bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Distributed Temperature Sensing to Inform the Quality of Cementing Operations
Authors: Ricard Ludovic Paul 
Published: November 2020

Abstract
Surveillance of well work-overs and downhole operations is not trivial but is becoming increasingly feasible with recent improvements in the technology of fibre optics. Well cementing operations are critical for providing zonal isolation over the life of a well. However, there are limited downhole options to monitor and inform operations in real-time. Installing a permanent fibre optic cable enables surface to reservoir permanent surveillance. In this work, fibre optic cables were deployed in 4 different wells using different configurations and test passive and active distributed temperature sensing (DTS) setups to interpret the quality of the cement injection and hydration processes.
Well cementing can occur during well installation and decommissioning. For 3 wells, fibre optic sensing cables were installed for the purpose of monitoring the casing cementing installation, detect zones of isolation and any background lateral flow in the formation.
For one of the well, fibre optic cables were installed inside casing to monitor a full wellbore decommissioning cementing operation. Following the same process, datasets were acquired prior to and during cement injection.
Dataset acquired during mud circulation highlights interval of thief zones and potential leakage zones for the cement into the formation. The real-time surveillance of cement injection informs about the top of cement but also the in-fill of breakout intervals and the blockage of thief zones.
The long-term surveillance of the vertical temperature distribution enabled to determine the timing and intensity of the cement hydration process and provided a unique insight on the quality of the cementing operations and its possible correlation to breakout intervals and thief zones.
Active DTS was also used to confirm the completion installation as temperature diffuses differently depending on the presence or absence of gravel pack and the thickness of the cement sheath.
Our results show that downhole surveillance of cementing operations is possible using DTS. This technology enables high vertical accuracy in real-time and long-term surveillance providing insights on the quality of the cement bond. In this case study, DTS has proven to be a very valuable and reliable tool throughout the cementing operations at 4 wells.
A Case Study of Continuous Improvement: Successes and Challenges of the Norton Multi-Lateral Development
Authors: Dutta Brijesh , Cahill Quinton , Negrini Victor , Jelly Christian , Butler Ben , Kent David 
Published: November 2020

Abstract
The recent, sustained depression in global oil prices has driven a significant reduction in upstream Exploration and Production (EandP) expenditure, particularly in the capital-intensive offshore environment. The high costs traditionally associated with EandP development projects, specifically in subsea developments, have driven a requirement for the adoption of technologies that not only increase the efficiency of the well construction process, but also reduce the total number of wells required, whilst increasing production rates and recoverable reserves.
Building on recent industry experiences with the varying multilateral systems available, Woodside implemented the use of an alternative innovative multi-lateral system, which has gone through multiple evolutions and marked improvements in system reliability and installation efficiency compared to Woodside's previous multilateral experience. The latest evolution of this system has been implemented during the construction of multi-lateral wells for the Greater Enfield Project (GEP). Within GEP, the Norton over Laverda (NoL) field development comprises three tri-lateral production wells (namely NoL01, NoL02 and NoL03). Norton field is an offset to the Vincent field, which employed an alternative multi-lateral completion design. On average, the Norton multi-lateral well operations were executed 15-30% faster than previous comparable Woodside installations. This has been attributed to the application of operational learnings from the previous Vincent multi-lateral development and the implementation of the new system. These wells were constructed in water depths of &gt; 800 m, the deepest for such a system globally. Of the three wells, NoL01 and NoL02 were constructed well under budget, and ahead of schedule. NoL02 was constructed in a time that benchmarked as the fastest well per 1,000 m versus basin offsets. NoL03 was completed within budget, whilst having faced two major NPT (Non-Productive Time) events (ultimately resolved using world first solutions for the given system). This paper will discuss the successes, challenges experienced, and lessons learned during the installation of the three Norton tri-laterals. This field is a prime example of how new technology and the installation practices for multilateral systems within the operator's assets of the North-West margin of Australia have improved over time.
Well Integrity-Sealant Pressure Barrier for High Delta P, V0 Sealing and Long Durability
Authors: Shan Youngbin , Gao Wenxiang , Wang Xuelong , Xu Minglei , Cao Cong , Zhang Chao , Du Hai , Jin Xiaohu , Su Xiaodan , Wang Wenxiong 
Published: November 2020

