bluuebunny/crossref_metadata_2025 huggingface dataset:
Assessing the feasibility of detecting epileptic seizures using non-cerebral sensor
Authors: Hamlin Alexandra , Kobylarz Erik , Lever James , Taylor Susan , Ray Laura
Published: December 2021

This paper investigates the feasibility of using non-cerebral, time-series data to detect epileptic seizures. Data were recorded from fifteen patients (7 male, 5 female, 3 not noted, mean age 36.17 yrs), five of whom had a total of seven seizures. Patients were monitored in an inpatient setting using standard video electroencephalography (vEEG), while also wearing sensors monitoring electrocardiography, electrodermal activity, electromyography, accelerometry, and audio signals (vocalizations). A systematic and detailed study was conducted to identify the sensors and the features derived from the non-cerebral sensors that contribute most significantly to separability of data acquired during seizures from non-seizure data. Post-processing of the data using linear discriminant analysis (LDA) shows that seizure data are strongly separable from non-seizure data based on features derived from the signals recorded. The mean area under the receiver operator characteristic (ROC) curve for each individual patient that experienced a seizure during data collection, calculated using LDA, was 0.9682. The features that contribute most significantly to seizure detection differ for each patient. The results show that a multimodal approach to seizure detection using the specified sensor suite is promising in detecting seizures with both sensitivity and specificity. Moreover, the study provides a means to quantify the contribution of each sensor and feature to separability. Development of a non-electroencephalography (EEG) based seizure detection device would give doctors a more accurate seizure count outside of the clinical setting, improving treatment and the quality of life of epilepsy patients.
Promoting a culture of openness: Institutional open access policy development and evaluation at a Canadian university
Authors: Moore Alison J. , Zerkee Jennifer , Shuttleworth Kate , Dowson Rebecca , Bird Gwen
Published: December 2021

Institutional open access (OA) policies can act as a solid foundation on which to build university-wide support for open access. This is the first paper to reflect on the entire process of developing, implementing, and reviewing an institutional open access policy at a Canadian post-secondary institution. Simon Fraser University (SFU) is one of a few Canadian universities with an institutional open access policy. As a leader in open access, SFU is well positioned to share observations of our experiences in the first three years of our OA policy. Throughout this paper, we reflect on the role that the policy plays in the broader culture of openness at SFU and on the OA resources and supports provided to SFU researchers. Other institutions may find our observations and adoption of the SOAR (strengths, opportunities, aspirations, results) appreciative inquiry framework useful as they explore future policy development or review and work to promote a culture of open access within their university community.
New Advances in Surface Data Logging Technologies for Comprehensive Real-Time Petrophysical Evaluation to Optimize Logging Programs in a Mature Field; A Case History, Onshore, Abu Dhabi
Authors: Al Arfi Saif , Sarhan Mohamed , Adene Olawole , Rizky Muhammad , Baruno Agung , Ullah Ikram , Enrique Roswall , Al Braiki Ali , Shaker Maged , Fares Wael , Diab Emad , Elfaramawy Hossam
Published: December 2021

The challenges of drilling new wells are increasingly associated with minimizing HSE risks, that relate to chemical radioactive sources in the Bottom Hole Assembly for formation evaluation. Drilling risks such as differential sticking, also necessitates investigation of alternative petrophysical data gathering methodologies that can fulfil these requirements. Surface Data Logging presents a viable alternative in mature fields, satisfying petrophysical data gathering and interpretation in real-time as well, as traditional geological applications and offset well correlations in a way, to optimize well construction costs.

During the planning phase, a fully integrated approach was adopted including advanced cutting and advanced gas analysis to be deployed, in this case study, well together with experienced well site personnel. A comprehensive pre-well study was conducted reviewing all offset nearby wells data. The workflow included provision of full real-time advanced cuttings and gas analysis for formation evaluation and reservoir fluid composition, lithology description, and addressing effective hole cleaning concerns.

