ROCKMAN wrote:When oil prices were much higher:
Held during a month in which the Brent crude oil spot price averaged more than $100/bbl, western gulf Lease Sale 238 in 2014 saw 14 firms place 93 bids on 81 tracts, with a sum of apparent high bids at $110 million. It offered about 4,000 tracts covering 21.6 million acres.
Bottom line: when oil prices were averaging yearly record highs there were bids on only 81 tracts out of 4,000 available. That sounds like a good bit of tapering off. But despite what many folks think the Deep Water GOM is actually 31 years old. And we could be bearing GOM PO thanks to the DW trends:
http://www.eia.gov/todayinenergy/detail.php?id=25012
"U.S. GOM crude oil production is estimated to increase to record high levels in 2017, even as oil prices remain low. EIA projects GOM production will average 1.63 million barrels per day (b/d) in 2016 and 1.79 million b/d in 2017, reaching 1.91 million b/d in December 2017. GOM production is expected to account for 18% and 21% of total forecast U.S. crude oil production in 2016 and 2017, respectively."
"U.S. GOM crude oil production is estimated to increase to record high levels in 2017, even as oil prices remain low. EIA projects GOM production will average 1.63 million barrels per day (b/d) in 2016 and 1.79 million b/d in 2017, reaching 1.91 million b/d in December 2017. GOM production is expected to account for 18% and 21% of total forecast U.S. crude oil production in 2016 and 2017, respectively."
vt - "At what WTI price would it be so low that they would stop exploration in the deep water GOM?" Really impossible to answer. DW GOM exploration economics aren't dependent upon current oil prices or expectations next year or even 5 years down the road. Here's a typical time line. First, it assumes the seismic data base already exists... If not add another 3 years or so to pertmit, shoot and process the data. OK: the seismic data base is in-house. Now at least 1 year to identify BOI's...Blocks Of Interest. Once a number of BOI's are identified more detailed seismic might be bought or shot. But we'll skip that and go straight to detailed mapping...another year. Present to management for BA...Bid Approval. Years ago once a lease has received BA another 2 to 4 years to nominate that lease to be added to the next scheduled lease sale for that area. But now the feds are making all tracts available...4,000+ as of late.tita wrote:"U.S. GOM crude oil production is estimated to increase to record high levels in 2017, even as oil prices remain low. EIA projects GOM production will average 1.63 million barrels per day (b/d) in 2016 and 1.79 million b/d in 2017, reaching 1.91 million b/d in December 2017. GOM production is expected to account for 18% and 21% of total forecast U.S. crude oil production in 2016 and 2017, respectively."
The GOM was indeed one of the few places where US could increase oil production (before LTO of course). It increased by 1 million barrels of daily production between 1990 and 2002, when it reached 1.67Mb/d (jun 2002). Since then, production is more or less a plateau. After 2009, production retreated to 1.3Mb/d for a few years, amid moratorium and new rules brought by the Deep Water disaster, which delayed a lot of projects. Starting 2014, production increases again, and eia expects a new high.
But we also see the end of the projects coming online. 8 fields in 2015, 4 in 2016 and 2 expected in 2017.
Production in 2016 averaged 1.59 Mb/d (jan-july) so far. It feels a little bit optimistic to see 300kb/d of production increase in 1.5 year. And anyway, depletion is expected to affect production right after that, as the activity is at its lowest since the beginning of the GOM trend.
Well thanks but I don't think you answered my question. I was and am aware of all those things that I don't know or the dollar value per barrel to place upon them. But I was hoping that you with a lot of at the well head experience might narrow it down to a range where on the high end companies seek out every possible winning bore hole and on the low end everybody cuts up their platforms for scrap.ROCKMAN wrote:vt - "At what WTI price would it be so low that they would stop exploration in the deep water GOM?" Really impossible to answer. DW GOM exploration economics aren't dependent upon current oil prices or expectations next year or even 5 years down the road. Here's a typical time line. First, it assumes the seismic data base already exists... If not add another 3 years or so to pertmit, shoot and process the data. OK: the seismic data base is in-house. Now at least 1 year to identify BOI's...Blocks Of Interest. Once a number of BOI's are identified more detailed seismic might be bought or shot. But we'll skip that and go straight to detailed mapping...another year. Present to management for BA...Bid Approval. Years ago once a lease has received BA another 2 to 4 years to nominate that lease to be added to the next scheduled lease sale for that area. But now the feds are making all tracts available...4,000+ as of late.tita wrote:"U.S. GOM crude oil production is estimated to increase to record high levels in 2017, even as oil prices remain low. EIA projects GOM production will average 1.63 million barrels per day (b/d) in 2016 and 1.79 million b/d in 2017, reaching 1.91 million b/d in December 2017. GOM production is expected to account for 18% and 21% of total forecast U.S. crude oil production in 2016 and 2017, respectively."
