related decisions and make the class experience more targeted for operators.
New Insights on the Interaction of Stick-Slip and HFTO Shown in a Case Study in North Sea
Authors: Heinisch Dennis , Kück Armin , Hohl Andreas
Published: November 2020

Drilling tools are subjected to mechanical loads while drilling, resulting in loss of performance due to accelerated wear and subsequent tool damage. Two special phenomena are well known to generate high mechanical loads in torsional direction: Stick-Slip and High Frequency Torsional Oscillations (HFTO). Preceeding studies have explained the nature of the interaction of these phenomena, how they can superimpose and how stability maps define safe combinations of operational parameters. This paper will provide a systematic and quantitative study of these effects based on high-frequency measurements recorded during a North Sea deployment.

In this paper, for the first time, an in-bit high frequency measuring device is used to validate the theoretical modeling of the stick-slip-HFTO interaction. Field data from the North Sea including surface and MWD measurements are used in a broad study to investigate the influence of operational parameters, bit and formation on the torsional dynamics over the increasing depth of a well. Pure Stick-Slip, pure HFTO as well as the development of HFTO within a slip-phase of stick-slip is observed, described and compared to the theoretical model describing self-excitation. Several hundred instances of stick-slip are used to determine characteristic RPM thresholds for combinations of RPM and WOB. The totality of these thresholds compose a stability map indicating zones of reduced torsional loads.

The study shows that stick-slip amplifies torsional loads generated by HFTO up to a certain RPM threshold. Further increasing the RPM leads to reduced loads for certain combinations of bit, formation and operational parameters. In contrast to common belief, higher RPM can lead to lower torsional loads in certain scenarios while also increasing ROP. The stability map summarizes the learnings, indicating zones of safe operation in an accessible manner.

The resulting stability map can be used by operators to navigate in stable regimes of operational parameters. This reduces wear, tool damages and enhances drilling performance.
Maximizing Mature Offshore Field Value by Using Auto Gas Lift Technique
Authors: Grifantini Simona , Saqib Talha , Sabri Abdel Mouez , Keshtta Osama M. , Albadi Bader S. , Beaman Daniel J. , Al-Hassani Sultan D. , Bigno Yann , Draoui Elyes H. , Bansal Bhagwan D.
Published: November 2020

The giant heterogeneous carbonate field presented here consists of multi-stacked reservoirs and is located in the Arabian Gulf approximately 135 km north-west of Abu Dhabi. The reservoir named "T" measures 9 km by 11.5 km, with large accumulation of 35 °API oil with initial gas oil ratio of about 400 scf/STB. The current reservoir pressure is around 2,700 psi; many of wells are unable to flow naturally against the high sealine pressure, due to low productivity and relatively low GOR. To produce these wells, "artificial lift" or lower sealine pressure are required.

A collaborative team of Reservoir Engineers, Petroleum Engineers and Geoscientists was assigned to find a sustainable and cost-effective solution to produce reservoir "T" in order to evaluate its potential. The team conducted a detailed and comprehensive study of the field starting from reservoir "T" and then expanded to the other reservoirs. As a result, the proposal of an "Auto Gas Lift" (AGL) pilot was formulated to use gas from the reservoir "C" (underlying reservoir T) to artificially lift the oil produced from reservoir T.

AGL is a cost-effective artificial lift system, directly replacing for conventional gas-lift equipment, gas compression facilities, gas transport pipelines and ancillary equipment. This technique has been identified as the most suitable for such mature offshore field, where existing platforms have limited spare load and space capacity and could not accommodate gas-lift compression facilities or ESP topside equipment. The first pilot completion has been designed. It consists of a perforated downhole high GOR zone from which gas is bled into the tubing at a rate controlled by a downhole gas lift valve. The gas produced from high GOR reservoir C will allow reservoir T to flow by reducing the hydrostatic head of the fluid column in the well.

