bluuebunny/crossref_metadata_2025_split huggingface dataset:
Digital Transformation in Oil and Gas Industry
Authors: Zeynalli Aytan , Butdayev Ruslan , Salmanov Vugar 
Published: October 2019

Abstract
Digital transformation is the large-scale business transformation, which affects the entire set of enterprise functions from the automation of processes to execution and control. It directly affects both the change in the operating model and the infrastructure of the enterprise. This paper explores the industry trends in digital transformation as well as SOCAR AQS initiatives in this field. Digital transformation in the oil and gas industry has gained momentum in the last few years. The use of digital advances and innovation is not new to the oil and gas industry, as early as the 1980s, leading companies began to adopt digital technologies.
The study explores different approaches to the conceptualization of digital transformation. The result of a successful digital transformation is not the creation of a new organization, but its restructuring of the existing valuable assets in a new way. In other words, digital transformation is not only technological change but also the change in the tasks that management is facing. Practical examples and insights on digital transformation journey are provided.
The research analyses multiple case studies to understand how the world's leading companies are embracing digital transformation to reshape their operating landscape and achieve greater productivity, higher efficiency, and cost optimization. With digital transformation, businesses in the oil and gas industry no longer only save money, but also make money. How does this work? It's the vernal part of the topic. There's no precise model or approach that has been widely accepted in the industry, contrary to the consumer market, which has successful and mind-blowing cases like Uber and AirBnB where businesses do not own assets and create an ecosystem for customers to find the products and services they need. In the industrial sector, specifically oil and gas, this topic is sensitive to the competitiveness between businesses and others. However, it's clear that whichever industrial companies manage to have a breakthrough in the synthesis of AI, big data and cloud computing for the benefit of comparative advantage will lead and dominate the industry reshaping it for the next generation.
Alice: Would you tell me, please, which way I ought to go from here?
The Cheshire Cat: That depends a good deal on where you want to get to.
Lewis Carroll, Alice in Wonderland
Implementation of Data Driven Machine Learning Methods and Physics Driven Concepts for Real-Time Well Performance Estimation in Kashagan Field
Authors: Mursaliyev Adilbek , Kushekov Adilbek , Sultangaliyev Ruslan 
Published: October 2019

Abstract
This paper presents the implementation and value of Data Driven Machine Learning methods and Physics driven Concepts for real-time well performance estimation in Kashagan Field. The models are expected to be used to detect fluid properties changes, restrictions in the well tubing and instrumentation malfunctioning.
The paper also describes how the data driven and physics driven models are built, tuned and maintained. The comparison of the methods will also be attempted in terms of redundancy.
The data driven machine learning method (DDML) used in the paper is artificial neural networks model. The model consists of several inputs, layers of artificial neurons and output parameter(s). The built DDML model is trained by feeding labeled input test data and trained. Then the trained DDML model is validated and tested against separate labeled data which the model did not "see" before.
Physics driven model (PDM) is built on Vertical Lift Performance (VLP) equation. The PDM is also "trained" with input data by tuning the model in order to fit to test data. The tuning parameter is friction coefficient.
The trained DDML and PDM models are then tested on same set of data in order to compare the performance. Both methods showed similar degree of accuracy. The reference data comes from MPFM, Test separator and downhole gauges. Downhole pressure gauge signal is used by both of the methods. However, if the downhole gauge is broken, the PDM will not function for estimation of the rate. On the other hand, DDML model can be re-trained with available signals (tubing head pressure, temperature, choke size, flowline pressure and temperature, etc.) by excluding the downhole gauge signal from the training data. It is clear that the DDML model trained without downhole pressure signal is not as accurate fully trained DDML model. However, it is still possible to have reasonable estimate of the parameter with even partially trained model. Both models can be used to estimate downhole pressure in cases where the gauges are broken.
The proposed methods can be used by practicing engineer to estimate well performance parameters. The methods are mostly suitable for so called smart fields where the data is readily available and makes it possible to extract useful insights from the archived data. With hands on experience with such simple implementation of data driven machine learning techniques an engineer can try to implement ML methods for other applications, e.g. well interference, history match, anomaly detection, etc.
An Integrated 3D Geological Modeling Study of a Heavy Oil Field in Southeast Turkey
Authors: Kamanli Safigul Tuba 
Published: October 2019

