bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delivering a Dependable Zonal Isolation Barrier for an Extreme HPHT Well in Offshore Vietnam - Lessons Learned from Cementing High Pressure High Temperature Well
Authors: Nguyen Tam Chanh , Bhaisora Devesh , Ninh Nga Thi , Nguyen Tai Trong 
Published: March 2022

Abstract
With recent discoveries, offshore Vietnam continues to provide promising prospects for hydrocarbon production, especially with rapid exploration and deployment in the offshore HPHT fields in the last decade. However, Vietnam has some of the most complex and hottest wells in the region. An operator was planning to break the barrier of the hottest well in offshore Vietnam. Bottom hole pressure and temperatures for this well were predicted to be around 12,000 psi and 200 deg C, respectively. Designing and delivering a dependable zonal isolation barrier was paramount to the success of the well.
The well architecture included the primary cementing job for six casing strings - 30-in. conductor casing, 20-in. surface casing, 16-in. casing, 13 5/8-in. casing, 9 7/8-in. casing, and 7-in. production liner. The well was for exploration purposes and was to be abandoned by seven (7) cement plugs in cased hole across various depths. A total of 4,200 bbls of cement slurry with a wide density range from 12.0 lbm/gal for the surface casing to 18.0 lbm/gal for the production liner, were tailored and pumped in the well. Rigorous slurry testing was conducted up to 198 deg C and 13,000 psi downhole pressure for the production section slurries. To provide for proper hole cleaning a tailored spacer was designed and tested for stability under the same downhole pressure and temperatures. A total of ~1,000 bbl of spacer were pumped in the well, having a density range from 10 lbm/gal to 17.2 lbm/gal. To maintain the robustness of the slurry design in order to handle any changes in well parameters various sensitivity tests were performed at different temperatures, retarder concentrations and with mud contamination levels (predicted by computational fluid dynamic modelling). For the production section, an aggressive slurry with less than a 15 min transition time was designed to avoid any gas migration in the setting cement.
This case study, techniques and lessons learned can be applied to similar wells around the globe especially in the challenging environments of extreme HPHT.
Effective Mono Ethylene Glycol Meg Injection Optimisation at Offshore Gas Platform Facility: A Novel Case Study for Hydrate Control During Summer and Winter Operation
Authors: Samusideen Salu A. , Alwani Mohammed Abdo , Kurdi Abdullah A. 
Published: March 2022

Abstract
The objective of this paper is to show five innovative options of operating the hydrate inhibition system which aims to eliminate future wet natural gas production limitations and optimize capital and operation expenses during a 25-year life cycle period.
Mono-Ethylene Glycol (MEG) is injected in wet natural gas trunk lines from an offshore gas field, as a means of hydrate inhibition during the winter season. The used MEG is supposed to be recovered in MEG Regeneration Unit (MRU) at onshore gas plant, where the wet natural gas is further processed. The MRU often faces challenges in producing to achieve specified MEG purity, which consequently results in injecting a diluted solution of MEG into the offshore systems, and thereby lowering the maximum allowable production capacity of wet natural gas.
This paper describes the study in five different options. Option 1 represents the current operating scenario of maintaining the existing system with MRU in service, while option 2 explores shutting down MRU at onshore gas plant, and pumping fresh MEG during winter days from the gas plant to the offshore platforms. Option 3 explores shutting down MRU at the gas plant and pumping fresh MEG during winter days, but from a Beach Valve Station (BVS) at an onshore location. Option 4 explores maintaining the existing system with MRU in service and upgrade the storage tanks to address the unsteady state nature of rich MEG flow. Option 5 explores pumping lean MEG during winter days from the gas plant, storing rich MEG in tanks for MEG regeneration and reclaiming MEG through the existing system during the summer including storing lean MEG in tanks for winter usage.
The evaluation has shown that options 2 and 3 can easily meet the required hydrate depression specification during winter period, at far lower MEG injection rates and at a substantially lower life cycle cost (LCC) compared to option 1. The evaluation also showed that options 4 and 5 will ensure MRU operation not interrupted due to low-low levels in MEG storage tanks and will maintain high purity MEG in the trunk lines, which is different from option 1. In conclusion, option 5 has the lowest LCC which is the most economically attractive option.
Noise Logging Application for Well Integrity Evaluation: A Case Study in Peninsular Malaysia
Authors: Saw Li Juan , Linda Hanalim , William Tolioe Amelio 
Published: March 2022