Artificial lift has not been implemented yet in the field. However, several artificial lift techniques, such as Electrical Submersible Pumps or conventional gas lift, are foreseen in long term development plans. "AGL" technique, if successful, could represent a cost-effective solution for further appraisal of this reservoir, without waiting for the implementation of large-scale artificial lift techniques.
Full Automated Casing Running: The Next Step Completed in Field Automation
Authors: De Mul Arthur
Published: November 2020

Objective

Although the drilling industry is slowly moving toward a higher degree of automation, casing running is still left out of this equation. Until now. Due to the more delicate handling that is required to handle casing, the task is often handed over to dedicated casing running service companies. This year, a new rig is build that performs the task of casing running, including making and monitoring the connection, fully automated and 100% hands off: "just press start sequence".

Methods

To enable full-automated casing running, it is required to have a dedicated handler with high precision handling and measuring systems. To reach the maximum safety level, the goal is set to have no people in the red zone on the floor for any assistance.

An integrated (scada) control system needs to combine data as casing length, positioning, amount of turns to spin in and make up torque into one system. It also needs to communicate to the other rig equipment as drawworks and topdrive to enable smooth fully hands off operations.

Results

The above is this year integrated in an HM100 mobile rig and will be deployed in the oilfield in Q3 2020 for a mayor operator. The equipment is capable of handling casing up to 13 3/8" in full automated sequences at a speed of ∼ 1300 ft/hr, more then 300% faster then manual operations.

At a traditional catwalk machine, casing is pushed over the pipe slide. For this reason the thread needs to stay protected by thread caps, until the pipe is in wellcentre. Here usally 2-3 people are present to guide the casing and apply dope etc. To make sure that no people need to work in the red zone on the floor, it is chosen to develop a pipe handler that lifts the casing from pipe bed to wellcentre in one movement, while keeping the thread clear: a massive safety improvement.

The sequence is completed by an automated hand over to the casing running tool on the topdrive.

As final step, while making the connection, the integrated torque turn graph system controls and monitors the connection and stores this combined with the length in the auto-tally system.

Fast save operations, with data readily available.

Novel

This is the industry first mobile rig with full automated casing running capabilities, an important step in the ongoing field automation. With a consistent speed of over 30 casings / hour the time per well is reduced significantly, while there is no need to have separate crews and tools available on location. Casing running will now be predictable in time and duration, with real time results immediately available on the OPC-UA server for the client.
The Digital Transformation Journey from Digitization to Opportunity Generation
Authors: Makanjuola Oluwafemi , Meroney Pat , Gray Max
Published: November 2020

Throughout the history of subsurface exploration, the energy industry has acquired, recorded, and archived extremely valuable subsurface data (including new data) on legacy and new media such as round reel magnetic tape (14-track, 7-track, 21-track, 9-track, etc. circa 1950s), square cartridge tape (3480, 3490, 3590, 3592 series, LTO series, 8mm, 4mm, etc. circa 1980s), optical media (CD, DVD, etc.), and hardcopy documents. The physical media are boxed, inventoried and stored in climate controlled salt mines and/or warehouses. Pertinent media with high priority datasets are recalled from storage, transcribed, and made available for processing, interpretation, data rooms, etc.

The challenges associated with the physical storage construct of these assets include residual storage and shipping costs, pace of deterioration of legacy media, delayed access to requested dataset, valuable data locked away and inaccessible, amongst others. To combat these challenges, ExxonMobil initiated a strategic, upstream wide, digital transformation partnership with Katalyst Data Management whose mission is to increase opportunity generation by reducing the turnaround time of high priority datasets and providing access to previously undiscoverable data.

The digital transformation partnership leveraged the latest tools, technologies, and techniques including enhanced metadata capture, live/automated QC, parsers and loaders, data analytics, automated metadata extraction, etc. In addition, petroleum data management standards and best practices were employed across the digitization value chain.

The digitization of nearly 3 million hardcopy paper or mylar documents and more than 420,000 seismic tapes to date (as of July, 2020) has eliminated recurring physical storage costs, recovered valuable data from deteriorating media, shortened access to high priority datasets from weeks to hours, and provided access to previously undiscoverable "dark" data. Other digitization ‘wins’ include the elimination of the need for ExxonMobil to maintain facilities and hard drives to read physical media. This strategic partnership between ExxonMobil and Katalyst Data Management has led to the convergence of digital data from multiple physical data sources and data types, all on a single integrated subsurface domain agnostic platform. More importantly, it has enabled Artificial Intelligence and Machine Learning use cases bringing about business insights and leading to prospect opportunity generation.
Installing Highly Alloyed Corrosion-Resistant Alloy 25% Chrome Tubing with Dope-Free Connections in Triple Joint Stands to Reduce Running in Hole Time in an Offshore Field
Authors: Bertoldi L. G. , Goretta E. Actis , Piemontese M.. , Sita F. J. , Joao O. C. , Okolie E. V.
Published: November 2020

