[vtsnowedin]

I Have a question Rockman. What is a ballpark figure for the cost of production/bl in the deep water GOM?

[ROCKMAN]

vt - I can only give a rough generic guess. As I mentioned in another post folks should really think more about the monthly cost then per bbl and not $'s per bbl. The per bbl cost will often sound ridiculously low because of the typically high daily production rate of offshore fields...especially Deep Water. Not the highest by a long shot but let's use 50,000 bopd initial rate. That's 1.5 million bbls/month. At $2/bbl that's $3 million/month. Sounds like a lot...and it is. But consider the cost of one service boat at the rig 24/7...a regulatory requirement. At $15,000/day that $450,000/month. And then there's a small crew...say 6. Add $50,000/month. And then there's fuel, insurance (pricey in hurricane alley), helicopters ($5,000/flight), etc, etc. It adds up but at $2/bbl you have a $3 million budget to work with.

Now think of a field that comes on at 300,000 bopd as some of the big ones have: now we're talking around $0.50/bbl...or less. Put that number out there and some of our locals here would have a sh*t fit. LOL. But it also tells you why you'll never see offshore wells producing at anywhere near stripper levels. Thus their relatively short commercial live compared to onshore fields with even much lower production rates: no boats, no helicopters, etc. In some cases not much more the a guager who swings by for a hour once a day to check the tank levels. That's typically less than $3,000/month per well. Unlike onshore fields for an offshore field it doesn't make much difference if there's 24 wells or just one...the ops cost is about the same.

[Subjectivist]

$this->bbcode_second_pass_quote('ROCKMAN', 'W')hen 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."

[vtsnowedin]

But that, of course, is after they have gone to all the expense of finding the oil, moving a platform out there and drilling the wells.

[vtsnowedin]

Perhaps I should ask the question a different way.
At what WTI price would it be so low that they would stop exploration in the deep water GOM?
$2.00 lifting and operation costs seems ridiculously cheap but there are all those other costs such as lease purchase (plus all those leases that turned up nothing but dry holes)State of the art surveys that actually found the right place to drill a hole, and the permits to actually put a hole in that spot plus moving a deep sea platform to that site and manning it with staff that know what they are doing.
That bottom line is what I'm looking for even though I know it varies tremendously from field to field and well by well. A high and a low range would serve as well as an imprecise average.
I'm thinking that this deep water oil is what we have left to find and exploit and the cost of that will have a major impact on world oil prices going forward. Last marginal barrel and all that Econ 102 crap.

[tita]

$this->bbcode_second_pass_quote('', '&')quot;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."

[ROCKMAN]

$this->bbcode_second_pass_quote('tita', '')$this->bbcode_second_pass_quote('', '&')quot;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."

[Zarquon]

There's some more info in this thread:
gulf-of-mexico-update-t68631-80.html

[vtsnowedin]

$this->bbcode_second_pass_quote('ROCKMAN', '')$this->bbcode_second_pass_quote('tita', '')$this->bbcode_second_pass_quote('', '&')quot;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."

[ROCKMAN]

vt - Sorry. That answer is easier: there is obviously no single $value. But a range? Any guess is good once you decide what the reserve base is. Let's assume all the seismic, lease bonuses and exploration/confirmation has been done. Let's use 100 million bbl recoverable. After royalty that equates to a 88 million bbls to the company. Actually the reality is much more complicated.

Now it gets tricky. Since the 88 mm bo aren't produced in a day one has to take into account the time value of money. Most companics use a 10% discount rate to calculate net present value: each year the revenue value is decreased 10%. Here's the biggest problem: what will it cost to drill the development wells and buiold out the production infrastructure.

The best I can do is offer some generic insight from an industry publication:

http://www.offshore-mag.com/articles/pr ... rices.html

"It is interesting to note that, around the year 1996/1997, Shell’s Auger and other contemporary fields in around 1,000-m (3,280-ft) water depths in the Gulf of Mexico (GoM) were profitable at about $20/bbl. When BP’s Atlantis and Chevron’s Blind Faith were sanctioned in 2005, the price was about $25/bbl. In fact, oil companies were making more profit at lower oil prices in the near past than recently at higher oil prices. Based on this data, the industry should be able to make do with a price of $44/bbl, although the general consensus is that at least $65/bbl is required. Most likely, a higher price is required depending on the size of fields; the difficulty associated with reservoirs; and the operating company overhead structure. But what has changed?

