The recent global pandemic is an unprecedented event and took the world by storm. The Movement Control Order (MCO) issued by Malaysia's government to halt the spread of the deadly infection has changed the landscape of work via a flexible working arrangement. The Wells Real Time Centre (WRTC) is not an exception and is also subjected to the change. WRTC is an in-house proactive monitoring hub, built to handle massive real-time drilling data, to support and guide wells delivery effectiveness and excellence. The functionality of the WRTC system and applications are embedded in the wells delivery workflow. The centre houses drilling specialists who are responsible for observing the smooth sailing of well construction and are tasked to intervene when necessary to avoid any unintended incidents. WRTC is equipped with myriads of engineering applications and drilling software that are vital for the operations. Such applications include monitoring software, machine learning applications, engineering modules, real-time data acquisition, and database management. These applications are mostly cloud-based and Internet-facing, hence it is accessible and agile as an infrastructure that is ready to be deployed anytime anywhere when it is required. The strategy for WRTC mobility started as soon as the MCO was announced. This announcement mandated the WRTC to operate outside of the office and required the staff to work from home. The careful coordination and preparation to transform and adapt WRTC to a new norm was greatly assisted by the infrastructure readiness. All of these factors contributed greatly to a successful arrangement with zero to minimal downtime where a workstation was set up in each personnel's home, running at full capacity. This transformation was done within one day of the notice and completed within hours of activation. Despite the successful move, few rooms for improvements such as redundancy of VPN use to access applications and limited access to some proprietary software can be enhanced in the future. WRTC is ready to be mobile and agile to support the drilling operations remotely either in the office or from home. The quick turnaround is a major indicator that WRTC infrastructure and personnel are ready and capable for remote operations without interruption.

The execution phase of the wells technical assurance process is a critical procedure where the drilling operation commences and the well planning program is implemented. During drilling operations, the real-time drilling data are streamed to a real-time centre where it is constantly monitored by a dedicated team of monitoring specialists. If any potential issues or possible opportunities arise, the team will communicate with the operation team on rig for an intervention. This workflow is further enhanced by digital initiatives via big data analytics implementation in PETRONAS. The Digital Standing Instruction to Driller (Digital SID) is a drilling operational procedures documentation tool meant to improve the current process by digitalizing information exchange between office and rig site. Boasting multi-operation usage, it is made fit to context and despite its automated generation, this tool allows flexibility for the operation team to customize the content and more importantly, monitor the execution in real-time. Another tool used in the real-time monitoring platform is the dynamic monitoring drilling system where it allows real-time drilling data to be more intuitive and gives the benefit of foresight. The dynamic nature of the system means that it will update existing roadmaps with extensive real-time data as they come in, hence improving its accuracy as we drill further. Furthermore, an automated drilling key performance indicator (KPI) and performance benchmarking system measures drilling performance to uncover areas of improvement. This will serve as the benchmark for further optimization. On top of that, an artificial intelligence (AI) driven Wells Augmented Stuck Pipe Indicator (WASP) is deployed in the real-time monitoring platform to improve the capability of monitoring specialists to identify stuck pipe symptoms way earlier before the occurrence of the incident. This proactive approach is an improvement to the current process workflow which is less timely and possibly missing the intervention opportunity. These four tools are integrated seamlessly with the real-time monitoring platform hence improving the project management efficiency during the execution phase. The tools are envisioned to offer an agile and efficient process workflow by integrating and tapering down multiple applications in different environments into a single web-based platform which enables better collaboration and faster decision making.

Given the increased demands on the production of hydrocarbons and cost-effectiveness for the Operator's development wells, the industry is challenged to continually explore new technology and methodology to improve drilling performance and operational efficiency. In this paper, two recent case histories showcase the technology, drilling engineering, and real-time optimization that resulted in record drilling times. The wells are located on shallow water in the Gulf of Mexico, with numerous drilling challenges, which typically resulted in significant Non-Productive Time (NPT). Through close collaboration with the Operator, early planning with a clear understanding of offset wells challenges, well plan that minimize drilling in the Upper Cretaceous "Brecha" Formation were formulated. The well plan was also designed to reduce the risk of stuck pipe while meeting the requirements to penetrate the geological targets laterally to increase the area of contact in the reservoir section. This project encapsulates the successful application of the latest Push-the-Bit Rotary Steerable System (RSS) with borehole enlargement technology through a proven drilling engineering process to optimize the drilling bottomhole assembly, bit selection, drilling parameters, and real-time monitoring & optimization The records drilling times in the two case histories can be replicated and further improved. A list of lessons learned and recommendations for the future wells are discussed. These include the well trajectory planning, directional drilling BHA optimization, directional control plan, drilling parameters to optimize hole cleaning, and downhole shocks & vibrations management during drilling and underreaming operation to increase the drilling performance ultimately. Also, it includes a proposed drilling blueprint to continually push the limit of incremental drilling performance through the use of RSS with hydraulics drilling reamers through the Jurassic-age formations in shallow waters, Gulf of Mexico.