The GOM was indeed one of the few places where US could increase oil production (before LTO of course). It increased by 1 million barrels of daily production between 1990 and 2002, when it reached 1.67Mb/d (jun 2002). Since then, production is more or less a plateau. After 2009, production retreated to 1.3Mb/d for a few years, amid moratorium and new rules brought by the Deep Water disaster, which delayed a lot of projects. Starting 2014, production increases again, and eia expects a new high.
But we also see the end of the projects coming online. 8 fields in 2015, 4 in 2016 and 2 expected in 2017.
Production in 2016 averaged 1.59 Mb/d (jan-july) so far. It feels a little bit optimistic to see 300kb/d of production increase in 1.5 year. And anyway, depletion is expected to affect production right after that, as the activity is at its lowest since the beginning of the GOM trend.
That answers Ghung's question.
Now Company A is the high bid on Block X. Now begins a 1 to 3 years process gathering the data in order to just drill the first well. The feds require a lot of data for this process.
OK...now we're 5 to 8 years from when Company A decided to explore for oil in the DW GOM. Now it needs to contract a rig to drill the first well. depending on activity level that might take 1 to 3 years to get a rig on location. One reason some operators sign long term rig contracts so they'll have one available when they need it. It's also how Company A might get burned by a sudden drop in oil prices: last year a company paid $400 MILLION in cancellation penalty to break such a contract. Yes: paid $400 million TO NOT DRILL WELLS.
But onward and upward. Company A drills its first exploration well on Bock X. And BAM!...it finds oil. But it most cases the first well doesn't provide enough info to determine if it's worth developing. And erven if it does add another year of remapping to pick locations for 1 or more confirmation wells. But a year or two later...BAM!...commerciality confirmed. Now a year but more likely 2+ to the design an engineering plan to develop the field, submit it to the feds and get their approval. And now approved a year but more likely 2+ to build and install the development infrastructure.
And now Company A is ready to begin drilling and completing development wells. Depending on the field size add another 2 to 4 years.
Now go back and add the years. From Day 1 when Company A decided to explore the DW GOM how long before it sells the first bbl. And what are they paid for that first bbl? And what to they get paid for oil produced 4 years after production begins?
There you go.
Conclusions
US deepwater projects can be economically viable at current oil prices, provided costs can be brought down to a level aligned with the realistic 3% inflation. It will require dedicated leadership, good discipline and control on capex and opex, and innovation in technology and operations from all stakeholders through the full cycle of the oil and gas industry. It is a paramount challenge.
Now is the time to reorganize and restructure to become lean and efficient, verify, validate, and to implement cost saving operational procedures such as innovative sub-contracting.
Empowered champions with vision must take the lead to step changes in technology and in operations, challenging the status quo. Otherwise, the high cost of deepwater development will continue to be a barrier to future projects, especially in the cases of smaller fields.
The industry cannot wait for oil prices to rise so that they can match the present level of cost. Rather, we need to proactively learn to live with the “new normal” price. From time to time, the price will rise to more than $44/bbl due to outside influences, and that will be windfall gain. Such gains should then be used wisely. Perhaps, spending a portion in future research will improve safety, reduce cost, and increase net oil recovery.
And don't say you don't have experience: I have no doubt you can predict such future oil prices accurately as anyone else. LOL.
Transport, Fate and Impacts of the Deep Plume of Petroleum Hydrocarbons Formed During the Macondo Blowout
The 2010 Macondo oil well blowout consisted in a localized, intense infusion of petroleum hydrocarbons to the deep waters of the Gulf of Mexico. A substantial amount of these hydrocarbons did not reach the ocean surface but remained confined at depth within subsurface plumes, the largest and deepest of which was found at ∼ 1000–1200 m of depth, along the continental slope (the deep plume). This review outlines the challenges the science community overcame since 2010, the discoveries and the remaining open questions in interpreting and predicting the distribution, fate and impact of the Macondo oil entrained in the deep plume. In the past 10 years, the scientific community supported by the Gulf of Mexico Research Initiative (GoMRI) and others, has achieved key milestones in observing, conceptualizing and understanding the physical oceanography of the Gulf of Mexico along its northern continental shelf and slope. Major progress has been made in modeling the transport, evolution and degradation of hydrocarbons. Here we review this new knowledge and modeling tools, how our understanding of the deep plume formation and evolution has evolved, and how research in the past decade may help preparing the scientific community in the event of a future spill in the Gulf or elsewhere. We also summarize briefly current knowledge of the plume fate – in terms of microbial degradation and geochemistry – and impacts on fish, deep corals and mammals. Finally, we discuss observational, theoretical, and modeling limitations that constrain our ability to predict the three-dimensional movement of waters in this basin and the fate and impacts of the hydrocarbons they may carry, and we discuss research priorities to overcome them.
