bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Solutions for the Redevelopment Plan of Offshore Mature-Oilfield
Authors: Shi Hongfu , Liu Yingxian , Jiang Lifu , Zheng Jingding , Gan Liqin
Published: March 2021

Abundant faults, long oil-bearing intervals (up to 500m), and diverse fluids including conventional oil and heavy oil, result in P oilfield became one of the most complex oil fields in the Bohai Bay. The main characters ofinitial development plan are directional well with commingle production, open hole completion, large draw down, high oil production rate, and reverse nine-point well pattern. At present, the oilfield has entered a stage of high water cut, with average water cut more than 85%. What can we do next, decommissioning or rebirthing?

An integrated solution was proposed to redevelop the oilfield which focus on the layers’ subdivision, the fine description of the sand body,a large number of horizontal wells on the top of the water-flooded layer are used to tap the potential, increase the water injector to transform the stream lines and rebuild the reservoir pressure, and search for potential sand bodies to increase reserves.
A Breakthrough Approach to Solve Shallow Gas Hazards in Corrosive Carbon Dioxide Wells
Authors: Li Yi , Mohammad Solim Ullah , Ai Wu chang , Kumar Avinash Kishore , Hen Lau Chee , Hun Ong Sheau , Qiu Guo liang , Duan Zhi wei , Mahaiyudin Ahmad Rizal , Wang Zhen , Luo Yu wei , Xiang Xian zhong , Yu Bin , Chua Keting , zhang Hao , Ma Chun Xu , Fang Guo wei
Published: March 2021

In offshore Malaysia field, several development wells were drilled and cemented in 2019. The presence of shallow gas zone directly below the surface casing shoe posed a significant challenge to isolate shallow gas flow. A High presence of carbon dioxide (CO2) also increased the complexity of the cementing jobs by potentially corroding the set cement sheath. Wells with sustained casing pressure due to poor cementing jobs would causelosses to hydrocarbon reserves, while polluting aquifers with hydrocarbon and well security issues. It was crucial to prevent remedial cementing work, due to unnecessary and costly non-productive time. The objective of primary cementing is to achieve long term zonal isolation across the gas reservoir. A bespoke engineered cementing solution was successfully developed in order to provide a solution to assure long term zonal isolation for shallow gas flow. This paper will describe in detail about the cementing method, how it fits the well situation, the methodology in the slurry design, and thevalidation process in the lab with a novel, uncommon method in the industry, capped off by the post-cementing results analysis. This technology was proven as a solution for shallow gas well cementing and long-term zonal isolation, which is a great referencefor the cementing industry.
An Empirical Analysis of Artificial Intelligence, Big Data and Analytics Applications in Exploration and Production Operations
Authors: Agbaji Armstrong Lee
Published: March 2021

Oil and Gas operations are now being "datafied." Datafication in the oil industry refers to systematically extracting data from the various oilfield activities that are naturally occurring. Successful digital transformation hinges critically on an organization's ability to extract value from data. Extracting and analyzing data is getting harder as the volume, variety, and velocity of data continues to increase. Analytics can help us make better decisions, only if we can trust the integrity of the data going into the system. As digital technology continues to play a pivotal role in the oil industry, the role of reliable data and analytics has never been more consequential.

This paper is an empirical analysis of how Artificial Intelligence (AI), big data and analytics has redefined oil and gas operations. It takes a deep dive into various AI and analytics technologies reshaping the industry, specifically as it relates to exploration and production operations, as well as other sectors of the industry. Several illustrative examples of transformative technologies reshaping the oil and gas value chain along with their innovative applications in real-time decision making are highlighted. It also describes the significant challenges that AI presents in the oil industry including algorithmic bias, cybersecurity, and trust. With digital transformation poised to re-invent the oil & gas industry, the paper also discusses energy transition, and makes some bold predictions about the oil industry of the future and the role of AI in that future.

