Guest Post by Cabot Martin
Uncle Gnarley’s recent invitation to pen a few
words on Oil & Gas issues has emboldened me to return to a few of my
favorite offshore issues.
There will be two articles – the first on our most neglected sector, offshore natural gas development; the second on oil issues.
The natural gas aspect seems to be largely absent from the recent “Town Hall” efforts in support of the oil & gas industry’s continued presence and vigor in our offshore area.
These comments are meant to “complement those efforts” in the old days I would have said “demonstrate they are missing the boat” – but that was then and this is now.
Indeed, the first draft of this piece included a long list of unfortunate aspects of the natural gas debate – but in the interest of the common cause it ended up on the cutting room floor.
Because
we seem to have arrived at a curious point of inflection, one where our
provincial interests, those of the industry and those of the Planet plainly
coincide.
So, let’s get the main proposition on the table right away:
Developing the Natural Gas resources of the Grand Banks now is in the best interests of the world community as it would make a significant contribution to the fight against climate change by helping to back China and India off coal at the most important time - ie over the next 30 years before Temperature Liftoff is irreversible.
Of course, there are some (maybe many) who will still say “Let’s talk first about making money; I’m running a business ?”
Turns out natural gas is a winner economically as well, particularly if, in foregoing some of our royalties, we see increased benefits in terms of climate change, employment, local R&D, a strengthened energy sector and an enhanced offshore service sector.
The natural gas strategy I propose follows, in some respect, Norway’s recent informal, industry led, re-orientation of its offshore oil & gas sector, as succinctly stated last fall by Rystad Energy’s senior exploration analyst Palzor Shenga as quoted in Offshore Engineer on November 29,2019:
“The most popular drilling strategy for energy companies in Norway continues to center on infrastructure-led exploration in mature areas of the North Sea and the Norwegian Sea. This approach has been delivering consistent results and generating a gradual increase in discovered resources from year to year, whereas frontier drilling campaigns in waters north of the Arctic Circle have largely led to disappointment in recent years.”
This is not to say that the current Equinor led efforts to open up the deep water Flemish Pass Basin for oil is ill advised – I’ll get to that in my second article – just to say that it is always best not to put all one’s eggs in the one basket.
Now, I am going to make a number of assumptions, some of which in “the old days” may, no, would, have sounded naïve but which in these troubled times may actually be seen as plausible.
In the management of publicly owned oil and gas resources, there has always been a tension between how government saw certain things and how the risk-taking investor oil companies saw the same issue. It was true in Texas starting off; it was true in Alberta right up to Lougheed’s days; and it was certainly true here in Moores’ and Peckford’s days.
Apart from the division of the revenue pie, the public goal of preventing “waste” is probably the next big point of contention – governments don’t like to see their resources, to use a mining industry term, “high graded” (the reservoir poorly managed; the natural gas left behind, etc); companies on the other hand want to maximize the rate of return on their investment – it’s an arm wrestle.
A mutually beneficial and public saleable compromise will require each side to articulate a concrete set of objectives – a broad subsidies or royalty reductions ask from industry without the corresponding achievement of a set of concrete public benefits obvious to the public is a formula for short term gain for long term pain.
For me, the most concrete public benefit I’d like to see come out of the current debate is the creation of an offshore natural gas industry.
I’m going to start off by showing some CNLOPB numbers for gas “resources” already discovered in the Jeanne d’Arc Basin.
Gas Resources are a physical concept not an economic concept you can take to the bank. Depending on a number of factors, especially the expected price to be received per cubic foot of gas and the estimated cost of development on a unit basis, some part of “Resources” can be skidded over into the bankable “Reserves” column, unlocking the funds to developed them.
Now
it is obvious that to get an offshore natural gas industry going, we’ll
probably need the development of a fair amount of new technology, new ways of
co-operating between companies, new flexible fiscal regimes, new, new, new.
Such requirements have never stopped the progressive development of Norway’s industry starting with their famous insistence back in the 1970’s, that it was possible to extend current pipelaying technology to allow the construction of an oil pipeline from their first big find (Ekofisk) east across the deep Norwegian Trench to land in Norway (rather than the company’s preferred and shallower route west to England).
Norway was not intimidated, but rather galvanized, by the challenge.
Accepting an English landing for Ekofisk oil in return for the operator providing petroleum products to Norwegian industry without transport cost, it set to work.
