bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full Offline Well Cementing Implementation Resulting in Significant Time Savings and Improvement in Operational Efficiency
Authors: Lo Rex Lun Kai , Tiyor Sion Dan , Abdul Razak Aizal Haziq Bin , Abdul Razak Ahmad Hakam Bin 
Published: March 2022

Abstract
The current global low oil price environment has driven many operators to consider having a quicker and more efficient operations and reduction of the well construction cost. Recently in Field A which was located in offshore Sarawak, Malaysia, four monobore completion wells were successfully batch drilled and cemented offline through ingenious planning. This involves skidding of rig floor away from the well to allow access for the cementing operations to be performed underneath the rig floor simultaneously while drilling operations are allowed to resume above it. This paper will discuss about the offline activities performed, well barriers classification and the offline cementing techniques including the cementing design slurries employed from the top hole section until the final tubing section cementing.
Offline activities were able to be performed before and after the rig skidding package is moved from one slot to another, thus reducing the overall project time. These activities included but were not limited to offline cementing, wellhead installation and tubular rack back on the derrick. Once the conductor was cleaned to the shoe, casing was run and the rig will skid to the next conductor slot and offline cementing adapters were installed on the wellhead. As the rig continues with the drilling operations, cementing operations will be performed offline below the rig floor.
For the conductor section, 3 conduits were run and cemented simultaneously within a conductor offline. For the next section, the intermediate hole was drilled to its section TD, casing was run to bottom and cement head was installed offline after the rig skidded to next well. The next operation which included mud circulation and casing cementing was also performed offline. These same operational steps were repeated for all wells including the offline tubing cementing operations.
The cement slurries were designed as per well requirement which was a conventional Class-G cement slurry design for the conductor and the intermediate section. LCM material and sealing spacer were prepared onboard to mitigate any potential losses which could happen during drilling or cementing operations. For the tubing cementing section, self-healing cement system was introduced to ensure well integrity and zonal isolation is guaranteed for the life of the well.
All four wells were drilled and completed within 34 days, resulting in a time saving of 30 hours just for cementing operations; which was 23 % of cumulative time savings. This drilling and cementing approach will be a footprint to the operator for all future development wells.
A Floating Hub Solution for Offshore CO2 Injection and Sequestration
Authors: Lopez Audrey , Dechiron Cyrille , Favennec Morvan 
Published: March 2022

Abstract
This paper describes a new offshore CO2 sequestration concept: The Floating Hub Solution for Offshore CO2 Injection and Sequestration called in this paper Offshore C-Hub, proposes a flexible transport and storage solution for captured and liquefied carbon dioxide.
The Offshore C-Hub allows permanent CO2 sequestration in an offshore geological reservoir from multiple CO2 emitters via an offshore floating storage and injection facility.
The paper details key elements of the concept, tested in different case studies, and shares results on technical, economic and carbon footprint assessments.
Carbon Capture and Storage (CCS) is circa 10% of the total expected reduction for global Green House Gas (GHG) emissions in the next 30 years (IEA, 2018). Therefore, the contemplated unit will enable a significant CO2 injection capacity (several Million tons per annum) to provide an industrial scale solution.
The Offshore C-Hub concept is a novel floating facility allowing temporary storage and processing of CO2 prior to its continuous injection into a geological reservoir. It is part of a global CO2 management chain comprising the following steps:
Onshore CO2 capture, liquefaction, and temporary storage (or from offshore oil and gas production facilities) Liquid CO2 transportation by ships Offshore CO2 offloading to the Offshore C-Hub Offshore C-Hub injection process and storage Subsea systems to inject the CO2 in the geological reservoir
The generic studies demonstrate the Offshore C-Hub technical and economic feasibility considering a logistical approach and based on the main technological choices for some of the key components. The paper also assesses the technology maturity of the proposed system.
The carbon footprint assessment finally allows identification of alternate means to ensure a low carbon solution and reinforces the performance of the solution.
Until today, projects involving CO2 injection in geological reservoirs have been based on onshore or offshore pipelines.
This work describes a new floating solution for offshore CO2 continuous injection and sequestration.
The paper explains the key benefits of this solution, such as adaptability to project specifics (capacity, distances, etc.) and the ability to receive CO2 from multiple emitters in various locations.
The floating concept also provides strategic advantage by allowing rapid deployment and potential future relocation.
A Novel Engineering Approach in Drilling an ERD Well in a Carbonate Field, Malaysia
Authors: Abdul Hakim Hazlan , Mohamed Nooraini , Jusoh Kamri , Annuar M Nasrullah , Zahri Fakhrul Radzi , Ahmad Ani M Qayyum , Ibrahim Azrul Mizam 
Published: March 2022

