bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intermittent Gas Lift Technology for Optimising Production from an Oilfield Using Next Generation IoT Based Intelligent Autonomous Controller
Authors: Tyagi Himanshu 
Published: February 2023

Abstract
This paper outlines an approach to optimize production from a shallow, low bottomhole pressure (BHP) reservoir in a mature onshore oilfield by the application of intermittent gas lift technology using Next Generation Internet of Things (IoT) based Intelligent Controller which works on industry 4.0 technologies. Enhanced software-based analysis, design, optimization, and automation has proved to be effective in enhancing the production rate from an existing gas lifted well.
A selection criterion and workflow setup were devised for a major operator to enhance the efficiency of a gas lift system. Low production capacity wells were analyzed, designed, and troubleshooted from an intermittent gas lift technology perspective. It incorporated an IoT-based intelligent autonomous surface controller with a minimal change in downhole completion jewelry which eliminated the need of workovers, optimized oil production, reduced over injection of gas, diminished downtime, and improved the effectiveness of the overall petroleum production process beyond the capability of a conventional gas lift system.
This system was successfully installed in wells with 2.375-in. tubing without any production deferment. A pilot project on sixteen wells for a major operator in the Middle East exhibited a significant improvement in well performance with an incremental gain of 600 bfpd along with savings of 5 mmscfd of injection gas. It is a cost-effective technology to optimize production and enhance the field value from existing wells.
This paper considers cases in which an integrated software-automation portfolio helps in reviving and increasing ultimate recovery and recommends suitable actions which allow production engineers to analyze performance of reviving existing oil wells. With the increased complexity of mature fields, each next step to enhance recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.
Success Stories and Lessons Learned from Pilot Implementation of Unmanned Air Vehicle and Computer Vision to Improve Transmission & Distribution Reliability in Complex Oilfield
Authors: Yudhy Muhammad , Pratama Muhammad , Wibawa Ramdhan , Lubis Ardiyansyah , Pujihatma Priambudi 
Published: February 2023

AbstractElectrical power supply reliability is a key enabler in supporting massive and aggressive exploration and exploitation campaigns in the upstream sector. For a certain complex oilfield asset, a total of more than 3,000 km of power transmission and distribution lines are operated and maintained to support its massive operation. All these power lines shall be monitored and inspected regularly to ensure it is free of operational threat that could reduce their reliability. From historical data, there are two main threats in power line operations, vegetation risk (trees and animals) and broken insulators. The current method of manual inspection and monitoring through Operator Routine Duties Check (ORDC) is not very effective since it took a considerably long period to complete and can only cover a limited area for each inspection activity session whereas the area to be inspected is vast. As a result, the inspection and monitoring program was sub-optimal to detecting the operational threat earlier.The advances in digital technology, particularly computer vision, cloud computing, and artificial intelligence, enable every device with a camera and internet connection to become additional "eyes" that monitor, inspect and analyze everything in sight. One of the optical devices with high potential for utilization in power system inspection is the Unmanned Aerial Vehicle (UAV) or best known as the drone. Drone enhanced with computer vision will have the optimal capability for inspection and surveillance of vegetation risk and broken insulators for larger areas in each inspection round. Hence, we could automate the inspection and surveillance activities and even improve their effectiveness and efficiency compared with the manual method.In this paper, we will discuss the successful pilot implementation of drones, computer vision, and artificial intelligence technology in power system operations that have improved the effectiveness of the surveillance program at a lower cost. The pilot implementation has been proven to reduce the number of power outages caused by vegetation risk and broken insulators by 50% and bring verified financial benefit of USD 7,619 per month from avoiding loss of production opportunities due to power outages related to vegetation risk and broken insulators. The financial benefit can pay off the implementation cost in 4 months of continuous operation. As a path forward, the pilot implementation will be expanded further to several other areas with a high risk of vegetation threat and broken insulators to assess its applicability in other locations before full-scale implementation.
Successful Drilling of the Deepest and Hottest HPHT Carbonate Well in Offshore Malaysia, its Lesson Learnt and Way Forward
Authors: Ong Swee Hong Gary , Chia Boon Shin , Umar Lawrence , Kongpat Nitipong 
Published: February 2023

Abstract
HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty- gritty details are overlooked. The complexity is amplified with high risk of losses in carbonate reservoir with high level of contaminants compounded by the requirement of high mud weight above 17 ppg during monsoon season in an offshore environment.
The above sums up the challenges an operator had to manage in a groundbreaking HPHT carbonate appraisal well which had successfully pushed the historical envelope of such well category in Central Luconia area, off the coast of Sarawak where one of the new records of the deepest and hottest carbonate HPHT well had been created.
This well took almost 4 months to drill with production testing carried out in a safe and efficient manner whereby more than 4000m of vertical interval was covered by 6 hole sections.
With the seamless support from host authority, JV partners and all contractors, the well was successfully delivered within the planned duration and cost, despite the extreme challenges brought about by the COVID-19 pandemic.
This paper will share the experience of the entire cycle from pre job engineering/planning, execution, key lesson learnt and optimization plan for future exploitations which includes an appraisal well and followed by more than a dozen of development wells.
A Customised Solution Using Catenary Coiled Tubing to Deploy a Gas Lift Valve Deepening System With Straddle Packers For a Challenging Horizontal Well Offshore Brunei
Authors: Lim Hong Chean , Leong Azemi , Azizan Yusri , Yusoff Khairul , Sabri Daniel , Hu Ziwei , Adizamri Rudzaifi 
Published: February 2023