And while it took years of research, in 1993 a pipeline across the Trench landed liquid hydrocarbons from the Sleipner field in Karsto, Norway to help sustain and expand a local petrochemical facility.
This sort of determination (and success) has been the hallmark of the Norwegian offshore industry ever since.
What
I am calling for is a similar concerted effort on everyone’s part to convert
our natural gas “resources” to “reserves”, so that industry can justify a
massive offshore natural gas development – now – or next year – or shortly
after that - not at some always receding “not now I’m busy with oil” time.
Our economy and the world’s climate problems can’t wait. The window of opportunity will close leaving us with a very large “energy asset” that will stranded – perhaps permanently.
So what have we got by way of gas resources to put on the table so far ?
These are the 11 discovered Jeanne d’Arc Basin fields with natural gas resources – sometimes in conjunction with oil accumulations. They are ranked in descending size which may change with delineation.
FIELD RESOURCES (BCF) (billion cubic feet)
White Rose 3,018
Hibernia 2,353
Ballicatters 1,143 *
North Dana 472 *
Hebron 451
Springdale 239 *
South Mara 144 *
North Ben Nevis 116
Terra Nova 64
North Amethyst 35
Trave 30 *
Total 8,344 Bcf or 8.344 Tcf (trillion cubic feet)
* No Delineation Well
The fact that there are 5 fields on which no delineation wells have been drilled is probably significant; resource/reserve numbers generally go up with a step out well.
Of course, much of the debate about gas has referred to the resources at our four producing fields; As I will try to demonstrate below, it is symptomatic that 70 % of our offshore gas resources are associated with the 4 producing fields.
GAS RESOURCES ASSOCIATED WITH THE 4 PRODUCING FIELDS
White Rose 3,018 bcf
Hibernia 2,353 bcf
Hebron 451 bcf
Terra Nova 64 bcf
Total 5,886 bcf (5.886 Tcf) (70%)
In fact, all the natural gas found so far has been found “accidentally’ in the search for oil. Gas has never been a primary target.
A classic example of an “accidental gas find” was the significant 2010/2011 gas discovery at Ballicatters roughly half way between Hibernia and White Rose.
But this “surprise” should be of no big surprise when one looks at the burial depth of the main hydrocarbon source rock in the Jeanne d’ Arc Basin (the Egret Formation). The bulk of it (especially as you move north) is in the gas window, not the oil window, meaning - that there could be more energy ready to come out of the basin in the form of gas than in the form of oil - if we can make the natural gas production cost and other economic numbers line up.
So let’s go back to basics.
In oil & gas exploration, in any given area, the volume, quality and degree of cooking of your source rocks is all important – and I do mean all.
It sets the upper limit on what you can expect to find – other factors may cut that back -like poor porosity or permeability, lack of a trapping mechanism or no seal – but your source rock and it’s burial history is king.
Basic point for our purposes is that if you take a shale with a high TOC (total organic content) and cook at a relatively low temperature, you get oil.
Increase the temperature and you get wet gas (with lots of heavier ends like propane and butane).
Increase the temperature even higher and things really break down and you get near pure methane.
Really neglect the BBQ and you end up with a steak too black to eat (graphite – source rock over-cooked – pack your bags).
And by and large, the cooking comes mainly from the weight of over lying sediments combined with the increasing geothermal gradient with depth that has lots of organically rich shale (but not burnt to a crisp).
The real good news in the Jeanne d' Arc Basin - we have tremendous quantities of a rich world class source rock that is in the Goldilocks slot – cooked just right for gas (and some of it cooked right for oil as well - as per the oil reserves at Hibernia , Terra Nova, Hebron and White Rose).
The lowly organically rich gas prone shale – can’t get no respect (this is a core from the Barnett Shale that turned the gas industry on it’s ear- yes, they get gas out of this “hard” rock).
Let’s not skip over these geological basics – in the oil & gas Exploration and Development business, geology is key.
First that marvelous oil & gas “kitchen”, the Jeanne d’Arc Basin- home to the giant Hibernia field et al.
Beneath a relatively flat seabed in less than 600 feet of water, lies the Jeanne d’ Arc Basin, the deepest of the many geological basins that dot the Grand Banks - not all of which have been adequately explored by any means.
It has a funnel shape deepening to the North and contains more than 20 km of Mesozoic and Cenozoic sedimentary fill. Down at the bottom, it’s as hot as hell.
