bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Flow Comparison Between Distributed Fiber-Optic Sensing and Conventional PLT in a Cased Hole Horizontal Wellbore With ICD
Authors: Hveding Frode , Guraini Walid , Mahue Veronique , Hafezi Sina 
Published: November 2020

Abstract
A cased hole well with inflow control devices (ICDs) was logged for production profiling as part of a field trial campaign testing a new fiber-optic wireline system. Pulled by a conventional tractor, both the fiber-optic wireline and a set of conventional production logging tools (PLTs) were placed at the bottom of a horizontal wellbore, locating the fiber across the reservoir for sensing purposes. The well produced at two different choke settings, enabling both technologies to capture low flow rate as well as high flow rate. The main objective with the testing was to compare the two technologies for production flow allocation and learn more about fiber-optic analytics.
The two different measurements were performed as close in time as possible. While the fiber-optic cable was sensing, the PLT was stationary and not logging, and while PLT was logging, the fiber optic was deactivated. From fiber optics, high-quality noise logging plots were generated with distributed acoustics (DAS), identifying the inflow points despite the relatively challenging acoustic environment. Propagating sound allowed for a profile of fluid sound speed to be established. Distributed temperature (DTS) was less useful on this job due to some accidental inflow of borehole fluid causing hydrogen darkening. This affected the multi-mode fiber more than the single-mode fiber; hence, DTS data could not be used. The wireline-based MAPS tool consisted of capacitance-, resistivity- and spinner-array. With the sensors located on bow springs, the tool detected various flow patterns 360 degrees around the borehole. The fiber-optic cable is located low side in a horizontal wellbore and might be affected by this in a laminated flow situation. Still, the fiber-optic sensing system managed to provide useful flow information, comparable to the PLT tool.
Prediction of Lost Circulation Zones Using Artificial Neural Network and Functional Network
Authors: Ahmed Abdulmalek , Elkatatny Salaheldin , Ali Abdelwahab , Abdulraheem Abdulazeez 
Published: November 2020

Abstract
Drilling high-pressure high-temperature (HPHT) wells lead to many difficulties and issues. One of the most difficulties during the drilling is the loss of circulation. 40% of the drilling's cost is belong to the drilling fluid, so the loss of these fluid causes an increasing in the total drilling operation's cost. Circulation loss has many consequences related to well control which can lead to the worst case of blowout. There are several approaches to avoid loss of return, one of these approaches is preventing the occurrence of the losses by identifying the lost circulations zones. However, most of these approaches are difficult to be applied due to some constraints in the field.
The purpose of this work is to apply two artificial intelligence (AI) techniques to identify the zones of lost circulation. A data of real-time surface drilling parameters from three wells were obtained using real-time drilling sensors. The two methods of AI are functional networks (FN) and artificial neural networks (ANN). Well (A) was utilized to build the two AI models by dividing their data into training and testing. Then, well (B) was utilized to validate the developed AI models.
A high accuracy was achieved by the two AI models based on the root mean squared error (RMSE), confusion matrix and correlation coefficient (R). Both AI models identified the zones of lost circulation in Well A with high accuracy where the R is more than 0.98 and RMSE is less than 0.09. ANN is the most accurate model with R = 0.99 and RMSE = 0.05. Moreover, ANN was able to predict the lost circulation zones in the unseen well B (R = 0.952 and RMSE = 0.155).
World First Integrated Zero Waste Discharge Solution in Restricted & Highly Environmentally Sensitive Areas
Authors: Hamdan Tariq , Turpin Craig , Husein Mohamad , Alblooshi Salem , Alhammami Mohamed , Hussain Mohamed , El Shahat Ayman , El-Meguid Mohamed , Oko Vincent , Al Ramahi Basil , Abbas Fady 
Published: November 2020

Abstract
The objective of this paper is to demonstrate the challenges, solutions and results of performing offshore Drilling Waste Management operations in a highly environmentally sensitive marine environment and UNESCO World Biosphere Reserve in offshore Abu Dhabi.
The solution was to treat all drilling waste at source. This required both NOV Thermal Treatment Technology and NOV Cuttings Re-Injection Technology and became the World's first single-source operation for this equipment. The equipment was shipped to the island, installed and operated in parallel with the Operator's drilling programme. The drilling waste (Oil-Based Mud) was handled and stored by EMDAD then processed through the NOV Thermal treatment unit, which generated three separate treated waste streams - oil, water and solids. The recovered oil and water were reused on-site, whilst the treated solids were slurrified and fed to the NOV Cuttings Re-Injection system (CRI), which injected the solids into a disposal well.
This paper will also demonstrate the results of the integrated operation.
Tamuh: Implementing A Graduate Development Scheme for Fast Tracking Young Professionals in Petroleum Development Oman
Authors: Lamki Amal , Abri Yaqoob , Al-Jumah Ali , Mahruqi Shabib 
Published: November 2020