Abstract
It is a great challenge for well integrity when a high volume gas production well is found with the production casing broken near the wellhead hanger resulting in high pressure communication between Annulus A and B.
The objective of the paper is to propose a new solution to establish a strong pressure barrier between annulus via a sealant system and to show that such a barrier has been proven to be durable for long time.
A proprietary resin sealant is the key technology and precise job planning and execution are also viewed as being vital to the success of treatments.
Because tubing flow pressure may reach up to 10,000 psi during production after recompletion, operator decided to pressure test the sealant barrier to 10,000 psi for a minimum of 30 minutes duration. If pressure drop during the pressure test is less than 100psi, then the well is allowed to be recompleted.
Several spots and squeezes of sealant eventually setup a strong pressure barrier and were pressure tested up to 10,000 psi in both A and B Annuli. There was no pressure communication at the other annulus in the 30 minute test period.
In the past six (6) years, the operator has tried several jobs to repair casing leaks but none were successful. It was the first time that a sealant system provided a solution to repair a casing leak and hold a high pressure differential.
During recompletion, the production packer failed to set but the operator decided to initiate production. A annulus pressure increased quickly and finally stabilized at 8700 psi. It is now a year since the job was completed in October, 2019, and B annulus pressure in has consistently remained at zero pressure. This has proved that the sealant technology can securely setup and provide a high pressure barrier which is valid for long term V0 sealing.
Evaluation of CO2 Injectivity for CO2-EOR Using a Two-Stage Well Test Approach: Case Study of a Chinese Tight Oil Reservoir
Authors: Honari Vahab , Wang Xiangzeng , Underschultz Jim , Garnett Andrew , Wang Xingjin , Johnson Raymond , Ribeiro Ayrton , Sedaghat Mohammad , Gao Ruimin , Liang Quansheng , Hurter Suzanne 
Published: November 2020

Abstract
CO2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO2 storage sites, mature oil fields are often considered primary targets for CO2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO2 storage and CO2 injectivity plays equally an important role for site selection to store CO2. Therefore, evaluation of CO2 dynamic storage capacity (injectivity) and ultimate CO2 enhanced oil recovery (EOR) are key elements for a successful CO2 storage – EOR project.
CO2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test.
A unique two-stage well testing approach was proposed to inject water and CO2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO2 fronts in the reservoir as well as CO2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir.
The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO2-EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO2-EOR project to unlock further oil resources from tight formations.
Validation of a Novel MEG Sensor Employing a Pilot-Scale Subsea Jumper
Authors: Kumar Asheesh , Di Lorenzo Mauricio , W. E. Norris Bruce , Lupeau Alexandre , Solheim Harald , M. Aman Zachary 
Published: November 2020

