bluuebunny/crossref_metadata_2025 huggingface dataset:
Frontline Maintenance Re-Strategy: Perspective of Cost-Benefit Analysis
Authors: Alfarisi Haidar Husein , W M Yaakub W M Nadzmi , Zukhri Syifaa
Published: February 2023

Effective August 2021, Malaysia Assets Reset has launched Clustered Maintenance Planning and Execution (CMPE) department towards value focused asset management. To align with the department aspiration to continually generating optimum cashflow as well as staff upskilling, this study focuses on one of CMPE key result areas, with its main objective is to steer frontline maintenance work practice to value-generation perspective.

Cost-Benefit Analysis (CBA) process is used in this study to analyze which maintenance tasks to proceed and which to forgo. It is performed by comparing the cost of frontline maintenance versus outsourcing for a maintenance task over a period of time. Elements taking into consideration for the cost calculation are materials, special tools, additional cost required to ensure internal resources competent to perform the job, outsourcing contract rate (on annual basis), and logistics associated costs.

Currently, CBA assessment has been performed by CMPE on 15 potential maintenance tasks which was previously executed via outsourcing. Based on the cost saving/cost incurred derived from Frontline Maintenance versus outsourcing, 14 of the tasks are classified as cost-effective. Taking into consideration of clustered planning and scheduling, each planner are required to further assess on the perspective of manpower availability and re-strategize on manpower arrangement to execute the maintenance task via frontline maintenance. This CBA assessment not only resulted to an increase of 29% total planned frontline maintenance activities in 2022 versus pool of activities performed in 2021 but also contributed to additional technical skill sets to perform value-added maintenance tasks.

The assessment via CBA has added value-generation perspective in identifying cost-effective and feasibility of the activities selected. By performing this study, it has supported towards achieving the company End State Aspiration.
A New Method to Calculate Loading Liquid Water of Gas Wells in Qinghai Oilfield
Authors: Wang Haoyu , Du Jing , Chen Jun , Cao Guangqiang , Li Nan , Zhu Jianjun , Jia Min , Yang Xiaopeng
Published: February 2023

Sebei Gas Field is located in the Qaidam Basin, China, and is an unconsolidated sandstone gas reservoir with edge and bottom water layers. This special characteristics is a great challenge for gas production. As liquid column in the wellbore with a height of 1000 meters will bring 100 times of atmospheric pressure to the bottom of the well. Once the pressure of water in the wellbore is higher than the bottom hole flow pressure, the gas well will face the risk of shutdown. Actually most of the wells in Sebei, which have produced for several years, are producing water and taking drainage measures to assist gas producing. However, the exact moment of liquid loading is hard to determine, therefore the following drainage measures, also known as deliquifications, are difficult to design and optimize. Accurately and timely judging the degree and the height of liquid loading in the wellbore is one of the prerequisites for rational deliquification design. In this paper, Dr. Cao's liquid loading calculating model is applied to compute liquid loading in Sebei gas wells. The model is verified to be strong while the water production is relatively low but bring more errors for high water production. To solve the problem, a machine learning method is used to optimized and modified Cao’s model by adding a dynamic correction coefficient.
New Innovative Approach to the Upgrade of Ageing Existing Offshore WellHead Platforms
Authors: Jandali Morhaf W. , Hajri Khamis M.
Published: February 2023

