bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Aspects of Cost-Effective Solution for Global Lateral Buckling Mitigation with Residual Curvature Method for Subsea Pipelines
Authors: Mak Kok Wah , Ngai Tommy , Paul Eldho 
Published: November 2020

Abstract
Practical aspects and the application of lateral buckling mitigation for subsea pipelines with Residual Curvature Method (RCM) are discussed in this paper. The main purpose of this paper is to promote the RCM in the Asia Pacific region as a practical and a cost-effective alternative to the existing buckle initiation methods for subsea pipelines.
The RCM is assessed and compared with two existing buckle initiation methods (i.e. sleeper and zero-bend radius) using finite element analysis. The build-up of the effective axial force is the key driving mechanism in inducing a buckle in the pipeline. The effective axial force builds up along the pipeline with buckle length and the critical buckling force for buckle mitigation methods mentioned above are presented for comparison.
Some practical aspects and design considerations of the RCM are also discussed. The local residual curvature section, which so far has been applied with reel-lay vessels can be implemented with S-lay vessels as a buckle mitigation scheme. Discussion on a proposal to consider the use of RCM with S-lay vessel is also covered. Additionally, the advantages and disadvantages of RCM are compared with respect to the technical challenges, the construction cost and time, handling operations and installation.
This paper shall provide some good exposure to practising engineers and local/international operators in the Asia Pacific region with a relatively new and efficient method for lateral buckling mitigation and has, to date, been utilized for shallow water pipelines installed by reel-lay vessels.
Drilling Minimum Standard as Regulatory Benchmarking for Drilling Performance in Malaysia
Authors: M. Yunus M. Nasir , A. Tarmizi M. Farid 
Published: November 2020

Abstract
As part of Drilling cost optimization initiatives, Malaysia Petroleum Management (MPM) Drilling as the regulatory body of PETRONAS has been enforcing Drilling Minimum Standard (DMS) as Drilling performance benchmarking to Petroleum Arrangement Contractors (PACs). This paper explains the Key Performance Indicators (KPIs) & Well Complexity Categorization contained in the latest version of DMS.
DMS uses 3 main KPIs to benchmark PACs’ Drilling performance specifically Drilling Days per Thousand Foot (DDPTF), Drilling Cost per Foot (DCPF) and Well Cost per Foot (WCPF). Numerous versions of DMS were iterated from time to time to reflect on the ever-changing Drilling operations. Utilizing Online Drilling Benchmarking System (ODBS) developed by MPM Drilling as the data source and benchmarking tool, DMS has been updated with the inclusion of latest Daily Drilling Reports (DDRs) data over a span of 7 years covering more than 500 wells. KPIs figures for each category from previous DMS version were compared with latest actual Drilling KPIs figures prior to the revision.
The latest DMS version maintains the same well complexity categories of the previous DMS while introduces a new Sidetrack complexity category based on the number of hole sections. In conclusion, the newly updated DMS version introduces more pertinent KPI figures thus, reflect on MPM efforts to improve drilling performance from the costs and time perspectives. With the availability of reliable data in ODBS, MPM Drilling set a highly accurate DMS for performance improvement mindset within the PAC's throughout the Drilling industry in Malaysia context.
Pioneering Slickline Deployed Through Tubing Gravel Pack in Malaysia; Successful Case Study and Lessons Learnt
Authors: Mappanyompa Ertiawati , Trinh Ba Loi , Mazzlan Khairul Akmal , Aripin Izura , M Sulong Etiqah Siti , Nik Khansani Nik Zarina , Picou Robert , Salahudin Sharifudin 
Published: November 2020