The answer to that is: water depth has doubled; subsea tieback distances have increased; and some reservoirs may be difficult, uncertain, or have higher temperature and pressure. This may result in more money spent on research and development. Still, these factors alone do not justify the escalation of capex and opex to the high level that the industry now faces. For example, the cost of Shell’s Auger was $1.2 billion (1997) in 1,000-m water depth; the cost of BP’s Atlantis and Chevron’s Blind Faith in 2,200-m (7,217-ft) water depth were about $1.8 billion (2005); whereas the cost of Chevron’s Jack/St. Malo project, also in 2,200-m water depths, was $8 billion. (2015)." BTW Jack was the last DW well site work the Rockman did.

But back to the same problem: future prices. If it takes 3 to 5 years to bring a defined field into production what future price do use? $100/bbl of several years ago? $40/bbl of a year ago? Do you think a company 3 or 4 years ago used $90/bbl for oil prices between 2016 and 2021?

As I've pointed out many times: tell me the name of any analyst that has consistently predicted the price of oil +/- 20% over the last 25 years. I've yet to get answer. Today a companies are making go-forward decisions on developing DW GOM that won't start producing for 4 or 5 years. They have to correctly not only predict the price of oil the day production starts but also for the following 6 to 8 years.

The reality of how companies pick a price schedule: reverse engineering. They develop a forward price model that generates an acceptable rate of return . And then run the ecvonomic models on price platforms above and below that price to measure a project's ROR sensitive to oil price variations. And then all the senior managy gathers in the big conference room and argue over which bullshit economic model to use.

I'm not kidding. Been in many such meetings. And the motivations are always based on the risk/profitability. I've seen more mangers fired for not developing new reserves then for drilling dry holes. Sorta like I've mentioned about the shale plays: there are Morse the a few companies that have lost their ass where the management/boards have collectively made $billions.

So to reiterate IMHO there is no oil price that will allow development of X billions of bbls of oil in the DW GOM.

[vtsnowedin]

Thanks Rockman: That article was a good read and gives some insight to industries thought processes. From that I would expect little new Deep water exploration until prices and the world supply situation normalize. They say as much in a gung ho sort of way in their conclusion section.
$this->bbcode_second_pass_quote('', 'C')onclusions

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.

[ROCKMAN]

vt - "From that I would expect little new Deep water exploration until prices and the world supply situation normalize". Or not. That's why I broke that time line down. Forget the seismic exploration time component. Start with an unleased prospect identified. What price would you use to build your economic model? Remember it might be 1 to 2 years before your target block comes up for lease. And then you win the bid. Then 1 year to get your drilling planned approved by the feds. And then 1 to 2 years waiting for a rig. Then 6 months to drill. And then 6 months to refine mapping. And the 1 to 2 years to drill and evaluate a confirmation well. And we'll skip the possibility of needing a second one. Now 1 to 3 years to build and install productyion infrastructure including pipelines. And now, for a big discovery, 2 to 3 years to drill and the development wells and 1 more year to tie all the equipment together. So even in this rather fast track plan first oil sales don't begin for 7 to 10 years from today.

So do you use $45/bbl for your economic model for your revenue stream that doesn't start for a minimum of 5 to 6 years? Or maybe 10 years? Or do you use the $90/bbl price we had a few years ago? And the field will produce for 10 years: do you keep the oil price flat at $45/bbl for the entire 10 year life? Or $90/bbl? Or go with a two tier pricing model using both $45 and $90 per bbl?

This isn't a hypothetical question: there are managers sitting in the big conference room right now trying to make that decision. So what would you use? 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.

Do you get the idea? Drilling a $150 million dry hole in the DW GOM isn't the biggest risk companies face: it's unpredictable oil prices many years into the future. That should give some indication as to how the large pubcos are so desperate to add reserves: they have no choice but to toss the dart relatively blindless out there.

[vtsnowedin]

$this->bbcode_second_pass_quote('', ' ')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.

