bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting Seismic-Based Anisotropy for Prevent Pre-Drill Risk Using a Novel Type Neural Network
Authors: Ding Yan , Cui Meng , Wang Hai ge , Fei Zhao , Shi Xiao yan , Huang Kai 
Published: October 2021

Abstract
While drilling into fracture zones, lost circulation frequently occurs, resulting in a waste of productive operation severe cases, the well's destruction. However, due to complex development mechanisms and high heterogeneity, identifying and predicting fractures is extremely difficult. This study proposes a new drilling loss prevention idea to evaluate fractured lost circulation risk using seismic and wellbore data by a novel neural network. The approach works in two steps. First, the fracture anisotropy of a lost circulation sample curve is computed and interpreted using well logs. Second, using seismic attributes as constraints, a novel neural network is used to develop a prediction model. The field application in the Sichuan basin verifies the method's efficacy and confirms the method's ability for predicting lost circulation probability both along the well trajectory and in regions away from the drilled wells.
Successful and Efficient Drill & Drive Conductor Operation in Offshore East Java
Authors: Akbar Muhammad Ikhsan , Tobing Jerry , Musa Mohd Zarir Bin , Fajar Irshad , Ardiansyah Fajar 
Published: October 2021

Abstracts
Conductor setting depth is critical to provide structural support for next drilling sections. The shoe strength must suffice for drilling ahead and avoid any washout and unstable zone. The objective is to design and run conductor smoothly in regards to engineering and operation aspect.
Multidisciplinary approach including geotechnical, drilling engineering, and structure, was implemented during planning strategy. The pre-determined conductor setting depth was defined on the maximum mud weight to be used during drilling surface hole section in accordance to the formation strength below the conductor with the purpose of not inducing losses to the formation. Lateral distance between conductor and platform jacket pile was also analyzed to secure the jacket integrity. Anti-collision analysis was performed to prevent collision due to the existence of production well in same platform. Conductor pipe size and specification with some feature was defined to withstand under anticipated load and environment. To determine the way to achieve target depth and the suitability of hammer type, drivability analysis was performed with various anticipated condition. Considering shallow refusal depth, drill and drive was required to reduce shaft friction of soil. Another environmental challenge arise during conductor operation was unable to contain fluid and cutting returns from clean-out process causing return to cover part of the production platform facility. Some of technology were planned to mitigate this challenge.
By having comprehensive conductor design, the conductor pipe in all four wells drilled has been successfully installed without any problem on platform jacket integrity and subsequent drilling section. This approach also enabled to efficiency of conductor installation where the number of clean-out and driving run could be reduced. The overflow return challenge could be fully contained by utilizing selfdesigned equipment. The overall operation days of conductor has shown improvement with 1.02 saving days on the last well which equivalent to amount of cost saving around USD 203,500.
Successful Lifting of Oil with High Concentration of Hydrogen Sulfide by Artificial Lift System – Case Study
Authors: Rehman Abid Ur , Abdelbary Marwan 
Published: October 2021

Abstract
Due to the low cost of crude oil, it is highly unusual for the operators to drill exploration wells, for the past few years. Adding that as well to the world's economy collapse due to the pandemic at the start of 2020, it is now more than ever a necessity to use artificial lift methods to lift from previously shut-in wells or maximize current production of the wells, as to grapple with the running expenses of operators.
The artificial lift is a vast field with different lift methods applicable to a single well. Hence, the selection of an optimum lift method is critical. During the worst economic slump, the economic analysis will play a decisive role in the application of an artificial lift system (ALS) along with a technical review. The jet pump system is one of the most reliable artificial lift systems for lifting shut-in wells. The installation time of this system is minimal, and production starts right away. However, the system can prove to be very expensive, if the design is not done critically.
This paper is about lifting a well that was not able to flow naturally. The vertical well B3 located in northern Iraq was drilled in May 2018 to a total depth of 521 meters. But the well was not able to flow naturally, and the jet pump was designed for the well based on well completion, downhole pressures, temperature and reservoir fluid properties. The evaluation and design of the downhole jet pump and surface pumping unit requirements were performed on Jet Pump Evaluation and Modeling Software.
This well produced approximately 1700 BOPD. Since, the well was not flowing before the installation of the jet pump, most of the production data was obtained after deployment of ALS and production was optimized accordingly. The production had a high content of Hydrogen Sulfide as well, which was treated accordingly for safety of personnel, equipment, flow lines and environment. This paper describes the details about the application, optimization and operation of the jet pump system deployed on inactive wells with a high concentration of sour gas.
Understanding the Facies Architecture of a Fluvial-Aeolian of Tensleep Formation Using a Machine Learning Approach
Authors: Hardanto Lilik Tri 
Published: October 2021