The restriction or inability of the drill string to reciprocate or rotate while in the borehole is commonly known as a stuck pipe. This event is typically accompanied by constraints in drilling fluid flow, except for differential sticking. The stuck pipe can manifest based on three different mechanisms, i.e. pack-off, differential sticking, and wellbore geometry. Despite its infrequent occurrence, non-productive time (NPT) events have a massive cost impact. Nevertheless, stuck pipe incidents can be evaded with proper identification of its unique symptoms which allows an early intervention and remediation action. Over the decades, multiple analytical studies have been attempted to predict stuck pipe occurrences. The latest venture into this drilling operational challenge now utilizes Machine Learning (ML) algorithms in forecasting stuck pipe risk. An ML solution namely, Wells Augmented Stuck Pipe Indicator (WASP), is developed to tackle this specific challenge. The solution leverages on real-time drilling database and supplementary engineering design information to estimate proxy drilling parameters which provide active and impartial pattern recognition of prospective stuck pipe events. The solution is built to assist Wells Real Time Centre (WRTC) personnel in proactively providing a holistic perspective in anticipating potential anomalies and recommending remedial countermeasures before incidents happen. Several case studies are outlined to exhibit the impact of WASP in real-time drilling operation monitoring and intervention where WASP is capable to identify stuck pipe symptoms a few hours earlier and provide warnings for stuck pipe avoidance. The presented case studies were run on various live wells where restrictions are predicted stands ahead of the incidents. Warnings and alarms were generated, allowing further analysis by the personnel to verify and assess the situation before delivering a precautionary procedure to the rig site. The implementation of the WASP will reduce analysis time and provide timely prescriptive action in the proactive real-time drilling operation monitoring and intervention hub, subsequently creating value through cost containment and operational efficiency.

Gas injection has become an important means of enhancing oil recovery (EOR) in clastic reservoirs, the Donghe Oilfield, Tarim, has been undergoing gas injection to enhanced oil recovery. During the gas injection, dynamic justification of gas injection was the most severe challenges, which needed to monitor the pressure profile, temperature profile and gas injection profile. Therefore, monitoring gas injection profile has becoming an important part of gas drive reservoirs. Donghe Oilfield was characterized by ultra-deep (>6000m), high temperature (>140°C) and high content of carbon dioxide, conventional manometer and thermometer cannot meet the downhole condition of ultra-deep and high temperature. To continuously monitor gas injection well, permanent fibre-optic surveillance technique featured with outstanding conformance, nice corrosion resistance and long-life span was developed, and a program was developed to use real-time fiber-optic Distributed Temperature Sensing (DTS) and Distributed Acoustic sensing (DAS) to identify the gas injection profile (gas channeling). Monitoring principle and system assembly of the fibre-optic was demonstrated in detail, the DTS utilized Joule - Thompson cooling principle as the gas injected into formation through screen pipe, while the DAS captured the amplitude and frequency of acoustics from the gas flow. DTS and DAS data obtained at the same time by using fiber wireline outside the gas injection string during gas injection. There was a field application in gas injection well of DH1-H3 and gas injection profiles derived from DTS and DAS had the extremely high consistency to radioactive tracer profiles run at about the same time and under similar injection rates and pressure. The success of the fibre-optic surveillance in DH1-H3 exhibited great potential of fiber-optic sensing in gas injection EOR projects, which could provide a new and effective tool in identifying gas channeling.

