bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Predrill and Real–Time Pore Pressure prediction for Exploration Well Drilling in Xihu Depression, East China Sea
Authors: Lu Fawei , Gui Feng , Wang Meng , Bordoloi Sanjeev , Reese Michael 
Published: November 2020

Abstract
The drilling of the exploration wells in Xihu depression in East China Sea becomes very challenging as the drilling campaign shifts towards the deeper part of the west slope. Due to the complex pressure compartments formed by highly faulted blocks, unexpected high pressure encountered in the targeted formations has caused the early abandonment of some of the wells without managing to properly evaluate the reservoir potential. Providing an accurate pore pressure prediction therefore becomes very crucial to enable the decision-making process required for drilling success.
An integrated approach was adopted to combine detailed predrill prediction with real-time pore pressure monitoring considering the uncertainties in the seismic velocities and varying geological conditions in different faulted blocks. During the predrill modelling, a few nearby offset wells were reviewed in detail to construct the pore pressure model and to understand the overpresure mechanisms and geological settings. Seismic velocities at offset well locations were also compared with the acoustic logs to understand the uncertainties in different datasets. For the planed well, a range of low, high and most possible pore pressure profiles were interpreted using all the available data including seismic velocity and depth-stretched logs from different offset wells to account for the geological and geophysical uncertainties. During the drilling of the exploration well, real-time pore pressure monitoring was conducted by integrating the Logging While Drilling (LWD) acoustic and resistivity logs, mud logging and drilling data. Pore pressure and fracture gradient profiles were updated in real-time to enable proactive decision making to optimize mud weights and casing points to reduce drilling risks and hazards.
This approach was applied in the drilling of one of the exploration wells in Xihu depression. The well was drilled successfully by optimizing the casing design based on the real-time pressure monitoring results. This enabled the operator to properly evaluate and appraise the reservoir potential owing to setting a liner just above the high overpressured section in the deeper formations that caused drilling issues in previous wells. The overpressure magnitude was confirmed later by blind drilling for testing purposes.
After the completion of the planed well drilling, a post drill summary was conducted to compare the pressure models at different stages. In addition to the final detailed pressure model, a clearer understanding and interpretation of the overpressure transition, overpressure mechanisms and pressure variations compared to the nearby area were summarized and correlated for reference, while planning for drilling of the future wells.
Ten Years of Successful Tailored Cement Design and Execution in HP/HT Wells in Indian Offshore Drilling Projects: Case Study
Authors: Gupta B. K. , Dange Mikhil , Fortner Kelly , Kumar Animesh 
Published: November 2020

Abstract
The challenges, experiences, and best practices established from cementing in high-pressure high-temperature (HP/HT) offshore wells in India are discussed along with the design and tailoring per the parameters of each well, real-time operation analysis, post-operation evaluation, and lessons learned from 10 years of experience. Challenges encountered, associated potential risks, and solutions implemented to overcome such challenges in a bid to achieve desired zonal isolation are presented.
The obvious presence of high temperature (&gt;400°F) and high pressure (&gt;15,000 psi) as well as a narrow range of fracture gradient and pore pressure created challenges in cement, spacer design and field execution. Another task was to maintain desired rheological hierarchy and fluid compatibility of fluid pumped to achieve the desired displacement efficiencies under these vital well conditions. The introduction of specialty chemicals to develop cement and spacer fluid, which can help maintain downhole properties under these extreme conditions, has been vital to the success of dependable cement barriers in these wells.
The wells presented multiple issues during the course of planning, and a few of them had to be sidetracked one or two times. Losses during drilling, gas flow, etc., were commonly encountered in both 12 1/4- and 8 1/2-in. sections. This caused a reexamination of cementing practices, particularly for production sections completed with expandable liner hangers (ELHs). The successful liner operation in these wells encountered an additional challenge—placement of the cement sheath with a higher top of cement in a HP/HT environment. An integrated basis of design was developed to help mitigate challenges and achieve objectives, and it primarily included the following:
Successful running-in and placement of an expandable liner system Using specialty chemicals to sustain the downhole extreme environment throughout the life of the well Using computer-aided simulators to achieve excellent zonal isolation across and over the zones of interest
An expansive additive was used to enhance hydraulic isolation of the zones of interest because it helps the cement expand in an HP/HT environment and fill any microchannels. A 3D displacement fluid dynamics simulator played an important role in determining efficient placement of cement. This helps pinpoint potential fluid channeling caused by reduced standoff, poor displacement efficiency, or abnormal in-hole geometries.
Specialized additives were introduced when designing spacers to modify their parameters to withstand downhole HP/HT conditions, which generated the necessary friction pressure under a low pump rate to achieve rheological hierarchy, and eliminate compatibility problems with all drilling fluids. The successful design and cementation of more than 20 HP/HT wells was executed, including the deepest well in the operator's history throughout the previous 10 years.
Realising Lost Well Productivity via Wellbore Implosion
Authors: Rivas Mora Cenobio , Azman Muhamad Syazwan , Jumaat Mohd Shafie , Al Busaidy Adil 
Published: November 2020