Big data lays the foundation for the broad adoption and application of artificial intelligence. Analytics and AI are going to be very powerful tools for making predictions with a precision that was previously impossible. Analysis of some of the AI and analytics tools studied shows that there is a huge gap between the people who use the data and the metadata. AI is as good as the ecosystem that supports it. Trusting AI and feeling confident with its decisions starts with trustworthy data. The data needs to be clean, accurate, devoid of bias, and protected. As the relationship between man and machine continues to evolve, and organizations continue to rely on data analytics to provide decision support services, it is imperative that we safeguard against making important technical and management decisions based on invalid or biased data and algorithm. The variegated outcomes observed from some of the AI and analytics tools studied in this research shows that, when it comes to adopting AI and analytics, the worm remains buried in the apple.
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

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

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

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

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

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

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

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

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

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

In 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.
Accelerating Value Through Company Wide Digital Field Implementation: A Success Story
Authors: Abu Bakar Afdzal Hizamal , Jamaluddin Muhamad Nasri , Musa Rizwan , Fuenmayor Roberto , Trivedi Rajesh , Mokhlis Mohamad Mustaqim , Hassan Muhammad Firdaus , Mohamad Azili Ammar , Harith Mikhail , Basarudin Mohd Ashraf , Bernard Gerald , Soriano Jerome
Published: March 2021

PETRONAS Upstream is cognizant of the need to provide a unified digital production platform to the entire upstream community. The digital platform enables the community to perform analytical, collaborative monitoring & surveillance, and optimization to sustain production and improve our operations.

Digital Fields (DF) is a modern digital platform, integrating data and analytical services, that provides smarter insights and shed light on potential insights that contribute to better-informed decision-making and improves the way of working.

A big data ecosystem and strong infrastructure is the foundation of this digital platform, allied to existing business processes, it allows frictionless secure flow of data, high performance, scalability to support business operations.

Digital Fields platform provides the following features:

Scalable to all PETRONAS fields operated in Malaysia as well as International assets Solution architecture that allows fast implementation of new solutions and insights A common company-wide platform with the same familiar user interface and user experience

The critical aspect to liven up a digital production platform is to identify first the available data sources. Some fields have the luxury of transmitters and sensors installed at the well head, topside facilities and export pipelines where the data can be easily retrieved from the SCADA system for data acquisition. Some other fields with less real-time data luxury would keep their operational data inside some operational reporting documents.

A smart report ingestion solution was developed with the means to transform unstructured data from the operational reports, which empowers the users with multiple options for data upload and consumption while ensuring a single, traceable and auditable source of truth.

Digital Fields leverages the combination of Daily Operation Reports (DOR), data with different frequency, such as real-time data, with engineering models changing the way the users consume data and provides proactive actionable insights to accelerate tangible values for the business organization.

The solution establishes the foundational digital capabilities for field operations and speeds up data-driven value opportunities from operational data and analytics at scale.
Implementation of TAML Level#4 Multilateral with Gravel Packed Lateral Leg to Solve Field Production Challenges
Authors: Li Jin , Wang Kunjian , Chen HaiNing , Ruescher Nigel , Pang Ruicheng , Liu Pengfei
Published: March 2021

An offshore oil field in China was experiencing production challenges due to high water cut and low overall production. In order to boost production and address these challenges, adjacent reservoirs would need to be accessed and developed. Application of multilateral completion technology was considered the best method to achieve this, saving platform slots, increasing reservoir contact and keeling development cost low. An integrated solution was provided that allowed Technology Advancement Multilateral (TAML) Level#4 Multilateral Junctions with Gravel Packed Lateral sections, the first application of this type in China. The existing mainbore was temporarily isolated. Casing Exit was conducted at designated setting, and Hook Hanger TAML Level#4 Multilateral junction system was successfully installed and cemented. The horizontal Lateral bore was subsequently entered and gravel pack operations were successfully performed. Hydraulic integrity along well string is key to successful horizontal open hole gravel pack(OHGP). This TAML level#4 Multilateral completion design provided hydraulic integrity at junction during the whole OHGP process, the key to successful gravel pack. The mainbore can be restored as required. This paper concentrates on the technology utilized to successfully complete these wells. Multilateral and Gravel Pack equipment, challenges and solutions that were deployed to make this project a success are outlined.