This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet drilling challenges in Mexico's offshore Homol field. This innovative solution integrates a new state-of-the-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as the ballooning effect due to drilling plastic formations, losses, wellbore instability, and stuck pipe were effectively mitigated, and improved drilling performance with reduced NPT was delivered compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol proved crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset well analysis to deliver a comprehensive risk assessment and mitigation plan jointly with the Operator to tackle drilling hazards such as ballooning without compromising the directional drilling requirements. In addition, flow processes and procedures were developed for contingency events, including but not limited to losses, stuck pipe, wellbore instability, and well control. After successfully deploying the new RSS tool in Mexico offshore, the Operator came across a challenging directional well with a history of ballooning effect, losses, stuck pipe, and wellbore instability. Combining the RSS tool with MPD Constant Bottom Hole Pressure (CBHP) technique to mitigating the ballooning effect while maintaining constant surface back pressure (SBP), the well was drilled while minimizing the downhole pressure fluctuation to mitigate against wellbore instability until reaching the lower paleocene formation, taking care to maintain an equivalent circulating density (ECD) of 2.04g/cc while drilling, and 1.99g/cc during connections, in order to reduce the ballooning effect observed in offset wells. As a result of careful planning, the RSS and downhole-surface communication continued to work well, while the MPD CBHP variant successfully mitigated against ballooning and well control hazards. The paper will also discuss the effective communication protocol between directional drilling, MPD services, and rig contractors to ensure safe operational alignment. Rotary steerable systems (RSS) for directional drilling must drill in increasingly hostile environments and with different challenges inherent to formations; examples of this are formations with plastic behavior that cause ballooning effect. This phenomenon can confuse drilling crew cause its behavior is very similar to kicks from wells. Homol is an oilfield with marked ballooning characteristics, causing significant Non-Productive Time (NPT). Drilling challenges in the Homol field require the utilization of both Directional Drilling technology and MPD techniques to improve drilling performance and reduce NPT at the same time. However, the technologies need to be optimized for one another. Also, directional services had to ensure reliability and accurately position wells, while the MPD technology to discern ballooning from actual influx and managing wellbore stability. This article describes the teamwork carried out by the directional team and MPD to avoid/minimize the ballooning effect while drilling directional jobs, improving operational time. The paper also includes a planning and operational blueprint to reduce NPT related to, while increasing drilling performance in terms of rate of penetration (ROP) and wellbore quality to allow the liner to be run to section TD in the Lower Paleocene formation.

In the event of offshore oilfield blow-out, real-time quantification of both spilled volume, recovered oil and environmental damage is essential. It is due to costly recovery and restoration process. In order to develop a robust and accurate quantification, we need to consider numerous parameters, which are sometimes tricky to be identified and captured. In this work, we present a new modeling technique under uncertainty, which accommodates numerous parameters and interaction among them. We begin the model by identifying possible parameters that contributes to the process: grouped into (1) subsurface, (2) surface and (3) operations. Subsurface e.g. well and reservoir characteristics. Surface e.g. ocean, wind, soil. (3) Operations e.g. oil spill treatment blow-out rate, oil characteristics, reservoir characteristics, ocean current speed, meteorological aspects, soil properties, and oil-spill treatment (oil booms and skimmers). We assign prior distribution for each parameter based on available data to capture the uncertainties. Before progressing to uncertainty propagation, we construct objective response (amount of recovered oil) through mass conservation equation in data-driven and non-intrusive way, using design of experiment and regression-based method. We propagate uncertainties using Monte Carlo simulation approach, where the result is presented in a distribution form, summarized by P10, P50, and P90 values. This work shows how to robustly calculate the amount of recovered oil under uncertainty in the event of offshore blow out. There are several notable challenges within the approach: 1) determining the uncertainty range in blow-out rate in case of rupture occurs in the well, 2) obtaining data for wind and ocean current speed since there is an interplay between local and global climate, and 3) accuracy of capturing the shoreline geometry. Despite the challenges, the results are in-line with the physics and several recorded blow-out cases. Through sensitivity analysis with Sobol decomposition, we can define the heavy hitters. These heavy hitters give us knowledge on which parameters should be aware of. In real-time quantification, this analysis can provide an insight on what treatment method should be performed to efficiently recover the spill. We also highlight about the sufficiency of the model to obtain several parameters’ range, for example blow-out rate. The model should at least capture the physics in high details and incorporate multiple scenarios. In the case of blow-out rate, we extensively model the well completion and consider leaking due to unprecedented fractures or crater formation around the wellbore. We introduce a new framework of modeling to perform real-time quantification of offshore oil spills. This framework allows inferring the causality of the process and illustrating the risk level.