This paper describes the novel experience of running Corrosion-Resistant Alloy (CRA) 25% chrome tubing with Dope-free connections in triple joint stands to reduce online running-in-hole (RIH) time. To achieve this, an international operator of a deepwater field development in Angola, defined a special set-up for the make-up and handling equipment, along with connections featuring Dope-free technology.

5 V2" production tubing strings were run in triple joint stands in 2 deep water wells offshore Angola. Well "A" had 14 triples while Well "B" had 67 triples installed. Running highly alloyed CRA tubing with Dope-free technology in stands, in conjunction with using the special handling equipment resulted in faster and safer installations, thus reducing operational risk and saving rig time for the operator. Furthermore, the thread compensator performed the make-up with the neutral point at thread pin thus minimizing stress at the thread's metal seal zone. Several other benefits recorded include savings in jet-wash water, zero dope discharge, reduced personnel exposure to risk, reusability of non-contaminated thread protectors and improved well productivity.

The notion of installing highly alloyed CRA tubular in oil and gas wells initially considered too sensitive to be run in triples has been shown to be conservative. This paper shows that from field experience, running highly alloyed CRA tubulars with Dope-free connections in triples is achievable with demonstrable operational improvement and increased reliability.
The Enhancement of Horizontal Water Injection Well by Integrating Single Well With Full Field Dynamic Model in Carbonate Reservoir: Case Study from North Kuwait
Authors: Ashawesh Luai , Al-Otaibi Basel , Khoriakov Vitaly
Published: November 2020

Water injection using horizontal wells has started since 2012 in North Kuwait carbonate reservoirs. The objective of this work is to integrate a detailed steady-state single well model with a dynamic reservoir model along to improve the permeability distribution inside the dynamic model along the horizontal section of the well.

The workflow starts first by building a well model and quantifying the injectivity profile along the horizontal section from the actual wellhead injection pressure and dynamic reservoir parameters. Then the ILT (Injection Logging Tool) data is used by the well modeling simulator to calculate permeability distribution along the horizontal section of the well resulting in the measured outflow profile. The final step is to export the permeability multipliers along the open hole horizontal section of the well into the dynamic model to improve the dynamic model results at the well level.

This workflow was examined on one injection well from the North Kuwait Carbonate formation and shows improvement in well bottom hole injection pressure, reservoir pressure, well injectivity index and water injection rates distribution along the horizontal Openhole section from the dynamic model and better history match.

The coupling of a single-well advanced ILT interpretation with the field-scale dynamic model is considered as a novel approach that improves the dynamic modeling construction on a well-scale level. Instead of a classical approach where reservoir properties are used only to calculate outflow into the well an inverse problem is solved: calculate reservoir properties from a measured outflow profile.
Operational Challenges of Hydraulic Fracturing of Thin, Low Permeability and Highly Sour Reservoirs in the UAE – A NOC Journey
Authors: Edmonstone Graham , Martin Anthony N. , Turniyazov Nurlan , Talib Noor , Al Shehhi Hessa , Jaiyeola Abiodun , El Shahat Ayman , Gerardo Cardozo Luis
Published: November 2020

Although hydraulic fracturing is widely employed throughout most of the Middle East Region's carbonate reservoirs, it remains a relatively unused improved oil recovery (IOR) technique within the Emirate. Given the Company's goal to increase gas production, an in-country initiative was mandated to progress hydraulic fracturing of low permeability reservoirs. A multi-disciplinary project team was created and tasked to prove that hydraulic fracturing of a single horizontal lateral would give an improvement in well performance and value to that of the current technique of drilling open hole tri-laterals.

The first step of the project to develop fracturing capability and best practices, required detailed up front planning by drilling a vertical pilot hole to collect data to build the mechanical earth model (MEM) and thus improve the fracture modeling and design.