Abstract
In order to extract the remaining reserves from a depleted carbonate field as well as to explore the possibility of finding additional reserves in a new fault block, PETRONAS is required to drill an Extended Reach Drilling (ERD) well from the existing platform in the FX field. The new target block is located approximately 4 km from the existing platform. This paper summarizes the planning challenges as well as the solutions in delivering the ERD well in a carbonate reservoir.
During the design phase, the team put a high emphasis in avoiding any complications while drilling an ERD well in a carbonate reservoir especially in managing severe or total losses. As such, the subsurface team came out with a novel approach in mapping the karst in the carbonate reservoir allowing optimum placement of the well trajectory. With the optimized target, the well was designed accordingly, addressing all the challenges that were raised during the detailed risk assessment such as hole cleaning issues, wellbore instability, Equivalent Circulating Density (ECD) management, Torque and Drag (T&D) during drilling as well as running casings/liner, cement integrity in high angle well etc. An ERD consultant was engaged to facilitate the design and execution phases.
The final well design and implementation plans were finalized with the ERD consultant's assistance which addressed all the anticipated challenges. An Advanced 1D Mechanical Earth Model (MEM) was constructed with the latest offset data to determine the proper mud weight window to drill the ERD well. The finalized Torque and Drag simulation provided the necessary strategies in completing the well including expected drilling parameters as well as delivering the casing and liner to bottom. Ensuring cement integrity while managing ECD by implementing new technology was also planned. The new technologies and specific approaches implemented to deliver the ERD well in a carbonate reservoir include detailed Seismic analysis to detect and predict the presence of karst in the carbonate, Pseudo Catenary well trajectory to optimize the well trajectory, 9-5/8" liner full air flotation to get the liner to bottom, Definitive Survey While Drilling to reduce vertical uncertainties as well as minimizing the stationary time and flow diverter to ensure cement integrity especially in the high angle / horizontal sections.
A Successful Case Study of a Collaborative Approach in Operational Optimization via Adoption of Automated Drilling Performance Measurement
Authors: Arif Normin Muhammad Afiq , Rosli Azlesham , Meor Hashim Meor M Hakeem , Arriffin M Faris , Ghazali Rohaizat 
Published: March 2022