Abstract
Formation sand production is a major concern in brown field operations, especially as the field depletes and water production commences. There are many methods to control sand production in primary well completion; however, it becomes more challenging in producers where no primary sand control is installed initially, and it starts producing sand later in the well life.
Selecting the right method for remediating these wells has become a hot topic with both Operators and Service Providers alike striving to discover effective and economical solutions for their brown-field operations. Currently, the solutions for through-tubing sand control in existing producers are screen hang-offs, through-tubing gravel packing1 (TTGP) and chemical sand consolidation.
Through-tubing sand screen (TTSS) hang-offs above the producing zone, is an inexpensive sand control method. Unfortunately, these installations are typically short lived, often requiring regular well interventions due to screen plugging or erosion, or sand clean-out operations to remove sand accumulated in the production tubing. Alternatively, TTGP is a robust method to control sand production; however, more equipment is required to deploy the gravel pack which subsequently increases costs significantly in offshore applications. To simplify TTGP and make it economical, a major Interventions Service Provider devised a methodology to install TTGPs utilizing Slickine that reduces the overall installation cost tremendously. The methodology has been proven a great success in the US Gulf of Mexico where over 1,200 applications have been installed.
The pilot implementation of slickline deployed through-tubing gravel pack (SL-TTGP) was executed in three S-Field wells in late 2018 which were shut-in due to higher than permissible sand production. These were challenging intervals in that they were uphole recompletions between cement packers in dual string 9-5/8" casing which had produced sand.
The results from the installation proved that the methodology provides effective sand control and enables reinstatement of production from these wells. Further, the installations were achieved with lesser resources and at lower costs; less than half that of a CTU deployed TTGP. This success has led to further installations in the following year.
This paper presents in detail the case study of the pilot implementation of SL-TTGP, key successes, as well as critical lessons learnt during execution and production phase. It includes the challenges, risks and their recommended mitigation plans, as well as the well performance comparison before and after the implementation both in terms of production and sand count.
The Occurrence, Saturation and Distribution of Gas Hydrate Identified from Three Dimensional Seismic Data in the Lw3 Area: The Northern Slope of the South China Sea
Authors: Yan Chengzhi , Shi Hesheng , Wang Xiujuan , Li Yuanping , Li Jie 
Published: November 2020

Abstract
Gas hydrates with high saturation in clayey silt sediments have been identified from several gas hydrate drilling expeditions in the South China Sea (SCS). However, the spatial distribution is not well delineated due to the limitation of two dimensional or pseudo-three dimensional seismic data. The three dimensional (3D) seismic data acquired by oil & gas exploration was reprocessed using high-density velocity analysis, which can be used to show the detailed mapping and characterization of high concentration gas hydrate in the LW3 area, SCS. The well log data and core samples have indicated that pore-filling gas hydrates have various saturations and thickness in the study area, but the spatial variations are still poorly defined. High-resolution broadband inversion without well constraint was conducted based on the high-resolution velocity analysis, which dramatically increased the accuracy in detecting thin gas hydrate-bearing layers. Rock physical models were involved to quantitatively predict gas hydrate saturation, which has been used to describe the gas hydrate-bearing layers with a thickness ranging from 5 to 6 m. Multi-attribute analysis extracted along the base of gas hydrate stability zone (BGHSZ) was used to predict the gas hydrate distribution. Gas hydrate distribution identified from the reprocessed high-resolution 3D seismic data indicate that gas hydrate-bearing layers are mainly located at four ridges of the migrating canyons in the Liwan 3 area. The thickness and saturation of gas hydrate distribution at the third and fourth ridges are better than the other two ridges. The gas hydrate saturation is over 40 % with a thickness exceeding to 70 m. Moreover, the thin gas hydrate layer is interbedded with thick layer at the forth ridge. However, the gas hydrate saturation is over 70 % with a thickness of 30 m at the third ridge. The gas hydrate distributions exhibit obvious heterogeneous at each canyon zone. The accuracy prediction and delineation of gas hydrate distribution are very important for assessing gas hydrate test production responses and scenarios.
Self-Installing Platform with Conductor Guide Support Frame System
Authors: Kuan EngYeow , Yee KienPeng , Tan Jaime HuiChoo 
Published: November 2020

Abstract
In a conventional shallow water field development with dry trees, fixed platforms are utilized to support the topsides processing facilities, dry-tree wellheads and well conductors. The fixed platform can be a fully integrated platform or a dedicated process platform and a wellhead platform. A new innovative integrated processing and wellhead platform concept by means of a suspended conductor guide support frame which is retractable, provides an alternative for the structural design of facilities for dry-tree field developments. This conductor guide support frame concept is developed for a Self-Installing Platform (SIP) such that it can support well conductors and dry trees, besides the processing facilities similar to a conventional fixed platform and does not require the mobilization of a heavy lift vessel for installation. Being self-installable, it can be easily deployed and redeployed at different sites and hence is suitable for marginal fields developments. A case study has been performed on this concept and the in-service structural stress and fatigue performance of the conductors have been verified based on design parameters for a typical development offshore Peninsular Malaysia. The range of suitable applications of this SIP with conductor guide support frame concept is presented.
Deepwater Flowlines and Risers Decommissioning
Authors: Jaafar Azam Syah , Obaidellah Ahmad Taqiyuddin , Karim Khairul Anuar , Hussien Hayati , M. Ali M. Nazmi , M. Yunus M. Jeffri 
Published: November 2020