The advancement of technology in this era has long profited the oil and gas industry by means of shrinking non-productive time (NPT) events and reducing drilling operational costs via real-time monitoring and intervention. Nevertheless, stuck pipe incidents have been a big concern and pain point for any drilling operations. Real-time monitoring with the aid of dynamic roadmaps of drilling parameters is useful in recognizing potential downhole issues but the initial stuck pipe symptoms are often minuscule in a short time frame hence it is a challenge to identify it in time. Wells Augmented Stuck Pipe Indicator (WASP) is a data-driven method leveraging historical drilling data and auxiliary engineering information to provide an impartial trend detection of impending stuck pipe incidents. WASP is a solution set to tackle the challenge. The solution is anchored on Machine Learning (ML) models which assess real-time drilling data and compute the risk of potential stuck pipe based on drilling activities, probable stuck pipe mechanisms, and operation time. The output of the analysis is built on a warning and alarm system that can be utilized by the engineers to refine and optimize the well construction activities; tackling the stuck pipe issue before it manifests. This solution is evaluated by comparing historical and real-time drilling parameters with the prediction data to generate an error analysis. On top of that, a confusion matrix is tabulated based on the analysis of warnings and alarms raised by the solution to rule out Type 1 and Type 2 errors. The WASP solution has demonstrated tolerably accurate predictions of drilling parameters with minimal warnings and alarms error. With the solution, the stuck pipe issue can be identified hours earlier before the actual stuck pipe was reported in the historical well. It is a powerful tool with the capability to pinpoint possible stuck pipe mechanisms for engineer's immediate analysis and intervention. Value creation from the WASP solution has been massive with a reduction in manhours of analysis, potential NPT events, and unexpected operational costs. Data-driven techniques are effective in preventing stuck pipe incidents and will be scalable to tackle other downhole issues such as loss of circulation, well control, and borehole instability.

The objective of this research is to describe the methodology used to drill the most extended reach well (ERD) in the Gulf of Thailand. The Jasmine field is a mature, sophisticated, oil field with many shallow reservoir targets that require a minimum 10,000ft horizontal displacement. As such, the main challenges faced, and the novel technology applied is described in detail by this research. The research is an example of successfully drilling a challenging well, safely and efficiently. The Jasmine C – Well X, is a 3-string design structure with an 11-3/4in top hole, an 8-1/2in intermediate section, and a 6-1/8in reservoir horizontal section. Well X was constructed by utilizing an existing platform well slot. The challenge involved drilling from the top hole to the kickoff point and directional drilling away from the casing stump of the existing well to avoid any collision with nearby wells emanating from the Jasmine C platform. The 8-1/2in hole section was the most important segment as it had to reach the landing point precisely in order to start the 6-1/8in section for GeoSteering in the reservoir section. The 8-1/2in section encountered three challenges that could affect drilling efficiency. Directional Drilling – The complexities of the well profile: The method involved making well inclination (INC) lower than 82deg in the tangent interval in order to reduce the well's tortuosity as much as possible. Hole condition – Hole cleaning and fluid losses control: The method involved the use of Low Toxicity Oil Based Mud (LTOBM) CaCO3 system, the chemical elements in the drilling fluid system could help to seal the high permeable zones. Drilling Engineering – Torque and Drag (T&D) control: The method taked into account the 7in casing run to the bottom of the hole, which the casing driven system did not allow for rotation The well was completed successfully without any additional trips. A Total Depth (TD) was of 13,052ftMD was achieved to reach reservoirs at 3,260ft TVDSS. It was therefore announced in 2019 as a new ERD record for Mubadala Thailand (ERD ratio = 3.26, Directional Difficulty Index (DDI) = 6.95). The top hole and 9-5/8in casing were set in the right depth. An 8-1/2in section was accomplished on the planned trajectory with an average on bottom Rate of Penetration (ROP) at 319 ft/hr. The 6-1/8in section was drilled by geosteering to achieve sub-surface objectives. A total of 2,143ft intervals inside the reservoir was successfully achieved. While drilling, lost circulation events occured, but the mud system was conditioned with Lost Circulation Materials (LCM). Therefore, drilling performance was unaffected. Moreover, the Bit's Total Flow Area (TFA) and Rotary steering systems (RSS) flow restrictor was configured to allow directional drilling at a very low Flow rate of 470gpm. Addition, 30 joints of 5-1/2in Heavy Weight Drill Pipe (HWDP) and 39 joints of 4in HWDP were added into the Bottom Hole Assembly (BHA) to transfer string weight to drill bitsand drill to well TD. As complexities of the well profile were fully aware, the casing was runned and minimized the open hole friction until the casing was deployed successfully. In the Gulf of Thailand, drilling the longest ERD well in a shallow True Vertical Depth (TVD) was clearly groundbreaking and entailed the successful management of the key operational challenges related to identification, job planning, design, technology selection, and implementation. This research illuminates the challenges and technical solutions of long ERD well and serves as an example of what can be achieved in the region and globally.