Abstract
Strengthening Technical and business skills with new perspectives, thinking and new insights are critical to ensure high performance and value creation in the short- and long-term. Nimr Cluster relentlessly aspire be renowned and respected for the excellence of our people and the value we create for Oman and all our stakeholders. In the midst of disruptive time where 'Do More with Less' is a guideline we have innovated and persevered the journey of professional / personal development - Make the Future - Oman 2040!
Nimr Cluster in Petroleum Development Oman's (PDO) south oil directorate is one of the first clusters to implement and enroll graduates in the Graduate Development Program (GDP). This is a tracking tool to ensure a balance between staff development as well as delivering business activities.
This approach provides a focused Staff Development to Progression, with Clear synergy with Function and Business needs to drive individual aspiration to progress.
The cluster in question, Nimr, is the biggest in the Oil South Directorate, comprises more than 20 fields with different production mechanisms, including depletion, polymer and Waterflood. It also has more than 2,000 active wells, the highest count for an individual asset in PDO, and delivers a substantial amount of produced oil. The scope and scale of its operations gave the Nimr leadership a significant opportunity to make efficiency improvements.
Nimr Cluster started to implement Tamuh since 2019, and that took three stages. It started by hard copy tracking sheet in 2019 into a fully digital tracking sheet in a cloud-based database that can be accessed by all. The coach and coachee balance is set and the Gemba is taking place in different level. Team leads and the cluster leader the function, and the petroleum manager level. This allows for better management from the graduate side, as the past situation had many factors to juggle and manage effectively.
Operations Excellence Journey on Digital in Enhancing Production Operations, Planning and Process Cycle Efficiency
Authors: Choudhuri Amit 
Published: November 2020

Abstract
Increased focus by Upstream Oil and Gas Companies to adapt to the current business environment has led to leveraging upon process simplification, Industry- 4.0 and digitalization programs for enhancing the field operations, reduce deferments and standardize planning processes inline to operational excellence. Objective is to lean current processes through developing lesser decision stage gates and providing input data bank for faster decision making, thus transforming the way of working into "value based" and improving on efficiency. In current business environment, digital solutions are being favorably viewed as enablers instead of disruptors, as was considered in the past. Digital solutions encompass development of model based technical workflows, lean business process workflows, robust planning methodology and integrated performance dashboards to enable informed and optimal decision making. Through this paper, experience from various Oil and Gas Upstream Operators in their journey of digitalization and in business and technical process simplifications will be shared, based on author's work and interaction with different oil and gas operators.
Automated Well Correlation using Machine Learning and Facial Recognition Techniques
Authors: Bakdi Sara , Kannan Nitish , Reddy Masini Shashipal , Chennakrishnan Balaji 
Published: November 2020

Abstract
This paper outlines the study results of machine learning application to automate well correlation. Algorithms are designed to address challenges such as geological field complexity, number of wells and geological horizons, and quality of log data, that are usually associated with well correlation
The Kansas state oil and gas fields, USA has more than 350000 wells and produced over 5 billion barrels of oil, with an estimated 11 billion barrels of oil still remaining underground. Nearly 100 wells from Thomas, Scott, Logan, Barton, Stafford and Wichita Counties are selected for this study.
Petrophysical data such as Gama Ray, Neutron, and Density logs, considered most sensitive for lithology and Geological Cores descriptions are used as input. Sedimentary facies variation from limestone, shale, sandstone and coal were used as indicators to separate stratigraphic sequences.
The approach followed is a 1D adaptation of panoramic stitching using feature vectors generated from a 1D Convolution Autoencoder. Convolutional autoencoders learn a compressed representation of input by first compressing the input using encoder and decompressing it back using decoder to match the original output This autoencoder is a neural network trained to reproduce input image in output layer, similar to facial recognition techniques. It identifies a series of matching points between a pair of well logs and trained to pick and match geological well tops.
In order to demonstrate the performance of algorithms in term of accuracy, speed and to address the range of uncertainties, more than 30 wells were used for training. The study results have demonstrated high level of constancy in automatically subdividing the reservoir units of different wells consistent with stratigraphy and consistent across wells even though distance separating for each individual well is considerably more than one kilometer.
The Success of Drilling Long Departure Wells with Light/Slim Casing Design in United Arab Emirates Onshore Field
Authors: Morales Annie , Salem Gamal , Asef Mohammed , Yamani Sultan Al , Nava Jose 
Published: November 2020