The challenges faced in the project so far were:

Data sourcing, calibration and modelling. Low permeability sour gas reservoir with H2S and CO2 around 7%. Gross reservoir thickness less than 50ft. and the absence of strong mechanical barriers to adjacent depleted reservoirs. Limited experience of hydraulic fracturing and conducting operations with a drilling rig. Zonal isolation for open hole multi-zone hydraulic fracturing in low permeability reservoirs. Technical and commercial processes for sourcing required equipment and optimising job execution.

This paper will outline the strategies and tactics employed to implement fracturing in low permeability, thin, sour gas reservoirs, as well as the technical, operational, logistical and contractual challenges that have had to be overcome to date. The stated challenges and also that of operating under current restrictions due to global virus conditions will be described. The contents of the paper and subsequent material will build a Best Practice to successfully implement hydraulic fracturing operations in the Emirate.
Managing Offshore Deepwater Decommissioning: Subsea and FPSO Decommissioning and Abandonment in West Africa
Authors: Zainal Abidin Suzaini
Published: November 2020

An oil field located about 80km west of the African coast at the water depth of 818m had reached its end of economic life. The facilities and wells would need to be decommissioned and abandoned (D&A). The Floating Production Storage & Offloading (FPSO), which was the key component of the facilities, would need to undergo the disconnection and demobilization (D&D) phase. The objective of this campaign was to restore the field back to its safe condition whilst minimising the environmental impact, complying with local and international legislative. The abandonment & decommissioning works was performed in line with good industry decommissioning practices at the most optimize cost. Upon completion of the D&D, the FPSO would need to be demobilised to her original base in the South East Asia (SEA).

This paper discusses a case study for a D&D campaign and activities of the FPSO which includes the Subsea, Umbilical, Riser and Flowline (SURF) and mooring system. One of the crucial areas during the execution phase was pertinent to the management and disposal of the hazardous waste that is subjected to transboundary movement as per the relevant convention. Amongst the hazardous waste were Natural Radioactive Occurrence Material (NORM), low specific activity (LSA) material, hydrocarbon sludge and contaminated water. The FPSO need to be cleared from the above said hazardous waste for her to be accepted by the receiving base country.

This paper also describes the actual experiences and lessons learnt which can be applied for future projects.
Applied Cognitive Cleaning Technology to Increase Average Heat Transfer Coefficient of Heat Exchangers
Authors: Rodin Ilya , Cherednik Eduard , Dolbunov Alexey
Published: November 2020

Industrial processing such as crude oil refining, petrochemical production, power generation and other may involve the transport of hot and cold utilities (fluids or gases) through heat transfer equipment such as heat exchangers. Over time and under various conditions, this transport of such utilities may result in fouling and scale deposits forming within the preheat trains or heat exchangers. Fouling and scale deposits reduce the performance of the equipment, leading to heat energy losses which has a negative productivity impact as well as overall negative economic and environmental impact on the industrial process.

Due to the lack of existing technologies oil refineries clean their key heat transfer equipment during major overhauls or roughly once in 2-4 years. Between these stops heat exchangers work below 50% of their heat transfer efficiency.

Cognitive Cleaning systems and methods integrates chemical innovation, process innovation and business model innovation into a single solution aimed to maximize technical, economic and environmental performance of the industrial processes through reducing energy intensity of the processes via cleanliness of heat exchangers.

Cognitive Cleaning is applicable for wide range of equipment geometry: shell and tube, plate, spiral heat exchangers. According to laboratory tests and on-site implementation's it is safe for equipment and has no harmful residues after cleaning.

Cognitive Cleaning technology was successfully commercialized on operating bitumen units, CDU, VDU, acid alkylation unit; on spiral, plate, shell-and-tube heat exchangers of several refineries of Gazpromneft, LUKOIL, TANECO demonstrated boost in equipment efficiency. Companies were able to extract real value out of previously done investments into digital infrastructure.