Installation of Wet Gas Metering System (WGMS) on a platform for the purposes of real-time measurement of liquid and gas production rates as well as performance monitoring as part of reservoir and production optimization management are quite common nowadays in Malaysia. Nonetheless, understanding of wells production deliverability invariably measured using these Wet Gas Meter (WGM) which provides the notion of production rates contributed by the wells are paramount important, eventually the produced fluids will be processed by various surface equipment at the central processing platform before being transport to onshore facilities. However, the traditional WGM are known to operate within ±10% accuracy, whereby the confidence level on measurement of the produced fluids can be improved either by updating with accurate PVT flash table or combination of results from performing tracer dilution technique for data verification. Sarawak Gas Field contains a number of gas fields offshore East Malaysia, predominantly are carbonate type formation, where one (1) of the field operated by PETRONAS Carigali Sdn.Bhd.(PCSB) is a high temperature accumulation at which temperature at the Gas Water Contact (GWC) approximately 185°C and full wellstream Flowing Tubing Head Temperature (FTHT) records at 157°C. Cumulative field production of five (5) wells readings from WGM had shown 9.1% differences as compared to the export meter gas readings. As part of a strategy to provide maximum operational flexibility, improvement on accuracy of the WGM is required given that the wells have higher Technical Potential (TP) but are limited by threshold of the multi-stage surface processing capacity. This also impacts commerciality of the field to regaining the cost of capital investment and generate additional revenue especially when there is a surge in network gas demand, as the field unable to swiftly ramp-up its production to fulfill higher gas demand considering the reported production figures from cumulative WGM surpassing the surface equipment Safe Operating Envelope (SOE). Our approach begins with mass balance check at the WGMS and export meter including the fuel, flare and Produced Water Discharge (PWD) to check mass conservation by phases because regardless different type of phases change occurs at topside the total mass should be conserved (i.e. for total phases of gas, condensate and water) provided that precise measurement by the metering equipment. Tracer dilution measurement of gas, condensate and water flowrates were used to verify the latest calibrated Water Gas Ratio (WGR) and Condensate Gas Ratio (CGR) readings input into the WGM. Consequently, PVT separator samples were also taken via mini-separator for compositional analysis (both gas and condensate) and for mathematical recombination at the multi-rates CGR readings to generate a representative PVT compositional table. Simultaneously, process model simulation run was conducted using full wellstream PVT input to validate total field production at the export point. This paper presents practical approach to balance the account, to ensure the SOE at topside as well as to improve the PVT composition at the WGM for high temperature field that emphasizes on understanding of compositional variations across production network causing significant differences in total field production between WGM and the allocation meter.