Abstract
Online pipeline management systems provide real-time and look-ahead functionality for production networks. However, they are limited by a dearth of data to inform their predictions. This represents a barrier to a true, high-fidelity ‘digital twin’ where greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, we present a novel MEG (Mono-ethylene glycol) sensing system from OneSubsea, the AquaWatcher v2.0, and validate it in our newly-constructed HyJump flowloop.
The HyJump flowloop has a unique subsea jumper-like geometry, with three low points and two high points and is equipped with a MEG sensor - mounted on the second low point. The sensor features an open-ended microwave frequency probe mounted flush to the pipe wall which measures the apparent permittivities of the liquid phases in the vicinity of the probe tip. It can determine the MEG concentration or water salinity by processing the measured permittivities, and has further shown that it may be able to detect hydrate deposition. Experimental work was performed to test the performance of this novel equipment while enabling a more accurate calculation of the overall mass balance in the flowloop.
An experimental campaign was conducted where, in each measurement, the jumper low points were loaded with aqueous solutions of MEG at mass fractions between 10 and 30 wt%. The entire loop was then pressurized with Perth city natural gas to 1200 psi. The pipe wall temperature was controlled with a cooling jacket in the range of 25.2 °F to 35.6 °F. These conditions simulate transient shut-down and restart operations with a high probability of hydrate formation. Results illustrate that the MEG content readings measured by the sensor were consistently accurate within a 5% relative deviation with respect to the nominal values. Further, flow restrictions due to hydrate deposition were assessed in their severity through differential pressure measurements, where it was observed that the measured MEG content oscillates significantly during hydrate sloughing-type events.
The HyJump flowloop facility offers a unique testbed for new subsea sensors, enabling performance evaluations with internal fluids at subsea conditions. The deployment of these novel sensors in the field will both improve the performance of integrated pipeline management solutions and assist operators in optimizing MEG injection dosages to enable higher fidelity hydrate management in subsea pipelines.
Middle East to India Pipeline
Authors: Nash Ian , Rawlings Matthew 
Published: November 2020

Abstract
This paper presents details of a comprehensive array of technical and commercial challenges associated with the feasibility of a long distance deepwater Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. It examines the techniques, analysis and technology development now available to make such challenging routes increasingly feasible.
The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan.
High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets.
The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas. The Middle East to India Deepwater Pipeline
Gorgon Produced Water Treatment and Disposal: Commissioning and Operating a Vital Part of LNG Production
Authors: O'Reilly Daniel , Yee Boniface , House Andrew 
Published: November 2020

Abstract
The Gorgon gas plant produces 15.6 Million Tonnes per Annum (MTPA) Liquified Natural Gas (LNG) from the Gorgon and Jansz-Io subsea gas fields. First LNG production commenced on the Barrow Island, Australia facility in 2016. One of the first systems commissioned was the wastewater treatment, collection and disposal system, a critical support utility for production operations. The Produced Water Disposal (PWD) facility is unique on Barrow Island due the location's national nature reserve status, and all treated waste must be disposed downhole. The objective of this paper is to review key lessons from design, startup and steady state operations. Perspectives will be given on facility/well management and production operations of PWD at the Gorgon plant.
Wastewater on Barrow Island is generated from several sources: Condensed water originating from hydrocarbon gas (separated at gas dehydration and Mono-Ethylene Glycol (MEG) regeneration facilities), drainage and runoff water from the plant, treated sewage effluent and other ad hoc liquid waste. These sources are collected and treated before the final product is pumped into two available onshore disposal wells. One of the challenges initially faced was that the disposal water quality did not meet the design specification required to maintain well performance. This problem reduced as the plant reached steady state operations and the team gained a better understanding of well performance over time. Other current challenges include hydrocarbon carryover and water polishing, so Engineering and Operations work together closely to ensure reliable water disposal and hence LNG production.
This case study will explore the success and lessons learnt in Gorgon PWD through a summary of field data, facility descriptions and experiences. An overview of the design will be given along with photographs of key components. The required design performance will be compared against actual operating data. In the new energy landscape, the Upstream Operators' social license to operate centers around our environmental performance. In our work we demonstrate that it is possible to treat and dispose of waste liquids responsibly while generating cashflow through LNG production.
Well Abandonment Efficiency Improvement through Collaboration!
Authors: Obodozie Ikenna , Blakeman Philip , Knox Brendan , Hutama Aditya , Firdaus Lutfy 
Published: November 2020