Abstract
Many aeolian dune reservoirs are built from various dune types, and many may remain unrecognized in subsurface work. The challenge is to tackle the complex geological architecture of dune types within the Teapot Dome dataset caused by wind and water erosion. Machine Learning (ML) helps predict facies architecture away from boreholes using seismic attributes and facies logs. It provides a detailed understanding of the facies architecture analysis of the relationship between the fluvial–aeolian environment in Tensleep Formation based on seismic and well data. It allows operators to wisely assess their hydrocarbon reservoir, improve safety, and maximize oil and gas production investment.
The data from the Teapot Dome field (Naval Petroleum Reserve No.3 - NPR-3) provides a good testing ground for Machine Learning, as it is easy to validate and prove its value. This study will show how the ML supervised learning method incorporating Neural Network Seismic Inversion (NNSI) can successfully create porosity log and facies volumes. Moreover, unsupervised learning using Multi-Resolution Graph-based clustering (MRGC) can be used to classify the facies logs. NNSI has 0.963 for the cross-correlation coefficients for all wells. The ML approach was used to help recognize the type of aeolian dune reservoirs in the subsurface and correlate the well log and facies volumes. In addition, ML allowed the distinct sequences and reconstruction of their depositional history in the Tensleep Formation. This study also refers briefly to other examples of fluvial-aeolian facies architecture worldwide. It successfully found the ancient model in an existing modern fluvial-aeolian environment, revealing hidden information about facies architecture based on the geometrical shape of geobodies in the oil-producing reservoir in the Tensleep Formation.
Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq
Authors: Tang Xueqing , Wang Ruifeng , Cheng Zhongliang , Lu Hui 
Published: October 2021

Abstract
Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved.
Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.
Driving Resource Stewardship to Secure Hydrocarbon Resource Development for Sustainability and Growth in Sarawak Region
Authors: Ngan Arthur Cheng Ho , Sinha Ankaj Kumar , Saad Harnee Bt , Jaafar Juhaidi B 
Published: October 2021

Abstract
Strategic vision and long-term view of upstream development plan is one of the key directives entrusted to Malaysia Petroleum Management (MPM) to secure sustainable production for the nation. The Sarawak Area Development Planning (SK ADP) is one such critical study aimed at identifying the inventory of hydrocarbon resources, potential outlook on projects' commercial viability, as well as shaping the portfolio mix strategy to deliver the long-term business growth. This SK ADP study also keeps Petroliam Nasional Berhad (PETRONAS) well-positioned to steer Petroleum Arrangement Contractors (PACs) in developing and maximizing the full value of resources. This includes outlining opportunities to collaborate in project sequencing and cost optimization efforts. This paper illustrates the methodology, process workflow and key takeaways from the SK ADP study.
The SK ADP study was conducted to establish a development blueprint based on overall available resources and projects' first hydrocarbon sequencing for the short-term and long-term development planning in the Sarawak region. The key objective of the study was to identify the most optimum and technically viable integrated development plans, whilst also incorporating the agreed commitments and existing limitations inclusive of technology application and replications. The process workflow consisted of identifying six focus areas to further enhance the Sarawak Portfolio, maximizing the assets' value and ultimately meeting overall supply and demand requirements. These focus areas act as guiding principles to mature the overall development plan for the area, relating to generating an inventory basket, facilities optimization, clustering strategy, technology evaluation, contaminant management and risk assessment. Cross-discipline integration plays a pivotal role in shaping the final roadmap for each of the focus areas coupled with holistic validation.
With the SK ADP in place, it can function as a key reference document and kept updated with the latest developments to maintain PETRONAS' agility in the pursuit of both business sustainability and continuous growth in the region. Key deliverables from this ADP can be turned into actionable insights for field implementation and help boost overall resource management in the region for long-term production delivery. This paper presents the best practices adopted for region level development planning in alignment with strategic vision for business growth.
Breakthrough Enhanced Oil Recovery Technology with Low Cost & Fast Yield on Pilot Test of Vibroseismic EOR Technology in Tempino Field, Sumatera, Indonesia
Authors: Sitompul Victor , Alfian Muhammad , Sitompul Fransiskus Ondihon , Winata Denie , Diharja Tino , Sutadiwiria Gunawan , Paryoto Sumadi , Dusyanto Erwin Dicky , Rahadian Reza , Erwanto Pungki Eka , Triwanto Alip , Sumirat Iik , Alfajri Reza , Ekalaya Muhammad Aji , Nurrakhman Ahmad Ardhy , Asy'ari Husein 
Published: October 2021