Abstract
Digital transformation has always been one of the focuses of the oil & gas industry players in recent years. However, the pandemic and oil downturn last year has put the industry players in a digitization overdrive in the pursuit of leaner and cost-effective operations to stay ahead in these unprecedented times. This paper discusses the strategy, approach, and challenges in the adoption and implementation of the Automated Drilling Performance Measurement (ADPM) onsite and remote approach. This includes Wells Real-Time Center (WRTC), which utilizes the ADPM, an easy access analysis application for operational optimization. The implementation of ADPM falls under the PETRONAS Well Cost Compression focus area of Operational Optimization, which aims to achieve the operational technical limit and non-productive time (NPT) reduction. The stages of operational optimization via ADPM are broken down into pre-spud operations, operations, and post-well analysis. A historical performance study is conducted in pre-spud operations and case study sessions with the project team and Subject Matter Experts (SMEs). Once in operations, best practices for the focused key performance indicator (KPI) and ad-hoc gap analysis are implemented onsite throughout the well construction. Remotely, the KPIs are monitored by WRTC while rig contractors monitor the crew performance. The performance review is studied in post-well analysis, and the best practices are compiled for replication and lesson learned to improve future well's excellence. The evaluation of rig performance is conducted based on the focused KPIs criteria and Rig Scorecard criteria. Implementation of ADPM set clear and defined strategy from top management on digitalization and performance optimization. ADPM also helps foster performance optimization awareness and culture with clearly defined roles, responsibilities, and expectations. For example, the application deployment for the Field B drilling campaign focused on tripping, drilling and casing KPI improvement while utilizing ADPM for data gathering and analysis. The result of this deployment is commendable, with a total actual savings of 2.94 days gained throughout the campaign. From 2016 to 2021, PETRONAS has gained a total of 39.03 days of actual savings for their entire rig fleet.
Leveraging an Integrated Execution Model, Digital FEED Platform and Product Standardisation to Improve Project CAPEX
Authors: Fessy Antoine , Jothee Sivananthan , Jacquemin Sebastien , Sammon Jonathan , Cruz Carolina , Ferreira Igor , Bell Jill , Hosen Hariz Akmal , Askat Amirul Asraf 
Published: March 2022

Abstract
This paper illustrates how a typical subsea development (Subsea Production Systems (SPS) and Subsea Umbilicals Risers Flowlines (SURF)) can benefit from an integrated execution model which will significantly improve CAPEX, time to first oil and reduce delivery risk. The PETRONAS Limbayong Deepwater Development offshore Sabah, Malaysia is a successful example of close collaboration between a contractor and operator to leverage integrated contracting models and extended service scope, while maximizing Malaysian participation.
Digital platforms for Front End Engineering and Design (FEED) and Configure to Order (CTO) product designs were utilized in combination to assess and establish the optimal field architecture for improved cost and schedule. Adopting an integrated one-stop contract approach (SURF, SPS and Subsea Services) enabled an improved development schedule and reduction in cost and risk normally associated with split-contract interfaces. Digitalization of FEEDs and standardization of product configurations created value for the Limbayong field development, accelerating time to First Oil Date (FOD) as well as securing aggressive long-lead items delivery schedules.
The combination of the methods described above provides the required enhancement to a traditional execution approach, ill-suited to current oil and gas economics. This approach is instrumental in making many subsea developments feasible and a preface for accelerated future collaborations.
Challenges in Managing Surface Controlled Subsurface Safety Valve SCSSV Integrity Issue in Gas Field, Offshore Malaysia
Authors: Hasbi Nurul Ezween Binti , Barat Junnyaruin , Maluan Lilihani , Lidwin Sharon Ellen 
Published: March 2022