Three old wells in the field have applied this technology and have successfully improved production by 200m3/d. The wells give ability to selectively produce or comingle, allowing more flexibility with production. The introduction of Gravel Pack into the lateral affords greater sand control capabilities and ultimately assists overall production in well life. This application is now field proven with demonstrated production benefits and has potential for implementation in more developments in the region in future.
Accelerating Digital Transformation in E&P Business
Authors: Karim Anak
Published: March 2021

As a resourced based economy, Malaysia relies heavily on the energy oil, and gas industry - a critical sector contributing to the economic growth of the Malaysian economy; which makes up in the range of 20% - 25% of the total gross domestic product (GDP) of Malaysia as of 2017. No analysts can properly predict prices of the future, with the highs and lows of crude and natural gas and renewables as the fuel of the future and are perhaps new way of things. This "new normal" in which countries, including Malaysia, must learn to adapt in a more agile manner to the "new way of work" of increased productivity and efficiency (de Graauw, McCreery, & Murphy, 2015). In adapting to the new normal, measures of increased productivity must continue to be pushed forward and implemented. Energy companies and services provider still need to continue with exploration and development (E&P) operations and activities to meet long term strategic objectives and demands of the nation, in line with the aspirations of the national oil company, however, it needs to add more value to every dollar spent as margins have continued to shrink and reduce profit margins of energy producers. This is where Digital Transformation comes into play and the urgency for implementation has gone from novelty solutions to critical business survival.

Changing industry trends such as Industrial Revolution 4.0 have made it more prevalent than ever to make better use of capital at a time when productivity is essential. At the same time, the industry needs to continue to explore and develop to meet long-term demands, which continues to grow albeit slower than before.
Produced Water Debottlenecking Delivers Low Cost Incremental Production for the Pyrenees FPSO
Authors: Elliott Paul , Gilbert Melissa
Published: March 2021

The Pyrenees FPSO development, located offshore Western Australia, produced first oil in 2010. By 2017, the topsides facility had became constrained by produced water production, reaching the facility design capacity of 110,000 bbl/d. A strong business driver was presented to debottleneck the water processing train to increase oil production, for which a holistic, system-wide approach was required.

A series of brownfield debottlenecking scopes were identified and assessed using a systematic value versus risk approach. The key value drivers were recognised as incremental oil production, execution timing and cost. The assessment focused on improving Produced Water Re-Injection (PWRI) pump throughput and uptime, optimising the produced water treatment and overboard discharge systems, and the use of cargo oil tanks for separation. Project execution was phased to allow early debottlenecking gains to be unlocked as major modification scopes were progressed. The most capital intensive project executed was the installation of a side-stream Compact Flotation Unit package to polish and discharge produced water overboard. In combination, the projects delivered a 36% increase in produced water handling capacity to 150,000 bbl/d, accelerating 8.5% production over a 3-year period. In addition, the projects increased facility uptime by 1.8% and reduced the risk of late-life produced water injection system failures.

This case study illustrates a logical and systematic approach to production debottlenecking, resulting in a significant production uplift, safely delivered for low relative CAPEX investment. The processes described and lessons learned in this project may be applicable to other maturing fields and facilities, and can be used to assist resolving late-life produced water challenges.
Rationalising PSC Fiscal System Principles for Sustainable Future
Authors: Mohamed Ibrahim , Mohd Yunus Muhammad Iqbal
Published: March 2021

PSC fiscal system serves as a framework to determine the sharing of petroleum revenues between stakeholders. Understanding its behavior is essential, given the nature and duration of upstream projects. The paper rationalizes fiscal systems that can promote a balanced, progressive, and robust revenue-sharing mechanism. The impact and efficiency of three typical fiscal regimes are assessed by observing how they react to different scenarios and outcomes, which could be either better or worse than the initial expectation.

