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Though expensive and complex, extended-reach drilling (ERD) is moving more into the mainstream as the industry is driven to develop frontier reserves in fragile environments like the Arctic where drilling from shore to offshore targets reduces a project's infrastructure costs and environmental footprint. A form of directional drilling, ERD is also being used increasingly to tap into hard-to-produce reservoirs, making viable projects that might otherwise be written off as noncommercial. This article highlights how the Russian Far East became the ERD epicenter in the past decade, given ExxonMobil and Rosneft's extensive use of ERD in developing Arctic resources offshore Sakhalin Island, and how ERD is becoming more widely used in regions as diverse as the Gulf of Thailand, offshore Brazil, and the Arab Gulf. By definition, an extended-reach well (ERW) is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:1 (PetroWiki). An ERW differs from a horizontal well in that the ERW is a high-angle directional well drilled to intersect a target point, a feat requiring specialized planning to execute well construction.
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.
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.
Tropical storms severely affect oil and gas production in the Gulf of Mexico, especially during the storm season from June to December. Offshore well managers often need to shut down operations and evacuate the facility because of storm alerts. Furthermore, if the storms have a more-severe effect, facilities may need to be repaired before production restarts. The purpose of this paper is to determine the effect of storms on production by quantifying metrics such as downtime days and downtime percentage after the storm has passed and whether a facility's platform type affected these metrics. Oil and gas production at offshore facilities (Figure 1) are severely affected, especially in the Gulf of Mexico, by frequent storms.
Transocean told investors the debut of the world's first two 20,000-psi-ready (20K) rigs has been pushed into next year. While the share price dropped on the news, the delay attributed to supply chain disruptions during the pandemic could be well timed to a rising tide of work with oil demand and prices up sharply. Transocean's message is that the market is recovering in time for the start of work by the Deepwater Atlas, which is set to begin drilling next year, and the Deepwater Titan, scheduled for early 2023. They are the new high-specification rigs to be available for deepwater work at a time when demand is rising for the limited supply of high-end deepwater rigs. Bobby Thigpen, chief executive officer for Transocean, predicted that by year's end nearly every active rig in the deepwater Gulf of Mexico is likely to be on contract.
Gelvez, Camilo (The University of Texas at Austin) | Cedillo, Gerardo (BP America) | Soza, Eric (BP America) | Gonzalez, Doris (BP America) | Slotnick, Benjamin S. (BP America) | Moreno, Sol (BP America) | Pineda, Wilson (BP America) | Saidian, Milad (BP America) | Mullins, Oliver C. (Schlumberger) | Paul, Scott (Schlumberger) | Cañas, Jesus (Schlumberger) | Kulkarni, A lok (Schlumberger)
Abstract Reservoir Fluid Geodynamics (RFG) is a novel thermodynamic methodology that integrates pressure-volume-temperature (PVT), geochemical fingerprinting (GCFP) and reservoir geology with downhole fluid analysis (DFA) data to understand the evolution of reservoir fluids over geologic time. RFG enables the enhancement of reservoir description, estimation of reservoir fluid properties, and optimization of data acquisition plans. Deep-water reservoirs comprise multiple uncertainties in reservoir connectivity, viscous oil and flow assurance. This paper demonstrates the development of digital fluid sampling techniques for deep-water fields using the RFG workflow to predict fluid properties and distribution, to address compartmentalization uncertainties and flow assurance risks, as well as to redefine the well-logging program. Identifying key reservoir concerns is the first step during the implementation of the RFG workflow. Five questions define key reservoir concerns: Do optical density measurements explain the impact of biogenic methane on fluid behavior? Is it feasible to characterize baffling and fault compartmentalization? Can we predict reservoir fluid properties and assess flow assurance risks based on fluid behavior? Is it possible to identify all this in real time? How could we optimize future fluid sampling programs? The next step is to collect the available DFA data and to integrate it with the existing PVT and geochemistry datasets. This