The advanced Mud Logging services was run in parallel to the Logging While Drilling services for a few pilot wells, in order to correlate downhole tool parameters, with respect to data quality control, to identify the petrophysical character of the formation markers for benchmarking future data gathering requirements. In addition to the potential use of standalone fully integrated advanced Mud Logging to reduce risks and minimize field development costs.

With the help of experienced wellsite geologist on location and real time advanced gas detection utilizing high resolution mass spectrometer and X-Ray fluorescence (XRF) and X-Ray Diffraction (XRD) data, geological boundaries and formations tops were accurately identified across the whole drilled interval. Modern and advanced interpretation techniques for the integrated analysis were proven to be effective in determining sweet spots of the reservoir, fluid type, and overall reservoir quality.

Deployment of fully integrated mud logging solutions with new interpretation methodologies can be effective in providing a better understanding of reservoir geological and petrophysical characteristics in real-time, offering viable alternative for minimizing formation evaluation sensors in the BHA, particularly eliminating radioactive sources, while reducing overall developments costs, without sacrificing formation evaluation requirements.
Connecting Data, Model and Process to Streamline and Enhance Single-Point Production Well Test Validation
Authors: Mokhlis Mohamad Mustaqim , Hazali Nurdini Alya , Hassan Muhammad Firdaus , Hashim Mohd Hafiz , Jamaludin Afzan Nizam , Hermann Roland , Fuenmayor Roberto , Trivedi Rajesh , Vo Tri Nghia , Muhamed Salim Muzahidin , Elabdin Taha Mazin Zain
Published: December 2021

In this paper we will present a process streamlined for well-test validation that involves data integration between different database systems, incorporated with well models, and how the process can leverage real-time data to present a full scope of well-test analysis to enhance the capability for assessing well-test performance. The workflow process demonstrates an intuitive and effective way for analyzing and validating a production well test via an interactive digital visualization. This approach has elevated the quality and integrity of the well-test data, as well as improved the process cycle efficiency that complements the field surveillance engineers to keep track of well-test compliance guidelines through efficient well-test tracking in the digital interface.

The workflow process involves five primary steps, which all are conducted via a digital platform:

Well Test Compliance: Planning and executing the well test Data management and integration Well Test Analysis and Validation: Verification of the well test through historical trending, stability period checks, and well model analysis Model validation: Correcting the well test and calibrating the well model before finalizing the validity of the well test Well Test Re-testing: Submitting the rejected well test for retesting and final step Integrating with corporate database system for production allocation

This business process brings improvement to the quality of the well test, which subsequently lifts the petroleum engineers’ confidence level to analyze well performance and deliver accurate well-production forecasting. A well-test validation workflow in a digital ecosystem helps to streamline the flow of data and system integration, as well as the way engineers assess and validate well-test data, which results in minimizing errors and increases overall work efficiency.
The Development of a Pressure Actuated Isolation Nozzle Assembly and its Application as Flow Control Device in Extended Reach Water-Alternating-Gas Pilot Wells
Authors: Wang Zhihua , Qureshi Aqib , Abdelfattah Tarik A , Snitkoff Joshua R
Published: December 2021

The re-development of a giant offshore field in the United Arab Emirates (UAE) consists predominantly of four artificial islands requiring in most cases extremely long horizontal laterals to reach the reservoir targets. Earlier SPE technical papers (1,2) have introduced the development, testing, qualification, and deployment of the plugged liner technology using the dissolvable plugged nozzles (DPNs). The use of DPN plugged liner technology has resulted in CAPEX savings and enhanced production performance.

The benefits of DPN technology are its simplicity along with its cost effectiveness. However, the dissolvable material has some limitations, such as pressure rating and dissolution time, which are fluid chemistry dependent. To overcome these limits, a new Pressure Actuated Isolation Nozzle Assembly (PAINA) was developed as an alternative to the plugged liner tool for applications where a higher pressure rating is required, as well as on demand opening. Furthermore, the new PAINA also functions as a flow control device during injection and production, enhancing acid jetting effects during bullhead stimulation and reducing brine losses during liner installation.