Abstract
An offshore horizontal oil well was identified as having multiple tubing leaks and depleting reservoir pressure. Intervention was required to reinstate the well and optimize the gas lift system performance to maximize oil recovery.
Various challenges were identified in the project design stage due to the horizontal well trajectory and its potential to cause debris obstructions combined with the absence of any capability to monitor downhole parameters. Software simulations were performed to determine the downhole reach limitations of the rigid tool string to ensure that the deepest Gas Lift Valve (GLV) could be successfully deployed to the target depth under live well conditions. The viability of safely deploying such a long Bottom Hole Assembly (BHA) from a limited deck space with a short riser height also needed to be resolved. To accomplish this while maintaining a double barrier on a live well without setting a deep plug and killing the well required detailed planning. A specific space out of the Coiled Tubing (CT) Pressure Control Equipment (PCE) was tailored to enable the simultaneous holding of a 350 meters long gas lift string while also allowing make-up of the packer assembly on surface. Due to the completion design not containing a suitable profile for depth reference with a conventional mechanical locator tool, the Real-Time (RT) catenary CT system was selected as an ideal method of achieving reliable depth correlation.
The catenary CT system, equipped with a BHA containing various RT sensors such as pressure, temperature, compression, tension, inclination, Casing Collar Locator (CCL), Gamma-Ray (GR), and torque, was critical in monitoring the downhole parameters in this challenging trajectory to allow decision making and confirmation during the packer setting process. Despite the complexity of job design, preparation, and operational planning with challenges involving pumping, flowback, and the CT package set up in an offshore environment, this customized solution successfully deployed 350 meters of GLV deepening string with precisely set straddle packers to isolate the leak points without any issues. The completion of this project successfully reinstated significant production following a prolonged shut-in period, and gas lift performance was optimized for maximum oil recovery from the considerable remaining oil reserves in the reservoir.
This project marked the first successful deployment of a thru-tubing GLV deepening system on a horizontal well for the asset operator. The catenary CT system was an effective solution that managed to safely achieve all of the objectives while overcoming all the challenges faced throughout the project.
Overcoming Flow Assurance Challenges of the First Deepwater Gas Field in Malaysia
Authors: Kiertkul Suphawat , Saranyasoontorn Korn 
Published: February 2023

Abstract
Block H, located in 1,300 meters of water depth at offshore Sabah, consists of Rotan and Buluh fields. The subsea trees, jumpers, manifold, umbilicals, risers and flowlines were installed and tied-back to an FLNG facility. The objective of this project was to develop most practical and effective solutions to overcome flow assurance challenges owing to low seabed temperature and high-pressure gas to achieve 1st gas from the first deepwater gas field in Malaysia.
A model was built in OLGA software with all field conditions to run simulations and predict process parameters at every critical point in subsea wells, risers and flowlines as well as topside facilities. Besides, all constraints from the subsea wells, jumpers, risers and flowlines all the way to topside inlet receiving facilities were carefully reviewed and optimized with an abundance of caution to determine the stepwise approach by utilizing the high-pressure gas from wells to remove around 1,000 m3 of pre-filled MEG fluid out of the flowline, called ‘DeMEG operation’ before feeding gas to LNG process operations.
With 200-230 barg pressures from deepwater gas wells and 2-4°C temperature at seabed as well as pre-existing water content in saturated gas given by reservoir aquifer, this start-up operation would expect to be in the hydrate zone. One of the unavoidable potential consequences was a hydrate formation and could result in plugging of jumpers, risers or even flowlines.
The DeMEG operation results indicated the lowest temperature at the downstream of the subsea choke was −23°C due to Joule-Thompson cooling during the cold start. One mitigation strategy was to inject a batch of MeOH at the subsea wellhead until the temperature is above the hydrate point. After the gas flowed along the flowlines, it would cool down to the seabed temperature during the steady state condition. Hence, additional mitigation was to continuously inject Mono Ethylene Glycol (MEG) as another thermodynamic hydrate inhibitor mixed with gas stream. The MEG affixed water molecules and thus deterred them from forming a cage around gas molecules to prevent hydrate formation.
A multi-stage DeMEG operation was carefully planned to overcome liquid handling capacity at topside and eventually executed at offshore until the remaining MEG in the flowline was as low as reasonably practical to proceed with gas production from the field.
With an excellent collaboration from the team and proper planning, the DeMEG solution together with hydrate mitigation strategy were proven to be effective and the commissioning operation was successfully completed as per the plan until the 1st gas was achieved on 6-Feb-21 and supplied to FLNG. The 1st LNG drop subsequently came in 7 days later. This field has increased production volume around 270MMSCFD, equivalent to 45,000 barrels of oil per day to PTTEP and JV partners.
3D Fault Seal Analysis of the Jasmine Field, Gulf of Thailand: Capillary Pressure Estimation and Calibration Using Fluid Contact Data
Authors: Wilson Paul , Povey Danny , Davies Russell , Prasongtham Pattarapong , Shibano Siriporn , Ampaiwan Tianpan , Nuada I Nengah , Saifuddin Farid 
Published: February 2023