paper describes the evaluation of over 150 fluid sampling DFA measurements acquired during the operational history of a Gulf of Mexico field. Fluid behavior and optical density gradients are interpreted from a geological perspective to understand reservoir connectivity. A strong correlation between optical density and asphaltene content enables digital fluid sampling for different PVT and geochemical parameters. Lastly, a general correlation of optical density and asphaltene content is derived for multiple Gulf of Mexico oil fields. Optical density measurements support a consistent characterization of biogenic methane along the studied deep-water field, suggesting a relation to fluid migration and charging from deeper to shallower reservoirs. Likewise, optical density gradients and its integrated evaluation facilitate the identification of mass transport complex (MTC) baffles in the north part of the field and the characterization of fault compartments in the main reservoir sands. In addition, the RFG workflow reveals the difference in fluid behavior of sampled wells located in the area of a water injection project by identifying asphaltene clustering near the oil-water contact. The correlations of optical density and asphaltene content help to predict fluid properties and to estimate its uncertainty, benefiting risk assessment for asphaltenes deposits and flow assurance in deep water operations. Real time analysis of optical density measurements during fluid sampling permits the characterization of fluid properties and reservoir connectivity, optimizing future fluid sampling programs when fluid contamination reaches 10%. Ultimately, this innovative methodology conveys a general correlation to predict asphaltene content based on optical density measurements for deep-water reservoirs in the Gulf of Mexico, enabling the possibility to predict reservoir fluid properties in real time fluid sampling operations.
Lands beneath navigable waters are interpreted as extending from the coastline 3 nautical miles into the Atlantic Ocean, the Pacific Ocean, the Arctic Ocean, and the Gulf of Mexico excluding the coastal waters off Texas and western Florida. Lands beneath navigable waters are interpreted as extending from the coastline 3 marine leagues into the Gulf of Mexico off Texas and western Florida.
On 20 April 2010, a kick and blowout in the Gulf of Mexico resulted in a series of explosions that killed 11 people and started an environmental disaster. Now, 11 years later, government and industry continue the drive to improve safety. The disaster at Macondo Prospect resulted in the largest environmental catastrophe in the Gulf of Mexico; the US government estimates that 4.9 million bbl of oil spilled into the Gulf. Investigations after the disaster led to several safety initiatives from the industry and the identification of areas of improvement by government. To commemorate the date, the BBC has gathered some of those who were closest to the epicenter--those who worked on the rig or who worked so hard to staunch the flood of oil and clean up the disaster afterward--for an online program.
ExxonMobil proposed this week to build what would become the world's biggest carbon capture and sequestration (CCS) project in the Houston area. The supermajor's plan is to capture the CO2 from the petrochemical and industrial facilities that line the Houston Ship Channel and then transport it via a subsea pipeline to an offshore reservoir. The realization of this megaproject will depend on a number of other private and public stakeholders to help fund it and to create new policies that will facilitate the growth of the CCS sector in the US. It will also require the skills of petrotechnicals who will be challenged with de-risking the region's formations to find those that are truly suited to absorb the vast volumes of CO2. The company estimates the Houston-based CCS hub could reach an annual capacity of 50 million metric tons (Mt) by 2030, and 100 million Mt tons by 2040; a figure that represents a sevenfold increase of total capacity in the US today.
The US Energy Information Administration's (EIA) latest short-term energy outlook is predicting a raft of new projects will increase crude oil production from the US Gulf of Mexico by 200,000 B/D by the end of next year. The forecast sees 13 new projects coming on stream over the next year-and-a-half accounting for about 12% of total Gulf of Mexico oil production. Last year, US Gulf crude output averaged 1.65 million B/D. Production is forecast to exceed 2020 levels, reaching 1.71 million B/D in 2021 and 1.75 million B/D in 2022. Over the past 2 decades, the highest crude oil production year was 2019 at 1.9 million B/D.