The three typical fiscal regimes are fixed-rate, production sliding scale sharing, and profitability-based sharing. The early days’ fixed rate sharing system is rigid and does not effectively address the different scales of upstream project investments and the associated uncertainties. The production sliding scale sharing is a partially progressive system that addresses production level variation but does not respond to the variation of other value drivers such as actual cost, price volatility, and project schedule. The profitability based fiscal term represents a progressive win-win system that is more robust, self-regulating, and balances stakeholders’ value objectives. Profitability-based sharing also promotes subsequent field developments. New investment lowers the profitability ratio, which in turn increases contractor profit share percentage. This mechanism results in higher incremental value to the contractor when developing the next field. Compared to the fixed-rate and production sliding scale based sharing, the profitability based sharing could provide a fiscal balance system that is self-regulating, progressive, and more robust. It fits nicely with the oil and gas industry known for the inherent risks and wide range of uncertainties throughout the life of the project.

The profitability-based system could be further enhanced to encapsulate the multiple claw-back provisions by switching from the traditional stair-step sharing to a steeper linear sharing with the appropriate ceiling, floor, and triggering points. The linear representation of profitability-based sharing could also complement the various available PSC management control provisions to mitigate the potential cases of opportunistic gold-plating. The sensitive feature of linear sharing could help deter such manipulation. (334)
Design, Testing and Field Deployment of an Online Sand Sampling and Particle Size Analysis Package
Authors: Ambrose Jonathan , Mackie Alex , Lee John Yung , Bibic Ovidiu Cristian , A. Rahim M. Shamir , Nik Khansani Nik Zarina , Hassan M. Hafiidz
Published: March 2021

Particle Size Analysis (PSA) of formation or produced sand is an important process in oil and gas exploration and production. This information is required to design downhole sand control, surface sand monitoring and removal systems, and to predict erosion in completion and production systems. A major operator in Malaysia required PSA data as well but found it a challenge as their wells, located offshore in Field Z, contain high amounts of contaminants such as TENORM, Mercury and Hydrogen Sulphide (H2S).

Manually collecting produced sand samples was deemed too hazardous to people and the asset thus a closed loop Online Sand Sampling and PSA package was developed and deployed offshore. Samples were taken directly off flowline sample points, flowed through an online PSA system and continued its flow path to a closed loop drain line. The system therefore collected liquid, gas, and sand samples without any need for manual handling thereby eliminating exposure of harmful substances to personnel.

A field laptop, running propriety software, connected via ethernet cable to the PSA system continuously measure and record the size of sand particles as they flow through the said system. This allowed the offshore execution team to view and record particle size data in real time. Data collated was available for further analysis onshore because the file format of the PSA software allows play back to refine particle images captured during the sampling operation.

This was completed for 32 wells with the majority of the sampling providing good clear particle size information. Results were re-run and analysed again onshore by a sand management technical team from both the operator and service provider. The results were comparable to lab analysed samples of commonly used Laser Particle Size Analysis (LPSA). Therefore this first of its kind method provides a novel way for operaters to sample sand and solids in hazardous and also non hazardous environments.
On consistency of quantum theory and macroscopic objectivity
Authors: Lanz L. , Vacchini B. , Melsheimer O.
Published: March 2021

We argue that the consistency problem between quantum theory and macroscopic objectivity must be placed inside a quantum description of macroscopic non-equilibrium systems. Resorting to thermodynamic concepts inside quantum field theory seems to be necessary.
Equiangular spherical codes in quantum cryptography
Authors: Renes J M
Published: March 2021

Quantum key distribution protocols based on equiangular spherical codes are introduced and their behavior under the intercept/resend attack investigated. Such protocols offer a greater range of secure noise tolerance and speed options than protocols based on their cousins, the mutually-unbiased bases, while also enabling the determination of the channel noise rate without the need to sacrifice key bits. For fixed number of signal states in a given dimension, the spherical code protocols offer Alice and Bob more noise tolerance at the price of slower key generation rates.
On “Principles of Quantum Computation and Information Volume 1: Basic Concepts”
Authors: Bacon D.
Published: March 2021

Book Review
Correcting quantum channels by measuring the environment
Authors: Hayden P. , King C.
Published: March 2021

