bluuebunny/crossref_metadata_2025_split huggingface dataset:
World Longest Single-Trip Multizone Cased Hole Gravel Packing with Alternate Path Shunt Tubes
Authors: Chin Pui Ling , Moses Nicholas , B Ahmad Mahdzan Abdil Adzeem , Abu Bakar Azfar Israa , B. M. Nor M. Abshar , Bin Mohd Aziss Muhammad Yusof , A. Rashid Noor Hidayah , Bela Sunanda Magna , W. Hasan W. Helmi , A. Kadir Zairi , Kamarudzaman Zayful Hasrin , Hashim Saharul , Shahabuddin Syukri 
Published: March 2021

Abstract
A multizone cased hole completion with a bottom hole assembly of world-record length at 2,600 ft was installed in Malaysia in November 2019 where three zones were simultaneously gravel packed in a single trip utilizing shunt tube technology. This sand control completion was successfully executed with a combination of sand control pumping and sand control tools, unconventionally performed by two different service providers.
The well consisted of three zones of interest approximately 1,000 ft apart. The bottomhole assembly was designed with two shunted cup packers for zonal isolation and shunted 12-gauge wire wrapped screens across each perforation. The shunts were left open ended below the cup packers, allowing the carrier fluid to exit the zone below with minimal friction. Downhole memory gauges were deployed along the washpipes for post job evaluation. Diligent lab testing was performed to select the carrier fluid, a clarified high-grade xanthan polymer with good 20/40 proppant suspension with less formation damage and acceptable dehydration to avoid bridging inside the shunts.
Detailed risk assessment that was performed during the planning stage focusing on interfaces, equipment limitations, expediting, and decision flow charts between the two service providers led to flawless execution at the wellsite. Compared with conventional stack-pack completion, significant time savings of approximately seven days was observed with this single-trip design; the concept of open-ended shunts below the cup packers replaced the majority of the shunted blank pipes with standard blank pipes, eliminating the time required to install jumper tubes. Good results were observed during the injectivity test in addition to the well already having losses of 20 bbl/h. Hence, no acidizing was required prior to the gravel-packing operation. Based on surface monitoring, there was clear indication of sequential packing from the top zone to the bottom-most zone via shunt tubes, followed by a final screenout. Findings were further verified after performing the downhole bottomhole gauge analysis using the retrieved data from the memory gauges. The well has been in production since December 2019.
Technology for Determining the Inflow from Near and Far Zones of Fractures During Hydraulic Fracturing by Chemical Tracers in a Production Well
Authors: Filev Maksim , Soldatov Vadim , Novikov Igor , Xu Jianhua , Ovchinnikov Kirill , Belova Anna , Drobot Albina 
Published: March 2021

Abstract
The tracer-based production logging technology can be used to obtain the well production data continuously for several years without the need for risky well interventions and expensive equipment. The paper examines the case of placing polymer-coated tracers dopped proppant in a horizontal well with ten multi-stage frac intervals and using two different tracers dopped proppant codes for two frac ports (the first and the last ones) to identify the performance of the far and near zones of a hydraulic fracture.
Upon the completion of the hydraulic fracturing operations, the collected reservoir fluid samples were studied in the laboratory. Chemical tracers contained in the samples were detected by flow cytofluorometry using custom-tailored machine learning-based software. The studies helped identify the productivity of each frac port, calculate the contribution of each port in percentage points, and also evaluate the productivity of the near and far hydraulic fracture zones in the first and the last intervals.
The analysis provided data on the exact content of oil and water in the production profile for each frac interval. The results of tracer-based logging in the well in question revealed that the interval productivity is changing in the course of several months of surveillance. The most productive ports and those showing increasing oil flow rate were identified during quantitative analysis.
The use of tracer dopped proppant with different codes within one multi-stage frac interval enabled detecting a peak release of chemical tracers from the far fracture zone in the initial periods of well operation followed by a consistent smoothing of the far and near zones’ production profiles. Laboratory analysis of reservoir fluid samples and hydraulic fracturing simulations proved the uniform distribution of proppant across the entire reservoir pay zone and laid the foundation for further research required to better understand the fracture geometry and reduce uncertainties in production optimization operations.
Novel Sample Pretreatment to Determine Iron Counts in Sour Glycol Streams by Spectrophotometer
Authors: Mahmoud Mohamed , Alsalman Ahmed , Almalki Hassan 
Published: March 2021