Abstract

Objectives/Scope
Field-X was first discovered in 1979, comprising of saturated oil reservoirs with several shallower non-associated gas reservoirs. Field-X is currently producing from several oil producers. X8 well was recently drilled, completed, and produce from A and B reservoirs. However, 5 months later, the oil rate has been reduced by half with gas oil ratio (GOR) increased up to 5 times. Consequently, the well had to be shut-in due to reservoir management plan (RMP) violation. X9 well was drilled and completed, but 5 years later the well started experiencing the sustained production casing pressure (PCP) and was forced to shut-in in the following year with the locked-in potential of both A and B reservoirs.
To diagnose the root cause of high GOR (HGOR) in X8 well and sustained PCP in X9 well, the Spectral Noise Log (SNL) was deployed. The main advantage of utilizing SNL is its capability of detecting fluid movement behind tubing and casing. High differential pressure creates lots of fluid movement, which generates higher noise amplitude. Meanwhile, smaller pores or leaks generate higher frequency noise that can be easily picked up by SNL.
SNL tool was run in flowing condition for X8 well and the results indicated the HGOR zones were mainly contributed by the shallower B05 sand which was flowing through the leaked 4-1/2″ liner packer. Temperature deflections also indicated that the liner packer seal was leaking and B05 reservoir was contributing to the production. The liner packer leak and B05 reservoir flow would not have been detected by conventional production logging tools as the flow was happening beyond the tubing and casing. For X9 well, SNL was run in the wellbore whilst pumping water via annulus, through the leaks and flowing back up the tubing. Three tubing leaks were successfully detected from the SNL run, whereas previous conventional noise log only managed to detect 2 leaks. It is possible that the third small leak was very small, hence the conventional tool was unable to detect it.
X8 well successfully back online with 8.4% rate increase than last production with GOR reduced back to initial GOR and X9 well successfully back online as per last production rate. The liner packers which are not permanent barriers for reservoir isolation and allocation can be validated, moreover, verifying that tubing leakage is mainly contributed by tubing joints, which can be used as the main input in tubing materials selection in the future.
Well integrity issues can cause significant loss of production, oil spill or worst case, even loss of lives. Proper selection in data acquisition tools helps to accurately diagnose well integrity issues that can be swiftly addressed. In the low oil price environment, skimming down on data acquisition costs may not uncover the true underlying well issues or reservoir issues, but might jeopardize future projects to be undertaken in years to come.
Mitigating Downhole Hazards and Improving Operational Performance using Advanced Human Performance Techniques and High-Fidelity Simulations
Authors: Pathy Kuhanesapathy Thavaras , Khazali Khairul Amir B , Wallace Grant , Christie Bruce , Battisby Clive 
Published: March 2022

Abstract
In August 2020 the Operator deployed a fully immersive On The Rig (OTR) Simulator for the execution of a Drill the Well On Simulator (DWOS) project on the semi-submersible Maersk Developer to prepare the crew to drill the 1st Petronas Deepwater exploration well (name redacted to Well X) offshore Suriname. The offset well data showed numerous downhole troubled time events, such as well control and stuck pipe in addition to other risks that required to be actively managed.
With many of the crew being new to the rig, competence was identified as a key risk. The Operator engaged a DWOS program to ensure the rig crew competence was accelerated and project risks were understood and mitigated. This was achieved through realistic simulations, well/rig specific training and advanced human factors training, specifically designed to ensure the successful delivery of the well.
A New Way to Extend the Life of Pipe
Authors: Wells Austin J. 
Published: March 2022

Abstract
It is well known that formations can be very abrasive, and can quickly and severely wear drill pipe tube bodies. Once the body wall of the tube no longer meets requirements for used pipe, the entire joint must be scrapped. A new method of applying sacrificial wear pads to drill pipe tube bodies is presented, by using a proprietary low heat input welding process to apply hardbanding directly to drill pipe tubes.
Using a proprietary low heat input welding process, hardbanding was safely applied to drill pipe tube bodies. This created new, raised contact areas for the tubes with the abrasive formation. Two wear bands consisting of this hardbanding create a wear pad for the tube body, improving its overall wear-resistance by up to 15 times and casing-friendliness up to 3 times. The application itself was validated through metallurgical testing, including advanced hardness mapping, tensile testing, and non-destructive inspection methods. Following this testing, multiple field trials were performed, which provided case studies for the effectiveness of the wear pads.
Three separate oil and gas Exploration & Production (E&P) companies were having issues with tube body wear of drill pipe in various formations in the USA. To address this, wear pads were applied to a sample set of drill pipe for each E&P company using a proprietary low heat input welding process. Measurements were taken from the drill pipe before and after drilling activities to determine if the wear pads protected the pipe as planned. In addition, non-destructive testing was performed on the wear pads to determine if any cracks existed. For all three case studies, the wear pads effectively protected the tube bodies of the drill pipe, preventing them from wearing. This proved that the wear pads were a cost-effective solution for protecting pipe from abrasive conditions downhole.
The novelty of this improved welding method is that it allows for the economical protection of drill pipe that would otherwise be scrapped due to tube body wear. This extends the life of the drill pipe itself, which is of great value to owners of drill pipe and E&P companies that rent or own strings. Furthermore, the hardbanding used for the wear pad is far more casing-friendly than the unprotected tube, which is also very important to E&P companies.
Polymer Lining – A Solution for Water Injection Corrosion Challenges in Asia
Authors: Suhaimi Radzlan Ahmad , Feeney Allan , Roux Arnaud 
Published: March 2022