Abstract
Enhanced Oil Recovery (EOR) is a tertiary recovery which requires relatively a high cost of CAPEX and OPEX. The current EOR technique is generally stand alone and injected into single reservoir layer without contributing to the other layers (unconnected reservoir layer). For this reason, a breakthrough of low cost EOR technology (CAPEX & OPEX) is needed, especially since oil prices tend to fall low. Vibroseismic EOR is one of the EOR methods (categorized as mechanical EOR) that is inexpensive, fast response / yield, high mobility (can be moved to another place), environmentally friendly, and could be combined with the waterflood method or other EOR methods to get more effective and optimal result. However, the research & implementation on Vibroseismic EOR are still limited. The paper describes the pilot test of Vibroseismic EOR technology in Tempino Field.
The initial stage is to select the suitable field for implementation Vibroseismic EOR. Then, the rock & fluid properties of the selected field are tested and examined by vibration and stimulation in the laboratory to obtain optimum frequency of 20 Hz S waves (circular / transverse) and 35 Hz P waves (longitudinal). The field scale-up process is carried out by measuring or testing field parameters called Vibroseis Field Parameter Test (VFP Test). VFP Test results get the optimum frequency of S and P waves of 20 Hz using 3 trucks and drive level 70% with amplitude value up to 0.024 rms (root mean square). Through the EOR vibroseismic method, the truck is the source of vibrations on the surface will generate acoustic waves propagating through the rock (subsurface) throughout the reservoir layer within the wave penetration range, generally reaching a depth of 6500 ft depending on the amplitude / power source of vibration, thickness of weathered layer, and rock type. The waves that reach the reservoir will affect the rock & fluids properties.
The pilot test results on production wells showed a positive response within 1 month after vibration, especially those around the existing injection wells which the permeability was relatively good. The increased production accumulative of 10 (ten) monitoring production wells about 8% and withhold declining rate up to 20% from base case. Oil drainage around production wells and drainage direction are confirmed by changes in hydrocarbon saturation maps through passive seismic techniques measured before, during, and after vibration.
The results of this pilot test show that Vibroseismic EOR technology is very promising to be developed to the full-scale stage and implemented in other areas.
Novel Simulator for Design and Analysis of Wax Removal Treatment from Well Flow Lines Using Thermochemical Fluids
Authors: Qamruzzaman Mohammed , Chandra Roy Dhirendra , Raman Ravi 
Published: October 2021

Abstract
Treatment of well flow lines with thermochemical/exothermic fluid has shown good results for wax removal compared to conventional hot oil, hot water or solvent treatments. However, the technique has not gained widespread use due to lack sufficient scientific publications that can give more insights over its use and help in designing a safe and effective treatment.
This paper presents a novel transient mathematical model for design and analysis of thermochemical treatment for well flow lines by taking into account the chemical kinetics, heat transfer, fusion of wax and associated two-phase flow. The governing equations have been solved using tools of computational fluid dynamics and heat transfer (CFD - HT). The resulting simulator can be used to prepare an optimum thermochemical plan by analysing the effects of important factors including wax details, deposition profile, heat loss, formulation composition and injection strategy.
Simulation results with the developed model indicate that entire filling of flowline with thermochemical fluid is not necessary for complete wax removal. Injection of a small thermochemical spacer in the flow line followed by its displacement with crude oil can be suffice in case of short flowlines of onshore fields. Selection of initial reactant concentration and pH has to be done judiciously based on the maximum allowed temperature in the flowline and the desired extent of chemical utilization. A sensitivity analysis has shown the existence of an optimum range of injection rate below which wax removal efficiency is compromised by excessive heat loss and above which it is reduced by insufficient residence time. The major limitation of this technique is encountered for large flowlines where a possibility of re-solidification of removed wax deposits exist due to excessive heat loss. Flowlines of length less than 5 km are found to be ideal candidates as in that case, sufficiently high temperatures can be maintained throughout the journey of thermochemical spacer in the flowline which will prevent re-solidification. The simulator has been validated with field implementation results of two well flow lines where the designed jobs have been successful in removing the entire wax deposits as predicted by the simulator.
A Step Change in the Digital Oilfield Arena: Cloud Computing and Workflow Integration for Production Operations Solutions
Authors: Kotiyal Aditya , Prasad Nagaraj Guru , Michael Lester Tugung 
Published: October 2021