Abstract
The operator, rig contractor and services company formed a trilateral collaboration to plan the safe plug and abandonment of four onshore wells located in a densely populated region of Indonesia. These wells, located in scattered locations, posed a significant logistical challenge for project mobilization and moves between the wells. Well information was incomplete due to a change in asset ownership.
Some of the challenges faced in these wells were: Well integrity issues resulting from the presence of H2S and CO2Sustained casing pressureSurface water safetyFluid losses
Personnel safety and future well integrity was crucial to this operation. Consequently, plans were developed to conduct the operation safely and efficiently, as well as to provide solutions that mitigated well integrity challenges.
The method adopted for this project was to approach this as an integrated project where the collaboration team was responsible for planning, executing, monitoring and closing out all segments of the project. Well information from the previous field operator was analyzed and a solution to safely plug and abandon these wells was created. Because inadequate well information posed a major challenge, the collaboration team planned multiple contingencies. An abandon-the well-on-paper (AWOP) workshop was organized to review and refine the execution plan.
An intelligent coiled tubing system, which could be used for simultaneous logging and pumping operations, was selected as well as an efficient and environmentally friendly mechanical pipe cutter that did not use explosives or hazardous chemical substances for tubing severance operations. The sustained casing pressure challenges (in previously fully cemented/non sealing annuli) were addressed by using advanced milling technology for section milling.
The early engagement plan enabled development of a project execution strategy that clearly outlined equipment mobilization schedules from various locations in Indonesia. Because of the collaborative projects structure, local personnel recruited for this project were quickly on boarded and integrated with the rest of the project team. This approach led to the safe and efficient execution of the plug-and-abandonment scope of work, with zero HS&E incidents and 167 perfect HS&E days during project execution.
Extensive testing of cement mix water was introduced to this project. The testing improved the cement design and enabled accurate plan transition times that reduced waiting on cement. Based on lessons learnt from the first well, extensive logging operations were performed to determine the formation temperature and specific leak locations in the casing. These pre-cementing logging operations helped in collecting accurate well temperature and pressure information that aided the design of cement recipes for the barriers placed in these wells.
A Novel Application of Filter Cake Remover to Free Differential Stuck Pipe
Authors: Egbe Peter , Al-Mousa Fawaz , Gadalla Ahmed 
Published: November 2020

Abstract
Historically, stuck-pipe events have been shown to cost the industry several hundred millions of dollars per year, and over 30% non-productive time (Muqeem et al. 2012). In all cases, remedial operations to salvage the subject well are expensive; and success is not guaranteed. This paper describes a case history demonstrating how a differentially stuck string was freed in a relatively short time using an innovative enzyme/weak acid recipe.
The string was a 4-1/2 in. lower completions bottom hole assembly (BHA) comprising of swell packers, and inflow control devices. The string was deployed in a carbonate reservoir. After deploying the string in the first 1,000 ft of open hole, the crew stopped to fill up the string to confirm circulation. Upon resumption of operations, the completions string was found to be stuck with no string movement possible in the upward or downward direction. Full circulation was still achieved. The fluid in hole was a water-based fluid.
The string was diagnosed to be differentially stuck. It was established that the stuck point was across the high permeable zone. Efforts to work the string free with glycol pills proved unsuccessful. An attempt to place 20%; HCl acid induced up to 30 - 40 barrels per hour (BPH) dynamic losses at the shoe. Luckily, the losses healed relatively quickly, but the string remained stuck. After 29 hours of several unsuccessful attempts, a recipe of an enhanced combination pill of enzymes, and a weak acid accelerator was proposed, pumped across the stuck point, and allowed to soak. After a relatively shorter period of soaking, the string became free. The action of the enzyme/acid pill worked by destroying the polymer base of the filter cake created by the water-based drilling fluid. The homogeneous placement and action of the enzyme/weak acid pill across the stuck area ensured that it was more effective than the conventional HCL acid pill. Hence, the application is being presented as a potentially safe, efficient, and cost-effective option to free a differentially stuck BHA in water-based drilling fluid.
Success in freeing a stuck-pipe usually depends on two critical factors - an accurate diagnosis of the mode of stuck-pipe event (i.e. differentially or mechanically); and the ability to implement the remedial operations quickly, and effectively. By implementing the above described technique, significant non- productive time (NPT) was averted. The technique has since been implemented in subsequent differential stuck-pipe events in water-based drilling fluids with a 100%; success rate.