Abstract
Perforating an existing producer with a completion in place would typically be limited in terms of gun size and perforation cleanup ability, hence affecting the well performance. This paper is a case study of a through-tubing additional perforating job, its performance analysis, and finally the implementation of a wellbore implosion technique for perforation tunnels cleanup. Job design and the well performance analysis are also presented.
The zone selected for the initial additional perforation was analyzed and a gun system simulation was performed. After the initial perforating job, surface and downhole surveillance data were collected for perforation performance analysis. Based on this analysis, a wellbore implosion technique was selected for perforation tunnels cleanup to enhance their productivity. Several wellbore implosion job simulations were performed based on various design scenarios. The optimal design was selected and executed successfully. Postjob well performance was then analyzed and compared with earlier performance. Although this implosion technique cannot improve or alter the reservoir rock deliverability, its ability to perform perforation cleanup is expected to be evident from the well performance analysis.
Analysis of the well performance after initial perforations showed a lower productivity index (PI), which was expected considering that the perforating job was conducted through-tubing while the completion was in place. The subsequent well implosion technique was executed successfully, and after that operation, the PI of the well improved, indicating the success of the technique to clean the perforation tunnels.
Because many wells suffer from improper perforation cleanup, this case study provides an important example for such wells, whether old or new, to replicate and instantly enhance their productivity. This technique can also be implemented in injector wells to enhance their injectivity.
Integrated Sub-Surface and Surface Modelling for Gas Field Planning and Refinery Feedstock Evaluation
Authors: Wong Siong Ming , Wan Hashim Wan Mahsuri , M. Norpiah Rohaizad , A. Samat Ida Nordiana , Ahmed Shata Karem , Hajizadeh Mubarak Alireza , Shridhar Kulkarni Sukrut 
Published: November 2020

Abstract
A gas field is producing condensate with higher density than typical due to its higher napthene and aromatic content. Several future gas fields to be developed also have condensate with similar properties as this single field. The changes in future condensate properties and increasing amount of this atypical condensate will have major impact on existing refinery. It was necessary to create an integrated reservoir and surface facilities model and characterised fluids that can produce prediction of future feedstock including these aromatic condensate to the refinery. The model also produced the usual outputs such as gas quality and condensate quantities forecast over the life of the gas fields. A compositional network model consists of fluid modelling, reservoir, well, topside facilities and pipeline modelling through to the onshore terminal process modelling were developed in order to model the export gas and condensate network. Steady state models were developed and validated against operating condition for each system and an integrator was utilized in order to integrate the subsurface and process simulator together. For the fluid modelling, a compositional model suitable to produce assays was used instead of black oil model in order to predict the quality of both the gas and condensate delivered. The fluid models for fields with aromatic condensate used True Boiling Point (TBP) assay instead of a standard gas chromatograph composition from a Pressure, Volume and Temperature (PVT) laboratory test report. Several characterisation methods were developed and tested in order to obtain representative and relevant properties for refinery design. Other gas fields which had a more common chemical characteristic of paraffinic dominant condensate used standard characterisation method. The model enables representative prediction of condensate properties relevant for refinery design and evaluate options to develop the fields. The work will show that an integrated sub-surface-surface network model is essential in order to define the impact for a development throughout the value chain, specifically the changes to the products and downstream facilities. It will also provide an insight on the impact of fluid characterization methods of different types of condensate.
Evaluating the Implementation of Resident UAV Unmanned Aerial Vehicles into Oil and Gas Industrial Facilities and Construction Sites
Authors: Tcherniguin Nicolas , Mortier Régis , Tan Jaime HuiChoo 
Published: November 2020

Abstract
Use of robotics for subsea field developments became common practice during the last few decades. The development of unmanned aerial vehicles in conjunction with Internet of Things (IoT), Artificial Intelligence (AI), Cloud and Edge computing, the fast-evolving technologies, are opening new horizons for construction monitoring and supervision and facility inspection, maintenance and repair activities. This paper presents the results of TechnipFMC's latest investigations and tests to develop the use of advanced Unmanned Autonomous Systems (UAS's) to leverage the operational performance of some of its activities.
Long Term Internal Pressure Strength of Spoolable Reinforced Plastic Pipe and Comparison of Qualification Requirement Based on API Specification 15S and DNVGL ST F119
Authors: Putra I Wayan , Shahru Haslan Tengku Mohd , Tan Chin Chien , Badaruddin Mohd Fauzi , Mohd Ali Napiah Mohd Nazmi 
Published: November 2020