Objectives/Scope The benefits of real-time estimation of the cool down time of Subsea Production System (SPS) to prevent formation of hydrates are shown on a real oil and gas facility. The innovative tool developed is based on an integrated approach, which embeds a proxy model of SPS and hydrate curves, exploiting real-time field data from the Eni Digital Oil Field (eDOF, an OSIsoft PI based application developed and managed by Eni) to continuously estimate the cool down time before hydrates are formed during the shutdown. Methods, Procedures, Process The Asset value optimization and the Asset integrity of hydrocarbon production systems are complex and multi-disciplinary tasks in the oil and gas industry, due to the high number of variables and their synergy. An accurate physical model of SPS is built and, then, used to develop a proxy model, which integrates hydrate curves at different MeOH concentration, being able to estimate in real time the cool down time of SPS during the shutdown exploiting data from subsea transmitters made available by eDOF in order to prevent formation of hydrates. The tool is also integrated with a user-friendly interface, making all relevant information readily available to the operators on field. Results, Observations, Conclusions The integrated approach provides a continues estimation of cool down time based on real time field data (eDOF) in order to prevent formation of hydrates and activate preservation actions. An accurate physical model of SPS is built on a real business case using Olga software and cool down curves simulated considering different operating shutdown scenarios. Hydrate curves of the considered production fluid are also simulated at different MeOH concentration using PVTsim NOVA software. Off-line simulated curves are then implemented as numerical tables combined with eDOF data by an Eni developed fast executing proxy model to produce estimated cool down time before hydrates are formed. A graphic representation of SPS behavior and its cool down time estimation during shutdown are displayed and ready to use by the operators on field in support of the operations, saving cost and time. Novel/Additive Information The benefits of real time estimation of the cool down time of SPS to prevent hydrates formation are shown in terms of saving of time and cost during the shutdown operations on a real case application. This integrated approach allows to rely on a continue, automatic and acceptably accurate estimate of the available time before hydrates are formed in SPS, including the possibility to be further developed for cases where subsea transmitters are not available or extended to other flow assurance issues.

In recent years, we have seen some refined drilling technologies crop up all over the world. These have given rise to implementation of remote centers to work on real time decision making with the wells. While drilling is in process, there are technologies that enable real time transmission of data and voice to and from remote sites, helping in real time intelligent commands and responses. It is hence now possible to form a single team of experts to monitor and control drilling operations. The development of remote operations in the oil and gas industry has evolved over years starting 2004 at different speeds in different regions of the world. For example, it took longer to reach the US land market because of resistance to change at the rig site. The decrease in oil prices in 2014 however, pushed remote operations into existence to reduce cost. Due to challenges such as either oilfield culture, company strategy, human factor, legal factor etc., it was not exactly the "norm". Fast forward to 2020 when the Covid-19 pandemic hit the oil industry into another slump, service companies have been pushed into the remote operations world. To learn with the times, this may be the new norm and maybe an excellent one. Many service companies have successfully performed operations wells globally increasing not only the efficiency of wellsite operations but also contributing to cost optimization and safety. During implementation, it is observed that remote operations are less a technical challenge, and more a value challenge requiring confidence from all stakeholders. In terms of drilling and operational efficiency, the results observed globally are significant, with fewer trips for M/LWD failure, as well as significant reductions in M/LWD NPT while drilling. This paper discusses the implementation of remote operations at global scale, lesson learnt on day-to-day basis, optimization opportunities, business workflow, positives such as business continuity, safety aspect and last but not the least, the environmental impact. The paper also talks of changes and effects of Covid-19 Pandemic on these operations. Remote operations prepare us well for such pandemic and it may be the safer way to operate now on. Also discussed are the keys to successful remote operations and various examples of remote operations establishments throughout the globe. Lastly a SWOT analysis is done to conclude how remote operations will help operators to add more value to operations and show that remote operations is the new future.

This paper will detail the engineering strategies utilized from design and planning stage up to and beyond the field execution stage which resulted in drilling the fastest well in a shallow water field, delivering superior drilling performance and successfully targeting the Upper Miocene (tertiary) reservoir in Mexico. From the 9 wells drilled in this field, the fastest well "Y"-200 was drilled with an average well construction index of 179 m/day when compared to the field average of 54.2 m/day. This shallow water field manifests several specific challenges which include tough drilling conditions, fluid property and hydraulic management, logging constraints and critical selection of casing setting depths. In order to enhance the drilling performance results to lower costs and improve production timelines, the project team performed a deep-dive into the well challenges and engaged with multi disciplinary teams and service providers to brainstorm different design improvements and operational practices. By doing so, the performance accelerates the 6000 to 9000 bbls of initial production estimated per well. The application of these creative engineering ideas proves that change, when applied correctly can really create lasting and proven improvements in drilling performance.