Liners with PAINAs can be run to TD similar to blank pipe: fluids can be circulated through the inside of the liner without the need for a wash pipe. Once on bottom, non-aqueous drilling fluid is displaced to brine without actuating the isolation mechanism. When the well is ready for production or injection, pressure is applied and the isolation mechanism is activated to establish communication between well and reservoir. These tools were successfully run as flow control devices in water-alternating-gas (WAG) pilot wells. The planning and execution of the initial application will be discussed, along with the tool development, qualification testing, and lessons learned.

The key advantage of this technology is in extending plugged liner applications to cases where other pressure-operated tools are included as part of the liner lower completion. Pressure can be applied to the well multiple times without activating the isolation mechanism as long as the applied pressure is below the actuation pressure.
Greening the Desert While Helping Business and Caring for the Environment
Authors: Singh Jasbindra , Lawati Mustafa , Hindawi Abdulkareem , Harthi Mohammed , Rady Abdel Samiee , Al Hinai Mohammed , Al Salmi Marya , Al Hatmi Safiya , Siyabi Mohamed , Rawahi Moosa , Mahruqi Issa , Al Azri Nasser
Published: December 2021

This paper describes the utilization of produced and treated formation water for planting trees and growing algae in large ponds; in a massive scale in South Oman. A detailed study has been carried out to assess the injection requirements for pressure maintenance in the producing reservoir and using the remaining excess pot-treated water for farming of the palm trees.

The produced water has been used as disposal in formations deeper than the producing horizons in the past. The produced water was separated in a processing station that received gross production from a number of fields in South Oman. This water was disposed in the aquifer underlying a producing reservoir that has experienced pressure maintenance due to this disposal. The impact of this excess water disposal on the aquifer was studied to evaluate the risk of breaching cap rock integrity. The risk was not significant but to ensure "no damage to the environment and people" it was decided to reduce or optimize injection rates to maintain the reservoir pressure safeguarding reserves. In addition, the disposal of the water required significant amount of power equivalent to emitting significant amount of CO2 annually just for water disposal. The study was carried out using simple material balance methods to predict the pressure behaviour given an injection profile.

The recommendations from the study have already been implemented to convert the deep-water disposal to injection in the aquifer. This has been achieved by the integration of number of interfaces from sub-surface to field operations. All the pieces are in place to take it the next level of execution that is to treat the water at surface for oil removal, hence rendering the water at acceptable quality levels for tree plantation and algae ponds.

The project also aims in a future second phase to further treat the water to higher specifications allowing the use of it for agricultural purposes. This would introduce a commercial farm that will depend on this source of water. This would be a novel concept in South Oman where the treated water will be used for farming solving multiple issues at multiple levels namely helping the business achieve its objective of sustained oil production, helping local communities with employment via farming and helping the organization care for the environment by reducing carbon footprints.
Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE
Authors: Fathalla Magdy Farouk , Al Hosani Mariam Ahmed , Mohamed Ihab Nabil , Al Bairaq Ahmed Mohamed , Ojha Aditya , Mengal Salman Akram , Pramudyo Yuni Budi , Nachiappan Ramanathan , Bankole Ibukun Olatunbosun
Published: December 2021

This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells.

The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme

The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.
Hydraulic Workover Unit Utilization for New Well Openhole Drilling with Directional Motor and Logging-While-Drilling Bottom-Hole-Assembly in M Area
Authors: Rachman Buna Rizal , Noviasta Bonar , Wijayanto Timora , Mardiana Ramadhan Yoan , Taufik Esa , Saputra Rangga , Styward Boris
Published: December 2021

Achieving a number of well targets in M Area is an important objective for MK, one of the oil and gas operators in Indonesia. An economic challenge is present due to marginal gas reservoirs in shallow zone. The conventional swamp rig unit requires significant costs for site preparation work and in some cases no longer fulfils the economic criteria. The objective was to drill the same one-phase well (OPW) architecture as the swamp rig normally drills, but at lower costs using a hydraulic workover unit (HWU).