Applied cognitive cleaning can keep cleanliness of equipment increasing heat transfer efficiency up to 70%-80%, reduce CO2 emission and return around $2.4B to oil refineries of GCC countries.
Analysis of Surface and Downhole Drilling Dynamics High-Frequency Measurements Enhances the Prediction of Downhole Drilling Dysfunctions and Improves Drilling Efficiency
Authors: Jones Steve , Sugiura Junichi
Published: November 2020

Drilling rigs in North America are outfitted with Electronic Data Recorder (EDR) systems that acquire measurements from rig sensors. These systems typically record surface data at low frequency (0.1-1Hz) which makes it difficult to identify high-frequency events that could be occurring downhole. In an effort to fully understand the transmission characteristics of drilling dynamics signals along the drill string, the top-drive saver sub was embedded with high-frequency drilling dynamics sensors, sampled and continuously recorded at either 800Hz or 1600Hz.

Instrumenting the bit, bottom-hole assembly (BHA) and surface saver sub with identical high-frequency drilling dynamics sensors provided a unique insight into drilling dynamics transmission along the drill string. The sensors were identical and outfitted with the same hardware, firmware and software to allow detailed dynamics signal analysis to be undertaken. The signals from the high-frequency surface and downhole sensors were combined with the low-frequency surface rig measurements for pattern recognition and correlation analysis.

All high-frequency surface/downhole drilling dynamics data and low-frequency EDR data were merged and over-laid to identify signal patterns that would be beneficial in understanding surface and downhole generated dysfunction. Vertical, nudge, tangent, curve and lateral sections of the wellbore were analyzed to fully understand the transmission of drilling dynamics from downhole to surface and from surface to downhole. It is discovered that at relatively shallow depths, the signatures of at-bit dysfunction were observed in the high-frequency lateral vibration channels. Even in deeper wells, certain rotation-speed and shock/vibration signatures were detected at the surface.

The novelty of identical high-frequency drilling dynamics sensors at surface and downhole is that the signals generated by each sensor are produced from the same hardware, firmware and software. There is no risk of signals being mis-interpreted because of the use of different sensors or different signal-processing methods downhole and on surface. Merging and overlaying of the signal data with rig EDR allows drilling dynamics patterns to be correlated.
First Hydrocarbon Discovery in Thin Clastic Reservoir in Western UAE by Applying Innovative Data Integration Solution
Authors: Aftab Muhammad , Sultan Mir , Swain Ashis , Al Blooshi Abdulla , Gareyshin Radik , Mingsheng LV , Abdalla Ruaa
Published: November 2020

Exploration is a high risk business. Hence, available data including those from offset fields have to be analyzed and reviewed critically prior to drilling a well. This becomes especially true in a marginal thin reservoir where innovative drilling and testing strategy would play a key role in deciding commercial discovery of the prospect.

Flow rate is one of the basic criteria, inter alia, on which commercial viability of a prospect depends. Conventional testing strategy performed in the vertical well did not yield commercially viable flow rate. Hence, innovative approach was adopted to achieve the desired results.

After drilling, multi-disciplinary data should be integrated to finalize the testing strategy, which is critical to announce the discovery to meet the criteria set by the company. Reservoir of interest is a thin clastic reservoir, which could not meet the criteria of flow rate during testing with conventional way even though volume in place assumed to be significant due to large area. After carefully reviewing all data, the flow rates were predicted with the modeling if well will be horizonalized.

In order to fully evaluate the prospect, the static and dynamic model of the first vertical well was thoroughly reviewed and re-evaluated. The vertical well was tested comingled with two reservoirs having a two feet dense layer between the two. The well flowed mostly water with traces of oil. A detailed review of the test data revealed that a higher prospectivity layer exists in the overlying thin clastic reservoir above the dense and that the two reservoirs are in isolation. Based on this finding, a modeling was performed to decipher optimal horizontal well length to achieve the flow rate. It was a challenge to geo-steer the well trajectory of horizontal section in this very thin reservoir, which was successfully achieved by an active coordination of an integrated teamwork.

An innovative approach was adopted by applying Wireline Formation Tester (WFT) data to confirm dynamic isolation from underlying reservoir, which is predicted to be major water contributor. Optimal horizontal well length was established by analytical model for achieving the best flow rate.

The well was drilled successfully with horizontal length of 1400 ft. in thin clastic reservoir and completed with fit-for-purpose completion followed by production testing that achieved the flow rate criteria as predicted in the model.