Sand production is one of the operators’ intimidating challenges as the cascading effects can cause significant damages to the surface equipment and often lead to costly clean-up effort. Its effects are further amplified in gas wells with higher gas velocities lead to more detrimental effects on the facilities. Consequently, the facilities will deteriorate, leading to uncontrolled hydrocarbon release which compromise the operation safety considerably. Hence, sand detection devices such as acoustic sensors are extremely crucial to detect sand production as early as possible prior to any undesirable damage. This paper highlights the selection reasoning and advantages of permanent acoustic sensors as well as the method in maximizing the data value through integration with digital field monitoring. Various sand monitoring equipment are available in the industry and its selection is mainly driven by operators’ purpose with cost-benefit analysis. The multi-disciplinary team collaboratively decided on a holistic approach of utilizing the permanent acoustic sensors to its maximum potential. Integration of permanent acoustic sensors with digital field monitoring further improves the investment return as the sensors can provide real-time sand production data. Effective real time sand monitoring can be performed by both offshore and onshore crews where immediate countermeasure can be deployed if abnormal readings detected. When handling sand prone wells, proactive measures have been proven to be more effective if compared to reactive measures. Each well production potential can be maximized by installing sand sensors to ensure safe operating envelope without sand production as well as to trigger alarm if sand detected. The key to unlocking the potential is to ensure data is effectively transmitted to the command center and to the office via our digital field system. The operators are also trained on the next course of action such as beaning down the wells to safe operational envelope in case of sand breakthrough. The value of the acoustic sensors outweighs the total cost involved as real-time sand monitoring system helps to safeguard surface facility integrity considerably.

PETRONAS Upstream is cognizant of the need to provide a unified digital production platform to the entire upstream community. The digital platform enables the community to perform analytical, collaborative monitoring & surveillance, and optimization to sustain production and improve our operations. Digital Fields (DF) is a modern digital platform, integrating data and analytical services, that provides smarter insights and shed light on potential insights that contribute to better-informed decision-making and improves the way of working. A big data ecosystem and strong infrastructure is the foundation of this digital platform, allied to existing business processes, it allows frictionless secure flow of data, high performance, scalability to support business operations. Digital Fields platform provides the following features: Scalable to all PETRONAS fields operated in Malaysia as well as International assets Solution architecture that allows fast implementation of new solutions and insights A common company-wide platform with the same familiar user interface and user experience The critical aspect to liven up a digital production platform is to identify first the available data sources. Some fields have the luxury of transmitters and sensors installed at the well head, topside facilities and export pipelines where the data can be easily retrieved from the SCADA system for data acquisition. Some other fields with less real-time data luxury would keep their operational data inside some operational reporting documents. A smart report ingestion solution was developed with the means to transform unstructured data from the operational reports, which empowers the users with multiple options for data upload and consumption while ensuring a single, traceable and auditable source of truth. Digital Fields leverages the combination of Daily Operation Reports (DOR), data with different frequency, such as real-time data, with engineering models changing the way the users consume data and provides proactive actionable insights to accelerate tangible values for the business organization. The solution establishes the foundational digital capabilities for field operations and speeds up data-driven value opportunities from operational data and analytics at scale.

The Well X in Nong Yao field, is an infill-well designed for the Gulf of Thailand which presented several interesting challenges due to its complexity, tortuosity, and potential collision risks with other wells. This paper demonstrates the application of a Real-time Advanced Survey Correction (RASC) with Multi Station Analysis (MSA) to correct the Measurement While Drilling (MWD)'s azimuth. The Well X is a 3D Complex design with a high drilling difficulty index (DDI) at 6.9, high tortuosity of 316 degree, and which has an aggressive build on inclination and azimuthal U-turning well path. The well also creates difficult doglegs severity (DLS) up to 5.5deg/100ft, which is near the limit of the flexibility required to achieve the horizontal landing point. The conventional MWD survey, with proximity scanning with the nearby Well A, demonstrates high risk with a calculated Oriented Separation Factor (OSF) of 1.01. The RASC-MSA method is applied with a clearly defined workflow during execution in real-time and provide significant improvement in calculated OSF. RASC-MSA is applied for every 1,000 ft interval drilling below the 9.625in casing shoe. The workflow ensures that the directional driller follows the corrected survey along the well path and especially in the last 300 ft before reaching the electrical submersible pump (ESP) tangent section. The result from RASC-MSA, indicated a 29 ft lateral shift on the left side of the MWD standard surveys. Without this technique, Well X has a high potential to collide with Well A and Well B ( Figure 1 ) as the actual OSF may less than 1 while drilling. The final 3D Least Distance proximity scanning with Well A shows a minimum OSF = 1.35, which is a 30% improvement compared to the conventional MWD survey. Another nearby well, Well B, indicates a minimum OSF=1.66 and passed the anti-collision OSF rule. In consideration of the drilling efficiency, availability, cost effectiveness and time saving, the RASC-MSA analysis to correct the MWD's azimuth are applied and the separation factor can be improved by 30%. In conclusion, the collision risk management technique applied successfully met the complex challenges of Well X, which was successfully drilled and safely delivered. Figure 1 3D visualization to exhibit the collision issue between Well X and nearby existing Wells A and Well B.