It covers an area of 4,000 sq miles and extends roughly 150 miles in a N-S direction and about 50 miles in an EW direction (Enachescu and Fagan, 2004) – that’s roughly the size of the Avalon peninsula and the presently producing area can fit in a triangle the size of one with points at Placentia/Carbonear/St Mary’s.
So stand up folks and salute that geological marvel – the Egret Formation – the source of our modern day bread and butter – and the Jean d’ Arc Basin “petroleum system” associated with it.
The Egret is a 60 million year old Kimmeridgian (Jurassic) aged organically rich shale dominated unit and is the only proven Hydrocarbon source rock in the Jeanne d’ Arc Basin.
I am using the big word “Kimmeridgian” because I think we should pay our respects to the little coastal village of Kimmeridge on the coast of Dorset in England - after the easily accessible “type section” exposed in seaside cliffs; that’s where our Egret shale gets its geologic time name; similar Kimmeridgian aged source rocks also underpin the massive North Sea oil & gas play.
Photo credit: Jurassic Coast Trust
Depending how deep the Egret was locally buried and cooked and the effectiveness of local fractures and faults providing local “migration routes”, sometimes it has produced deposits of:
-- oil and almost no gas (Terra Nova)
-- massive oil and lots of gas (Hibernia)
-- massive gas and some condensate (Ballicatters)
And it is expected in the deepest parts of the basin; sometimes it produced deposits of nothing but dry gas comprised of nearly pure methane – great stuff for converting to LNG (Liquified Natural Gas).
The Egret Member occurs all over the Jeanne d’Arc Basin and is buried to a depth which varies from 3300 m and 5000 m. The quality of the Egret source rock in industry terms is very high, contain oil-prone type I and II Kerogen. The TOC ranges from 2% to 12%.
The northern parts of the basin are over mature for oil, giving rise to gas-prone plays in these areas (eg perhaps Ballicatters half way between Hibernia and White Rose).
The Grand Banks natural gas debate over the last 40 years (yes it’s really been that long) has been dominated by the issue of iceberg scour and it’s potential impact on gas pipelines to shore. Suffice to say that our failure to solve this “problem” has effectively “stranded” (destroyed the economic value of) our massive d’Arc natural gas resources.
As noted below, there is new technology that might work around that issue. However, tackling Grand Banks iceberg scour anew should be at the top of the “To Do” list as part of any new concerted natural gas initiative. Memorial Engineering Professor Dr. Stephen Bruneau’s long standing concept of “going north to get down off the Banks and coming in deep through Trinity Bay” in particular deserves renewed study.
Interestingly enough, Exxon Mobil has since 2016 been successfully operating it’s GBOOC (Grand Banks Offshore Optical Cable) system consisting of a vital fiber optic cable system in a loop from Logy Bay out to the Hibernia and Hebron platforms and back to Cape Broyle - apparently without interruption by iceberg scour; these route roughly mimic potential shorter direct gas pipeline routes.
Do the risk assessments associated with the emplacement of this critical infrastructure contain new insights re the danger of iceberg scour that can be applied to natural gas pipelines?
The broader point is that in the sort of “all out” focus I am advocating, no stone should be left unturned.
In particular, we should look carefully at the new kid on the block – FLNG.
FLNG stands for Floating Liquified Natural Gas and it is, as advertised – a fully independent combined natural gas treatment and liquification plant in a ship that negates the need for a pipeline to shore altogether.
This concept is being increasingly used in SE Asia – calmer waters to be sure but it’s adaption to our conditions would not be unlike the process whereby US Gulf of Mexico offshore technology was beefed up for the North Sea and that of the North Sea beefed up for here.
As you can see in the sketch below, subsea gas wells feed into a seabed manifold with a riser feeding the produced gas up to the FLNG for treatment and liquefaction from where the LNG is fed in turn into an LNG carrier for transport to market – in our case in say Europe, India or China.
As it takes about 1 Tcf of gas in reserves to produce a million tonnes of LNG per annum for 20 years, Prelude will process 3.6 Tcf of gas into LNG alone, never mind it’s additional liquids components.
Fortunately, the FLNG concept is scalable.