Abstract
Determination of Iron Content in Triethylene glycol (TEG) samples is a very important indicator in measuring the system corrosion rate in oil and gas facilities. This study employed the application of an alternative/easy and reliable test method, which involved the use of a spectrophotometer for quantification of Iron concentration in tri ethylene glycol samples, that are used in sour gas dehydration units, rather than the sophisticated technique of Inductively Coupled Plasma Optical Emission Spectroscopy, ICP-OES. The main challenge was how to eliminate/minimize the significant interference from the carryover condensate hydrocarbons, BTEX, H2S and amine additives, which cause either precipitation with spectrophotometer reagents or turbid samples. The sample pretreatment process included: 1 - Sample digestion with dilution to eliminate the dissolved acid gases and the dissolved BTEX from the sample in acidic medium; 2 - pH adjustment from 9 – 10.5 to eliminate the amine additives interference with spectrophotometer reagents and 3 – Application of standard addition technique with certified reference material for iron with dilution, to reach the spectrophotometer detection limit and give intense color with more UV absorbance. The method was validated against ICP-OES and the results variance were within 10% acceptance criteria.
IG@P, Our Single Online Technology Crowdsourcing Platform
Authors: Nik Abdul Aziz Fadhlan , Abdul Hamid Khairul Azni , Matlasa Mazlina , Hasan Muhammad Hasif , Supparamaniam Deenitha Ambigai , Omar Marliana , Omar Intan Salwa 
Published: March 2021

Abstract
This year has been a year of unprecedented and mounting challenges. While many had to dig deep and find ways to ride a tough economic climate, Innovation Gateway@PETRONAS (iG@P) found itself flourishing with many technology companies submitting their technology solutions to be evaluated, endorsed and included in iG@P Technology Catalog. At the end of 2019, there were 387 submissions. The number more than doubled to 824 at the end of 2020.
iG@P is created to facilitate collaboration in the areas of technology and innovation for adoption and application, as well as accelerating pace in the deployment and replication of technology in PETRONAS. This paper discusses on the business pain points that iG@P has addressed and its corresponding technology value creation in cost savings, cost avoidance and cash generation.
Automated Selection of Completion Interval Workflow Using Python Script for Probabilistic Range of EUR in a Greenfield Development
Authors: Chong Emeline , Ong Derric Shen 
Published: March 2021

Abstract
In the greenfield development process, one of the key questions that needs to be answered is, "What is the range of EUR for a particular development concept and the associated completion method based on the existing range of subsurface uncertainties?" The key challenge then is how can the team forecast a representative range of EUR efficiently to obtain a range of results that represent a probabilistic outcome.
During the reservoir modelling process of this case study, a total of 405 static realizations had been run and then a STOIIP S-curve was generated. In the next step, 20 cases each of "High, Mid and Low" static models were selected based on the S-curve distribution for the next phase of dynamic simulation due to time and resources constraint. In terms of completion, the same development concept and completion method is assumed, where each dynamic case requires 8 horizontal producing wells with 200 metres of completion interval. Wells placement aside, each of the 60 dynamic models should not have the same fixed perforation depths and intervals due to the geological uncertainties with regards to facies distribution and they need to be selected based on the well effective k-h and hydrocarbon saturation along each well trajectory. Manual work could be used to analyse the best intervals for each of the planned wells, or in this case, this laborious process was replaced with an automated selection of the optimum completion interval workflow using Python script.
This paper will show the workflow of how a scripted Python code is designed to provide an "automated moving window" to find the best intervals along a well trajectory. This workflow was executed in the pre-processor of the dynamic simulator which has a workflow window with Python-embedded capability. The Python code then generated the simulation keyword COMPDATMD, which contained the best perforation intervals for all the wells as an output. This automated workflow resulted in an optimization of the completion intervals in all the 60 dynamic model cases, while the ultimate recovery for this greenfield development in Peninsula Malaysia increased by 30% compared to EUR from previously "unoptimized runs". This approach is managed to cut down the run preparation time by at least two weeks compared to the manual solution. The improved range of EUR is also considered as a more representative outcome of the field development evaluation.
Utilizing emerging technology breakthrough such as ability to customize specific features via a programming language is important towards a successful era of the Fourth Industrial Revolution (4IR). The results of this automated and customized workflow automation demonstrate a successful application of using machine learning for enhanced problem-solving in reservoir simulation.
Deepwater Subsea BOP Technological and Reliability Advancement
Authors: Picha Mahesh S. , Abdullah Ts. Malik , Rai Ashutosh , Sinha Sanjay , Patil Parimal A. 
Published: March 2021