This paper details a slip-over design concept and challenges for the replacement of existing ageing offshore Well-Head (WH) fixed platforms for relatively shallow and deep-water fields applications. A cost-effective slip-over design concept for replacement of existing platforms and the utilization of existing wells with cost effective reduction and increased oil production has been developed. The design has been implemented repeatedly in relatively shallow water offshore fields that requires minimum offshore execution work schedule with minimum installation risk, optimized shutdown duration and minimum loss of oil production. Further enhancement of the design ensured any future plan for installation of a slipover platform in a relatively deeper water would overcome the requirement for a much bigger derrick vessel hook-height capacity mobilization. The new developed slipover structure design, which is based on Company's standardized, simplified and SIMOPS (simultaneous operations capable) (SSS) multi-bay four (4) legged jacket, is compliant with all the latest Company and applicable international standards, which involves the demolishing of existing structure together with the leg-through piles to a depth of between 1.5-2.0m below seabed and transported to reclamation site, while existing well conductors remain and are secured in place. A new slipover platform is installed over existing conductors with additional well slots design utilizing the same existing platform seabed location for increased production. A minimum shutdown requirement for installation, additional production potential and reduced CAPEX and OPEX are achieved. This design concept is also extended to a relatively deep-water fields application by either, the mobilization of a higher installation derrick vessel hook-height lift elevation for utilization over existing free-standing wells or the use of a two-piece stacked jacket design.
Expanding the Envelopes of Openhole Gravel Packing in Sabah Deepwater Malaysia
Authors: Nopsiri Noppanan , Samuel Elvy , Chan Fong Lee , Kalalo Alxner , Moses Nicholas , Jayadi Agus , Yi Ding
Published: February 2023

Amongst the challenges encountered during infill drilling and completion is the requirement to penetrate depleted zones drained during the early phases of the field development. This condition is exacerbated for completions requiring openhole gravel pack as the maximum openhole lengths are traditionally limited by the effective circulating density experienced during the openhole drilling and gravel packing. This paper discusses the techniques implemented in four openhole gravel pack completions with openhole lengths up to 858m marking a new record for the longest openhole completed by PTTEP in this field. The wells were deployed by PTTEP in the Malaysian Deepwater Block K, during the field development of Siakap North Petai Phase 2, executed between Q4 2021 and Q1 2022.
Identification of Downhole Emulsion in a Light Oil Development and Demulsifier Injection for Increasing Production
Authors: Vu Huu Huy , Rangponsumrit Manisa , Hoang Ngoc Dong , Nguyen Duy Hung , Tran Hai Nam , Phi Ngoc Nguyen , Roche Tony , Dang Viet Long , Tran Minh Dung
Published: February 2023

TGT field is located offshore Vietnam, at a water depth of 45m and approximately 100km Southeast of Vung Tau. The field started production in 2011 and is currently producing about 13k bopd. The produced crude is 38-40 deg. API with viscosity of 0.45 cP at reservoir conditions and classified as light oil.

The field consists of three wellhead platforms with nearly 40 production wells, all being gas lifted. Emulsion, which is rarely encountered in downhole environment and not reported in the surrounding oil fields, was diagnosed to be present in production tubing of TGT wells by two indications: measured bottom-hole flowing pressure (BHFP) remarkably higher than calculated value, and emulsion observed on surface well fluid samples.

Upon completion of the laboratory testing for chemical selection, in early 2020 a field trial was carried out by injecting demulsifier into the production tubing of selected wells via the chemical injection line or together with lift gas. A successful field trial resulted in a clear reduction of BHFP of the wells along with a production increase by approximately 13% from 8 tested wells. Due to the low-cost of the application and major economic gain compared to other IOR methods, long-term downhole demulsifier injection has been applied in additional wells for increasing the field production.

Unlike for heavy oil developments, there is a lack of publications on downhole emulsion and demulsification for light oil fields. This paper describes a case study for application in a light oil field, covering identification of the wells having an emulsion issue in the production tubing, laboratory testing for selecting demulsifier, challenges in chemical deployment and the field trial results.
Anti-Agglomerants: Study of Hydrate Structural, Gas Composition, Hydrate Amount, and Water Cut Effect
Authors: Aminnaji Morteza , Hase Alfred , Crombie Laura
Published: February 2023

Kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) – known as low dosage hydrate inhibitors (LDHIs) – have been used widely for gas hydrate prevention in oil and gas operations. They offer significant advantages over thermodynamic inhibitors (e.g., methanol and glycols). While significant works have been done on KHIs evaluation, AAs suffer from their evaluation in terms of hydrate structural effect, gas composition, water cut, and hydrate amount, which are the main objectives of this work.