Abstract
Spoolable non-metallic pipe (NMP) is recently getting increased popularity as material for onshore and offshore pipeline. Even though the material is generally more expensive than conventional carbon steel, the total life cycle cost (TLCC) reduction is driven by reduction of pipeline installation cost (faster lay rate, less manpower/equipment) and operational cost (no chemical injection to combat corrosion, less operational pigging and inspection). The most common types of spoolable NMP currently used are reinforced thermoplastic pipe (RTP) and thermoplastic composite pipe (TCP). Non-metallic composite material strength capacity to withstand internal pressure is naturally decreasing over time. As new material, limited long-term performance data are currently available for these types of pipes. To obtain the long-term strength degradation properties of the material requires long duration and expensive qualification process, which burden the development of these types of pipes. PETRONAS has performed series of qualification test for both RTP and TCP in collaboration with several manufacturers. The qualification was initially based on API RP 15S (edition 2006) with few additional testing to suit offshore application due to the recommended practice initially only covers spoolable RTP and generally for onshore application. The latest edition as specification (API Spec 15S) covers more general types of spoolable plastic line pipes, including bonded (fully non-metallic reinforced plastic pipe) and unbonded type (with metallic reinforcement). Recently DNV also issued DNV RP F119 in 2015, a recommended practice for TCP, which subsequently upgraded to become specification, DNVGL ST F119 in 2018. Both reference specifications/standards above have different requirements on how to design and qualify the reinforced plastic pipe, however in general, both are based on long term test requirement. This paper provides requirement of long-term qualification of the pipe, based on API RP/Spec 15S and compare the result if it is qualified in accordance to DNVGL ST F119. Different result in term of long-term strength capacity is observed between these two standards. This paper also explains the pros and cons and provide feedback to both referenced specifications above, to further improve the specification requirements and reduce the burden of either manufacturer or end user in performing qualification for the pipe.
Investigation and Remediation of Electrical Integrity Issues in a Subsea Production Control System
Authors: Hammond Steven , Osman Hazreen 
Published: November 2020

Abstract

Objectives/Scope
Subsea production control systems are unique because they operate using electrical power and communications but in an underwater environment. Over time water ingress into an electrical distribution system can cause degradation of system electrical integrity. The objective of this paper is to show how these issues arise, to discuss methods for finding the location of integrity faults, and to give an example of how integrity faults can be located, what action can be taken to effect repairs, and how to mitigate against further recurrence.

Methods, Procedures, Process
Since it is not normally possible to determine the location of subsea electrical faults using visual methods alone, various other methods can be used such as Time Domain Reflectometry (TDR), Insulation Resistance (IR) measurements and branch isolations. In addition to the complexities of determining a fault location subsea, the situation is further complicated by difficulties in gaining access to potential subsea fault locations using divers or Remotely Operated Vehicles (ROVs). This paper will show the fault diagnosis procedures that were employed in determining the location of an electrical fault in a subsea production control system and will also discuss the issues and the procedures used in order to gain access to potential fault locations such as opening hatches and removing protection covers under water.

Results, Observations, Conclusions
The results of this work were the safe and successful location and remediation of the subsea electrical fault. The subsea production control system was restored to full operation and there were no HSE incidents during the work. The performance of the system continues to be monitored and analysed for signs of any new degradation.

Novel/Additive Information
This paper will present information that will be of benefit to others in the subsea industry who are facing electrical integrity issues in subsea production control systems. The benefits that can be gained are both in terms of testing strategies that can be followed and in potential new technologies that can be deployed.
A Central Luconia Case Study: Pitfall of Using Statistics without Geoscience Interpretation
Authors: Cheong Yow Lam 
Published: November 2020