Abstract
Subsea blowout preventer (SBOP) reliability is a major challenge in Deepwater Drilling & Completion operations, accounting for one of the major equipment failures and Non-Productive Time (NPT) costs yearly. This paper focuses on SBOP technological advancement since the Deepwater Horizon/Macondo incident in 2010, with additional emphasis on reliability, equipment condition monitoring and statistical root cause analysis. After finishing a deepwater well, the SBOP must undergo maintenance, repair if needed and pressure testing before being deployed on the next well. The rig owner is under great pressure to complete this turn-around to avoid waiting time. On an average, in-between wells, rig contractor took approximately 2.6 days extra time (NPT) waiting after completing top hole to get ready to deploy SBOP during 2019-20 exploration and appraisal campaigns. This can be critical during development campaigns where number of rig moves are involved quickly or in cases where top holes are batch drilled the waiting time for SBOP readiness can be as high as 7-8 days per well.
Some operators are collaborating with drilling contractors in number of ways to arrange for a second fully assembled and (offline) pressure tested SBOP to be available on the rig (Dual SBOP); deployment of additional trained subsea engineers for performing maintenance/repair. SBOP pressure-testing time can also be drastically reduced by using comparative pressure-testing software to eliminate human error and accelerate pressure testing. Furthermore, leak detection time can be eliminated by installing sensors, and real-time test monitoring providing increased reliability with the additional advantages that conditional monitoring can be enhanced with the same digital sensors. SBOP dashboard that simplifies existing diagnosis and allow remote monitoring of the subsea SBOP control system will improve communication of SBOP health also serve common platform across rig fleets that allow standardization of SBOP diagnostic data and aids in operational decision making
Ensuring additional SBOP redundancy especially while operating Emergency Disconnect System (EDS) available through Remotely Operated Vehicle (ROV) control panel or acoustic system. In addition, it is mandatory for the SBOP to have Autoshear and Deadman systems to be able to shut in the well in case of an emergency. Furthermore, technological workshop with several major service vendors have being held to ascertain current advances like Multifunctional profile, Accumulator recharged by ROV, ROV DP system, An Auxiliary Accumulator System and upgraded Acoustic System. In the end, the development of new technologies applied for the SBOP targets the overall cost optimization of the well lifecycle but also assure SBOP functionality. This paper is intended to provide considerations for operators in developing their future campaigns to frame scope of work for SBOP and rig contracting strategy.
Proxy Model for Real-Time Estimation of Cool Down Time of Subsea Production System to Prevent Hydrates Formation
Authors: Rizzo Cascio Joseph , Da Silva Antonio , Ghetti Martino , Corti Martino , Montini Marco 
Published: March 2021

Abstract

Objectives/Scope
The benefits of real-time estimation of the cool down time of Subsea Production System (SPS) to prevent formation of hydrates are shown on a real oil and gas facility. The innovative tool developed is based on an integrated approach, which embeds a proxy model of SPS and hydrate curves, exploiting real-time field data from the Eni Digital Oil Field (eDOF, an OSIsoft PI based application developed and managed by Eni) to continuously estimate the cool down time before hydrates are formed during the shutdown.

Methods, Procedures, Process
The Asset value optimization and the Asset integrity of hydrocarbon production systems are complex and multi-disciplinary tasks in the oil and gas industry, due to the high number of variables and their synergy. An accurate physical model of SPS is built and, then, used to develop a proxy model, which integrates hydrate curves at different MeOH concentration, being able to estimate in real time the cool down time of SPS during the shutdown exploiting data from subsea transmitters made available by eDOF in order to prevent formation of hydrates. The tool is also integrated with a user-friendly interface, making all relevant information readily available to the operators on field.

Results, Observations, Conclusions
The integrated approach provides a continues estimation of cool down time based on real time field data (eDOF) in order to prevent formation of hydrates and activate preservation actions. An accurate physical model of SPS is built on a real business case using Olga software and cool down curves simulated considering different operating shutdown scenarios. Hydrate curves of the considered production fluid are also simulated at different MeOH concentration using PVTsim NOVA software. Off-line simulated curves are then implemented as numerical tables combined with eDOF data by an Eni developed fast executing proxy model to produce estimated cool down time before hydrates are formed. A graphic representation of SPS behavior and its cool down time estimation during shutdown are displayed and ready to use by the operators on field in support of the operations, saving cost and time.

