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Isothermal compressibility is the change in volume of a system as the pressure changes while temperature remains constant. Below the bubblepoint pressure, oil isothermal compressibility is defined from oil and gas properties to account for gas coming out of solution. A total of 141 data points were available from the GeoMark PVT database. Table 3 provides a summary of the data. This data was used to evaluate and rank the performance of the isothermal compressibility correlations.
Chevron, Shell, and TotalEnergies are supporting a 12-month research project, which is expected to achieve a world-first in demonstrating high-resolution satellite-based monitoring of anthropogenic methane (CH4) emissions at sea. Led by Canadian-based GHGSat, the new research project aims to assess the feasibility of space-based methane monitoring technology to measure emissions from offshore oil and gas platforms. GHGSat is testing a technique developed by NASA, amongst others, and proven in fields such as ocean height and ice-thickness measurement. With a vantage point 500 km above the Earth, and high revisit rates, the company believes satellites could hold the key to verifying emissions from rigs, easily and cost-effectively. The study will monitor 18 offshore sites in locations such as the North Sea and the Gulf of Mexico for over 12 months.
Job cuts across Australia's gas industry have heightened concerns about maintenance risks on offshore rigs, which unions and environmentalists fear could threaten workers' safety and the marine environment. The international petroleum industry has been in the spotlight after a gas leak sparked the underwater "eye of fire" boiling to the surface in the Gulf of Mexico and a large blast at a Caspian Sea oil and gas field . Gas companies operating on Western Australia's North West Shelf and in Bass Strait shed workers in 2020 amid a coronavirus-induced price downturn because of plummeting energy demand, which was driven by travel restrictions. Unions estimate about 3,000 jobs were lost. However, both the unions and Australia's gas industry peak representative group rejected any comparison with international disasters, arguing Australia's safety record was better than other developed nations' gas industries in the UK, Norway, and the United States.
Abstract Objectives April 2010 in the Gulf of Mexico and January 2017 in Oklahoma brought into sharp focus what can happen if the oil and gas industry gets well control wrong: 16 fatalities, significant environmental damage, loss of assets and reputation. Each year we have multiple blowouts and several fatality events due to a loss of well control. The oil and gas industry can improve from a personnel safety, environmental and reputation perspective. The Automation of Well Control will bring a significant step change in the area of Process Safety forwells. It prevents blowouts, reduces all influx volumes, minimising kicktolerance volumes and reducingcasing and well costs. Method A system has been developedwhich enables Automated Well Control whilst in drilling mode. Pre-determined influx rates, agreed by the operator and drilling contractor, and input by the driller are established. Once the system detects the influx, it performs a series of operations by taking control of the drilling rig equipment. The drill string is spaced out, top drive and mud pumps are stopped, and the BOP is closed. All of this occurs without the driller doing anything; however, he can intervene at any moment. Thissystem is designed as an aid to the driller and does not remove his responsibility. Results The Automated Well Control system has been tested on drilling simulators with real drillers. Comparisons tests have shown that the technology enables shut-in times faster than conventional human interface methods, with influx volumes typically 10-20% of those experienced during manual shut-in. Additionally, a full Field Trial using a traditional rigdemonstrated the effectiveness of the system, proving up the functionality under different operational requirements. The system can now be applied to any type of rig worldwide. Over 50 potential modules have been identified. Planned developments forthe system include circulatingout the kick automatically, shut-in for tripping, circulating, cementing and in-flow testing. It provides assurance for afast, safe and effective shut-in.A full Technology Qualification process has been used for this technology. Innovative Technology Over the past 20 years, technology advancements associated with simulators and cyber-rigs have enabled new technologies to be developed. One of these technologies is Automated Well Control. It is believed that this innovative system will enable a step change in the performance ofprocess safety forwell control, dramaticallyreducing major accident hazards, thereby saving millions of dollars per well, reducing environmental impact and preventing loss of life.
Geoscience technology company CGG has launched SeaScope, a pollution monitoring service, as part of its growing portfolio of environmental products. SeaScope combines remote-sensing science, Earth-observation data, machine-learning, and high-performance computing to provide information on sea-surface slicks for industries to strengthen situational awareness of the interaction between offshore assets, coastal facilities, local vessel activity, and the natural marine environment. For energy companies with offshore assets, SeaScope's proactive monitoring enables the establishment of production-water baselines and provides early detection of anomalous events and third-party pollution incidents, as well as surveillance of natural seeps. It also supports the creation of a growing evidence base of responsible operations for stakeholders such as operators, regulators, investors, and insurers. SeaScope was developed with the support of the European Space Agency and a group of energy companies and emergency-response organizations.