Abstract
This case study presents the challenges faced and learning curve built while achieving longer departures with light / slim casing design instead of conventional / heavier design in shallow coastal water field in UAE.
This paper intends to explain the challenges that were encountered and the process of mapping the lessons learnt to ensure improvements along the process.
The process involved the casing points analysis evaluating the competent formations options, continues optimization of well trajectory by increasing the inclination across problematic formations while drilling the intermediate section (limited in previous drilling campaign in the area), the evaluation of the impact caused in the consecutive 8 ½" phase (longer section), implementation of best practices to mitigate stability issues and Invisible Lost Time (ILT) methodology application to minimize hole exposure duration.
The challenging campaign had the objective of saving cost by reducing one [FQ1] construction [FQ2] phase and continues achieving longer departures successfully which was a milestone during the well construction, thus a learning curve was built focused on continuous improvement of key operations.
After completing more than 100 wells, the most beneficial point this change has offered is drilling long departure wells saving one phase in comparison with the conventional design in the area, which is the key element for cost reduction and also allowed to reduce crew exposure to heavier casing handling improving HSE risks.
Currently, a maximum departure/vertical section of 10,700 feet has been achieved with light/slim casing design. Overall duration saving is 16 days compared with the best heavy casing design duration and 20 days with average heavy casing design duration with 35% saving duration.
Drilling light casing design instead of conventional heavy casing design enable average of USD 2 million saving per well. The consolidated experience built throughout planning and execution since the first well, enabled an important performance improvement based on the learning curve built along the years.
Nowadays, many fields require drilling wells with long vertical section / departures to reach further targets, away from the feasible surface locations. Additionally, cost reduction is another concern due to Oil Market fluctuation by applying new strategies and optimizing the performance without jeopardizing but improving the HSE at the same time.
This paper presents a novel approach to well construction by showing the lesson learn that allowed well duration reduction, drilling more wells per year and consequently bringing early production, increasing efficiency and significantly reducing cost, therefore increasing productivity and profitability, at the time of contributing to HSE improvement.
Acid Prohibitive Flexible Cement Enables Long Term Zonal Isolation in High Temperature High Pressure Well
Authors: Anwar Rameez , Elmoneim Hossam A. 
Published: November 2020

Abstract
Cementing of production casing in the Northern Iraq poses challenges to the cement sheath integrity due to mechanical and thermal stresses induced in the well life. The problem is further aggravated due to narrow window between pore pressure and fracture gradient. The acid-prohibitive cement system with improved mechanical properties was developed to mitigate the effect of induced stresses. The job was executed with operational optimization and zonal isolation was achieved.
Based on the operator's well testing and multi-stage high-rate well stimulation plan, the stress modeling was carried out to determine the optimum mechanical properties. The 19.6 ppg heavyweight cement system with a flexible thermoplastic polymer was designed to achieve the required Young's modulus and Poisson's ratio. Since the density and friction pressure hierarchy could not be met due to the narrow window between pore pressure and fracture gradient, therefore, the slurry rheological properties were optimized for effective mud removal. The pumping parameters were adjusted to maintain the primary well control during the cementing operation without compromising displacement efficiency.
The approach was implemented without any operational issues in the 9-7/8" production casing and 7" liner cementing. Following the job completion and waiting-on-cement time, the 9-7/8" casing was successfully pressure tested with a surface applied pressure of 2,000 psi and a well fluid of 1.78 SG. The isolation scanner cement evaluation confirmed the zonal isolation along the open hole of both the 9-7/8" intermediate casing and the 4½" production liner. Finally, the multi-stage high-pressure stimulation operations were performed during the completion/testing stage with no sign of communication between the different zones. The application of heavyweight acid prohibitive flexible slurry helped the operator to isolate the different zones of interest that were less than 10 m apart and retained the integrity of the seal throughout the high-pressure stimulation operation. Well is open to production without any annular pressure, thus, saving the operator's time and cost on the remedial cementing operations.
The proposed solution will help operators to ensure long-term zonal isolation in the HTHP wells which are subjected to dynamic pressure and temperature changes in the post slurry placement phase. The operators can also avoid the time and money on expensive remedial operations.
Controlling Congestion and Connectivity in Field with Multiple Reservoirs
Authors: Alhemeiri Sultan , Al Shehhi Mohamed , Soares Sofia Da , Chellappan Sanjeev Kumar , Wei Wei , Al Maysari Jawhara , Idicula Anoop Pappy 
Published: November 2020