A Shut-in-Restart procedure was carried out to experimentally evaluate (using a visual rocking cell) various commercial AAs in different gas compositions (from a simple methane system to multicomponent natural gas systems). The kinetics of hydrate growth rate and the amount of hydrate formation in the presence of AAs were also analysed using the recorded pressure-temperature data. The amount of hydrate formation (WCH: percentage of water converted to hydrate) was also calculated by pressure drop and establishing the pressure-temperature hydrate flash.

The experimental results from the step heating equilibrium point measurement suggest the formation of multiple hydrate structures or phases in order of thermodynamic stability rather than the formation of simple structure II hydrate in the multicomponent natural gas system. The initial findings of experimental studies show that the performance of AAs is not identical for different gas compositions. This is potentially due to the hydrate structural effect on AAs performance. For example, while a commercially available AA (as tested here) could not prevent hydrate agglomeration/blockage in the methane system (plugging occurred after 2% hydrate formed in the system), it showed a much better performance in the natural gas systems. In addition, while hydrate plugging was not observed in the visual rocking cell in the rich natural gas system with AA (at a high subcooling temperature of ∼15°C), some hydrate agglomeration and hydrate plugging were observed for the lean natural gas system at the same subcooling temperature. It is speculated that methane hydrate structure I is potentially the main reason for hydrate plugging and failure of AAs. Finally, the results indicate that water cut%, gas composition, and AAs concentration have a significant effect on hydrate growth rate and hydrate plugging.

In addition to increasing confidence in AAs field use, findings potentially have novel applications with respect to hydrate structural effect on plugging and hydrate plug calculation. A robust pressure-temperature hydrate flash calculation is required to calculate the percent of water converted to hydrate during hydrate growth in the presence of AAs.
Application of New Technologies and Best Operational Practices to Accelerate the Learning Curve in Wells Drilled in the Ayatsil Field, Mexico
Authors: Merchan Nájera Andrés Isaac , Urribarri Romero Orlando José , Jimenez Rangel Hector Hugo , Gonzalez Mendoza Luis Daniel , Ramírez Fuentes Erik Alberto , Rodriguez Efrain Jose , Zarate Vergara Marco Antonio
Published: February 2023

Today drilling wells is one of the biggest capital expenditures and is employed starting from exploration, delineation, initial wells for production, and fresh production incorporation when existing wells production have declined. The estimated cost for drilling new wells in Ayatsil field is around 20 to 25 MM $, which requires a high level of decision to achieve production goals without exceeding the budget assigned to the Ayatsil field. Therefore, to make the right decision requires an integration of multidisciplinary group of specialists (geologists, geomechanics, reservoir engineers, production engineers and drilling engineers) from well design to execution phases.

This paper will illustrate the methodology and process applied by the operator to optimize the drilling stages and accelerate field production, as a result the operator developed the operational excellence project, that consist of five phases and being executed by a multidisciplinary project team.

The drilling team has been successful in reducing the depth versus days curves from an average of 130 days in 2017 to an average of less than 58 days in 2022. The best performance achieved till now in terms of total meterage is 4,200 meters drilled in 51 days from the surface. The continuous improvement of the Ayatsil project has resulted in world class drilling performance.

The success factors include standardized well design, performance improvement processes that was made possible by the multidisciplinary well decision team like, flat times efficiency. In addition, the outcome of this approach has resulted that 30 to 33 million dollars have been saved from the original budget in reduction of well costs and impulse the productivity of Ayatsil field.
Effective Utilisation of Underbalanced Perforation with Electrical Submersible Pump's Boost Oil Production of Mature Oil Field in Western Desert of Egypt: Case Study
Authors: Sayed Mohamed , Sabaa Ahmed , Samir Ahmed , Mokhtar Mohamed , Medhat Ahmed , El-Wakil Ahmed
Published: February 2023

Conventionally, the transition from completion to production often requires the well to be killed immediately after perforation is completed, thus exposing the formation to potentially damaging killing fluid. To obtain a perforation tunnel with maximum productivity, this transition requires an optimal clean-up and removal of the perforation damages.