Abstract
Hydrocarbon column height is one of the most important parameters that affects the volumetric calculation. Previous prospect volumetric calculations were done using statistics built from the existing database of column heights of hydrocarbon discoveries of deeply buried carbonate pinnacles in Central Luconia. A re-look of the discoveries revealed that not all of the data in the existing database are applicable for a given prospect due to the different geological settings. As it is a common practice to update the database from time to time, a refresh was done after new multi-PSC 3D seismic acquisition and interpretation was completed and more published well information from adjacent PSC's were made available. A more scientific approach was taken this time around; the effective sealing unit of the deeply buried pinnacles was compared against our prospect. All the deeply buried pinnacles in the statistics were effectively sealed by the clastic 5.8mya depositional sequence. The percentage of hydrocarbon fill for each buildup was plotted on the existing paleogeographic map of the overlaying sealing strata. Given sufficient charge, multiple factors remain that can negatively affect hydrocarbon accumulation in Luconia carbonate buildups. These include high aquifer overpressure, crestal faulting, and channels which can impinge on the reservoir and act as thief beds. Some channels may clearly be seen in the seismic, while some appear to be pinched-out, and others may be sub-seismic. In the area of carbonate build-ups that were used in the statistical database, lower percentage of hydrocarbon fill coincides with the presence of a regional channel complex, interpreted to act as theif zones. However for our prospect, within this overall channel complex, several large buildups seem to act as baffles or barriers to the channels, deflecting them away from our prospective carbonate build-up. Thus, by comparing with our prospect, we realized that the regional statistics might not always be applicable, depending on several geological variables. Our prospect has no thieving channel at top seal level and is further protected by the updip channel belt by another carbonate platform. We should not use statistics generated from discovery wells that are affected by the thief beds. Statistics are always favoured whenever we have little knowledge about a basin or subject. By showing how geoscience can drive the statistics, we will be reminded on how using it without interpretation may be misleading.
Cost Optimization at Design Stage by Implementing Barefoot Completion in Carbonate Reservoir
Authors: Ghazali Hasyimah , Bernard Caesar Sokatte , Zahri Fakhrul Radzi , Khairul Salleh Nur Sakinah , M. Safari Lai Harni Farihah , M. Khir Khairul Ezee , Tuah Joroji , Mohamed Tatmimiddin Alhasani , Kouni Karim 
Published: November 2020

Abstract
Most of carbonate wells in PETRONAS Carigali Operated blocks in Malaysia are completed with pre-drilled liner. Barefoot completion is a new approach that is planned to be implemented in this particular carbonate field. This paper aims to share on how selection of lower completion based on in-house carbonate lower completion guideline could optimize overall well cost.
The offset well in X field are all completed with pre-drilled liner. As an initiative to further optimize the well cost and delivering an economic field development plan, barefoot completion has been proposed as a completion strategy for the upcoming drilling campaign. Selection of this strategy has taken into account the wellbore stability during production, geochemical effect and critical drawdown, including unconfined compressive strength (UCS) based on the outcome of the geomechanical study.
The advantages of the approach are mainly in reducing open-hole length thus reducing the drilling cost, secondly is eliminating all the equipment requirement for lower completion thus reducing completion cost by 14% in X field. This shows that the guideline is effective in choosing the fit for purpose and safe lower completion strategy for carbonate. The work evolved from replication of best practices and lessons learnt from the developed fields in Central Luconia.
Complimentary to the existing in house completion selection guideline, the new guideline for carbonate lower completion and its implementation in this design has contributes by minimized risk uncertainty in developing carbonate reservoir to a controllable level, thus becoming reference for future similar development within PETRONAS.
Dual Function Chemicals in Resolving Emulsion and Water Clarification for EOR and Normal Emulsion Application
Authors: Halim Nor Hadhirah , Salleh Intan Khalida 
Published: November 2020

Abstract
Emulsion created by EOR chemical flooding is difficult to break due to the presence of alkali and surfactant tightly bound with the oil and water. Many compounds have been used as demulsifiers in breaking this tight emulsion. Dual Function Demulsifier (DFD) is a copolymer based demulsifier synthesized for demulsification of water-in-oil and oil-in-water emulsion. By providing essential functionality with strong dehydration and dewatering capabilities, it is effective to dehydrate the oil at the separation point whilst improving the water clarity.
DFD formulated for normal emulsion was piloted in Field B, Malaysia with encouraging results better than incumbent chemicals during 8 days field trial. For EOR emulsion, since there is no EOR application in Malaysia as yet, the DFD chemical was tested at dynamic condition using Multi-Functional Separator Flow Test. The flow test involves a continuous fluid flow from the pipeline into the mini separator simulated Field A separator temperature of 60°C and 15 minutes retention times using 40 Liters commingled crude from Field A and 60 Liters Produced Water containing the EOR chemicals.
DFD implemented for pilot in Sarawak offshore been able to resolve the normal emulsion within Field B separator temperature of 40°C and 4 hours of separator and flow lines retention times until crude oil terminal. At 25 ppm DFD 0815, the chemical was able to treat the emulsion to less than 1% and reduced the Basic sediment & Water (BS&W) to 0.43%. This certainly meet the BS&W specification of the saleable crude to be less than 0.5%. DFD also reduced the Oil in Water (OIW) to 155 ppm from 900 ppm which the reduction is about 82%. For EOR induced emulsion study, 50 ppm of DFD A13 has proved to work successfully in the dynamic condition testing using Mini Separator Flow Test. The emulsion has been resolved from 30% to 1% and the Oil in Water was reduced from 239 ppm to 49 ppm. These two cases have proven the dual function capability of this chemical which is unique from the commercial demulsifier.