Abstract
ADNOC Onshore operates a sour field on South West of Abu Dhabi with the wells to the northeast of the field exhibiting generally higher H2S content than wells to the southwest.
Congestion of the field is recognized as a major issue affecting safety, access to existing reserves and operability since the early 2000. The congestion is caused by the high density of surface facilities resultant of numerous interfaces in the field (stakeholders), making well surface location finalization very challenging and impacting directly on subsurface congestion (by risking or impairing access to lower staked reservoirs - subsurface collision), rig moves, field connectivity, etc. This poses serious challenges to future developments if the approach of business as usual were to continue.
The field has been producing from several oil and gas reservoirs but accelerated plans for oil and gas long term developments extended the exploration to other new reservoirs, increasing the challenges on reservoir exploration (brown field vs green field approach), on safety (exponential increase in number of wells, reservoirs with higher H2S content, etc.). It also increases surface and subsurface congestion, as the complexity of producing from more staked reservoirs increases.
Decongesting the field and controlling the associated congestion of on-going projects is a key activity to manage space for future development, sustainable operation and business continuity. So far, the evaluation of a certain project options in terms of footprint impact has been qualitative in the sense that the decision is made based on the congestion observed on Enterprise Geograhic information System (GIS) map and in order to quantify footprint use and achieve a trustworthy comparision mechanism, a Geograhic Iinformation System (GIS) based congestion factor calculation tool had to be developed.
This paper covers the development of the Congestion & Connectivity tool as an important milestone in ADNOC Onshore's initiatives to quantify and address the congestion issues on surface and consequently on subsurface and extend to other ADNOC Onshore in the long run.
A Major Shift In Reservoir Management Strategies And Best Practices In A Mature Reservoir To Overcome The Current Reservoir Challenges: Case Study
Authors: Alshalabi Alaa , Al Saadi Haitham , Maire Flavien , Thomas Tony , Gueye Talla , Al Amiri Fatema 
Published: November 2020

Abstract
Reservoir X is a giant oil reservoir of 30×10 Km2 developed since 1973 using peripheral water injection. A major review study was done in 2016 highlighted major reservoir challenges that need to be managed and mitigated. The main challenges are (a) reservoir pressure decline in the central area (b) advancement of water cut/water conning (c) increased number of inactive strings (d) improper distribution of production offtake (e) inefficiency of current injection scheme. Consequently, reservoir deliverable potential has continuously dropped with increasing inactive strings threatening the attainment of the field mandated production target. This requires a major shift in our reservoir management strategies and best practices to cope with these challenges.
In this paper, a case study for reservoir management in a mature carbonate reservoir with its detailed methodology is presented. An intensive and integrated technical work was conducted to (a) regain the target technical rate of 20% (300Mbpd) (b) arrest the pressure decline (c) implementation of a more efficient long-term plan to increase reservoir pressure and to maximize ultimate recovery. A detailed approach was developed which consisted of short, mid and longterm actions. This approach involves (a) re-prioritization of infill drilling through weighted ranking (b) pressure recovery implementation strategy through sectorization, re-balancing of production offtake and improving water injection efficiency (c) sector based evaluation using simulation/streamlines/data analysis for the voidage replacement (e) water injection optimization with the help of new peripheral water injectors, increased water injection availability (New clusters and network debottlenecking) and new Water Injection scheme (Mid Flank water injectors) (f) tracking the implementation of the Pressure Recovery Plan with a dedicated and tailored monitoring dashboard.
Through this integrated approach a portfolio of wells is selected and ranked that help in achieving the objectives of the reservoir development efficiently and the 20% Technical Rate achievement. The sector wise analysis and tracking approach enabled in arresting the pressure decline in the crestal area and ensured that the focus remained on the recovering pressure in the worst affected areas of the reservoir while meeting the production requirements. Another important outcome of this work was to drive a slew of initiatives related to the improvement of water injection efficiency that is a necessary requirement to recover the pressure in the crestal area. This reservoir management methodology and framework put in place provides a platform to continuously integrate the inputs (production/injection; VRR; pressure) and develop understanding from the different disciplines of the reservoir development to monitor and manage the reservoir in and efficient and timely manner.