While the world is transitioning into a greener and less-carbon-rich energy source, the fact remains that there is a growing need for exploration and production of hydrocarbons in previously untapped resources. These frontier reservoirs, while extremely hot, are prolific and make the footprint of the exploration activity much smaller than shallower drilling, which would require many more wells to deliver the same amount of hydrocarbon. HP/HT wells can be found offshore in the North Sea and Gulf of Mexico, or on land--as seen recently in the Gongola Basin. Fluid identification, which is a critical process in fluid sampling, continues to be a challenge in temperatures above 350 F. At temperatures up to 450 F, fluid identification is currently achieved by bubblepoint and compressibility measurements, which cannot quantitatively measure contamination levels of the subject sample fluid. A possible solution to this problem would involve using pyroelectric detectors in the process of estimating a property of a downhole fluid.
Southeast Asian operators sit in the middle of the world's fastest growing economic region where energy demand is expected to double over the next 20 years. But this picture of growth has been juxtaposed with the region's declining oil and gas production--most of which comes from offshore fields--that has left it increasingly reliant on imports from overseas suppliers. The degree to which operators in Malaysia and Indonesia can help counter this trend was the focus of an executive panel last week at the International Petroleum Technology Conference (IPTC). While acknowledging that the region is marked by challenging geologies and mature offshore fields, the executives spoke highly of what the future holds. Several things underpin their optimism, not least of which is the region's rising demand for natural gas.
Abstract Drilling though salt is not a new challenge in the petroleum industry, with successful exploration and appraisal wells in salt environments paving the way for complex field developments. A detailed summary of how these advancements have subsequently evolved into the technology and methods being used today is presented. The numerous challenges, and the resulting solutions, of drilling in salt environments are well documented; a comprehensive review of the relevant published industry literature has been conducted. Additionally, workshops with several major service vendors have been held to ascertain the current status of research and new product development. These two areas form the foundation of this work and have been weaved together and presented to establish what is the state of the art in salt drilling. Since the first salt wells were drilled, the drilling industry has changed considerably. Significant advancements in salt drilling technologies and methods have been made in areas such as: best drilling practices, salt formation geomechanics, salt formation geochemistry, drilling fluids, well cementing, directional drilling, drill string and drill bit design. These advancements have all been clearly delineated in a chronology of continuous improvement, compounded by the considerable weight of industry experience and lessons learned which has in turn led to optimisation, and increased efficiency, of salt drilling operations. Today, salt drilling is prevalent in areas such as the Gulf of Mexico, deep-water offshore Brazil, and deep-water West Africa, where the boundaries are continually pushed due to the perseverance of both petroleum operating companies and service vendors. The existing body of literature on salt wells is large and covers many disciplines of the upstream business, from wildcat exploration through to production. However, this focus is solely on drilling, combining and summarising many years’ worth of experience, learning, research, and development, to present what is the state of the art in salt drilling.
Abstract Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients. This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.
Isnadi, Biramarta (PETRONAS Carigali Sdn. Bhd.) | Lee, Luong Ann (PETRONAS Carigali Sdn. Bhd.) | Ng, Sok Mooi (PETRONAS Carigali Sdn. Bhd.) | Suhaili, Ave Suhendra (PETRONAS Carigali Sdn. Bhd.) | M Nasir, Quailid Rezza (PETRONAS Carigali Sdn. Bhd.) | Sham, Hanisah (PETRONAS Carigali Sdn. Bhd.) | Puloh, Kathy Ping (PETRONAS Carigali Sdn. Bhd.) | Omar, Syahnaz (PETRONAS Carigali Sdn. Bhd.) | Saminal, Siti Nurshamshinazzatulbalqish (PETRONAS Carigali Sdn. Bhd.) | Lihin, Zul Hilmi (PETRONAS Carigali Sdn. Bhd.) | Khan, Riaz (PETRONAS Carigali Sdn. Bhd.)
Abstract The objective of this paper is to demonstrate the best practices of Topside Structural Integrity Management for an aging fleet of more than 200 platforms with about 60% of which has exceeded the design life. PETRONAS as the operator, has established a Topside Structural Integrity Management (SIM) strategy to demonstrate fitness of the offshore topside structures through a hybrid philosophy of time-based inspection with risk-based maintenance, which is in compliance to API RP2SIM (2014) inspection requirements. This paper shares the data management, methodology, challenges and value creation of this strategy. The SIM process adopted in this work is in compliance with industry standards API RP2SIM, focusing on Data-Evaluation-Strategy-Program processes. The operator HSE Risk Matrix is adopted in risk ranking of the topside structures. The main elements considered in developing the risk ranking of the topside structures are the design and assessment compliance, inspection compliance and maintenance compliance. Effective methodology to register asset and inspection data capture was developed to expedite the readiness of Topside SIM for a large aging fleet. The Topside SIM is being codified in the operator web-based tool, Structural Integrity Compliance System (SICS). Identifying major hazards for topside structures were primarily achieved via data trending post implementation of Topside SIM. It was then concluded that metal loss as the major threat. Further study on effect of metal loss provides a strong basis to move from time-based maintenance towards risk-based maintenance. Risk ranking of the assets allow the operator to prioritize resources while managing the risk within ALARP level. Current technologies such as drone and mobile inspection tools are deployed to expedite inspection findings and reporting processes. The data from the mobile inspection tool is directly fed into the web based SICS to allow reclassification of asset risk and anomalies management.