Introduction and Background
On April 20th, 2010, a deep-sea blowout caused the ultra-deep drilling platform Deepwater Horizon (DWH) to explode, killing 11 workers. Two days later the platform sank at the Macondo Prospect in the Mississippi Canyon Leasing Block 252 (MC 252), located about 66 km offshore the southeast coast of Louisiana. The sinking further ruptured the buckled riser pipe and lead to an uncontrolled release of live (containing dissolved gas) oil and free gas from a depth of approximately 1522 m into the waters of the Gulf of Mexico (GoM). The Macondo well was capped 87 days later, on July 15th, and permanently sealed September 19th. By then, the largest oil spill in US history had discharged over 4 million barrels of oil and about 250,000 metric tons of hydrocarbon gases into the northern GoM (Joye, 2015; Gros et al., 2017). More than 7000 tons of chemical dispersants, namely Corexit 9500A and Corexit EC9527A, were applied at the ocean surface (∼ 5000 tons) and injected at depth at the broken wellhead (∼ 2000–3000 tons) in the attempt to break the oil into small droplets and ease its dispersal and degradation (Lubchenco et al., 2012). Such subsea dispersant injection (SSDI) was unprecedented and was tested by deploying increasing volumes of dispersant beginning on day 10 of the spill until the Macondo well was capped (Gros et al., 2017; Paris et al., 2018).
The explosive outgassing at the blowout preventer (BOP) resulted in a turbulent jet that atomized the live oil into a spectrum of small drops (Aliseda et al., 2010; Bandara and Yapa, 2011; Johansen et al., 2013; Zhao et al., 2014a,b, 2015, 2016, 2017; Nissanka and Yapa, 2016; Socolofsky et al., 2016; Li et al., 2017; Wang et al., 2018; Murawski et al., 2020). Together, they formed a prominent plume of petroleum hydrocarbons at the trap height, about 300 meter above the wellhead (Socolofsky et al., 2011; Bp Gulf Science Data1, 2016), the so-called deep plume. Constraining the amount and fate of oil and gas released from the Macondo Blowout appeared immediately difficult as there was no metering of the flow underwater until the installation of an oil collecting cap (Aliseda et al., 2010; Griffiths, 2012). The initial estimates challenging the rate of the flow were based on quantitative analysis of video of the oil as it exited the broken pipes (Crone and Tolstoy, 2010). The deep plume, together with other smaller, secondary plumes found higher up in the water column (Diercks et al., 2010; Joye et al., 2011; Reddy et al., 2012) entrained nearly 50% of the discharged oil and most of the low molecular weight gases (McNutt et al., 2012; Joye, 2015), and largely contributed to the uncertainty.
The deep plume, for which more observations and numerical simulations are available than for the secondary ones, was distinct from the natural hydrocarbon seep plumes (Rogener et al., 2018). Specifically, it was characterized by extremely high methane concentrations (>380 μM) according to observations taken in May 2010 (Joye et al., 2011). These elevated gas concentrations were likely due to fact that the oil and gas fluid mixture that exited from the reservoir at enormous pressure, above of 900 bars, and at high temperature (Satter and Iqbal, 2016) came into sudden contact with the low temperature (4–6°C) and lower hydrostatic pressure (100–150 bar) of the deep water (Reddy et al., 2012). This abrupt change in the environmental conditions likely caused a super saturation of gas, its expansion and the formation of hydrates and gas bubble nucleation of the liquid oil phase (Joye et al., 2011; Pesch et al., 2018). Oil concentrations were elevated both in the deep plume and in the secondary plumes – BTEX (benzene, toluene, ethylbenzene and xylene) concentrations were as high as 50–150 μg L–1 (Camilli et al., 2010) – as oil droplets segregated along the isopycnals in which they were neutrally buoyant (Paris et al., 2012).
Non-hydrostatic buoyant forces advected the deep plume until its density matched the density of the surrounding water. From this point onward, the deep plume, composed of dissolved hydrocarbon compounds, small oil droplets and gas bubbles entrained with seawater, was transported by the ocean currents downstream and slowly developed laterally (Socolofsky et al., 2011; Gros et al., 2017; Dissanayake et al., 2018). This lateral multiphase plume gradually moved away from its source and some of the hydrocarbons contained in it rose out into the water column. At this stage, physical processes, varying on spatial scales from centimeters to tens of kilometers, and complex biogeochemical processes influenced the final distribution and fate of the liquid and gas phases of petroleum.
Increasing computational capabilities over the two decades preceding the 2010 spill allowed the development of complex hydrodynamic ocean models that implement complex data assimilation methods and could predict reasonably well the time evolution of circulations at the ocean mesoscales (∼20–200 km) over 5–7 days (e.g., Liu et al., 2011). At the same time, advances in oil science and in parameterizations of essential processes, such as oil droplet formation and fate (e.g., Yapa and Zheng, 1997; Yapa et al., 1999) largely improved numerical models for forecasting oil spill dispersal (reviews by Spaulding, 1988; ASCE, 1996; Reed et al., 1999). Over the same period, industry, government and academia undertook efforts to develop numerical models to simulate the complexities of deep-water spills following a sustained increase over time in the interest for deepwater and ultra-deepwater exploitation (Dutta, 1997; Ji et al., 2004). Further technical advances in super-computer and parallel computing allowed high-throughput and thus more realistic 3D modeling and visualization of the deep plume generated during the DWH blowout, as discussed in detail later in this review...
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