Drilling the 8½-in hole section OPW architecture using HWU was challenging, not only on the equipment rating and capability, but also on the deck space limitation part. The fit-for-purpose directional and logging-while-drilling (LWD) system was utilized in this project consisting of customized low-torque excellent hydraulics drill bit design, a positive displacement motor (PDM) with aggressive bend setting to achieve directional objective (with max 3.8°/30-m dogleg severity), annular-pressure-while-drilling (APWD) measurement to ensure equivalent circulating density (ECD) is maintained, and combined electromagnetic propagation resistivity and sonic slowness measurement coupled with high-speed telemetry measurement-while-drilling (MWD) tool to get an accurate and timely formation evaluation. The HWU deck space limitation was solved by implementing a single combined directional drilling (DD), MWD, mudlogging cabin, in addition to the remote operation control implementation to further reduce carbon footprint.

Five wells were drilled safely and successfully in this campaign. Drilling efficiency improved with up to 109% ROP increase as compared to the first well, showing the progressive learning curve and excellent teamwork from all involved parties. The directional bottom hole assembly (BHA) was capable of delivering up to 4–5°/30-m dogleg, not only achieving the directional objective, but also penetrating the reservoir targets with tight tolerances. The drill bit delivered very good ROP, reaching 60.4 m/h (about 66% of average OPW ROP achieved by swamp rig). This campaign also successfully reduced the overall site preparation cost by up to 30%, enabling MK to drill wells that were initially not feasible to be drilled using swamp rig within the time frame and budget. Thanks to the success, this new method is currently under study for industrialization. The HWU drilling campaign provided a valuable learning experience, is considered as a proven drilling method, and served as a benchmark for other operators in Indonesia.

HWU drilling has proven to be an efficient drilling method and capable of delivering the one-phase-well. This paper presents a unique case study of new well open hole drilling with the HWU and its applicability in M Area. Most studies in the past were HWU drilling in re-entry or sidetrack cases.
A Novel Approach to First in the World Retrieval of Open Water Vertical Xmas Tree
Authors: Liew William Sin Yoong , Heboul El Khalil , Bin Allapitchai Mohamad Shahril Majid , Sellapan Sattiyaraju , Bin Johan Ahmad Luqman , Bin Ahmad Zaini Ahmad Hafizi , Bin Abdul Razak Mohd Hairi , Binti Dharma Dian Puteri Dharmilla Syafawati , Bin Abdullah Ahmad Zharif , Zomerdijk William
Published: December 2021

Wells plug & abandonment was carried out in a deepwater field (Field C) offshore West Africa. There were 15 deepwater subsea wells in this field. Thirteen of the wells were completed with Open Water Vertical Xmas Tree (OXT) while remaining two were completed with Enhanced Vertical Xmas Tree (EVXT). In the wells with Open Water Vertical Xmas Tree (OXT), the upper completion tubing and hanger were ran together with the Xmas Tree in a single run. This posed challenges to Operator in retrieving the Xmas Tree. This paper will discuss the novel approach used by Operator in the OXT retrieval.

Due to the design of OXT which was different from most of the vertical Xmas Trees (XT) in the world, there were a few challenges in the process of XTs retrieval. If the XTs and upper completion tubing were retrieved in reversal of the way it was completed, it will exposed the well to prolonged duration of single barrier until a BOP can be latched on for subsequent activities. On top of that, the Original Equipment Manufacturer's Completion Workover Riser (CWOR) system and Support Landing Structure (SLS) was not available in full package to be utilized in this project. Furthermore, there were constraints on the rig moonpool space, handling of OXT on surface and clashes between the rig's BOP and existing subsea structures.