Novel/Additive Information
The benefits of real time estimation of the cool down time of SPS to prevent hydrates formation are shown in terms of saving of time and cost during the shutdown operations on a real case application. This integrated approach allows to rely on a continue, automatic and acceptably accurate estimate of the available time before hydrates are formed in SPS, including the possibility to be further developed for cases where subsea transmitters are not available or extended to other flow assurance issues.
Automation and Digitization Technologies Value Estimation Methodology – A Deepwater Well Construction Case
Authors: Telles Jose Daniel , Kandasamy Rajeswary , Gallo Covarrubias Rodrigo , Camacho Jacob , Costeno Hugo , Mejias Jose Efrain , Alvarez Francisco 
Published: March 2021

Abstract
This paper describes a methodology that can be used to estimate the potential value of implementing digital and automation technologies in the well construction process in the context of a complex deepwater environment during the drilling conceptualization phase. This serves as a guideline for those interested in quantifying the value of applying digitization and automation processes, not only to make informed decisions related to investment in drillship or systems hardware and software but as well as performance improvement.
Water Injection Operation Readiness of BB Field Redevelopment
Authors: Hadi Sriyanta , Hoodi M Junaida , Ting Sing Tat , Dana Setia , Atet Sabestiano Mike 
Published: March 2021

Abstract
BB field complex redevelopment is an integrated development under PETRONAS Enhanced Oil Recovery (EOR) project. BB fields are producing fields operated by PETRONAS Carigali Sendirian Berhad (PCSB). The BB fields redevelopment is a project to redevelop both B1 and B2 fields and to enable EOR implementation in the B1 field. The B1 redevelopment includes the EOR implementation through immiscible water alternating gas (IWAG), infill drilling, and safeguarding of no further activity (NFA) production. The B1 redevelopment also incorporates some provisions for the B2 field to secure gas supply for B1 IWAG. The B2 redevelopment focuses on safeguarding B2 NFA production. The redevelopment consists of three main elements, 1) EOR IWAG that involves injector well drilling at a new IWAG injection wellhead platform, 2) infill drilling at existing platforms and 3) safeguarding of NFA. Surface facilities scope includes installing a new Central Processing Platform (CPP) for B1 field, wellhead platforms, and intra-field pipelines. The CPP includes 60 kbpd water injection plant capacity, gas compression, gas-liquid separation, and produced water treatment. Modification in the B2 field is to flow gas from the B2 field to the B1 field. Operational readiness is crucial to ensure that the integrated project is executed smoothly. Two cases for changes are new technology deployment for water injection module (WIM) and people capability. It is a big challenge to achieve an effective start-up with minimum delay. There are some important aspects considered includes operation philosophy, Health Safety and Environment (HSE), and collaborative working environment (CWE) implementation. It is important to ensure improving oil recovery through infill and IWAG. Best practices in operation readiness of an integrated project that have many challenges that include process, people, and technology. These best practices may be replicated in any other projects by other companies/operators.
Remote Operations: The New Norm
Authors: Kakade Rachel Gajanan , Bagga Pawandeep Singh 
Published: March 2021

AbstractIn recent years, we have seen some refined drilling technologies crop up all over the world. These have given rise to implementation of remote centers to work on real time decision making with the wells. While drilling is in process, there are technologies that enable real time transmission of data and voice to and from remote sites, helping in real time intelligent commands and responses. It is hence now possible to form a single team of experts to monitor and control drilling operations.The development of remote operations in the oil and gas industry has evolved over years starting 2004 at different speeds in different regions of the world. For example, it took longer to reach the US land market because of resistance to change at the rig site. The decrease in oil prices in 2014 however, pushed remote operations into existence to reduce cost. Due to challenges such as either oilfield culture, company strategy, human factor, legal factor etc., it was not exactly the "norm". Fast forward to 2020 when the Covid-19 pandemic hit the oil industry into another slump, service companies have been pushed into the remote operations world. To learn with the times, this may be the new norm and maybe an excellent one.Many service companies have successfully performed operations wells globally increasing not only the efficiency of wellsite operations but also contributing to cost optimization and safety. During implementation, it is observed that remote operations are less a technical challenge, and more a value challenge requiring confidence from all stakeholders. In terms of drilling and operational efficiency, the results observed globally are significant, with fewer trips for M/LWD failure, as well as significant reductions in M/LWD NPT while drilling.This paper discusses the implementation of remote operations at global scale, lesson learnt on day-to-day basis, optimization opportunities, business workflow, positives such as business continuity, safety aspect and last but not the least, the environmental impact. The paper also talks of changes and effects of Covid-19 Pandemic on these operations. Remote operations prepare us well for such pandemic and it may be the safer way to operate now on. Also discussed are the keys to successful remote operations and various examples of remote operations establishments throughout the globe. Lastly a SWOT analysis is done to conclude how remote operations will help operators to add more value to operations and show that remote operations is the new future.