Underbalance perforation through Tubing Conveyed Perforating (TCP) system is one of the best practices to ensure less damage to the perforation tunnels (perforating skin) leading to increased well productivity. However, it is very challenging in cases of completions with Electrical Submersible Pump's (ESP) to maintain productivity with undamaged reservoir by preventing any contact between reservoir and completion fluid and achieve the above simultaneously with safe well control during ESP deployment. Otherwise, the alternative solution is to run TCP string in single run then kill the well after perforation in order to install the ESP completion.

As a result of the increasing emphasis on reducing operating costs, maximizing well productivity, and minimizing wellbore clean-up time, an integrated solution was designed and successfully implemented for perforating artificially lifted wells in static underbalanced condition and installing ESP completion in single run without killing the well. It combines the use of TCP system equipped with automatic release gun hanger. TCP gun string has been set by Electric Line against the required intervals, then the ESP has been separately installed and the guns has been activated through an electronic firing head for a shoot-and-drop operation. The static underbalance condition has been created by the ESP thanks to the programmed delayed firing time. After this operation, the well has been directly lined up to production flowline with minimal wellbore clean-up time. The combination of static underbalanced perforation with deep penetration charges which is able to bypass invasion zone, can create a clean perforation tunnel, and significantly reduce the post-perforating damage by killing fluid, and finally maximize the well productivity. Despite the challenging reservoir conditions (Depth= 16,500 FT, Pressure=6250 Psi, Temperature= 285 deg. F, Porosity = 8%), the Productivity Index (PI) of the wells were three times compared to the offset wells.

Five jobs have been performed by Agiba Petroleum Company, one of the main operators in Western Desert of Egypt, employing this combined TCP-ESP technique which has resulted in significant savings in rig time and increased operating efficiency. This paper summarizes the practical experiences gained during the development and deployment of this integrated technique, in addition to an evaluation of the impact compared to the conventional perforation techniques through ESP downhole sensor data and well modelling.
Intelligent Risk Based Cybersecurity Protection for Industrial Systems Control - A Feasibility Study
Authors: Houmb Siv Hilde , Iversen Fionn , Ewald Robert , Færaas Einar
Published: February 2023

Intelligent automated industrial process control requires a higher level of systems integration and connectedness than what has traditionally been the case. With such development comes increased risk of cyber-attack for Operational Technology (OT) systems such as Industrial Control Systems (ICS). For ICS, cyber-attacks can have significant consequences also in the physical world, with potentially catastrophic consequences, as experienced in the Colonial Pipeline and the Ukraine Power Grid attacks. Physical risk to the work environment, the product, and surroundings should therefore be accounted for in cybersecurity solutions for ICS.

For this purpose, models and methods are required that consider the function of the whole Cyber-Physical System (CPS) not just the ICS, with the capability of detecting and correlating observations across the layers of system control, including the physical process being controlled. To achieve this, a context-based detection approach that can model the CPS and combine this with a process-aware risk analysis for attack response is proposed. The approach also needs to be adaptable (intelligent) to account for the process dynamics and the evolving cyber-attack threats. For this purpose, diagnostic models adapted to the industrial process should be applied together with situational awareness monitoring and cyber-attack detection tools, such as ICS Intrusion Detection Systems (IDS). The capability of the ICS IDS therefore needs to be extended to cover both Information Technology (IT) and OT parts of the ICS and include an understanding of the physical system and process as a knowledge basis, fed by process sensor and instrumentation data. These diagnostic models must cover the whole CPS in the risk analysis to provide aid in the attack response decision making. To achieve this, the models need to combine the physical characteristics of the process with the characteristics of the other system layers.