Abstract
Numerical reservoir modeling is the most sophisticated tool to prepare field development plans and to facilitate decision-making for investment planning. This study presents geological modeling workflow of Bati Kozluca Heavy Oil Field for selection of the best infill well locations and the optimum EOR method to maximize production.
A 3D geological model was built for Bati Kozluca Field, which has been producing since 1985. Well locations, log data, structural surface of the main reservoir rock, i.e, Alt Sinan Formation and interpreted faults were input to the model. The formation is divided into three different flow units according to petrographic facies. Variogram maps were created for petrophysical properties and porosity was distributed by means of Sequential Gaussian Simulation (SGS). Water saturation to depth relation was generated and distributed. Cut-off values obtained from core data were used to generate net-to-gross.
Based on the geological model of Bati Kozluca heavy oil field, OOIP distribution was estimated and two new infill wells (Bati Kozluca-55 and 56) were drilled in the undrained area. Water saturation and porosity values obtained from well logs of these two wells perfectly matched with the values used in the model. Finally, the model was updated using the data from these wells. Porosity and oil-water contact were considered as variable in the Uncertainty analysis and oil-in-place was recalculated. Hence, the model is ready to be used for dynamic reservoir simulation by which secondary production methods to be decided.
This study presents the first stochastic approach to geological modeling of Bati Kozluca heavy oil field in order to quantify the uncertainty associated with reserve estimation.
From Papers to Steel: Delivering First Stimulation Vessel in Caspian Sea
Authors: Hadiaman Farid , Mollayev Samir , Amirov Ayaz , Ibrahimov Fuad , Azizov Ehtiram , Mammadov Hajagha , Mammadova Natalya , Bakirov Parviz 
Published: October 2019

Abstract
Stimulation is one of the initiatives to minimize production deferral. In Caspian Sea environment, stimulation job can be done through rig, which is not-so economical but provide more options to pump more volume; through simultaneous operation (from skid deck), which is economical but unfavorable in terms of space and opportunities generation; through simultaneous operation (from the vessel), which cater both advantages from skid deck and rig options earlier.
A stimulation vessel project was initiated in order to deliver first of its kind in Caspian Sea of a vessel that capable pumping stimulation fluids into the well. A conceptual design on paper was exercised. To progress the project from papers to real work, a transformation in a way of working and deliver the project is needed. As this is the first in Caspian Sea, there are multi-interrelated factors affecting the project and most of them are unknown as nobody been through this process before, either operator and service companies. The project will be executed with an agile way of working to meet stakeholder's aspiration, by applying agile values and principles to transform the feel and performance of how we deliver the project. Learning from experience that applying agile practices can improve our focus on safety, operational risk by promoting technical assurance, iterative development and rapid learning cycles. This technique proves to safely deliver the first Stimulation Vessel in Caspian Sea.
Production Sustenance and Offshore Operation Safety Through Facility Optimization and Debottlenecking
Authors: Mehran Fatemeh , Didanloo Ali , Mai Khanh Tu Le , Le. Q Hung 
Published: October 2019

Abstract
Hai Su Trang (HST) – Hai Su Den (HSD) fields are located in the Cuu Long Basin, in block 15-2/01 with approximately 60 km away from Ba Ria – Vung Tau, the Southern coast of Vietnam. This field has complex facility infrastructure consisting of one well head platform HSD and one well head separation platform HST. TLJOC recently faced some operational challenges such as instability and even system shutdown and as the operating safety is very critical for this offshore field, they have started the investigation on finding solution for more efficient operational condition.
In TLJOC system, debottlenecking of the three separates network including oil, water injection and gas lift network were typically needed for entire field life to maximize the production rate and avoid any further system shutting in future. In addition, there were few changes in reservoir system such as increasing perforation zone for some of the wells to enhance production rate which should be simulated in advance to make sure of facility capability and flow assurance. Furthermore, finding root cause of bottlenecking and controlling operational condition to avoid the exceed limitations was very critical for asset team.
All production units were modelled and analysed for current condition and future operational condition base on reservoir management plan. The several scenarios based on TLJOC- RMP cases has been run and result got evaluated to make sure facility pipelines and equipment have enough capacity and at the same time there will be no integrity in pipeline such as slug issue. Also, additional cases were defined for possible upcoming event such as dropping or increasing facility unit pressure or decreasing water injection pressure to have better view of system health and capacity for entire life of field.
The results of analysis prove that in oil pipeline the slug flow pattern exist in most of cases, as one of key reasons for recent operation issues. Recommendations are either control the operation condition of riser to mitigate slug or to control separator pressure in order to reduce slug. Another recommendation was to maintain the liquid level in separator based on certain level to avoid slugging. Based on back pressure effect analysis this system has capacity to increase production up to 20 %, however 15% increase is more efficient operationally. The water injection and gas lift network can handle all possible event and have no problem with capacity only need to keep monitoring the junction pressure to not fall or exceed the operational and integrity limit.
Determination the Source of Sustained Annulus Pressure in High GOR Oil Wells by Using Acoustic Logging
Authors: Vasilyev Sergey , Boltunov Nikolai , Shkaran Alena , Kirpichikova Elena , Minakhmetova Roza , Pimantyev Valeriy , Nagimov Vener , Zaripova Asiya 
Published: October 2019