In managing the risk of well exposure to single proven and monitored barrier during the process of OXT retrieval, Operator has evaluated a few options and came out with a novel approach in the OXT retrieval which managed to minimize exposure time and reduce risk in operations. In contrary to the original principle of well completion here, after a barrier was established in the well, the OXTs was retrieved separately from the upper completion tubing to allow rig BOP to be latched onto wellhead in shortest possible time. To achieve this objective, operations was planned to be carried out on a dual activity derrick rig. Meanwhile, a non-OEM rental CWOR system was used together with Tree Running Tool from the OEM CWOR system to access the wells for intervention work and subsequently retrieve the OXTs. By doing this, the combined CWOR stack exceeded the height limitation at the rig's moonpool. Some modifications were carried out to allow the operations to happen. A novel approach was also used to handle the OXT on surface without the OEM Support Landing Structure - which simplified the operations and reduced HSE risks. Solution was also put into place to enable latching of the rig BOP onto wellheads on Drill Centre although there were risk of clashing initially.
Troubleshooting Gas Dehydration Systems Using Data Analysis
Authors: Al-Aiderous Abdullah
Published: December 2021

The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to operate a TEG dehydration system optimally and reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature.

In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.
Doubling its Production in One Year: Reviving a Brown Field in South of Oman
Authors: Suut Suria Amalia , Al Kalbani Mahmood Khamis , Quseimi Issa , Gahaffi Abdullah , Wielaard Arjen , Hamouda Rady Abdel Samiee , Al Abri Abdullah Zahir , Hasani Hanaa
Published: December 2021

This paper summarises a ONE development success story of reviving a mature brownfield in South of Oman, Field β, just within ONE year through collaboration between different disciplines, comprehensive data analysis, optimising and recompletion of existing wells. Field β, comprised of multi-stacked clastic reservoirs, was put on stream in 1980s and peaked in early 1990s. Pilot water injection started in 1993 and full field water flooding continued in 1997. After more than 35 years since start of production, one can say the field was already in the tail end of its life. It had been stabilizing at low rate after 25 years and starting to decline further and at some point was one of the potential candidates to be decommissioned. A new FDP (FDP18) for part of the field was delivered in 2018 with the first well drilled at the end of that year. In 2019, despite drilling further wells on the FDP18, production was declining and was at 2018 rate towards the year end. Intensive data analysis and integrated reservoir reviews per reservoir layers were actively performed and new opportunities and data gathering were identified. FDP18 wells from 2019 onwards were then deepened to also acquire log data over deeper than the target reservoirs. Further synergy between asset and exploration teams also instigated in new discoveries including oil in shallower carbonate reservoirs, which were logged and sampled when drilling the FDP18 wells. Declining production, low oil price and COVID-19 crisis that hit 2020 challenged the team to be more resilient and with ONE development mindset between development and WRFM team, also between asset and exploration team, existing long-term closed in and very low productivity wells were utilised to tap these new opportunities. As a result, the field production has been increased by more than double, highest since 10 years ago, with a potential of triple its production rate, all achieved through optimizing and recompletion of existing wells within 1 year, at a very attractive low UTC.
Liverpool Bay Area CCS: An advanced Case Study to Achieve UK's Carbon Neutrality
Authors: Becker Bruce William , Baldino Francesco , Aleandri Alessandro
Published: December 2021

The Liverpool Bay Asset Carbon Capture and Storage (LBA CCS) project is being developed in parallel with, and as an integral part of, the HyNet North West integrated project, which is aimed at decarbonizing the important industrial region of North-West England and North Wales. The Liverpool Bay Asset (100% Eni UK Limited) is approaching the end of its production life and would be progressively decommissioned over the period 2023 to 2025 without the prospect of re-configuring to a CCS project. Eni plans to reuse and repurpose the depleted hydrocarbon reservoirs of the Hamilton, Hamilton North and Lennox fields together with their associated infrastructure to transport and store carbon dioxide (CO2) emissions captured upstream by the HyNet NW partners. A Carbon Dioxide Appraisal and Storage Licence was awarded to Eni by the UK Oil & Gas Authority (OGA) in October 2020 for this purpose.