Based on studies in a drilling control system environment, results indicate that existing tools can be used to detect and discern between different types of cyber-attack on Cyber-Physical Systems (CPS). This indicates feasibility with respect to monitoring of the OT and IT part of the system for building risk-based cybersecurity solutions. The challenge and novel part are to extend IT and OT systems cyber detection with automated evaluation of the resulting process risk taking physical process information into account, to make response decisions not only based on potential digital consequences but also consequences for the process and physical world.
Intermittent Gas Lift Technology for Optimising Production from an Oilfield Using Next Generation IoT Based Intelligent Autonomous Controller
Authors: Tyagi Himanshu
Published: February 2023

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

Electrical 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

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

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

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

We 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

Low-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

The 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

Corrosion 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.
Advancement of Open Hole Gravel Pack and Zonal Isolation with Selective Intelligent Completion in Deepwater Malaysia
Authors: Samuel Elvy , Nopsiri Noppanan , Chan Fong Lee , Kalalo Alxner , Moses Nicholas , Jayadi Agus , Yi Ding , Nordin Amirul , Teoh Melissa
Published: February 2023

As fields mature, the drilling and completion design and execution for infill development becomes challenging. In a deepwater environment, one of the strategies to address this challenge is to optimize subsea facilities by targeting several reservoir packages in a single wellbore. However, this technique comes with technical challenges because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. A smart completion architecture should overcome these constraints and reduce overall capital expenditure while maximizing production. Furthermore, for wells requiring sand control, the completion solution must ensure a reliable and proven approach that minimizes the potential completion failures introduced by unsuccessful sand retention. This paper presents the completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K, during the field development of Siakap North Petai (SNP) Phase 2 and executed in Q1 2022.
Production Optimisation and Surface Network Debottlenecking Using an Integrated Asset Model for Vietnam Offshore Field Development
Authors: Le Quang Dat , Hoang Ngoc Dong , Rangponsumrit Manisa , Supalasate Phruettiphan , Ngo Khanh Dong , Nguyen Duy Hung , Tran Minh Dung , Ho Van Tam , Luong Van Chi , Ali Samad , Antoneus Sarjono Tasi , Khan Osama Hasan , Hii Sing Kiet
Published: February 2023

CNV field in offshore Vietnam is experiencing excessive surface back pressure due to extended production pipeline and increasing field gas-oil ratio (GOR), which not only constraints the production from existing wells but also creates a challenge in evaluating production gain from future development activities. Therefore, it is critical to properly account the back pressure effect to generate a reliable long term production forecast for further investment decision.

This paper describes the details of integrating subsurface dynamic reservoir simulation model with surface network simulation model to holistically assess the impact of back pressure. The conventional method of using standalone dynamic simulation model is compared against the integrated model. The well control mode in the reservoir model is updated with the response of the network model, which consist of wells, topside piping, facility equipment and export pipelines. With this approach, the surface pressure constraints and responses will be captured, and the reservoir, well and network performance will be impacted accordingly. A unified field management is designed using an advanced orchestration engine to control the well operating conditions, schedule well activities and activation of equipment in the operational cycle.

Thorough assessment can be performed with the inclusion of accounting interactions between reservoir and network parameters. This integrated modelling workflow allows multiple domains of reservoir engineering, production engineering and engineering contractors to collaborate and achieve a better understanding of the impact of surface back pressure by producing a representative forecast of production profile.

To address the back pressure problem in the current facility, debottleneck the surface network and improve production was evaluated by installation of additional surface equipments such as booster pump and compressor. In general, the integrated model provides critical insights to the field development planning, evaluation for de-bottle necking surface system and production optimization.

There is lack of publication on the successful usage of the integrated surface network with subsurface dynamic simulation as it is uncommon for this feature in conventional modelling workflows. This paper describes the successful case of the implementation of an integrated simulation modelling workflow to simulate long term surface back pressure effect, back pressure from additional production into the system, and benefits of new surface equipment installation. Highly efficient and accurate prediction tool was developed in the scope of this study.