Abstract
The sustained annular pressure (SAP) related issues are always actual and especially in oil and gas wells with high GOR. The presence of SAP may have a negative effect and cause numerous issues such as uncontrollable gas seepage to the surface (gryphons), well performance impairment, and increased risk of accident occurrence. To prevent accident occurrence risks increase it is necessary to perform specific downhole logging operations in order to identify SAP sources in wells located in a green oil and gas fields.
The precise SAP sources localization requires the use of highly sensitive logging techniques as measurable physical filed perturbations caused by completion integrity damages are small-scale. This paper describes the logging methodology of the spectral acoustic and high precision temperature techniques in combination with pulsed electromagnetic defectoscope. The key requirement of the successful operations using the above-mentioned techniques was to select and maintain special well operation conditions to ensure the optimal survey conditions for solving the particular issue without pulling out of the downhole equipment.
Evaluating Performance of Horizontal Wells Using Integrated Approach: Micro Seismic Monitoring, Geophysical Logging Using Conventional PLT and Marker-Based Production Logging
Authors: Basov Artem , Bukov Oleg , Kuznetsov Vadim , Lazutkin Dmitry , Saprykina Kseniya , Ovchinnikov Kirill , Guryanov Andrey , Katashov Alexander , Novikov Igor 
Published: October 2019

Abstract
The resource potential of the Bazhenov formation is very highly estimated and chiefly involves kerogen reserves. However, currently the application of cutting-edge technologies providing efficient and economically viable industrial development is required.
The present article discloses the results of applying various horizontal well production logging technologies with multistage hydraulic fracturing in the Bazhenov formation deposits at one of the fields that has been developed since 2015.
Oil Production Stimulation by Creating a Vacuum in the Annular Space of the Well
Authors: Isaev Anatoliy Andreevich , Takhautdinov Rustem Shafagatovich , Malykhin Vladimir Ivanovich , Sharifullin Almaz Amirzyanovich 
Published: October 2019

Abstract
A significant number of small oilfields on the territory of the Republic of Tatarstan are operated by small oil companies. These fields are mostly characterized by high oil viscosity and low formation pressures. Sheshmaoil Management Company LLC is a leading one among small oil companies of Tatarstan in many respects. The structure of Sheshmaoil Management Company LLC includes 7 small oil-producing companies, three of them (Sheshmaoil JSC, Ideloil JSC, Geotekh JSC) are actively engaged in R&D activities in the field of improving the oil production efficiency from wells through their evacuation.
On the oilfields of Sheshmaoil JSC (Severnoye, Letneye, Novo-Sheshminskoye and Krasnooktyabrskoye fields), 19 local structures are under commercial development, the objects of which are oil deposits of carbonate sediments of the Bashkirian and Tournaisian stages, Vereiskian horizon, terrigenous sediments of the Aleksinsky and Tula-Bobrikovskiy horizons of the Early Carboniferous, Kynovskiy and Pashiyskiy horizons of the Late Devonian.
55 oil deposits confined to twelve local uplifts (Svetlogorskoye, Zagonnoye, Dachnoye, Novo-Kadeevskoye, Krasno-Klyuchevskoye, Kuteminskoye, Vostochno-Kuteminskoye, Yasakskoye, Sukhoye, Grivinskoye, Yuzhno-Ulyanovskoye, Serebryanno-Klyuchevskoye) have been identified within the area of the Dachnoye field of Ideloil JSC. Eight of them are confined to the carbonate deposits of the Vereiskian horizon, 8 — to the deposits of the Bashkirian stage, 1 deposit - to the Aleksinsky horizon, 13 deposits are confined to the deposits of the Tournaisian stage of Early Carboniferous. To terrigenous deposits of the following horizons: Tula - 4 deposits, Bobrikovskiy - 16 deposits, Kynovskiy - 5 deposits. 42 deposits of oil are under commercial development.
Subsea Well Intervention – An Operator's Experience in First Deepwater Temporary Wells Suspension in West Africa
Authors: Liew William Sin , Mohamed M'bareck Khalil , Mustaffa Shahira Emie , Abdul Razak Mohd. Hairi , Yaakub Mohd. Yuzmanizeil 
Published: October 2019