Abstract
Surface Controlled Subsurface Safety Valves (SCSSV) is a critical completion accessory to maintain the Safe Operation Envelope (SOE) of the well and ensuring the production sustainability. In PCSB, it is a requirement that SCSSVs are tested on specific periods to ensure this safety device meet the acceptance requirement as per company guideline.
Monitoring and maintaining the SCSSVs is proven to be challenging for E1 gas fields, located in Offshore Malaysia. Wells in E1 field, recently transferred operatorship, is an aging field producing since August 1982. The wells are equipped with Wireline Retrievable SCSSV (WRSCSSV). Within few months after operating this well, few cases of SCSSVs inoperability were encountered, resulted in significant gas production loss from E1. The main problems with SCSSV are:
Control line hydraulic pressure unable to build up and maintain, hence unable to flow the well as SCSSV unable to open. Abnormal hydraulic return observed. E11 wells tripped due to Wellhead Control Panel Hydraulic pressure header hit low-ow trip setpoint. Inoperable after well close in, indication of control line leak.
Immediate action taken to rectify include retrieving the WRSCSSV and installing redressed old WRSCSSV, injecting and displacing of Pressure Activated Sealant through control line to patch leak point. Root Cause Failure Analysis (RCFA) conducted on the wells identified preliminary factors that lead to E1 SCSSV issues:
Frequent SCSSV cycling with high control line pressure in depleted well pressure (Frequent well tripping and monthly Corrosion Inhibitor batching activity requires close in and opening of SCSSV). Non-compatible SCSSV elastomeric parts with production & CI batching chemical. Wear & tear and corrosion due to valve age (manufactured in 1982 & 1985). Worn out seal bore of BP-6 landing nipple.
Short term solution such as reviewing the recommended hydraulic line opening pressure, downhole visual inspection, pressure activated sealant and caliper survey to confirm BP-6 Landing Nipple seal bore damage, Swellable Packer/O-ring (External) and re-dress using non-upgraded Elastomers (Internal) had been planned. Contingency for subsurface controlled SSV and replacement using new WRSCSSV had been put in place as long-term solution. This paper describes operator experience in managing the challenges in maintaining SCSSV operability, diagnostic and solution recommended to avoid production deferment due to this issue.
Digital Pipeline Network, Feasibility of Data Acquisition at Offshore Brownfield
Authors: Hussien Hayati , Zakaria Nor Salwanie , A Rahman Ahiruddin , Supian Aishah Mastura , Abdullah Nur Asiah Maryam , Juzilman Raizil Aisyaizni 
Published: March 2022

Abstract
Recently digital pipeline system has been introduced, advocating the advantages on the simplification of pipeline monitoring, elimination of inspection activities as well as the accessibility of information especially on the wellness of the pipeline(s). For successful implementation of digital pipeline system, availability of Internet of things (IoT); which is the network of physical objects "things" that are embedded with sensors, software, and other technologies for the purpose of connecting and exchanging data with other devices and systems over the Internet, is a must. The problems is IoT is rare or even non-existence for pipelines that have been there before 2005. Despite there are many oil and gas operators who have well advanced in control and monitoring their offshore facilities, they mostly monitor the only pressures and shutdown system. Other than that existing equipment in offshore facilities are often analogue and disconnected. A study on data retrieval feasibility to provide information to develop digital pipeline network for brown field facility arrived with very costly equipment installation. This is due the absent off communication system (DCS) and online measuring equipment (such as flow meter, pressure gauge and temperature sensor) at the required location of many offshore facility.
This paper will discuss the feasibility and urgency of implementing of Digital Pipeline Network in offshore facilities most importantly at the existing and aging facilities. It will put across the importance of data retrieval, the required additional equipment and the facility for communication system as well as the assessment of installation hurdles at the aging facilities and the consequential cost requirement.
Comprehensive data retrieval at brown field facilities can be achieved through rationalization between automated digital data online reading by installation of wireless IoT system (for equipment to measure pressure, flowrate and temperature) complimented with the existing communication system, manual data retrieval by site visit and network software analysis in order to reduce the material and installation cost while keeping the objectives intact. Pipeline OPEX will be subsequently reduced once AI based technology such as predictive and prescriptive assessment for effective pipeline monitoring and integrity management can be implemented and hence inspection and maintenance program for pipeline(s) can be optimized.
Expanding Acceptance of Normally Unattended Facilities NUF – A Collaborative effort within IOGP
Authors: Mengan Mohd Rizal , Aziz Saiful Azuan Abdul , Anuar Nadirah Khairul , Veroba Grant , Munoz Jean-Michel 
Published: March 2022