Abstract
Deterioration of carbon steel water injection subsea pipelines caused by internal corrosion is a common problem in oil fields around the world. Addressing this issue requires costly and complex water management solutions or could lead to reduced performance and total replacement of corroded pipelines.
This paper shall present the Polymer Lined Pipe (PLP) technology, a field proven solution to the water injection corrosion challenges, extensively used in the North Sea. A description of the key building blocks and the recent technology qualifications shall highlight the latest product development. Eventually, the main fabrication and installation steps shall be presented in view of a regional PLP application. A regional business case comparing the three water injection corrosion approaches shall highlight the typical economic metrics that could be achieved thanks to the use of PLP technology.
Today, this technology is accessible to operators in the Asia Pacific region with the recent opening of the Bintan Spoolbase in Indonesia enabling the deployment polymer lined water injection pipelines using the reel-lay method of installation. The strategic location of the spoolbase eliminates the significant intercontinental transit costs and the reel-lay method reduces offshore vessel days normally associated with conventional pipe-lay methods (S-lay and J-lay).
Predictive Analytics for Gas Turbine Driven Trains to Achieve Optimum Performance, Economics and Greenhouse Gas Emissions
Authors: Chidambram Siva Kumaran , Tan Jin An , Yusoff Mohd Amaluddin , Roy Jihok June Janesby 
Published: March 2022

Abstract
The current gas turbine performance monitoring infrastructure in Shell Malaysia yields inaccuracies of ±15% with no links towards emissions and fuel economics. This has resulted in severe limitations towards the ability to improve greenhouse gas (GHG) performance and generate value. This paper describes a novel, data centric approach to derive meaningful insights and economics/carbon savings from existing data on Plant Information (PI) and SMART CONNECT, a Shell in house performance management IT tool.
This project applies advanced analytics techniques based on historical data, supplemented by engineering performance models to derive robust outcomes. First, gas turbine and compressor modelling principles are programmed in Python and validated with engineering software such as UNISIM based on available operating data via PI. This yields a multivariate dataset tabulating the historical efficiency, power and fuel gas consumption of the fleet. The model is then utilized in a mathematical optimization algorithm and the optimized data used for training and validation of a Random Forest Regressor model.
The performance model in Python is able to achieve accuracies of &lt;1% absolute error when validated with UMSFM on the key performance parameters. Through parametric optimization, the Mean Squared Error (MSE) of the gas turbine and compressor powers is reduced to 0.55MW2 from its original 4.94MW2. The Heat Rate, Shaft Power, and gas generator exit pressures are also identified as the variables most correlated with efficiency. Lastly, the trained machine learning model demonstrated agreement with the dataset during testing, with a R2 value of 0.86 reflecting a strong correlation.
With a predictive digital model in place, production programmers can accurately identify the key levers to optimize the machine operating point for optimum fuel gas consumption. Optimizing Gumusut Kakap's high pressure compressors can yield 62,400 USD in savings per annum from increased sales gas and and 880 tCO2e per annum of reduction in GHG emissions, for every 1% increase in efficiency. This approach is a novel concept, leveraging on expertise from both engineering and data science to enhance equipment performance, and can be replicated towards other types of equipment to achieve efficiency, economic and emissions improvements at scale.
Deployment of Small Area Exposure Radiography S.A.R Technology to Maximise Multiple Work Fronts in Operating Offshore Facility
Authors: Sivarajah Jothi , Hassan Emran , Toh Jason , Lim Tee Bin 
Published: March 2022