The project has now completed the Concept Selection Phase and the paper describes the multidisciplinary work covering subsurface, facilities and drilling engineering, flow assurance and project management that has been completed to select the development concept for advancement into the concept definition phase. It demonstrates the viability and benefits of re-using depleted fields and existing infrastructure originally installed for hydrocarbon production to reduce the unit cost of storage, a key metric for all CCS projects.
Unifying of Steady State and Transient Simulations Methodologies for Increasing Oil Production of Integrated Network of Wells, Pipeline and Topside Processing Equipment
Authors: Ali Zalina , Anuar Astriyana , Grippo Nicolas , Ramli Nurshahrily Emalin , Rahim Najmi
Published: December 2021

Aging facilities and increasing complexity in operations (e.g., increasing water cut, slugging, sand or wax production) continue to widen the gap between actual production and the full potential of the field. To enable production optimization scenarios within an integrated system comprises of reservoirs, wells and surface facilities, the application of an integrated network modelling has been applied. The highlight of this paper is the synergy of Integrated Production Network Modelling (IPNM) utilizing Steady State Simulator (PROSPER-GAP) and the Transient Simulator (OLGA) tools to identify potential quick gains through gaslift optimization as well as mid and long-term system optimization alternatives. The synergy enables significant reduction in transient simulation time and reduced challenges in OLGA well matching, especially in selecting accurate modelling parameters e.g., well inflow performance (validated well (string) production data, reservoir pressure, temperature and fluid properties and the Absolute Open Flow (AOF) of each well). The paper showcased the successful production gain achieved as well as the workflows and methodologies applied for both Steady State Integrated Production Modelling (IPM Steady State) and Integrated Transient Network Modelling (IPM Transient) as tools for production enhancement. Even though IPM Steady State shows promising results in term of field optimization potential, to increase accuracy and reduce uncertainties, IPM Transient is recommended to be performed to mimic the actual transient phenomena happening in the well to facilities
Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field
Authors: Al Shehhi Hajar Ali Abdulla , Bernadi Bondan , Belal Al Shamsi Alia Belal Zuwaid , Al Hammadi Shamma Jasem , Alawadhi Fatima Omar , Mohamed Ihab Nabil , Al Bairaq Ahmed Mohamed , Al Hosani Mariam Ahmed , Abdullayev Azer , Roopal Allen
Published: December 2021

Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity.

The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore.

The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs

This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.
Elimination of Tight Emulsions
Authors: Ellingsen Haakon , Jaouhar Hikmat , Hannisdal Andreas
Published: December 2021

Maturing oil fields can pose a severe challenge for separation of oil and water. Increasing water production and tie in of new fields into existing infrastructure may result in separators struggling to meet performance specifications. Operational challenges are particularly experienced when the facilities are processing cold feedstock and tight emulsions. Typical solutions for overcoming separation challenges would be increasing operating temperature, injecting an increased quantity of demulsifier chemicals, or installing new larger separators. These alternatives may not be economically attractive or feasible for other reasons. The ability to successfully operate existing plants with tight and water-rich emulsions without incurring significant added operating expenditure is perceived as a major advantage.

This paper will share the results from testing on a separator operating with Flotta Gold crude oil. The oil is known to produce particularly tight emulsions at low temperatures. The ePack technology has been tested to study its capability of separating water and crude oil from tight emulsions by means of electrical forces.