This paper summarizes the processes of: (1) data integration, (2) establishing reservoir segmentation based on static and dynamic data, (3) modeling to predict flow rate and optimal horizontal length, (4) selection of fit-for-purpose completion and (5) addressing challenges and lessons learnt during planning and execution phases.
A Novel Approach, Determining Oil Pockets Size in a Very Complex Combination of Structural and Stratigraphic Traps of Middle Cretaceous Formation in Onshore Abu Dhabi
Authors: Jaya Sangga , Al Menhali Helal , Al shkeili Fatema , Shashanka Ashis
Published: November 2020

Mishrif formation has complex combination of stratigraphic and structure traps in western part of Onshore Abu Dhabi where according on petroleum system in western onshore Abu Dhabi there are three formations play roles; Shilaif formation acts as source rock, Mishrif as reservoir and Tuwayil seal as seal. Historically during the past decades less commercial discoveries have been thriven in Mishrif formation.

Generally, Mishrif formation consists of three Units: a lower Unit composed of fine-grained bioclastic packstones and wackestones, which represent distal shelf slope environment. The middle unit consists of medium-grained packstones indicative of proximal shelf slope environment. The upper Unit consists of coarse-grained bioclastic and shelly packstones and grainstones (rudist shell and debris) indicative of shoal of environment. Mishrif shoals are the favorable area where hydrocarbon charging was controlled by the heterogeneity inside shoal which has good reservoir qualities in term of porosity, permeability and oil saturation.

This case study is unique where the marginal field has several Mishrif reservoir pockets due to combination traps; stratigraphic and structural traps where lateral facies heterogeneity also plays a crucial part.

Several wells have been drilled and tested in Mishrif Formation during 1970's however the result still not encouraging and the company recently drilled appraisal wells; two vertical and one long horizontal well has been drilled towards an existing well and interference well test been implemented. Comprehensive data integrations of G&G and Reservoir Engineering are incorporated to generate/build new subsurface understanding with numerous geological concepts and several analog fields have been considered in order to generate new understanding.
ADNOC Senior Women's Leadership Development
Authors: Coffey Elizabeth
Published: November 2020

Objectives

Our aim was to prepare senior women in ADNOC for progression through Accelerated Leadership Development:∘to progress one or more into CEO roles by 2020∘to build the pipeline of the top 75 senior women leaders, priming their advancement within the organisation and∘to change leadership culture in ADNOC to be more inclusive and leverage diversity of both female and male leadership styles

Methods

Between November 2017 and June 2019, we deployed 3 strands of development:∘Accelerated Leadership Coaching for senior female leaders▪Each was coached 4 hours a month for 6 months∘6 Leadership Workshops for the top 75 female leaders, covering competencies critical for success in ADNOC's CEO and Director level.▪Strategic Influencing, Leading Change, Gravitas, Leadership Priorities, Managing Conflict, Making an Impact in Senior Groups∘Mentoring Workshops for the Group's 20 most senior men (CEO and Director level roles) and women.▪Content included gender differences in leadership styles.▪Mentoring pairs met monthly over 6-months.

Results

Novel information
Digital Transformation of Historical Data for Advanced Predictive Maintenance
Authors: Giunta Giuseppe , Bernasconi Giancarlo , Giro Riccardo Angelo , Cesari Simone
Published: November 2020

In recent years, big data technologies have paved the way for digital transformation in oil and gas industry. Multi-domain measurements are collected by advanced sensor systems and processed using data-driven approaches, allowing to derive constitutive relations between the operational status of the asset and the measured variables. In addition, historical pressure measurements can be exploited for advanced pipeline monitoring. This paper presents a methodology, applied to a case history, where legacy data are repurposed and employed both to track pump health and to enhance the digital conversion. The dataset consists of past pressure signals collected by Eni for several years at the pumping terminal of a crude oil transportation pipeline, which has a length of 100 km and 16" diameter pipes, located in Italy. Pressure transients' variance, kurtosis and variation range, computed on appropriate window lengths, are fed to an unsupervised clustering procedure based on a Gaussian Mixture Model (GMM), which automatically identifies four clusters. An expert analysis of the labeled data reveals that each cluster corresponds to a well-defined and different pump operational mode, namely: standby (pumps off), transition (pumps switching on/off), normal (line flowing) and anomalous. The latter mode is connected to a high value in the pressure transients' variance and kurtosis: during such regime, pump maintenance logs report a failure and replacement of a system part. Interestingly, the anomalous condition starts to show up several days before the actual part replacement. The proposed case history reveals the potentiality of: adding value to legacy data, as they can be reprocessed, tagged and used as supervised examples in the training phase of new data-driven procedures; comparing, merging and complementing monitoring strategies of assets at different digitalization stages; aiding the development of predictive maintenance strategies.
Mature Fields - Optimizing Waterflood Management Through DNA Based Diagnostics
Authors: Sawadogo Jordan , Ursell Luke , Reeve Nicolai , Schlecht Mathias
Published: November 2020