Abstract
Malikai Phase 2 project is a brownfield infill drilling project consisting of 5 new infill wells with 1 sidetrack scope. These new wells are tied into existing Malikai Tension Leg Platform (TLP) production facilities for offshore processing prior to export. Offshore execution activities were heavily congested with multiple works fronts from Drilling, Mooring, Hook-up Commissioning alongside existing production and maintenance operations of the Malikai facility requiring prioritization via simultaneous operations (SIMOPS) activities.
The paper highlights the challenges of conventional radiography for inspection activities post pipework welding, which is usually scheduled within windows of low activities i.e. in the night with lower risk of personnel exposure to possible radiation. Since drilling operations runs 24 hours continuously, it renders almost impossible for conventional radiography inspection activities to take place as required.
This paper also describes the benefits with the introduction of SAR technology, the radiation exclusion zone can be set to less than 5 meters, thus allowing the topsides facilities pipework welding to take place concurrent with drilling and operation activities, achieving project success factors of optimized manning requirement and earlier than plan First Oil Date (FOD).
Advanced NDT technologies in the market like small area radiography and phased-array ultrasound were evaluated. Considering the piping diameter/wall thickness & material being Stainless Steel/Duplex SS (coarse grain welds – requires more extensive PAUT qualification), the final decision was to use SAR. A demo was conducted onshore with representation from various internal stakeholders. Necessary approvals from local regulatory bodies were obtained to facilitate the use of this technology for offshore assets.
The team further evaluated the implementation in our offshore facilities in a HAZID workshop, collaborating with several contractors and asset counterpart to assess the hazards and risks associated with SAR. Results were then compared and used by the execution team to develop procedures suitable for offshore use.
The paper compares past experiences of hook-up and commissioning activities using conventional radiography methods. By using SafeRad technology, the project can continue with the topside's fabrication work simultaneously during drilling instead of conducting the pipework fabrication activities in series after drilling is completed. This allowed project team to be able to continue the fabrication works and subsequent pre-commissioning and commissioning activities whilst drilling in progress. As a result, project is able to liquidate the critical path in hook-up and commissioning activities and ultimately contributed to the project delivering early project ahead (circa 6 months) of the first oil milestone.
Marginal Field Development: Evaluation of Offshore Developments
Authors: Arora Eka 
Published: March 2022

Abstract
Offshore marginal fields historically have been discoveries that have not been pursued due to factors such as size of field, lack of infrastructures, product incompatibility with the nearest host or uneconomic assets. However, according to Energy Information Administration Report (2021), Malaysia’s total liquid field production have been declining since reaching peak of 762,000 b/d in 20161. To offset the decline, marginal fields are being considered. This trend is also being echoed in other Asian oil and gas producing nations.
Through the advancement of technology, standardization and focus on cost control during the last oil downturn; marginal fields are now seen as economically viable and are being sanctioned to keep up with the falling production demand. These fields are typically developed via the use of minimum often unmanned wellhead platform or through Jack up Shallow water Subsea systems. It is a vital consideration for the operator to make in selecting either of the methodologies or a combination of the two. The offshore marginal fields being classified here are usually based in shallower water depth (&lt;100m) and have 7-12 years production lifespan.
The aim of this paper is to highlight key technical considerations that will assist the operator in making informed decision to develop the marginal fields using Integrated offshore solutions (IOS). Case study scenario is presented in which the operator was able to optimize their field layout, perform equipment selection by leveraging standardization and engineering and focus on minimizing installation and completion timelines.
A Hybrid Wind and Solar Energy Supply System for Offshore Platform in Gulf of Thailand
Authors: Tangpuk Sirichat , Thubthimsang Warawath 
Published: March 2022

Abstract
For offshore unmanned platforms, reliable and continuous power is critical in the remote wellhead platform operation of the oil and gas company. Thermoelectric generators (TEG) and solar panels are being examined as sources of power to meet the energy needs. Because of high expenses of TEG installation and upkeep, a study was initiated to explore the renewable energy source with better reliability while minimizing costs. A combination of solar and wind turbine system was fully met these requirements.
TEG was replaced by a wind turbine during the experimental phase. The wind turbine can be easily connected to an existing system, making it incredibly versatile and cost-effective for upgrading to a hybrid wind and solar system.
The wind speed profile was used to figure out how big a wind turbine and battery should be. The study suggested that by combining solar and wind power, the cost of consistent power generation can be reduced. There is a huge potential for capital cost savings when compared to TEG.
As a result, a Hybrid Wind and Solar Energy Supply System could be a viable option for remote power supply for offshore platforms, lowering capital, operating, and maintenance costs while also environmental friendly.