The force generated by the high electrical field can break even tight emulsions, and the test results shown have proven the ability to go from very low separation efficiency without the ePack, to more than 90% water removal with the ePack turned on. Testing with residence times of up to 19 minutes without the ePack was not able to surpass the performance of a three minutes residence time with the ePack energized.
Full Waveform Inversion for the Near Surface Characterization, Onshore UAE, Case Study
Authors: Dixit Rahul , Vasilyev Pavel , Mihaljevic Ivica , Tham Michelle , Vigh Denes , Zarkhidze Alexander , Cambois Guillaume Marie , Mahgoub Mohamed
Published: December 2021

Full-waveform inversion (FWI) has become a well-established method for obtaining a detailed earth model suitable for improved imaging, near-surface characterization and pore-pressure prediction. FWI for onshore data has always been challenging and has seen limited application (Vigh et al, 2018). It requires a dedicated data processing approach related to the lower signal-to-noise ratio, accounting for variable topography and complex near-surface related effects.

During the past few years, ADNOC has been acquiring and processing one of the world's largest combined 3D onshore and offshore seismic surveys in the Emirate of Abu Dhabi. The modern acquisition parameters that were implemented enabled the acquisition of broadband onshore seismic data rich in low frequencies that could benefit the initial stages of the FWI workflow.

Sand dunes and sabkha layers at the surface, and high-velocity carbonate and dolomite layers in the subsurface pose a significant challenge for near-surface modeling in the UAE. The purpose of this work is to evaluate FWI application onshore UAE for near-surface characterization. We will compare the FWI results with conventional approaches for the near-surface model building that has been used routinely on land datasets in UAE, such as data-driven image-based statics (DIBS, Zarubov et al, 2019).

One of the main challenges is data preconditioning, as onshore seismic data typically exhibits high levels of noise. It is imperative to denoise gathers sufficiently prior to the FWI process. A well sonic velocity function with large smoothing was used to build the starting velocity model for FWI. The process aims to minimize the least-squared difference between predicted and observed seismic responses by means of updating the model on which the prediction is based. As the predicted and seismic responses are functions of model parameters as well as source signature, a good estimate of the source wavelet is important for update and convergence in FWI. During this FWI work, source wavelet inversion was done as a separate step and used in subsequent FWI passes.

FWI inversion started with adjustive FWI (Kun et al, 2015) on lower frequencies, moving to higher frequencies where both adjustive and least square objective functions were used. We will further show assessment of the anisotropy, initial conditions, usage of geological constraints, and comparisons to the conventional solutions. A comparison of results shows that FWI has successfully added velocity details to the near-surface model that follow the geological trend and conforms to well information while producing a plausible static solution.

We have demonstrated the application of FWI onshore UAE for near-surface modeling. Although turnaround time (TAT) has increased compared to the conventional approach, the learning that was gained during this trial will decrease TAT for the future FWI work.
Expanding Polymer Injectivity Tests on a Second Giant Carbonate UAE Oil Reservoir at High Salinity & High Temperature Conditions.
Authors: Baloch S.A. , Leon J.M. , Masalmeh S.K. , Chappell D. , Brodie J. , Romero C. , Al Mazrouei S.H. , Al Tenaiji A. , Al Balooshi M. , Igogo Arit , Azam M.U.F. , Maheshwar Y.K , Dupuis G.
Published: December 2021

Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs.

A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot

This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer.

Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme.

This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period.

Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.
Well Lifting Capability to a Green Power Generation Using Microturbine Generator
Authors: Sedaralit Mohd Faizal , Ibrahim M Imran Iskandar , Maam Azman
Published: December 2021

A new way of utilizing access gas to power generation using newly developed technology named micro-turbine electric generator (mTEG). This technology is using relatively low gas flow rate: same region of gas-lift consumption between 0.3 – 0.5 MMscf/d of power generation for a minimum of one kilo Watt (1kW) per unit. The technology is classified under green category is due to no combustion process instead using pressure differential as the mechanism for power generation. Therefore, it supports PETRONAS’ net carbon zero program especially for unmanned platform operation.

The mTEG is simple unit developed based on differential method by allowing gas to flow inside for rotation without combustion for power generation. Flow and pressure requirements are relatively low at 0.4 MMscf/d at 10 bar, respectively. One of gas supply sources to run the unit is coming from well or gas lift skid. Per skid of mTEG it can produce up-to 4 kW power. This technology helps to support unmanned platform operation to reduce operation cost and moreover, this technology is compact and superior than solar power scheme unit. Life cycle cost between the two technologies was indicated superior saving is possible for mTEG technology.