We propose an entanglement tensor to quantitatively compute the entanglement of a general pure multipartite quantum state. We compare the ensuing tensor with the concurrence for bipartite state and apply the tensor measure to some interesting examples of entangled three-qubit and four-qubit states. It is shown that in defining the degree of entanglement of a multi-partite state, one needs to make assumptions about the willingness of the parties to cooperate. For such states our tensor becomes a measure of generalized entanglement of assistance. We also discuss the degree of entanglement and the concurrence of assistance of two generic multi-qubit states.
Cryptanalysis of a Practical Quantum Key Distribution with Polarization-Entangled Photons
Authors: Beth Th. , Muller-Quade J. , Steinwandt R.
Published: March 2021

Recently, a quantum key exchange protocol has been described\cite{PFLM04}, which served as basis for securing an actual bank transaction by means of quantum cryptography \cite{ZVS04}. The authentication scheme used to this aim has been proposed by Peev et al. \cite{PML04}. Here we show, that this authentication is insecure in the sense that an attacker can provoke a situation where initiator and responder of a key exchange end up with different keys. Moreover, it may happen that an attacker can decrypt a part of the plaintext protected with the derived encryption key.
Communicating continuous quantum variables between different Lorentz frames
Authors: Kok P. , Ralph T.C. , Milburn G.J.
Published: March 2021

We show how to communicate Heisenberg-limited continuous (quantum) variables between Alice and Bob in the case where they occupy two inertial reference frames that differ by an unknown Lorentz boost. There are two effects that need to be overcome: the Doppler shift and the absence of synchronized clocks. Furthermore, we show how Alice and Bob can share Doppler-invariant entanglement, and we demonstrate that the protocol is robust under photon loss.
Deterministic Local Conversion of Incomparable States by Collective LOCC
Authors: Chattopadhyay I. , Sarkar D.
Published: March 2021

Incomparability of pure bipartite entangled states under deterministic LOCC is a very strange phenomena. We find two possible ways of getting our desired pure entangled state which is incomparable with the given input state, by collective LOCC with certainty. The first one is by providing some pure entanglement through the lower dimensional maximally-entangled states or using further less amount of entanglement and the next one is by collective operation on two pairs which are individually incomparable. It is quite surprising that we are able to achieve maximally entangled states of any Schmidt rank from a finite number of 2x2 pure entangled states only by deterministic LOCC. We provide general theory for the case of 3x3 system of incomparable states by the above processes where incomparability seems to be the most hardest one.
Steric vs Electronic Effects: A New Look into Stability of Diastereomers, Conformers and Constitutional Isomers
Authors: Datta Sopanant , Limpanuparb Taweetham
Published: March 2021

A quantum chemical investigation of the stability of compounds with identical formulas was carried out on 23 classes of halogenated compounds made of H, F, Cl, Br, I, C, N, P, O and S atoms. All possible structures were generated by combinatorial approach and studied by statistical methods. The prevalence of formula in which its Z configuration, gauche conformation and meta isomer are the most stable forms is calculated and discussed. Quantitative and qualitative models to explain the stability of the 23 classes of halogenated compounds were also proposed.
Assessing the Accuracy of the SCAN Functional for Water Through a Many-Body Analysis of the Adiabatic Connection Formula
Authors: Lambros Eleftherios , Hu Jie , Paesani Francesco , Lab Paesani
Published: March 2021

We present a systematic analysis of the accuracy of a series of SCANα functionals for water, with varying fractions (α) of exact exchange, which are constructed through the adiabatic connection formula. Our results indicate that that all SCANα functionals exhibit substantial errors in the representation of the water 2-body energies. Importantly, the inclusion of exact exchange is found to have opposite effects on the ability of the SCANα functionals to describe the interaction energies of water clusters with 2-dimensional and 3-dimensional hydrogen-bonding arrangements. These errors are found to directly affect the ability of the SCANα functionals to describe the structure of liquid water at ambient conditions, which is investigated using explicit many-body models (MB-SCANα) derived from the corresponding SCANα data. In particular, it is found that all MB-SCANα models predict a more compact first hydration shell, which results in a denser liquid with a more ice-like structure. These ap- parent opposite trends can be explained by the inability of all SCANα functionals to provide a balanced description of the water 2B and 3B energies at the fundamental level. The analyses presented in this study provide new insights that can guide future developments of improved exchange-correlation functionals for water.