Abstract
Operators around the world are reviewing their aging assets, and are coming to clench with the reality that some offshore fields are no longer economically viable. The North Sea and the Gulf of Mexico have seen numbers of decommissioning activities. In other regions, decommissioning activities had started to emerge, now and in the coming years. Decommissioning, an easy-look-but-massive-task come with unique challenges and cost ranging in the billions. Delivering an effective decommissioning especially when dealing with deep-water operations are paramount as to secure the economic value from the assets. Health, Safety and Environmental (HSE) concerns are always vital in any decommissioning process. The target is to effectively reduce the long term risks to other benefactors of the sea while the associated short term risks to those responsible for decommissioning operations are minimized. A major part of any decommissioning project is the decommissioning of subsea pipelines including the flowlines and risers.
Referring to a field case example from one of PETRONAS's deepwater field decommissioning project in Atlantic Ocean, a numbers of techniques had been considered for decommissioning of subsea pipeline system which sited in 700m to 960m water depth, ranging from preservation for potential future use, leaving in-situ or full recovery. Noted that each subsea pipeline decommissioning technique should be considered on its own merit, thus the assessment of each decommissioning technique had been based on many parameters, amongst others, size of pipeline, type of pipeline (e.g. single pipe, pipe-in-pipe, flexible), type of fluid in the pipeline, operational environment (location), production history, Inspection, Repair and Maintenance (IRM) records, HSE considerations, connection to other facilities, technical feasibility (including potential use of advanced technologies), regulatory authorities requirements and socio-economic considerations.
This paper covers only at specific of PETRONAS deepwater subsea flowlines and risers decommissioning experiences. It outlines the activities done starting from desk top activities (e.g. planning and concept) up to operational activities (e.g. pigging, flushing, cleaning, disconnection, retrieval or leaving in-situ). Different considered scenarios are discussed and potential advantages and disadvantages of each scenario are presented.
Breaking the Norm: Spudding the Well Riserless with Directional CwD BHA For Surface Casing Enables to Reach Shallow Reservoir
Authors: Shahrul Amar Muhammad Shafiq , Za'ba Muhammad Afiq , Bayking Elias , Phan Van Chinh , A. Rahman Iz'aan 'Irfan , Rj Hassan Rj M. , Khazali-Rosli Khairul Amir 
Published: November 2020

Abstract
Shallow Hazard was detected and prevents this exploration wells to be drilled vertically above the prospects. Thus, a directional well was planned 60m away from the intended surface location. The challenge was to use the same spudding method as the normal vertical well used by the operator in this area. A Casing while Drilling (CwD) level 2 was the norm in this field to spud the surface casing vertically. However, with this shallow hazard, this must be drilled directionally to achieve the intended reservoir. Kicking off deeper will cause the dogleg severity to be high in the subsequent section as the reservoir TVD is as shallow as 1200m.
A feasibility study was done to understand the requirement and the complexity in ensuring the objectives of the wells achieve. Numerous discussions with different expertise from the operator, contractor and drilling engineering to outline the technique, BHA design, drilling parameters, and the risk mitigation in case of any shallow hazard struck. Bit and reamer studies with Dynamic BHA Vibration modeling were performed to define stable drilling parameters and predicting the BHA capability.
With the systematic technical approach, the BHA spudded smoothly until a planned depth before the reamer activated and BHA started to rotate and drill. Kicking off is a challenge with heavy CwD BHA in this soft unconsolidated formation with few stringers observed along the way. 50% of the total meterage was used to slide with WOB ranging from 3-5 klbs to bring the trajectory towards the planned inclination 22 deg and reached TD as per plan depth.
This paper presents the technique and risk evaluation, workflow on offset well data analysis, BHA design process, customized bit/reamer selection and a dynamic vibration analysis to deliver this special Directional CwD Level 3 Technique. The successful of spudding and drilling this surface section had enable the operator to achieve this shallow prospect exploration target.
Spotlights of the Lessons Learned from Thap Raet West EOR Pilot
Authors: Pancharoen Monrawee , Kiravanich Parntip , Laochamroonvorapongse Rapheephan , Nopichai Sombat , Kulthamrong Theeraphot , Sardsangjun Pimporn 
Published: November 2020