Completed prototype model – integrated skid and in 2019 team managed secured full in-house development under prototyping and engineering centre unit located in PETRONAS Research Sdn. Bhd. (PRSB), Bangi. One of the technologies used to produce the mTEG unit is 3D printer with also available in PRSB. Passed factory acceptance test (FAT) in 2019 based on positive outcome of endurance test performance. Embarked detail engineering for installation of the skid and completed electrical and installation in 2020 and the skid unit is expecting to provide 1 kW power by end of this year at field E and upon completing the test, this technology will be able to benefits other operating unmanned platform or event small plant operation.

The technology was designed for green power generation: operation greenification with no combustion elements instead provide flexibility for recycling of the gas and reuse for another means such as gas lift gas application to improved oil recovery.
Horizontal Water Injection Wells: Injectivity and Containment of Injection-Induced Fractures
Authors: Hwang Jongsoo , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten
Published: December 2021

Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers.

Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth.

Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.
The Concept of Floating Shipyard
Authors: Samir Ghowel Ahmed
Published: December 2021

Shipyards are known as a land-based facility that ships steer to for docking and repair. This study represents an introductory conceptual study for a new principle of developing a Floating shipyard: changing the phenomena of a fixed site shipyard into a self-propelled floating shipyard.

This Floating Shipyard can travel and conduct dry-docking activities at the client's location or even lift the client's vessel and travel to the F-Yard extension, taking advantage of having comprehensive repair or conversion.

The arising challenges to this floating shipyard, such as lay-offs, restructuring, and environmental legislation, requires a balanced solution. The solution of all this relies on adapting talent management and competitive production tools during this massive undergoing change in its backbone structure.

The Floating shipyard, here named "F-Yard", changes the mindset of dry-dock. This is because F-Yard travels to the client's location or is capable of pick the client's unit nearby the cargo destination, where it can complete the required dry-dock or repair.

The cutthroat advantage of the F-Yard comes from self-propelled, where the other approaches depend on others for mobilizing and anchoring from one location to another.

In addition, F-Yard could serve other industries, due to its fully equipped workshops, that able to serve different market needs such as oil and gas and renewable energy...etc. These open the door for a variety of business scope.

F-Yard depends on front-end engineering and marketing teams to optimize its route and sort the supply chain requirements.
Backpressure Minimization as Objective Function for Production Optimization in Absence of Wells Performance.
Authors: Corti Mauro , Montini Marco , Gioja Giorgio
Published: December 2021

In the Oil & Gas sector, the production optimization is one of the most challenging problem, since it involves many operational variables linked by complex relationships. Moreover, during the asset life cycle those parameters could change. Conflicts and interactions between variables, constraints, and operational limitations could be solved holistically by an optimization tool based on an Evolutionary Algorithm. The algorithm searches for the optimum field configuration from the operational point of view, leading to the production maximization.

Eni Production Department developed a tool based on this algorithm for management and optimization of surface asset hardly focused on field viewpoint. e-Rabbit (Risked Algorithm for Biogenetical Balance Integration Tool) provides integration for reservoir, well, network and process models.

The present work has been developed to overcome a recurrent problem in the Oil & Gas business: the lack of data. There are many cases in which this situation occurs, for example in old fields where measurement tools and digitalization are not so widespread or in assets characterized by many wells and complex gathering systems, in which the detail on well performances could not be available. e-Rabbit, to perform its optimization, requires that information so, under those conditions, somehow, it is necessary to find another way to be able to optimize and manage the surface asset.

A novel technique to optimize the whole production system has been introduced, whose objective function rely on backpressure minimization. To verify its effectiveness two case studies have been analyzed comparing the proposed optimal configuration with the output of the classical e-Rabbit - optimization.