Abstract
Abandonment and decommissioning activities of oil and gas assets had been on the increasing trend for the past few years. Mature assets approaching end of life cycle and depleted production coupled with the low oil price environment has contributed to poor economic evaluation of the producing fields. This paper will discuss operator's experience in planning and executing subsea well intervention to temporary suspend fifteen (15) deepwater subsea wells tied to a Floating Production, Storage and Offloading (FPSO) unit in West Africa.
The approach of the temporary wells suspension will be shared. Decision to temporary suspend the wells was made to meet the objective of releasing the FPSO early due to high operating cost. This temporary wells suspension design is mainly driven by the objective to meet the industry standard and best practices in re-instating double barrier envelope in the wells during the suspension period. During the planning stage few methods of barrier installation including contingency plans were considered.
The temporary barriers placement were designed with end state in mind, the subsequent wells plug and abandonment after the suspension period. Based on the barriers placement philosophy, the subsea well intervention activities were planned and followed by the selection of vessel or rig for the operations. Drivers behind the temporary wells suspension design, approach for subsea well intervention - using riser based or riserless operations; and selection of vessel or rig for the operations will be shared in this paper. In addition, the lessons learnt and optimization opportunity throughout the execution of this subsea well intervention activity will be presented.
This project is the pioneer to deepwater subsea abandonment and decommissioning (A&D) in the region of West Africa. The fifteen deepwater subsea wells were successfully suspended safely, ahead of planned schedule and below AFE cost. The lessons learnt from successful temporary wells suspension through subsea well intervention carried out by operator is believed to benefit all industry players, including the regulators, operators, service partners; and could be reference for industry's deepwater subsea decommissioning.
First Successful Application of Multistage Fracturing Completion in Cased Old Vertical Well
Authors: Nurlybayev Nurlan , Asanov Karim , Bashev Adilbek , Rakhymberdi Rauan , Khlestov Ivan , Zagranichniy Stanislav 
Published: October 2019

Abstract
Hydraulic fracturing has proven to be one of the most efficient and common completion methods to increase well productivity in mature oil fields with tight sandstone formations. However, the efficiency of the overall completion process is influenced not only by the applied fracturing technology but also by the well completion methods and production approach – especially in wells with long perforation intervals.
Nowadays, multistage fracturing systems have become widely used for more effective fracture placement and optimization of inflow profiles. This technology is mostly applied in an openhole section of horizontal wells where such completion requirements are most critical. However, the development of existing vertical wells can also benefit from the technology allowing selective stimulation of production zones, which could not be efficiently fractured otherwise. The approach described in the paper covers the candidate selection, recompletion technique, stimulation and production process applied for the oilfield in West Kazakhstan.
The sample well had been in production for several preceding years completed with perforations (up to 182 meters) at four main oil-bearing zones. Previously, there was done acidizing treatment which gave two-fold increase in production, but full potential of the well was not achieved. It was identified that the most of the inflow had been coming from only 43% of perforations while the rest intervals did not contribute to production. To achieve the coverage of all productive layers with fractures and involve all layers into production, it was decided to recomplete the well with four-stage completion system with ball activated multishiftable frac sleeves.
Four stage completion system was installed in the cased old well and multiple fracturing stimulation was performed successfully. The job is a subject for further testing process of each treated zone, but the effectiveness of applied technology had already been proved as the overall production surplus more than four times. The operator considers replication of similar approach to the other wells in the oilfield.
Successfully Navigating the Narrow Pressure Window in an HPHT Offshore Well
Authors: Devadass Lingges , Syrapushchynski Sasha , Rockwood Jene 
Published: October 2019

Abstract
While the main objective for Well #1 was to appraise the hydrocarbon potential at depths below a known gas reservoir, the operator was able to drill a high-pressure, high-temperature (HPHT) reservoir section with a mud density of 18.4-lb/gal (2.2 sg) with zero fluid losses. The highly deviated appraised interval had both very low and extremely high pore pressures, with the maximum overbalance of approximately 6,800 psi(46,900 kPa).
Compared to offset appraisal wells, downhole losses, hole instability, differentially stuck pipe and well control issues were avoided through the adoption of a low-invasion synthetic fluid system designed with wellbore shielding technology. During the planning phase, the operator conducted extensive laboratory testing to assure technical performance, as well as cost reductions, were achieved by optimizing the drilling fluid design. Best practices from previous HPHT wells were carefully studied and replicated to ensure the success of the well.
Wellbore stability was achieved and the 8½-in. hole section was drilled into the targeted formation tops. In the reservoir hole section, the mud weight was increased to 18.4-lb/gal (2.2 sg) in order to compensate for high pore pressures up to 14,000 psi (96,500 kPa); the highest overbalanced pressure measured was 6,800 psi (46,900 kPa) due to the low pore pressure in the sands above. The drilling fluid was designed with wellbore shielding technology to create an impermeable barrier across low-pressure zones and minimize pressure transmission from high mud density. The rheological properties of the drilling fluid were monitored along with maintaining a thin filter cake and low solids content.
Operational issues and challenges to drilling exploration wells in HPHT environments with high differential pressures continue to be an ongoing industry concern. The drilling fluid design used in this well shows great potential to eliminate drilling hazards in tough downhole conditions.