Maximizing the recovery factor achieved through water flooding depends on acquiring a detailed understanding of the vertical and areal sweep efficiency. DNA diagnostics can monitor changes in oil contributions from multiple zones and from injectors, becoming a leading indicator for the potential of water breakthrough, loss of injectivity, and the overall advancement of the water front when combined with subsurface information. This allows for proactive management of injection rates and timing to maximize recovery rates for green fields and brownfields alike.

DNA diagnostics use DNA markers acquired from microbes. DNA markers of produced fluids are compared to the DNA markers of injected fluids to establish relationships and shared fluid flow. This paper will cover the end to end workflow for long term waterflood monitoring:Establishing end members, even for a mature field, with the use of new samples from offset wells, properly stored samples from existing wells, and the analysis of commingled samples in combination with the subsurface model.Establishing the level of similarity between injectors and producers as an indication for the progression of the waterflood front using methods including Principal Coordinate Analysis (PCoA) of DNA marker profiles.Performing time series analysis and establishing sampling periodicity for effective waterflood monitoring.

A pilot project, consisting of 12 producers and 3 injectors in a conventional California reservoir, was conducted to prove the concepts and further develop the required analysis for waterflood monitoring. Fluid samples were taken weekly on each well over 3 weeks to establish the difference in DNA markers between the fluids. The DNA markers were used to determine the probability that injection fluid was being produced from the surrounding wells. These results were overlaid to temporal changes in the Total Fluid Logs. Taken together, the results correlated and confirmed previous water breakthrough information and provided insights into arial and vertical conformance changes. Additionally, the project provided new insights into strength of producer and injector connection based on geological features and with that informing future infill drilling decisions.

Waterflood monitoring is a powerful application for DNA diagnostics that is deployable on new and existing waterfloods. The spatial and temporal monitoring limitations of modeling or tracer studies can be improved upon through this non-invasive diagnostic. Initial results demonstrate the insights that can be provided not just for monitoring the waterflood but also for further field development decisions.
Industrial Implementation of Emulsion-Suspension System with Nanoparticles for Oil and Gas Wells Completion and Maintenance
Authors: Sergeev Vitaly , Tanimoto Kenji , Abe Masashi
Published: November 2020

An article presents comparative results of pilot of an innovative blocking pack for well-killing operation – emulsion-suspension system with supercharged nanoparticles (ESS). The ESS is characterized by the following competitive advantages: unlimited compatibility with petroleum reservoir fluids, gases, rocks and well-killing brine, adaptability of specific gravity in a wide range (900-1400 kg/m3), foreseeable rheology, alteration of wettability of rock surface, reversibility of blockage, no harm to downhole equipment, system of oil and gas gathering and environment. The ESS blocking pack pilot was carried out in multifractured horizontal wells under high-pressure (39.5 MPa) and high temperature reservoir conditions (115 °C) of Tortasinskoe oil-gas field, Western Siberia, Russia. The reservoir rock of Tortasinskoe oil-gas field is sandstone, characterized by low permeability (0.001-0.0001 μm2) and porosity (13%). A comprehensive laboratory tests program was executed for ensuring successfulness of the ESS blocking pack pilot in the complicated reservoir conditions of Tortasinskoe oil-gas field. The laboratory tests program included a basic research and specific experiments. The results of pilot confirmed significant competitive advantages of the ESS blocking pack in comparison with a synthetic polymer blocking pack, which was unsuccessfully applied earlier on the same production well. The ESS blocking pack showed high performance for well-killing operation in complicated HPHT reservoir conditions than widely used worldwide synthetic polymer system did not work at all.