Before exploring the implications of that aspect, let’s look at Shell’s rationale for making such a move and the issues they faced (in their own press release to celebrate the cutting of first steel October 18,2012):
"FLNG will enable the development of gas resources ranging from clusters of smaller more remote fields to potentially larger fields via multiple facilities where, for a range of reasons, an onshore development is not viable. This can mean faster, cheaper, more flexible development and deployment strategies for resources that were previously uneconomic, or constrained by technical or other risks.
Many of the technologies used on the FLNG facility are ones that Shell has used successfully onshore, but some have been extended or modified for offshore. The new technologies that Shell developed for FLNG include: managing sloshing in LNG tanks; systems for managing the close coupling between the producing wells and the LNG processing facility; LNG offloading arms; water intake risers; mooring systems; and the marinisation of processing equipment such as absorption columns and the main cryogenic heat exchangers. All of these technologies have been extensively modelled and tested to ensure they can operate safely and efficiently under marine conditions."
Sounds like something to be explored !
Indeed, less ambitious SE Asian projects are increasingly focusing on FLNG systems that are backed by say 1.5 Tcf of gas giving a production of around 1.2 million tonnes of LNG per year which is at the lower end of your common garden variety of onshore LNG plants – but still massive, covering hundreds of acres – the engineering feat of building an LNG plant in a box is not to be underestimated.
So a good notional target project in our offshore might be the development of one or more somewhat scaled back Prelude FLNG’s, each backed by 3 - 4 Tcf in reserves and each producing about 3 million tonnes of LNG per annum (plus some other petroleum liquids depending on gas richness).
I dare to go that far; and farther – for what might the long term look like ?
I have to stop here and admit that this sort of idea poses not just a daring technical challenge, although it certainly is that. Pulling this off would, just as critically, depend on an unprecedented degree of co-operation between the present industry operators and permit holders - that’s absolutely key and amazingly, not so implausible given the existential threats the oil & gas industry feel it’s under.
So let us indulge ourselves with the notion that all Grand Banks operators will agree to cast their various gas lots in together ! Normally not their pattern but hey, it’s Covid/Climate Change time and oil prices could be under siege for some time.
And we do have a strong and experienced group of internationally based operators/permit holders, who are used to working together at least on the local operating level, plus a strong internationally focused offshore service sector and finally some significant engineering resources at Memorial.
Taking just the 13 Grand Banks gas deposits we already have, what would a truly joint development look like in a best of all worlds ?
Certain constraints are obvious – the four oil producing consortia won’t be ready to “blow down” their gas caps for some time – so put them last. There’s some pure or non-associated gas finds like Ballicatters (from 2010/2011, already at 1 Tcf and dying for a delineation well) put them first and get a couple of rigs going focusing solely on gas targets to strengthen up the start group and the middle. Then there’s some smaller ones like Springdale, North Dana and even Trave that should be delineated plus numerous untested structures in the gas prone parts of the basin - they go in the middle group.
And for all of this, no new exploration permits need be issued and with a sensible approach, no additional long involved environmental reviews need take place prior to a full fledged Development Plan being filed.
It might over time look like this:
EXAMPLE OF WHAT A CO-ORDINATED GRAND BANKS GAS DEVELOPMENT MIGHT LOOK LIKE
FIELD NAME RESOURCES (BCF)
GROUNDBREAKERS
Ballicatters 1,143
North Dana 472 White Rose (Non-Assoc) 1,509
Sub-total 3,124 (3.124 Tcf)
(Susceptible to increase
by Delineation Drilling at Ballicaters & White Rose
and near term new gas discoveries)
MIDLIFE
Springdale 239
South Mara 144
North Ben Nevis 116
North Amethyst 35
Trave 30
Sub-total 564 (0.564 Tcf)
( Susceptible to increase by delineation and new Gas Discoveries
over life of the project)
GOLDEN YEARS
White Rose (Associated) 1,509
Terra Nova 64
Hibernia 2,353
Hebron 451 4,377 (4.377 Tcf)
All 3 Categories Present Total 8,344 (8.344 Tcf)
Of course there will be the naysayers and such things do tend to be complicated. On the other hand, I do remember well the fight to get the Hibernia Consortium to look seriously at using a GBS at Hibernia – there were serious divisions even within Mobil, let alone within the Consortium ! But with a little nudge here and a little nudge there, the concept did finally get a full and proper review and turned out to be the best solution.
Maybe, just maybe , it can happen again – this time without too much persuasion by the Province – self-interest being what it is.