Abstract
Digital oilfield applications have been implemented in numerous operating companies to streamline processes and automate workflows to optimize oil and gas production in real-time. These applications are mostly deployed using traditional on-premises systems; where maintenance, accessibility and scalability serves as a major bottleneck for an efficient outcome. In addition to this challenge, the sector still faces limitations in data integration from disparate data sources, liberation of consolidated data for consumption and cross domain workflow orchestration of that data.
The dimensional change brought by digital transformation strategies has paved a path for the Cloud- based solutions, which have recently gained momentum in the oil and gas industry pertaining to their wider accessibility, simpler customization, greater system stability and scalability to support larger amount of data in a performant way.
To address the challenges mentioned earlier, we have embarked on a journey with Production Data Foundation which brings together production and equipment data from across an organization.
In this paper, we will highlight how Production Data Foundation, hosted on the cloud, provides the underlying infrastructure, services, interfaces required to support and unify production data ingestion, workflow orchestration, and through the alignment of the common domain and digital concepts, improve collaboration between people in distinct roles, such as production engineers, reservoir engineers, drilling engineers, deployment engineers, software developers, data scientists, architects, and subject matter experts (SME) working with production operations products and solutions.
Replacement of MEG with KHI for Hydrate Control in Subsea Flowline Offshore Myanmar
Authors: Kim Jonghyun , Scalea Paolo , Hwang Chulhwan , Kim Jeongmoon 
Published: October 2021

Abstract

Objectives/Scope
This paper describes the successful replacement of Mono Ethylene Glycol (MEG) by Kinetic Hydrate Inhibitor (KHI) to guarantee flow assurance in the Shwe field subsea production system, offshore Myanmar. It covers the initial difficulties experienced with MEG, specific field conditions, the comprehensive KHI selection process and testing up to field application and operation.

Methods, Procedures, Process
MEG used for hydrate inhibition in the field's subsea flowline was originally regenerated in the topside facility, however contamination of the MEG with salts from formation water was causing process upsets. The option of installing a reclamation package presented many challenges and, after review of field conditions, the application of a KHI was considered as a promising alternative to MEG. With the engagement of specialist chemical suppliers a broad and challenging series of laboratory, as well as field tests, was carried out to select a suitable product. Finally a dedicated permanent injection skid was installed to guarantee stable KHI delivery and production.

Results, Observations, Conclusions
The difficulties caused by salt contamination of the MEG system, combined with the intricate field logistics at the remote site offshore Myanmar, entailed a speedy solution. This combined with suitable operating parameters of the field; i.e. low water content, high wellhead flowing temperatures, subcooling within known KHI operating range, ensured KHI was an economical solution.
Nevertheless from desktop study to successful field application a series hurdles had to be crossed, including performance and compatibility tests, simulating all the expected Shwe Offshore Platform (SHP) operating conditions: Determination of Hydrate Equilibrium Temperature (HET); Induction Time Autoclave test for the required residence time in the presence of Corrosion Inhibitor (CI); Hot Injection ests at wellhead operating temperature; Thermal stability tests for topsides and condensate disposal system; Umbilical material compatibility tests; Compatibility of KHI with incumbent products (MEG and CI).
Testing of a range of products, carried out by specialist chemical supplier, resulted in the selection of a qualified product, followed by a successful field application testing programme.
Seven years after its introduction, KHI has helped achieve optimum field uptime and reduced operational costs as well as eased logistics constraints.

Novel/Additive Information
KHI is not new to the Oil & Gas industry, however information on its selection and application is not widely available. This paper sheds light on the steps to be considered when evaluating KHI as a suitable hydrate inhibitor, as well as the detailed laboratory tests for proper selection of a product. The intent is to help operators who are facing challenges with hydrate inhibition and could revert to KHI as an alternative.