Abstract
A group of International Oil and Gas Producer (IOGP) members have established the Normally Unattended Facilities (NUF) Task Force aimed to position NUF as safe, cost-effective, widely accepted design and operating method for oil & gas facilities. The establishment of the Task Force was driven by the need to standardize, expand the NUF concept to all type of facilities and ensure industry wide acceptance of NUF standardization. To meet these objectives, the Task Force has produced a white paper to outline the design principles, anticipated challenges and enablers to allow for the implementation of a standard NUF design.
NUF will enable oil and gas facilities to be remotely operated in a safe and reliable manner with no crew visitation for determined periods of time. However, this requires a change in the approach to designing, constructing, operating, and maintaining the facility. The NUF Task Force focused on cost compression, unattended duration and sustainability through reduced carbon emissions as key objectives in NUF design optimization. The proposed NUF design will reduce carbon emissions through high reliability, low emission equipment selection and reduction of marine vessels utilization. Technology advancement will allow for lean design, remote control and analysis to efficiently and effectively plan maintenance and optimize operations. Brownfield quick wins will provide avenue for technology maturity, drive for higher reliability and improving overall asset performance. These help in shifting the mindset of personnel involved. Change management is required for governance & procedural changes whilst human retooling will be required for the new skillsets.
The main value drivers that support NUF implementation include but, are not limited to, the anticipated reduction in HSE risk exposure to personnel, a substantial reduction in CAPEX and OPEX, and lower greenhouse gases, with reliability better than or equal to attended facilities. Some standards and regulations may need to be revised to enable NUF application. At present, this is being investigated by IOGP under JIP39.
NUF concepts can be applied to any facility (onshore and offshore) and will be greatly facilitated by some level of standardization. This would create economies of scale for both the qualification and fabrication of equipment and sub-systems.
Substantial potential value drivers supporting the move to a standard NUF approach:
HSE Risk reduction due to elimination of personnel during normal operations Potential 20-30% CAPEX reduction in facility cost Potential 20-30% OPEX reduction in operating and logistics expenses Reliability better than or equal to attended facilities Green House Gases (GHG) footprint improvement
Increasing the Accuracy of Production Allocation from Each Reservoir: Integrating TAML-1 Well Construction Technology and the Dynamic Quantum PLT Method in the Field NP
Authors: Alekseev Alexander , Samigullin Linar , Zimoglyad Mikhail , Nagovitsyn Vladimir , Bolshakov Viacheslav , Bydzan Andrei , Upadhye Vishwajit , Vasechkin Dmitriy 
Published: March 2022

Abstract
One of the largest oil fields on the Yamal Peninsula, the Field NP is characterised by complex geological settings. Massive gas caps pose significant complications to the extraction of large oil reserves occurring immediately below them. In such conditions, new approaches are required to achieve economically viable production. This involves well construction based on a fundamentally new configuration and the use of new technologies.
When drilling wells that penetrate more than one target reservoir, the legislation requires performance monitoring and separate production allocation for each reservoir.
The article dwells on the first case of separate production allocation in a multilateral well completed with the TAML-1 solution. The well penetrates two reservoirs with different porosity and permeability, using the dynamic quantum PLT technology. The well was drilled taking into account the properties of the impermeable top of one of the reservoirs.
Engineering the New Normal: Optimizing Execution Cost for Low Well Count Subsea Projects and Tiebacks
Authors: Organ Mark Edwin 
Published: March 2022

Abstract
Smaller reduced well count projects and tiebacks with shorter lead times: As operators look to control their capital expenditure and optimize their existing assets, these are the key themes which will make up a higher proportion of future subsea production system (SPS) projects.
As part of its project execution framework, Project Connect, Baker Hughes has been seeking to optimize the way it can work cross-functionally and collaboratively with internal and external project stakeholders, to mitigate project risk and increase execution certainty. Through review of lessons learned and after-actions reviews from recent project execution, this paper presents BakerHughes’ key findings and associated conclusions for the optimization of engineering execution of low well count and tieback projects.
The findings may be grouped into the following categories: Building the right team.Strategic planning.Improved commercial awareness.Optimized engineering processes.
The three major conclusions which linked each of these focus areas are as follows: Early-engagement is key.There is no "one-size-fits-all" approach.Recommended practices for execution of smaller projects are readily scaled to projects of any size.