Reliable toolface calculation is essential for achieving robust automatic steering control with rotary steerable systems (RSS). For RSS with fully rotating sensor packages, this task becomes particularly challenging under extreme conditions, where signal-to-noise ratio (SNR) of measurements from one or more sensors reduce significantly (e.g., while drilling near-vertical wells, along dip, towards magnetic north, in the vicinity of casing and/or under severe vibration and stick-slip). To ensure robust toolface control for fully rotating RSS under these conditions, this paper proposes a novel dynamic toolface calculation method. The proposed dynamic toolface calculation method of the new-generation fully rotating RSS overcomes the challenge of achieving robust toolface control despite extreme drilling conditions, by bringing together real-time health monitoring, online sensor calibration and novel sensor fusion techniques. Considering that robust toolface control is the heart of any drilling automation architecture with RSS, this technology is key to enable advanced drilling control strategies in the future.

Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well. This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result. This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters. In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.

Real-time location information is essential in the hazardous process and construction areas for safety and emergency management, security, search and rescue, and even productivity tracking. It's also crucial during pandemics such as the COVID-19 pandemic for contact tracing to isolate those who came to the proximity of infected individuals. While global positioning systems (GPS), can address the demand for location awareness in outdoor environments, another accurate location estimation technology for indoor environments where GPS doesn't perform well is required. This paper presents the development and deployment of an end-to-end cost-effective real-time personnel location system suitable for both indoor and outdoor hazardous and safe areas. It leverages on facility wireless communication systems, wearable technologies such as smart helmets and wearable tags, and machine learning. Personnel carries the client device which collects location-related information and sends it to the localization algorithm in the cloud. When the personnel moves, the tracking dashboard shows client location in real-time. The proposed localization algorithm relies on wireless signal fingerprinting and machine learning algorithms to estimate the location. The machine learning algorithm is a mix of clustering and classification that was designed to scale well with bigger target areas and is suitable for cloud deployment. The system was tested in both office and industrial process environments using consumer-grade handphones and intrinsically safe wearable devices. It achieved an average distance error of less than 2 meters in 3D space.

With 20 years of operations, multiphase flowmeters (MPFMs) using a combination of venturi and multi-energy gamma-ray absorption have gained acceptance in the oil and gas industry by demonstrating reliable measurement and operational robustness. Nonetheless, some challenging operating scenarios are encountered such as significant water salinity changes in multiphase and wet-gas flows and rapid detection of small water quantities during production. Although MPFMs are not affected by small water salinity changes, inaccurate flow rates can be calculated when water salinity significantly departs from the initial properties. To maintain measurement metrology as per specifications, the water-point should be manually modified to track variations; however, this operation is time consuming and may incur nonproductive time. The salinity change measured by a newly developed sensor can be provided seamlessly to MPFMs to automatically update the water point calibration, thus ensuring good flow rate measurement performance over a wider water salinity range. Extensive validations at several flow loop facilities and field tests, including frac flowback operations, demonstrate the robustness of the method in terms of hardware reliability and the delivery of high-quality data when used with MPFMs with digital connectivity, which opens the way to unmanned production monitoring operations. Interpreting multiphase mixture's dielectric constant and electrical conductivity simultaneously measured by the new microwave water salinity sensor at a high data acquisition rate shows that water salinity can be tracked online in the presence of oil, gas, and sand, and small water quantities down to 50 ppm (part-per-million) water volume fraction (WVF), from the typical ~1000-ppm WVF for the MPFM, can be detected rapidly in multiphase and wet-gas flows. This paper describes the working principles of the new sensor that enable additional capabilities to maintain accurate water-liquid ratio (WLR) measurement in situations where significant water salinity changes occur and to provide a rapid, much lower WVF detection level. Successful cases demonstrating an accurate real-time salinity monitoring in flow loop tests and in field operations are also presented.