Abstract
Sirikit Oilfield (S1) is the largest onshore oilfiled in Thailand. The production has started in 1982 with waterflooding implemented in 1995. Chemical Enhanced Oil Recovery (EOR) is considered as one of the potential mechanical to improve field recovery. Surfactant reduces interfacial tension leading to a decrease in oil saturation while polymer increases injected water viscosity and improves flooding performance. As a result, oil recovery is expected to increase beyond conventional waterflood operations.
Following positive laboratory results, an inter-well chemical EOR pilot injection was implemented in the TRT-W area with a single injector-producer well pair. Reservoir simulation study was performed to determine pilot injection strategy, and the expected performance prediction from the process. Chemical quality control and measurement protocols were established by using titration method for surfactant and chemial oxygen demand (COD) method for polymer measurements. Oil saturation logging was performed in nearby producer to confirm the effectiveness of surfactant in reducing oil saturation at reservoir conditions. Production rate and water cut were monitored to observe any changes in well production. The injection period lasted for 14 months, from September 2017 – November 2018.
Several tools and techniques were deployed to ensure that the designed conditions were met and able to effectively evaluate the pilot injection results. A reduction of oil saturation was achieved by the surfactant injection, as evidenced from oil saturation logging results. It was a positive indication that the surfactant has worked as planned in the reservoir. Oil production and water cut were monitored by routine production test. However, significant improvement in oil production was not observed. During the pilot, no surfactant was produced in the monitored producer. Potential causes of lower-than-expected oil recovery were identified as change in water quality and high surfactant adsorption in the reservoir. A number of operational issues were also encountered during this pilot including facility disruption and artificial lift failure.
Further investigation is required to develop an appropriate surfactant formulation with a wider range of working conditions and, most importantly, identify ways to mitigate the high adsorption issue. Lessons learned from this pilot in terms of facility design, water quality control, pilot monitoring program and contracting strategies will be incorporated in the design and execution of future EOR pilot implementations in the S1 field.
Case Study on the Nano-Polysilicon Materials' Depressurisation and Injection-Increasing Technology in Offshore Bohaibay Oilfied Kl21-1
Authors: Feng Qing , Li Nan Xiao , Huang Jun Zi , Li Na , Li Song Jing , Tian Miao , Zeng Ming , Yang Xing Wei , Wang Hua Shao , Wang Fei 
Published: November 2020

Abstract
Due to low reservoir permeability and interlayer contradictions, high water injection pressure and low water injectivity index have become a big challenge in the waterflooding development of low-permeability reservoirs. Therefore, new pressure-lowering and injection-increasing technologies have been desired. Nanotechnology offers various creative ways to solve the problems of oil and gas production that also provided a potential oilfield chemical in pressure-decreasing application.
However, successful pressure decreasing nanotechnology have rarely been reported. This manuscript reports nano-polysilicon as a new depressurization and injection-increasing agent. The stability of nano-polysilicon was studied in the present of various ions, including Na+, Ca2+, and Mg2+. This study finds that the addition of nanomaterials can improve porosity and permeability of porous media. Injection / draw down test method is taken to evaluate injection effects of nano-polysilicon into water wells, and flow resistance changes are investigated by infectivity index curve. Through injection performance evaluation experiment, it is found that the nano polysilicon technology has the ability to improve the permeability and weaken flow resistance of fluids.
Field test results prove that biological nano-polysilicon technology has obvious effect on pressure reduction and injection-increasing. After the operation of test wells, injection-increasing nano-polysilicon technology has excellent performances with increasing injection rate by 40% and pressure drop by 10%. This work presents the first successful oilfield test of nanoagents in pressure-decreasing application that offers a novel, simple and pollution-free oilfield chemical. The importance of this work is not in stability and salt tolerance of nanoparticle but rather in their first real field application of depressurization, which takes an exciting example for nanotechnology to effectively solve another real difficulty in petroleum engineering.
Design and Safety Considerations to Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells
Authors: Singh Ishaan , Aryo Wijoseno Danny , Wolf Kellen , Sorman Ignatius , Dutta Shaktim 
Published: November 2020

Abstract
The wells in the "A" geothermal field located in the Philippines, have high bottomhole temperature (BHT) of 600°F and bottomhole flowing pressure (BHFP) of 2,000 psi. The productive section in this field has "shallow" and "deep" reservoirs which are separated by a low-permeability formation. The interaction between the reservoirs is hence limited except through the wells resulting in intrazonal flows under shut-in conditions. As observed with time, these flows have been upflows making the overall production very stable. However, in recent years, it has been found that the cooler fluid inflow from the shallow reservoir has relatively increased, causing reduction in production levels. Under flowing conditions, this has resulted in both flow instability and downflows in wells, which in turn have decreased the individual well production capacity. In order to activate and enhance well production, coiled tubing (CT) nitrogen lift operations were required to be performed to unload the cold water in geothermal wells, hence enhancing steam production.
The wells in this field are completed with large completion sizes (7-in., 9.625-in., and 13.375-in.) and have high BHT (600°F), which makes conventional coiled tubing operations highly challenging. Because the coiled tubing operations in geothermal wells are limited as compared to the conventional operations, planning and executing these for the first time in the "A" field was challenging operationally and technically. As such, surface equipment failure risk was high, putting at risk successful coiled tubing operations.
To gain further understanding of operations in high temperature and cold water downflow environments, CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped designing a new cooling loop system and allowed optimizing the nitrogen lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. coiled tubing in the Philippines.