[ROCKMAN]

vt - "...won't charge them five million a year for my best efforts." It really isn't a joke for many of those managers out there. They have to convince TBTB they have a viable economic 5 year plan or they'll get replaced by someone that will. More then once I've seen senior management build ridiculously optimistic plans they knew were complete buillshit just on the hopes of keeping their salary for another year or two. What if you were a 60 yo manager making $450,000/yr and you're watching laid off cohort s who can't get an interview let alone a job.

During the early 80's bust my company was going down. I was the company's division chief development geologist. My boss wanted me to approve a truly piece of shit prospect. I refused so he transferred it to the exploration manager and he drilled it out of his budget. And proved it was a shitty prospect. Less then a year later the dissolved in bankruptcy: a $100 million bond came due and they couldn't pay $1.

It wasn't that I was a saint or anything. I was young with an out of control ego and didn't like being told what to do. Nothing like I am today. LOL.

[tita]

Rock - So, exploration depends more on the availability of unleased blocks which offers some interesting seismic datas? The job of the geologist in charge being to push statistics in an optimistic bias, to get approval. But:

- The availability of interesting leases is not infinite. It feels like there was much more activity in the 90's than today, with less risky investments despite much lower oil prices expectations.
- Exploration budgets may be slashed for financial reasons, and would only focus on the most interesting leases.
- E&P companies may get cautious. They don't want another Deepwater Horizon, and they want a profit in the end. Of course, it doesn't directly affect exploration. But when risks increase, you need more insurance.

DW GOM is not exactly booming currently.

[ROCKMAN]

tita - Can't appreciate the dynamic just looking at the well count. Very different world drilling on the shelf (less then 600' water depth) and DW (greater then 600') in cost and reserve size.

Well counts + drilling problems.

http://www.spe.org/news/article/a-reque ... e-drilling

LWC: loss of well control incident is an uncontrolled flow of subterranean formation fluids such as gas, oil, water, etc. and/or well fluids into the environment or into a separate underground formation, in which case it is called an underground blowout.

Seismic evaluation offshore, especially DW, can be very complex. OTOH DW exploration demands large "structural closures". Essentially localized uplifted areas...i.e. structural "highs". Oil floats to the top of such highs. Again a simplistic explanation. But a 16 yo of average intelligence can point to a high on a seismic line. And also point to structural "lows" with very little potential for an oil accumulation. All the DW GOM highs were identified many years ago. So prime leases vs "dogs" have beern known for a good while.

But if a 5,000 acre lease block (often more the one block) IS NOT a dog the detailed nitty gritty work begins. And the dogs: very, very low on the priority list. Onshore one can generate a great looking oil prospect that covers 200 acres. OTOH if an operator knew with complete certainty a 200 acre trap was full of oil they wouldn't drill it.

The DW GOM trend covers a huge area. But an offshore prospect also has to cover a large area. And no one, including the govt, offers such regional maps. So I can't offer a sense of how mature the DW GOM might be. But in general terms it's fairly mature. And the much larger shelf area: extremely mature.

[ROCKMAN]

pstarr - Water depth could be a limiting factor for a portion of the DW GOM trend. But:

A Maersk drillship broke the world record for the deepest water depth for an offshore oil rig after spudding a well drilled offshore Uruguay in a water depth of 11,200'. The Sigsbee Deep is the deepest region of the Gulf of Mexico and contains depths of up to 14,400'. But as far as the GOM oil production: In almost 9,500' underwater, the project is the world’s deepest oil and gas extraction effort to date and was done by Royal Dutch Shell.

Despite what many think the DW GOM is not new and relatively undrilled: There are approximately 3400 deepwater wells in the Gulf of Mexico with depths greater than 600'. A bigger limitation in the future may be that much of the trend has been tested. First production began 37 years ago with over 165 fields discovered so far.

How many more DW GOM fields left to discover? No one knows. But every trend ever discovered gets played out eventually.

[pheasantenergy]

At the point when you take a gander at the underlying outline, it appears as though the article feature is painting a deceptive picture. Aggregate seaward creation looks equivalent to 2010 and as does profound + ultra profound. So I figure the article ought to be titled "Seaward oil creation in profound and ultra profound recoups to 2010 levels.

[Subjectivist]

Interesting report on gulf deep water horizon disaster impacts. Quoted summery with link to very much longer report below.

$this->bbcode_second_pass_quote('', 'T')ransport, 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...