AbstractWe present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.
Cause Analyses and Countermeasures of Abnormal-Low-Production Wells in Jingbian Tight Gas Reservoir, Ordos Basin
Authors: Wang Yang , Yao Yuedong , Wu Hao , Dai Jinyou , Wang Lian , Mu Zhongqi 
Published: February 2023

AbstractLow-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied.To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs.The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows:The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m3. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m3.All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production.This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.
Reservoir Souring in Mature Offshore Field Malaysia: Root Cause, Mitigation, and Management of H2S
Authors: Mithani Aijaz Hussain , Rosland Eadie Azhar , Jamaludin M Aiman , W Ismail W Rokiah , Lajawai Maxwell Tommie , A Salam Irzie Hani , Mousavi Mirkalaei Seyed Mousa 
Published: February 2023

AbstractThe field under study is a mature brownfield with no H2S in the fluid stream (PVT) at the time of development. However, concentrations more than 1000 ppm were recorded recently causing wells to shut in (a few already shut). Hence, to bring these wells on stream an assessment of souring potential in the field is required. This paper is the results of our experience in H2S mapping at reservoir-well-facilities modelling, history matching, and prediction of H2S. We will highlight the workflow adopted to find the root causes of souring via sampling and modelling approach since the H2S is measured throughout the field across all the reservoirs, including those undergoing waterflood. Moreover, various options that were studied through simulation will be discussed for mitigation and management of H2S within this field to safeguard the production, and thus recovery of the field.A systematic phased approach is adopted to mitigate and manage the unwanted sour gas (H2S). In the first phase, we performed the analysis of the historical development of H2S throughout the field and developed the concept for possible souring causes. In the second phase, we designed and conducted a comprehensive sampling and laboratory analysis program end-to-end to fill the existing knowledge gap. In the third phase, we performed 3D dynamic reservoir souring modelling where we history matched the H2S and assessed the future potential via forecasting. Finally, we developed multiple mitigation scenarios ranging from nitrate injection, sulphate reducing unit, limiting the nutrient supply for microbe growth via water mixing, etc.It was evident that a) increased injection water contributed to souring wells, b) link between souring wells and nutrient availability, c) increased negative fractioning of a Sulphur isotope as H2S concentration increases, and d) and mesophilic SRBs detected in some souring wells. This evidence suggested that BSR is the predominant cause of souring. It was also seen based on water chemistry that injection water was rich in sulfate while formation water was rich in volatile fatty acids. Results indicate that the nitrate injection (up to 200 ppm) alone may not be an attractive option to mitigate the H2S within this field. However, the combination of SRU and nitrate injection of 150 ppm could be a technically feasible option to mitigate such high concentration of H2S within allowable facilities limits.
Fragrant Flower Extracts as Corrosion Inhibitors in the Oil and Gas Industry
Authors: Almubarak Tariq , Ng Jun Hong , Almubarak Majed , AlOtaibi Fares 
Published: February 2023

AbstractCorrosion inhibitors used in the petroleum industry are a necessity to include in any acid job. When corrosion occurs to downhole tubulars and equipment, huge expenses are required to maintain the integrity and performance of the well. Unfortunately, commonly used corrosion inhibitors are accompanied with extreme environmental concerns and risk to human health. The recent developments in corrosion inhibitors have resolved the environmental aspect by focusing on biodegradability of these compounds, however, these inhibitors still struggle with issues of toxicity and high temperature stability. The project aims to develop new green, non-toxic, environmentally friendly corrosion inhibitors capable of performing well at high temperature conditions faced in the oil and gas industry.To achieve this goal, 13 commonly available flowers were screened for corrosion inhibition properties. The tests involved using low carbon steel (N-80) coupons and exposing them to 15 wt.% HCl solutions at temperatures between room temperature and 250 °F using a HPHT corrosion reactor to imitate oilfield conditions. A concentration of 0.2-2 wt.% grounded flowers were used to prevent corrosion. Moreover, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing flowers, extracts of these flowers were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance.The corrosion inhibition efficiency of the different flowers was compared at various concentrations and temperatures as well as the effect of adding corrosion inhibitor intensifiers. The results revealed that one new inhibitor can be developed from the 13 flower samples tested. The corrosion rate of the flower extract after 6 hours at 150°F was 0.0398 lb/ft2. Additionally, this flower extract was assessed at 200°F and 250°F with the addition of 1 wt.% corrosion inhibitor intensifier and exhibited a corrosion rate of 0.00823 lb/ft2 and 0.0141 lb/ft2, respectively.The results in this work share one new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from flowers and can successfully protect the tubular during acid treatments achieving rates below the industry standard of 0.05 lb/ft2 for 6 hours at temperatures up to 250°F.